Effingham County Power receives its fifth Best of the Best Award—tops in the industry

The Best Practices Awards program for owners and operators of generating facilities powered by gas turbines, sponsored by CCJ ONsite and its companion quarterly print edition, and their user-group partners, celebrates its 13th anniversary in 2017. Over the years, more than 600 Best Practices entries have been received from 200 or so individual plants and fleets; the accomplishments of more than 100 have been recognized with awards.

There are two levels of awards to acknowledge the achievements at individual plants: Best Practices and The Best of the Best, as voted by a team of highly experienced judges who evaluate the submittals with weighted consideration of the following characteristics:

      • Business value.

      • Degree of complexity.

      • Staff involvement.

      • Duration of value.

The five most successful plants over the years in numbers of awards received are Effingham County Power, Klamath Cogeneration Plant, and Tenaska Virginia Generating Station and its sister plants Lindsay Hill and Central Alabama. Effingham, today owned by Carlyle Power Partners and operated by Cogentrix Energy Power Management, was the only one of the five recognized in the 2017 program and it came away with the facility’s industry-leading fifth Best of the Best Award.

The 2 × 1, 7FA-powered Rincon (Ga) combined cycle, rated a nominal 525 MW, began commercial operation in August 2003. Plant Manager Nick Bohl’s team—including Bill Beahm, Cheryl Hamilton, and Bob Kulbacki—submitted four entries this year. The first one on the list below was the most popular with the judges.

Safe grounding of a generator step-up transformer

When maintenance is required on the high-voltage system, conductors must be effectively grounded to earth so the potential difference between the conductors and other grounded components is zero. The temporary protective grounds used are 4/0 Cu “C” style; they vary in length from 8 to 25 ft. In the past, they were connected directly to the conductors and an approved grounding point using a manlift.

There were several issues with this approach, including the following:

      • Damage to cables.

      • Use of a manlift.

          • A manlift is not rated for electrical use. Even if personnel in the manlift are using the proper electrical PPE, the workers at ground level are in danger if they touch the manlift because of the induced voltages from exposed conductors.

          • The plant doesn’t own a manlift. This means it would be necessary to lease one at a cost of about $1400 per week.

          • Operating a manlift within the close confines of the HV yard increased the potential for damage to insulators and arrestors.

The most practical place to install grounding cables on the low side (18 kV) of the GSU serving the gas turbines at Effingham is where the generator transitions from solid bus to ACSR cable (aluminum-clad reinforced steel). Because the bus and the GSU are at different heights, the ACSR cables are angled at approximately 45 deg.

Even if a bucket truck with a dielectric boom were used to assist in hanging the grounds, the angle and weight of the ground cable would put excessive stress on the aluminum conductors, causing the strands to separate. This was confirmed during an annual outage inspection of the substation.

The plant had to find a new method for hanging grounds safely and economically. First, plant personnel tried using a step ladder positioned on the loose gravel. The weight of the grounding cable and the uneven surface made it unsafe. Next, technicians tried working off an extension ladder positioned against the GSU. The close proximity of the workers to the transformer, and the weight of the clamps, increased the possibility of component damage.

Ideas then were solicited from technicians who had performed this task in the past to determine a safe alternative. An employee with transmission-line experience recommended using grounding posts installed on the low-side insulators. He researched the various designs available and whether they were compatible with the voltage that would be present on the insulators.

Ground hanger studs were purchased and mounted on top of the insulators on the “H” structure serving the two GTs (photo). This provided a fixed point of attachment for the ground clamp, which can be hung from ground level using an HV stick. Studs were installed by electrical contractors during a planned outage.

After installation of the grounding posts, technicians practiced hanging the ground clamps; all feedback was positive. Technicians liked the safety of being able to hang grounding cables from the ground versus climbing onto a ladder or using a manlift. Plus, use of the grounding posts means grounding cables no longer are clamped to the aluminum HV cable, eliminating the resultant wear and tear.

Success! Grounding posts are located directly above the technician’s head. This means the weight at the end of the stick is straight up and not at an awkward angle, making it easier to control the grounding cable being installed.

A longer HV stick (shotgun) was purchased, allowing the technician to hang the grounding cable from the ground without use of a ladder or scaffolding. The benefit: A more stable platform for the grounding process.

The grounding posts provide a defined grounding location and are clearly visible from the ground, enabling personnel to verify grounds are removed prior to closing any breakers. The grounding posts are bolted in position, so if there’s any damage they can be replaced easily during an outage.

Finally, eliminating the need for a manlift saves thousands of dollars annually.

Relocation of flow transmitter eliminates freeze-up, fouling

A condensate flow transmitter is critical to proper operation of Effingham’s hot-reheat (HRH) dump valve. It regulates condensate flow to control the temperature of steam dumped to the condenser.

The transmitter is located directly off the condensate process line with carbon-steel piping and valves. It is insulated with both lag pads and heat tracing. In winter it would freeze, damaging the instrument and causing plant upsets. Damaged transmitters would have to be replaced at a cost of $1500 per.

During the summer, buildup of biological matter would clog the short process lines. It caused the transmitter to indicate flow even when the condensate system was shut down and the condensate block valve would not open because of this false indication. This was an issue when the HRH dump valves were placed in service, because steam temperature would increase until condensate flow demand was high enough to overcome the false indication.

Result: Several high steam-temperature alarms and potential damage to the condenser exhaust-hood spray. This required that the transmitter be re-zeroed and calibrated numerous times during the summer. Also, process lines had to be flushed periodically to remove any build-up in the sensing line.

A new location was identified for the transmitter and the instrument was relocated. The material costs were approximately $4500; all work was performed by plant personnel during a routine maintenance outage. The transmitter was placed in an insulated box with a heater to prevent freeze-up and damage. The transmitter’s process lines were extended and placed below the process piping. They are insulated and protected with heat tracing.

Success! Relocation of the transmitter eliminated the threat of freeze damage and the longer process tubing mitigated biological growth. The latter reduced the possibility of plant upsets and erratic readings. Also eliminated is the need for flushing out the lines and/or zeroing the transmitter prior to startup.

Empowered technicians, inexpensive mod boost plant reliability

By design, there is a transmitter that senses the exhaust-duct pressure of Effingham’s gas turbines and provides an input to the Mark VI control system. Also, there is one pressure switch that activates an alarm when its set point is exceeded.

There are two additional pressure switches that provide a trip signal to the Mark VI system if their set points are exceeded. The GT is designed to trip if any two out of three exhaust-duct pressure switches exceed their set points.

These switches and a transmitter were connected in series. Because there was only one test connection installed in the sensing line to calibrate the switches, they had to be tested together. But if tested together all three switches would exceed their set points, activating a turbine trip signal. Thus the only time the switches or transmitter could be checked or calibrated was when the unit was offline.

After a major outage while the plant was ramping to 525 MW, the operator received an exhaust-duct high-pressure alarm, Twenty-four seconds later GT1 tripped because two out of three pressure switch set points had been exceeded. The exhaust-duct pressure at the time of the trip was 21.9 in. H2O. Staff determined that set points for one or both of the trip pressure switches had drifted down since the last time they were tested. Lost generation for this event was 100 MW.

On a second occasion, while at steady state, GT2 tripped on high exhaust-duct pressure, which occurred at 23.7 in. Prior to restarting the GT, the set points for the exhaust-duct alarm and trip pressure switches were checked. All three pressure switches were set at 23.6 in.—the two trip-switch set points had drifted down by almost 2 in. The switches were last calibrated 45 days prior to the trip. Lost generation for this event was 147 MW.

For each lost megawatt of generation the plant is charged $150; therefore, trips can result in thousands of dollars in lost revenue. It was important to find a way of checking pressure-switch set points easily and to check them frequently during the year to prevent trips.

Space constraints militated against installation of individual sensing lines. Other switches on the GT roof had a separate isolation valve and calibration ports for their sensing lines, allowing calibration of switches without disassembling sensing lines to connect test equipment. Based on that knowledge staff decided to install a separate isolation valve and calibration port for each of the exhaust-duct switches.

For about $100 a unit, technicians purchased the needed components to complete the sensing-line mod. With the GTs offline, technicians installed the isolation valves and calibration ports. At the completion of the modification, the tubing was leak-tested with air and the isolation valves were closed to ensure complete isolation to the instrument being calibrated.

In the short amount of time since this modification was completed, spurious exhaust-duct high-pressure alarms have decreased significantly. The ability to check the set points of switches has increased plant reliability.

Success! The ability to check and calibrate switches while the GTs are online has made this project noteworthy. For example, last June the plant remained online for 28 out of 30 days. During that time, personnel were able to check the switch set points weekly. A spreadsheet was developed to monitor the amount of drift and any adjustments required. Installation of improved switches has virtually eliminated trips attributed to drifting set points.

Lay up chillers dry in winter to protect equipment, save money

The GT inlet chiller system normally is taken out of service when daytime temperatures are consistently below 60F—typically December through March. When Effingham commissioned its chiller system in 2010 there was minimal experience on staff with winter layup. Plant personnel reached out to the chiller manufacturer and the chemical supplier for recommendations on how to prevent biological growth and minimize corrosion.

The first method used was to keep the system full and circulate the water for four hours, adding chemicals every three days during the off-season. The annual cost in chemicals and electricity for this approach was about $3300; plus, there was the possibility of freeze damage when the system sat idle.

The second method tried was to drain the entire cooling-water system by opening the vent and drain valves on the condenser and cooling-water pump. Once the system was drained, a nitrogen cap was placed on the cooling-water header. Adding one cylinder of nitrogen daily from a 12-pack was the direction provided to the operators, but it was not an effective solution for preventing corrosion. Leakage of nitrogen was one reason.

A quarterly service contract for the inlet chiller was the next solution tried and the one adopted. It calls for three operational inspections and one shutdown inspection annually. The shutdown inspection and condenser tube cleaning are conducted in the first quarter. To do the cleaning, one head must be removed from each of the condensers. Since the layup methods described earlier were expensive and failed to prevent biological growth and corrosion, staff decided to pull a head and keep it off for the duration of the winter layup period.

The current plan: Once the chillers are no longer required, the cooling-water system is drained and a condenser header from each chiller unit is removed and stored, allowing for complete drying of the system. Next, the service contractor is contacted and tube cleaning and inspection are scheduled.

The vendor responsible for the chemistry program also inspects the cooling-water system. Based on its findings, the effectiveness of the chemistry program is evaluated and changes made as needed.

Since instituting the practice of drying the chiller condensers during the winter, the corrosion rate has been reduced. In addition, no cooling-water tube leaks have occurred and no electricity and chemical costs incurred. Finally, since the entire cooling-water system is drained during the layup period, there is no need for additional insulation or heat tracing.

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Safety best practices among Woodbridge’s top priorities since commissioning

Woodbridge Energy Center is a nominal 725-MW 2 × 1 combined cycle powered by two of the first 7FA.05 engines to achieve commercial operation. It is owned by Competitive Power Ventures and operated by Consolidated Asset Management Services (CAMS) with Plant Manager Ken Earl at the helm. Given the leading-edge technology implemented at this facility, Earl and his team have been deeply engaged in plant activities since well before first fire.

The veteran manager is a believer of “owning” the operation of the plant from Day One. What he means is not to be in a position of blaming someone else for punch-list items after commissioning. To keep on top of things, Team Woodbridge implemented a formal process of system walk-downs during construction to correct as many oversights as possible before first fire. This level of involvement fostered the development of many best practices to ensure lessons learned would not be relearned.

Earl and team members Michael Armstrong, Justin Hughes, and Ryan Bullock share four of the plant’s best practices here. The first profiled below, Comprehensive plant heat-trace guide, received the highest marks, resulting in Best of the Best honors. This is the fifth Best of the Best Earl has had a hand in. The other four were awarded to Effingham County Power when he managed that facility for CAMS.

Coincidentally, Effingham, under new ownership, also was recognized with a Best of the Best this year—its first under Nick Bohl, who was promoted to plant manager when Earl accepted the challenge at Woodbridge.

Comprehensive plant heat-trace guide

Plant personnel found that poor installation practices coupled with the lack of documentation made it difficult to troubleshoot Woodbridge Energy Center’s heat-trace system. This required staff to spend roughly 60 man-hours per week identifying and fixing issues with heat-trace circuits not functioning as designed. The poor performance of the heat-trace system jeopardized reliability and operability by allowing critical equipment to freeze-up.

The central New Jersey facility was constructed as an outdoor plant with everything—including instruments, pumps, piping, control valves, etc—installed outside. Equipment must endure the elements of a Northeast winter, where temperatures may be below freezing for days on end. Obviously, equipment reliability depends on a functioning heat-trace system.

Woodbridge was constructed by a single EPC contractor with multiple equipment suppliers. Design of the heat-trace system was subcontracted to a reputable supplier while installation was performed by the EPC contractor’s craft electricians, who had little or no experience with heat-trace equipment.

The various scope-of-supply boundaries and types of heat tracing proved problematic. Many field changes were required to complete the installation—changes performed without the knowledge of the designer and poorly documented.

Heat tracing was designed to maintain an equipment temperature of 40F at an ambient of -8F. The heat-trace supplier implemented the use of microprocessor-based temperature control and monitoring panels which required other new equipment—including various temperature sensors, new alarm capability, DCS integration, self-testing circuit cards, and programmable RTD outputs.

The lack of qualified oversite from the heat-trace designer during equipment installation and in preparing documentation of as-built conditions proved challenging for the plant operator once it took possession of the facility.

First step in fixing the problem was to bring back the original heat-trace designer to audit the entire system and identify and correct any deficiencies. This required all 612 individual circuits to be reviewed to ensure the correct materials were used along with the correct installation practices. Next, all the documentation was updated to reflect as-built conditions. This information and a thorough review ensured the system was designed and installed as originally intended.  

With the proper installation and operational techniques identified for the new technology, the plant operator developed a heat-trace guide to provide a laymen’s approach to better understanding of equipment and operational requirements. In development of the guide, the details which had been segregated because of scope breaks are included in one location, eliminating the need for multiple sources of documentation. The guide is written in plain language and includes pictures of installed equipment to better acclimate the reader and facilitate troubleshooting.

The guide includes the following major sections:

      • Equipment and location defines what the pieces of equipment are, along with their associated location.

      • Operational overview describes the system from beginning to end.

      • General alarm and troubleshooting describes typical steps to take when an alarm is received. This section also advises the operator what information must be recorded to facilitate a work order in the event they are unable to troubleshoot the issues seen.

      • Examples of equipment onsite describes with pictures each piece of equipment.

Success! Using the original design team to identify and fix the installation issues the heat-trace system achieved its specified objectives. System performance now is aligned with the original design intent, ensuring safe and reliable operation of plant equipment during times of inclement weather.

Upon release of the guide, personnel were immediately able to reference site-specific information for heat-trace issues in a timely manner. Today, only about 10 man-hours per week are required to properly troubleshoot system issues, down from 60. The guide also helped personnel identify equipment improperly installed, before it adversely impacted heat-trace performance.

In sum, the guide’s effectiveness has shifted the response from reactive troubleshooting to proactive analysis and has removed any uncertainties associated with the new technology installed at the facility.

Logic changes reduce blowdown quench-water consumption, save $30,000 per month

At Woodbridge Energy Center, blowdown and drains from each heat-recovery steam generator are directed to a dedicated blowdown tank where they are cooled with potable service water supplied by the local water authority. Quenched steam and water drains from the blowdown tank into a blowdown sump and is then forwarded to the cooling-tower basin via HDPE piping, temperature-limited at 140F.

The blowdown tank and drain sump have independent temperature control valves. The blowdown-tank control logic was programmed to maintain a temperature below 140F using service water for quenching. The sump was programmed to maintain 120F using a separate but similar quenching setup. Each of the blowdown tanks required 65 gpm of quench water, the sumps an additional 25 gpm each.

To reduce potable-water consumption, the blowdown tank temperature control logic set point was raised to 220F, allowing blowdown to flash off and leave through the outlet piping to the muffler with minimal or no need for quench water. The elevation of the muffler provides enough exposed piping that steam entering the blowdown tank can cool naturally and condense, reducing the need for quench water. The new alignment reduces the temperature of water remaining in the blowdown tank to less than 120F, eliminating the need for quenching in the drain sump.

Service-water consumption has dropped by approximately 125 gpm since implementing the logic changes. This translates to a monthly saving of $30,000.

Safety program minimizes the potential for arc-flash injuries

Determining the appropriate arc-flash personnel protective equipment (PPE) was extremely difficult at Woodbridge Energy Center because of the complex nature of the installed arc-flash PPE and various scope breaks in arc-flash protection. The plant’s power distribution system was designed to restrict the incident energy level to a maximum value of 25 cal/cm2.

Differential protection, fiberoptic arc-flash detection, high-speed overcurrent protection, and maintenance switches were used to satisfy this requirement. Depending on the voltage and current rating of a particular piece of equipment, any one of these methods could have been employed.

The arc-flash rating for equipment with a “maintenance switch” could be changed dramatically by turning the switch on or off. Adding to the confusion, the arc-flash study performed by the EPC contractor during construction referenced NFPA 70E-2012 guidelines, which changed shortly after the study was completed when NFPA 70E-2015 was released.

Adding to the difficult nature of the protection was an arc-flash study over 300 pages with results for the incident-energy levels described not in alignment with NFPA 70E-2015 or the site’s arc-flash safety procedure.

Furthermore, the NFPA 70e hazard labels provided by the EPC contractor did not specifically call out a recommended level of arc-flash PPE, requiring the person performing the work to locate the piece of equipment in the arc-flash study and cross reference the incident energy level with the site’s safety procedure and NFPA 70E-2015. With so many different documents being used to accomplish one task, the risk of human error increased significantly; potentially hazardous situations could occur.

The first step in reducing the confusion regarding the hazard ratings was to ensure the site arc-flash safety procedure included easily understood PPE classifications. Following NFPA 70E-2015, site personnel aligned the plant’s arc-flash PPE with these three incident-energy levels: 0-1.2, 1.2-12, and 12-40 cal/cm2. For the 0-1.2 cal/cm2 range the company determined arc-rated uniforms and arc-rated face shield (as necessary) would be required and made them available.

For the higher incident-energy levels, separate kits were created for each arc-flash level and included all of the properly rated PPE in sizes large and extra-large. The kits are contained in a clear storage bin stored in a designated location at the site and are labeled to reflect the arc flash rating and designation by color and letter. The color code and letter designation labels also are applied to each piece of power distribution equipment adjacent the NFPA 70e label. Specifically:

      • Equipment rated <1.2 cal/cm2 is identified with a green label having white lettering stating, “Arc Rated Uniform.”

      • Equipment rated 1.2-12 cal/cm2 has a blue label with white lettering stating, “Arc Flash Kit A.”

      • Equipment rated 12-40 cal/cm2 has a yellow label with white lettering stating, “Arc Flash Kit B.”

These same labels then were placed on the outside of the clear storage bins containing the corresponding PPE. Note: Equipment rated >40 cal/cm2 has a red label with white lettering stating, “No Energized Work Permitted.”

Safety made easy. Site personnel now can walk up to a piece of power distribution equipment and easily identify the hazards and proper PPE required to perform energized work, greatly reducing the risk of incorrectly determining the required PPE. In addition to significant increases in arc-flash safety, this best practice has reduced the time required to evaluate energized work requirements—from hours to minutes. Man-hour reductions could save $150,000 over the life of the facility.

Trifold for contractors keeps critical site information readily available

Combined-cycle outages require a large skilled workforce to complete a substantial amount of work in a short period of time. It is not uncommon to have over 150 contractor personnel working during a major outage, increasing the risk of a safety or environmental incident.

To mitigate this risk, all contractors are required to participate in an onsite safety orientation prior to beginning work.

This orientation covers the site safety and environmental requirements and procedures along with all of the applicable plant policies. Most contractors participate in dozens of site-specific orientations per year so keeping track of which policy/procedure applies to the current worksite is nearly impossible. Additionally, contractors may have little knowledge of the equipment and processes they are working on, and may be expected to carry out tasks that are not routine for them.

After the relatively short orientation, contractors are expected to recall vital safety information including evacuation locations, emergency contacts, locations of equipment, and hazards. Tall order.

So Woodbridge personnel developed a contractor safety orientation trifold pamphlet. Upon completion of orientation, each contractor receives a hard-hat sticker and a copy of the pamphlet, which they are required to have on their person when onsite. The sticker tells plant personnel who should have copy of the trifold.

The trifold, printed on durable cardstock material, includes critical plant-specific information—including emergency phone contacts, plant radio system channel, what to do in the event an emergency, summary of safety policies and procedures, and a plant plot plan that identifies contractor parking, smoking areas, restrooms, and the evacuation muster point, plus major plant equipment.

The safety trifold was inexpensive (less than $350) and has provided immediate results in improved awareness and safety culture. To date, the plant has not experienced a safety or environmental incident attributable to contractor personnel. The trifold makes critical safety information presented during contractor orientation accessible at all times.

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Recovering ‘non-recoverable’ megawatts

Under its capacity agreement, Green Country Energy, Jenks, Okla, is incented to maximize capacity up to 795 MW, corrected to contract conditions. When new and clean, the facility was capable of producing the 795 MW from its three 1 × 1 F-class combined cycles, but after several years, capacity had declined by approximately 20 MW, depending on ambient conditions. The reason: Normal degradation of the gas turbine (GT), steam turbine (ST), and heat-recovery steam generator (HRSG).

Plant owner J-Power USA and its operator, NAES Corp, teamed up to find a cost-effective way to recover the lost megawatts. Several possibilities were evaluated within the time constraints imposed by equipment suppliers offering discounts for quick decision-making, including the following:

    1. 1. GT advanced gas-path technology.

    2. 2. GT combustion-air enhancements.

    3. 3. GE’s OpFlex model-based control system upgrade package.

    4. 4. Increased duct-firing.

The Green Country team (sidebar) weighed these options in terms of five criteria:

      • Financial.

      • Environmental impact.

      • Contracts evaluation, including the project’s contractual service agreement (CSA) with the OEM.

      • Technical feasibility study, including input from an engineering firm and the HRSG manufacturer.

      • Operations and maintenance impact study, to consider future O&M benefits and risks.

The evaluation team selected options 3 and 4: The OpFlex control system plus additional duct-burner equipment and a modified permit to increase heat input.

The OpFlex upgrade consists of an advanced model-based control (MBC) software platform that increases GT output, efficiency, and flexibility. OpFlex removed the legacy control methods— exhaust temperature control, for example—and replaced them with a more flexible solution, one offering greater capability to optimize performance.

It identifies operational parameters such as exhaust temperature, firing temperature, and emissions and creates specific control loops for each parameter to ensure that the turbine as a whole is always operating within the intended design space.

Among the OpFlex offerings, Green Country selected peak fire, cold-day performance, AutoTune, and enhanced alarm help. With OpFlex installed, operators can select a megawatt value above base load—up to 100% peak-fire capability. However, once peak fire is enabled, an increased hot-gas-path (HGP) maintenance factor is incurred.

AutoTune removes the combustion restrictions of the legacy control system that limited baseload output in cold ambient conditions, providing cold-day performance increases in GT output. AutoTune also provides constant tuning of NOx and combustion dynamics, reducing the need to perform seasonal tuning. Cold-day performance requires no operator action, and it incurs no increase in the HGP maintenance factor.

Green Country also installed enhanced GT transition pieces, flow sleeves, and Stage 1 buckets to minimize the effects of peak fire on GT maintenance intervals. The evaluation team expected a capacity increase for the facility of about 17.5 MW, as well as an improved combined-cycle heat rate.

As mentioned earlier, duct-burner hardware and controls also were added to enable increased duct-firing. This included addition of one burner element, four baffles, and upgraded pressure-reducing stations to each HRSG. These additions were projected to yield up to 3 MW more output per unit, or 9 MW total for the three-unit facility.

There were some concerns about deploying the peak-fire provisions in concert with the additional heat input from the duct-burner modifications, so the potential risks were evaluated:

      • The HRSG components could reach metallurgical temperature limits when both systems were fully deployed, especially during summertime ambient temperatures.

      • The additional burner element and related baffles could increase the HRSG pressure drop, which would negatively impact GT exhaust pressure, especially when deploying OpFlex cold-day performance during the winter months.

      • Existing equipment might not provide sufficient desuperheating capability to adequately control HP steam temperatures during the summer.

      • Relief-valve capacity (with required margins) might not be sufficient to respond to a baseload trip during deployment of both peak fire and maximum duct-burner heat input.  

After weighing the risks and benefits, the evaluation team determined that GE OpFlex together with the duct-burner modifications would provide a technically sound solution with limited commercial and technical risk. An overall increase of 17 to 20 MW was believed possible, depending on ambient conditions.

Success! The OpFlex and duct-burner projects met or exceeded expectations. Once the permitting requirements were finalized and the projects commissioned, Green Country conducted a capacity test that measured 801 MW. This achieved the maximum contract capacity of 795 MW with some margin.

In addition to restoring the megawatts lost through equipment degradation, the upgrades improved combined-cycle heat rate. Plus, the higher GT output and greater mass flow through the HRSG produced by OpFlex at both high and low ambient temperatures reduced the amount of duct-burner output needed to meet the plant’s normal deployment, resulting in fuel savings.

Green Country evaluation team

J-Power USA

Paul Peterson, VP of asset management
Masaru Sakai, VP of engineering
Justin Sperrazza, assistant director of asset management
Makoto Kaneko, assistant director of engineering


Rick Shackelford, operations director
Danny Parish, plant manager
Michael Anderson, maintenance manager
Daniel Barbee, contracts administrator
Greg Holler, compliance supervisor
Derek Hale, lead operator

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Healthy condenser makes for an efficient plant

Main-condenser vacuum is a primary driver of steam-cycle efficiency. Powerplant designers develop curves plotting condenser heat load and cooling-water temperature at an assumed tube cleanliness to arrive at a calculated condenser vacuum. These curves then can be used by the O&M staff to verify operation at or near design conditions.

However, the curves, as provided by the condenser manufacturer/EPC contractor, are of limited practical value to operations personnel. For example, they do not provide the following:

      • Data that are easily accessible during transient conditions. Many units in Talen Energy’s combined-cycle fleet, like the 2 × 1 F-class Nueces Bay (670 MW) and Barney M Davis (648 MW) Energy Centers, both located in Corpus Christi, Tex, change load frequently to follow market opportunities. Plus, inlet circulating-water (CW) temperature can vary by several degrees throughout the day because of ambient conditions.

      • Historical data to trend changes in deviation from design curves over time. This could provide valuable information to plant management for determining when to perform condenser maintenance as well as to quantify the effectiveness of maintenance performed.

The challenge was to develop an operating metric that could improve upon the design curves provided. The Nueces Bay and Barney Davis staffs came together to develop the solution described below. It can be implemented fairly easily at many other plants, possibly yours, to improve performance and predict maintenance needs.

During operation, the condenser heat duty presented on the abscissa of the design curves is proportional to steam turbine/generator (ST) output. The performance improvement team’s first step in developing a practical operational metric was to convert the heat duty on the x-axis to applicable ST output values in megawatts. The curves then were converted to mathematical formulas that could be programmed into the plant’s distributed control system (DCS).

The DCS can interpolate between the discrete curves to allow analysis at any CW inlet temperature. By inputting the actual ST output and CW inlet temperature into the appropriate formula, an as-designed condenser vacuum can be calculated. This then can be compared to the actual vacuum.

The difference from actual to design is called the condenser design vacuum deviation (CDVD). As a DCS-generated value, CDVD can be used by operators to gauge condenser efficiency in real time during both steady-state and transient operations.

In addition, the CDVD can be logged in the plant data historian to trend condenser performance. This can be used by maintenance team members to determine loss of condenser performance, or restoration of performance post-maintenance.

The performance-improvement team cited several instances of CDVD being used for determining vacuum leakage problems. They are:

Case 1. During 2015, condenser vacuum continually deteriorated. Given the long timeframe, cycling operation, and varying CW temperatures, the deviation was suspected, but not verified. When CDVD was graphed on a quarterly basis, the movement away from design was easy to see (Fig 1). Corrective action was taken and performance improved dramatically (table).

Case 2. Prior to the fall 2016 outage, the plant’s CW filtering system failed. The decision was made to continue operating until the scheduled outage. During the outage, significant resources were expended to restore the CW filtration system to good condition, as well as to clean the condenser tubes and tubesheet. Before and after CDVD values are shown in Fig 2.

Case 3. During a summer run, operations staff thought condenser vacuum was running high. An analysis of CDVD data showed vacuum was running well within normal specification and there was no increase in CDVD. This precluded chasing a non-existent vacuum issue.

Case 4. Condenser performance curves also are developed by designers for operation on one CW pump. When one of two 50% CW pumps is unavailable for operation, it is typical to de-rate the plant to half load. But by using these curves and knowing nominal CDVD values, when one pump is unavailable, actual CW temperature can be used to determine available condenser duty—hence, plant output. This may mean the plant can operate at a higher capacity on the single CW pump than it otherwise might.

Project participants

Norm Duperron, plant manager, Nueces Bay
Bill Smith, plant manager, Barney Davis
Eric Mui, senior ICE technician, Nueces Bay
Robert L Garza, operations manager, Barney Davis
Vince Powers, plant performance manager

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Plant staff fine-tunes operations, implements mods, upgrades to reduce startup NOx

These are difficult times for owner/operators of conventional assets. They get no relief from regulatory bodies regarding emissions, grid operators aren’t bashful about making still more demands on them, profit margins and O&M budgets have been squeezed dry in many cases, OEM solutions can be too costly, etc.

What to do? One thing is to “improvise, adapt, and overcome” the challenges facing your plant with in-house talent. Take a page from the lesson book of Riverside Public Utilities, the only aero facility recognized in 2017 with a BEST OF THE BEST award in the CCJ Best Practices Program.

The Riverside Energy Resource Center consists of four LM6000 simple-cycle peakers used to supply 200 MW of reliable fast-start power to the 105,000 electric customers served by the municipal utility. Each gas turbine satisfies its NOx emissions permit with water injection and a selective catalytic reduction system using 19% aqueous ammonia.

In addition to Riverside’s commitment to its city customers, the California Independent System Operator (CAISO) demands the four gas turbines be available for state-required dispatch when not used for self-generation. The CAISO frequent calls for the enginesto start up, sometimes multiple times daily. The problem faced by the asset owner: Each start produces three times the amount of NOx as does a normal production hour.

The Riverside facility is located in the most environmentally challenged air district in the nation—the South Coast Air Quality Management District. It restricts monthly and annual operations based on pounds of NOx discharged. Given the frequent starts mandated by the CAISO, the South Coast AQMD in effect reduces the number of hours the Riverside units can run monthly and annually. But the CAISO and the city of Riverside need the power “on demand” 24/7/365.

The utility found itself between the proverbial “rock and a hard place.” It could re-permit and purchase emissions offsets at prohibitive cost in both time and money, or find a way to reduce startup NOx emissions. The latter was the path chosen and it proved a career test for the solutions team headed by Generation Manager Chuck Casey, Plant Manager Bryan Atkisson, and technicians James Mysliwiec, Will Patton, and Ron Herrero.

One of the first steps was to see what the OEM could offer. The team re-learned that the turbine manufacturer would not deviate from tried and true historical methods of equipment operation and was more interested in selling new systems than in upgrading old ones.

The team moved forward by creating a wish list of possible changes to reduce NOx mass emissions. They termed this effort “black box” considerations because many of the proposed solutions were visionary—not yet available—but seemed achievable. Equipment suppliers were dared to go beyond their safety nets—to loosen limits without damaging equipment or causing emissions upsets. Staff worked closely with equipment and operations partners to seek feasible results.

After two years of researching, teaching, challenging, experiementing, brainstorming, and implementation, a 30% reduction in startup NOx was achieved, allowing a commensurate increase in operating hours while still holding emissions within the South Coast limits. Specifically, the number of starts was increased from 40 to 62 per month.

The path chosen to achieve a 30% reduction in startup NOx involved the following:

      • Use of a megawatt feed-forward signal to control ammonia flow rather than fuel flow, which is a lagging indicator.

      • Tune/improve the water injection curve. Keep in mind that water does not harm the SCR catalyst.

      • Lower the NH3 control valve/SCR temperature interlock set point.

      • Reprogram the ammonia vaporization heater. The SCR/NH3 injection temperature was reduced to 350F from about 540F to start the SCR earlier.

      • Improved maintenance.

The NOx mass emissions reduction program achieves the equivalent of investing $2 million in emissions offsets while increasing operational flexibility without exceeding local, state, and federal limits. The Riverside team believes it has learned enough to aim for a higher target by year-end—a 40% reduction in startup NOx mass emissions.

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Reconfigured heat-trace system assures accurate drum-level measurement

Heat-tracing challenges faced by plants in cold climes often are a discussion topic at user-group meetings. There are many suppliers of heat tracing and many different approaches to preventing freeze-ups. Beyond the obvious proper design and installation, critical to success is reliable operation of the control system and instrumentation charged with turning on and off sections of tracing as necessary and alerting where failures have occurred so they can be corrected before damage occurs.

While manufacturers have a wealth of experience to share in design, install, and system troubleshooting, don’t expect them to understand your facility’s specific needs. Plant personnel have to pick up the ball after the contractor leaves the site and do the customizing necessary to accommodate the idiosyncrasies of weather and operational requirements. The best practice described below illustrates the value of experienced personnel in such problem-solving. The process illustrated and the road to the solution identified can serve as a model for others.

At Athens Power Plant in the Albany (NY) area, cold winters and cycling operation challenged the facility’s heat-trace system—in particular the drum-level heat-trace system serving the heat-recovery steam generators for the three 1 × 1 G-class combined cycles.

Drums for the HRSGs are located 100 ft above the level transmitters; sensing lines run down the boilers into heated cabinets where nine drum-level transmitters are located. Because of the length of the sensing lines and change in water density, any difference in temperature between a variable leg and reference leg causes an inaccurate drum-level reading.

The sensing lines were run in Tracepaks—the product name for an insulated, weatherproof jacket offered by one manufacturer—with their heat tracing controlled by resistance temperature detectors (Fig 1). The RTDs provided input to a heat-trace panel that would turn the Tracepak bundles on and off. If the RTD did not turn off the reference and variable legs of each transmitter at exactly the same time, drum levels would deviate because of the temperature difference.

These deviations were exacerbated by ambient temperature and unit run status. If a unit was offline and ambient temperature 30F, all the heat tracing had to be on. Drum levels typically were fine in this condition. If the unit was started up, heat from the unit and the location of the RTDs would cause heat tracing to cycle on and off, contributing to the drum-level deviations.

Plant Engineer Hank Tripp and I&C Technicians Eric Van Zandt, Todd Wolford, and Bob Robinson considered several possible solutions, including the following:

      • Installing one RTD per Tracepak.

      • Pairing each drum-level transmitter with a single RTD.

      • Combining sensing lines into a single Tracepak.

None of these alternatives produced consistently reliable levels during the winter months, causing several forced outages and forcing numerous de-rates to correct the level deviations.

Plant personnel believed the drum-level heat-trace system had become too complicated. They decided to simplify it by using a single contactor operating by ambient temperature via the plant’s DCS (Fig 2) to ensure all drum-level heat tracing was turned on and off at exactly the same moment, thereby eliminating temperature deviations among the sensor lines.

Using the DCS allowed staff to build logic into the control system that would factor in run status and ambient temperature. The solution ensures that the heat tracing operates only when necessary and also alerts operators with an alarm if the contactor is not energized when the heat tracing should be in operation.

Success! The heat-tracing contactor and control logic were installed in October 2015. Since then, the plant, owned by Talen Energy and operated by NAES Corp, has experienced no unscheduled call-ins, de-rates, or forced outages related to drum-level heat tracing. Plus, drum levels across all units—whether running or shut down—are consistent.

Fig 3 shows drum-level deviation before the new system was installed. One channel indicates 7.2 in., the other two approximately minus 1 in. Ambient temperature was about 30F. As shown in Fig 4, drum levels following system reconfiguration ranged from plus 1 to minus 1 in. at an ambient temperature of about 25F.

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Mark V goes haywire, shuts down F-class unit’s lube-oil pumps

You’re an experienced operator/technician, perhaps with 10, 15, 20, or more years of powerplant service. You’ve seen it all. Nothing would surprise you. So you think.

Here’s a case history likely to tame your unbridled confidence.

A GE F-class unit, equipped with a Mark V control system is humming along at base load, no issues, reliable unit, nothing much for operators to do. Next instant: All lube-oil pumps—AC- and DC-powered—are forced out of service. Bearings are destroyed in a heartbeat (last reading on bearing-metal thermocouples was 950F) and rotor grinds to a halt severely damaging the compressor and turbine sections.

Say what?

Abel Rochwarger, chief engineer at Gas Turbine Controls (GTC), consulted with the owner/operator. A team of customer and GTC personnel analyzed the root cause in this case and deemed it irrelevant. Instead, the team engineered a solution to prevent the control system from ever shutting the lube oil pumps again without operator control. CliffsNotes: The team learned that the network connecting the turbine control panel (TCP) and human/machine interface (HMI) malfunctioned, forcing logic (sidebar) without human intervention. Tens of signals were “forced” within the space of 0.1 sec.

As you read on, keep in mind that the 7F Users Group’s 2017 conference starts May 15 in San Antonio’s La Cantera Resort & Spa. That’s the ideal venue to discuss the findings of the accident profiled here with colleagues to determine if your plant might be at risk. Plus, GTC will be participating in the vendor fair on Tuesday evening (Booth 36) if you want to dig deeper into its solution.

Rochwarger told the editors that GTC was unaware of any other instance in which “this behavior of ‘self-inflicted logic forcing’ occurred and forced all lube-oil pumps out of service.” He continued, suggesting units that have not yet implemented a protection scheme for the lube-oil system against a TCP failure should consider the following recommendation:

If the TCP starts to do “strange things,” such as unexplained logic forcing, immediately put one lube-oil pump in “manual.” To protect against an AC failure, start the emergency pump, too (it should latch and stay on). Shut down the unit immediately. If the cooldown sequence does not engage, turn the unit manually.

The chief engineer cautioned against accepting the results of a root-cause analysis as a vaccine against all ills. He said, “Eliminating the proximate cause of this failure does not necessarily eliminate all other potential situations that may result in the same scenario. The fact that the TCP failed to protect in this instance suggests that there might be other—today unknown—sets of circumstances in which the TCP would not keep the lube-oil system running when needed.


Logic forcing is a feature in modern (electronics based) turbine control panels allowing the operator to force the logic state of a digital (binary) variable to “0” or “1” independently of the following:

      • The logic state mandated by the control algorithm (that is, even in contradiction), and

      • The status of the unit (online or offline).

This feature may pose a significant risk to personnel and property; therefore, OEMs restrict the access to logic forcing via password protection.

“The initial assessment indicated that the network connecting the HMI to the TCP was ‘overloaded with signal traffic’ beyond its design capacity. The underlying problem: One TCP version did it.”

Rochwarger challenged those who might say “problem resolved” with the following question: How can you be certain there are absolutely no other combinations of circumstances that would result in a similar condition? He pointed to the fact that later versions of the TCP, such as the Mark VI and Mark VIe, are based on their predecessors, as the OEM points out in its literature.

This raises a second question: Could this possibly mean all TCP generations that followed the Mark V may have carried over the design patterns that allowed the “self-inflicted logic forcing” to happen?

The point stressed by Rochwarger is: not to split hairs on what may or may not happen, or to rush towards an expensive and unnecessary upgrade, but to eliminate the possibility by changing the controls paradigm. Until the event described above, the TCP controlled the starting and stopping of the AC and DC lube oil pumps (and seal oil pumps if installed). The controls paradigm he suggests and the one implemented for the affected customer (refer to simplified conceptual diagram), who agreed that preventing further occurrence was much safer than upgrading to new unknowns:

AC lube-oil pumps

      • Allow the TCP to start the AC pumps.

      • Do not allow the TCP to stop the AC pumps, but enable a manual stop.

      • Operator intervention is required to stop these pumps.

DC emergency lube-oil pump

      • TCP enables pump to start; lube-oil pressure controls the start.

      • TCP cannot stop the pump, but enables manual stopping.

      • Operator intervention is required to stop the pump.

      • TCP is allowed to cycle the pump to cool bearings when required at zero speed.

The AC auxiliary and DC emergency seal-oil pumps (not shown in the diagram) require similar logic changes if installed.

Wrapping up, Rochwarger said the sequencing, hardware (external to the TCP), and wiring modifications required by the GTC alternative are not difficult to implement. The company says its solution offers a higher level of operational safety in case of a TCP malfunction, regardless of the TCP model. Plus, the same solution can be adapted to steam turbines and to synchronous condensers. Finally, a similar controls scheme has been developed by GTC for B/E-Class machines, like the Frame 5, 6B, 7EA, 9E, etc. with a mechanical main lube-oil pump.

You can contact GTC at www.gasturbinecontrols.com or 914-693-0830.

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