2022 BEST PRACTICES AWARDS: Six plants earn Best of the Best honors in CCJ’s annual Best Practices program

By Team-CCJ | July 1, 2022 | 0 Comments

The COMBINED CYCLE Journal and the steering committees of the industry’s leading gas-turbine users groups—including 7F, 501F, 501G, 7EA, 7/9HA, Western Turbine, Frame 6B, 501G, 501D5-D5A, AOG, and V—collaborate to expand the sharing of best practices and lessons learned among owner/operators of large frame and aeroderivative gas turbines.

Thirty-five plants listed below participated in the 2022 Best Practices Awards program with eight selected by industry experts for Best of the Best honors. Details of the Best Practices submitted will be published in future issues.

CCJ launched the industry-wide Best Practices Awards program in late 2004. Its primary objective, says General Manager Scott Schwieger, is recognition of the valuable contributions made by plant and central-office personnel to improve the safety and performance of generating facilities powered by gas turbines.

Industry focus today on safety, outage management, and performance improvement—including starting reliability, fast starting, thermal performance, emissions reduction, and forced-outage reduction—is reflected in the lineup of proven solutions submitted this year.

2022 Best of the Best GT-based Plants

CPV Towantic Energy Center

Owned by Competitive Power Ventures
Operated by NAES Corp

  • Significant implementation of insurance recommendations reduces facility risk and annual cost of insurance premium increases
  • Cost-effective solutions to achieve SPCC certification, minimize spill risk and increase site safety
  • Custom weather protection for collector house assembly eliminates nuisance trips and moisture damage
  • Remaining ZLD without the initial infrastructure

C.T. Genelba

Pampa Energía S.A.

  • Predictive maintenance on SGT5-2000E gas turbine combustion chambers

Empire Generating Co LLC

Owned by Empire Acquisitions LLC
Operated by NAES Corp

  • Fall protection system continuous improvement project

Fairview Energy Center

Owned by Competitive Power Ventures
Operated by NAES Corp

  • Selection and optimization of remote monitoring and diagnostics
  • Enhanced DCS monitoring screens designed to improve starting reliability
  • Installation of redundant ammonia injection equipment reduces the probability of NOx exceedance

McIntosh Power Plant

Lakeland Electric

  • HRSG modifications to increase back pressure capability increase MW output
  • Mitigation efforts to protect 501G combustion turbine rotor through bolts
  • On-line monitoring and non-destructive testing to monitor the condition of steam turbine blades

St. Charles Energy Center

Owned by Competitive Power Ventures
Operated by Consolidated Asset Management Services

  • Improving safety and reliability with active wireless high energy piping monitoring

2022 Best Practices GT-based Plants

Amman Levant Power Plant

AES Jordan PSC

      • LFO day tank overflow shutoff valve improvements

Anson and Hamlet Generation Plants

North Carolina Electric Membership

  • Repair of PWPS FT8-3 dual-fuel nozzles

Athens Generating Plant

Owned by Kelson Energy
Operated by NAES Corp

      • Plant safety improvements
      • Water treatment enhancements

BASF Geismar


  • Increased equipment protection using duct burner firing overrides

Central Eléctrica Pesquería


  • Collector brush enhancement upgrade
  • Improved generator grounding brush system
  • UF 1500 module valve actuator upgrade
  • Dewatering pumps retrofit project
  • Redundant heat exchanger improves ZLD system operations

CPV Valley Energy Center

Owned by Competitive Power Ventures and Diamond Generating Corp
Managed by Competitive Power Ventures
Operated by DGC Operations LLC

  • Implementation of mobile electronic logging for operations, maintenance, and compliance
  • Employee-driven lighting enhancements for improved visibility at an indoor plant
  • Reduced outage time by implementation of steam turbine fast cooldown logic and procedures
  • Severe winter weather operations

Energía del Valle de México I

Owned by EVM Energia del Valle de Mexico Generador SAPI de CV
Operated by NAES Corp

      • Implementation of system to optimize gas chromatographs reduces consumables and maintenance costs

Essential Power Newington LLC

Owned by Essential Power LLC
Operated by Cogentrix Energy Power Management

  • Electronic contractor safety orientation program
  • Auxiliary boiler online instrumentation
  • Cooling tower chemical injection automation
  • Overhead door warning lights

Griffith Energy

Owned by Griffith Energy LLC
Operated by Consolidated Asset Management Services

  • Control-valve trim retrofit project yields significant savings

Kings Mountain Energy Center

Owned by Carolina Power Partners LLC
Managed by CAMS
Operated by NAES Corp

  • Steam turbine EHC fluid conditioning system
  • Remote user cybersecurity

Kleen Energy Systems, LLC

Owned by EIF Kleen, LLC
Operated by NAES Corp

  • Generator breaker moisture intrusion mitigation project

Lawrence County Generating Station

Owned by Hoosier Energy and Wabash Valley Power Assn
Operated by NAES Corp

      • Operator rounds software streamlines site O&M

Liberty Electric

Vistra Corp

  • Easy SDS file access enhances operator and contractor safety

Magnolia Power Project

Owned by Southern California Public Power Authority
Operated by Burbank Water and Power

  • Remaining agile in a changing generation landscape

Mid-Georgia Cogen

Owned by Rockland Capital
Operated by IHI Power Services

  • Combustion turbine fuel gas DP transmitter failure logic
  • Combustion turbine evaporative cooler supply water modification

Milford Power LLC

Owned by Starwood Energy Group and JERA Co
Operated by NAES Corp

      • Repurposing unused plant equipment for new service

MPC Generating

Owned by Mackinaw Power
Operated by Cogentrix Energy Power Management

  • Hydrogen cooling system upgrade

Pleasant Valley Station

Great River Energy

      • Fuel oil unloading piping modifications for faster offloading, extended fuel oil run times and increased resiliency during extreme cold weather events

River Road Generating Plant

Owned by Clark Public Utilities
Operated by General Electric

      • Hazard hunt program
      • Benefits of keeping a spare set of gas turbine inlet filters
      • Remote electronics for hotwell level transmitters
      • Ammonia piping upgrade project
      • MOV additions to manual steam valves

Rolling Hills Generating LLC

Owned by Eastern Generation LLC
Operated by Consolidated Asset Management Services

      • Excitation transformer termination cabinet humidity monitoring

Rumford Power LLC

Cogentrix Energy Power Management

      • Providing value through energy efficiencies
      • Hot-start efficiencies providing value

Salem Harbor Station

Owned by Footprint Power Salem Harbor Development, LP
Operated by NAES Corp

      • Winter readiness testing upgrades

Saudi Aramco Power Generation Sites

Saudi Aramco

  • Benchmarking a large gas turbine fleet to streamline O&M

Sentinel Energy Center

Diamond Generating Corp

  • Energy control and LOTO

State Line Power Station

Owned by Liberty Utilities and Evergy
Operated by Liberty Utilities

  • Second life for RO water

Walton County Power

Owned by Mackinaw Power
Operated by Cogentrix Energy Power Management

  • Gas room ventilation upgrade
  • Water wash system upgrade

Washington County Power

Owned by Gulf Pacific Power LLC
Operated by Cogentrix Energy Power Management

  • Electric fire pump testing procedures

Whitewater Cogen

Owned by LSP Whitewater LP
Operated by NAES Corp

  • Operational tag program identifies systems status

Worthington Generation Station

Owned by Hoosier Energy Rural Electric Co-op
Operated by NAES Corp

      • LM6000 package fan pulley/belt guards

Power Users forms Legacy Turbine Users Group (LTUG) for 7E, 6B, and Frame 5 Owners

By Team-CCJ | July 1, 2022 | 0 Comments

In the world of power generation there is a significant number of mature frame gas turbines that are the backbone for industrial settings and power generation. There are several well-established user groups that support owner/operators by sharing lessons learned, technical knowledge, and troubleshooting support. It’s critical that these groups maintain a strong presence in the industry to support and benefit both the users and suppliers that keep the equipment running. Combine that with a changing industry, a pandemic, shrinking budgets, and an aging workforce you now have challenges in keeping influential groups afloat.

With any challenge there is opportunity and that’s why Power Users formed the Legacy Turbine Users Group. Currently, LTUG comprises the 7EA, Frame 6B, and Frame 5 Users Groups. In combining forces, the future for these organizations will be stronger and have opportunity to grow. Each group maintains an independent steering committee and user forum hosted by Power Users, but when conducting a technical conference, the groups will be joining together under one roof, each in its own meeting room. Power Users believes this combined group provides many benefits to the user community and suppliers.

The first LTUG technical conference will be co-located with Power Users’ Combined Conference this coming August. For the first time, companies with a mixed fleet of these turbine types will be able to travel to one conference to gain the benefit of three. Additionally, companies that may not have such diverse fleets will be able to leverage the knowledge presented by these three groups with one trip. This addresses some of the challenges we are seeing that will likely to continue. Now companies can save on travel costs by attending an all-in-one conference and not have to choose which meeting to miss in a given year. All this without losing the benefit of training, sharing of lessons learned, building valuable networks, and meeting the supplier network that supports these gas turbines.

Suppliers also benefit from this merger of user groups. Their budgets are equally stretched, and the pandemic has made it challenging to share their services and build networks. The LTUG conference provides access to a diverse group of users that utilize a similar vendor base for support, parts, and services. This efficiency provides a budget-friendly opportunity for suppliers to build valuable connections to sell services and parts.

Our inaugural LTUG conference will be held in beautiful San Antonio (Tex), August 29 through September 1 (www.powerusers.org). Plan now to participate in this seminal event to strengthen your knowledge, build your network, share your experience, and find a supplier that can help solve problems your facility is facing.

Jake English, Duke Energy
Phyllis Gassert, Talen Energy
Sam Graham, Tenaska
Edward Maggio, TVA
Ben Meissner, Cogentrix
Peter So, Calpine

Collector brush system upgrade slashes maintenance requirements

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

Woodbridge Energy Center

Owned by CPV Shore LLC
Operated by CAMS
725 MW, gas-fired 2 × 1 7FA.05-powered combined cycle located in Keasbey, NJ
Plant manager: Chip Bergeron

Challenge. Woodbridge was notified four months before the planned 2020 fall outage that the generator collector brush systems serving its gas and steam turbines soon would be discontinued by the OEM. Faced with the obsolescence of a critical high-wear system, plant personnel had to move quickly to plan for the upgrade while also capitalizing on any opportunity to eliminate the various issues that plagued the existing system.

Solution. Having spent several years working with Cutsforth on the excessive brush wear and selectivity issues related to the OEM system, the company’s input was sought on the pending obsolescence issue. While upgrading to a Cutsforth system is not new and something many sites might do in their lifetimes, the team need to go one step further and find a way to reduce the weekly labor hours dedicated to brush maintenance. The OEM collector system was costing the site approximately 900 man-hours annually to maintain.

To address this issue, Cutsforth proposed its most advanced brush rigging system available (Fig 1) which came complete with the company’s Brush Condition Monitor (BCM). The latter gives staff a real-time view into the health of each brush by displaying vibration, usable life, temperature, wear rate, and location. These data are readily displayed on a local PLC, which eliminates the need to manually collect data for each individual brush. The site team also developed plans to bring the brush data directly into the control room where it can be recorded, trended, etc, using the historian.

Results. In its first six months of service, the benefits of the new collector brush system exceeded expectations. The brush selectivity and wear-rate issues that plagued the plant during its first five years of service were completely gone, along with any signs of vibration and/or collector-ring pitting. This meant that collector ring grinds, which had become annual affairs, would likely be required only once every couple of years. The saving from the reduction in ring griding alone will save the project $40,000 annually.

Additionally, the new system has reduced the man-hours required for brush maintenance by a factor of two-thirds (about 600 man-hours annually), taking what once was a significant weekly effort and reducing it to minor-task status.

Project participants:

Justin Hughes, production manager

Michael Armstrong, plant engineer

Best Practice: Use EMI to assess the condition of generators, transformers, HV electrical gear

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

Challenge. Soon after commissioning, one of Fairview’s gas turbine/generators experienced stator-ground-fault trips attributed to isophase-bus (IPB) water ingression into potential transformer (PT) cabinets, followed by persistent lower-than-expected resistance readings. Doble Engineering was engaged to perform electromagnetic interference (EMI) testing on several components of the plant’s three power trains to assess their condition. Generators, step-up transformers (GSUs), unit auxiliary transformers (UATs), and IPB were suspect in each train (Fig 1).

Following the first trip on stator-ground-fault 64 relay, damaged cables and condensation were found in a PT cabinet (Figs 2 and 3). To learn more on the importance of addressing grounding issues in a timely manner, read “IEEE standards may not sufficiently address grounding issues in rotor, stator windings,” by Clyde V Maughan, CCJ, 2Q/2013, p 7.

Solution. Given the extensive amount of IPB and connections, the CPV and NAES engineering teams advised the plant to perform EMI testing to identify other potential sources of arcing and abnormalities. An EMI diagnostic was conducted to determine the possible origin of the problems.

Recall that EMI testing is performed online and can detect several mechanical and electrical defects on generators, IPB, transformers, and motors. Defects in the bus connections or insulators generate radio-frequency signals that can be measured.

To perform an EMI diagnostic, a radio-frequency current transformer is placed around the neutral, a safety ground, or power conduit of the asset (Fig 4) to measure and identify the signals generated from the component or system defects. The EMI diagnostic method measures a broad spectrum of radio frequencies to evaluate signal patterns—including, but not limited to, corona, partial discharge (PD), and arcing.

Additionally, a handheld device is used in conjunction with the EMI signature to further identify the defect location. This device detects the EMI signals radiated from each component or system defect, allowing the technician to measure the intensity of the activity.

EMI testing is performed while the asset is in service and is a non-intrusive technique that will not cause the equipment to trip offline. A baseline measurement is helpful but not required for the analysis; therefore, maintenance recommendations are provided starting with the very first test, and the analysis helps to prioritize maintenance based on asset condition.

The generator, IPB, UAT, and GSU for each of the three units were tested and inspected. The table summarizes the most relevant findings. The EMI signatures in Figs 5 and 6 were acquired at different grounds on each component. The frequency ranges indicated on the EMI signatures, upon further and detailed analysis of the waveforms, revealed abnormal PD and sparking activities. Fig 7 is an example of a sparking waveform.

The activities detected typically are associated with insulation deterioration, defective connections, and loose hardware inside the IPB. To pinpoint the locations of the defects, a scan was performed with a handheld device to identify areas with high radiated EMI. After a thorough analysis, an internal inspection of different sections of the bus system was recommended.

Referring to the detailed EMI report provided by Doble, the locations identified in the table were highlighted on electrical one-line and 3-phase drawings. These marked-up prints were used to plan lockouts, scaffold erection, and inspections at the next planned outage. Figs 8-10 show examples of the findings in locations identified by EMI testing.

Results. Deficiencies were identified and corrected at each suspect location identified by EMI testing.

EMI testing enabled non-outage inspections of the electrical distribution system, thereby reducing the length of outage inspections and facilitating advance planning prior to the outage start date.

Given the success of the one-time EMI survey, CPV Fairview is installing a permanent EMI detection system. The team has initially selected the ST generator, IPB, and GSU for permanent monitoring.

A permanent installation may not fit everyone’s business model. As a minimum, we recommend conducting an annual survey or as-need surveys following repairs or the installation of new equipment.

Project participants:

CPV: Joe Michienzi, Preston Patterson, Tom Favinger, Ali Bibonge

NAES: Bill Lovejoy, chief engineer; Rick Marshall, maintenance manager; Jason Havash and Aaron Roberts, I&E technicians

Doble Engineering: Roberto Martinez and Oscar Montano

Fairview Energy Center

Owned by Competitive Power Ventures (CPV)
Operated by NAES Corp
1050-MW, 2 × 1 combined cycle powered by 7HA.02 gas turbines, located in Johnstown, Pa
Plant manager: Bob Burchfield

HRSG Forum discussion centers on creep damage, elemental zinc in weld HAZ areas

By Team-CCJ | May 16, 2022 | 0 Comments

As usual, a tremendous amount of technical content was offered in two presentations during the HRSG Forum, Jan 28, 2022—No. 7 in a series organized by Chairman Bob Anderson. But the underlying message was more about the state of our industry.

A few participants, discussing aging of high-energy piping (HEP), said they were “astonished at the lack of knowledge in major NDE [non-destructive examination] firms” and that boiler OEMs “are different” these days and there are new people in the industry. You can interpret “new” as suppliers who are inexperienced, or low-balling bidders, or doing shoddy work, but also buyers who accept low bids or don’t establish the proper design specs or QA processes and protocols.

Later in the Q&A, one Forum organizer, discussing zinc issues with boiler pressure parts, said HRSG OEMs are “not giving answers [about zinc] with high confidence levels” and that it is “buyer beware” when it comes to at least one OEM.

The first presentation, “NDE, Welding, and Metallurgy: Tools Supporting the Safe, Efficient Operation of Aging HEP,” was delivered by industry veteran Jeff Henry, now with the Combustion Engineering Solutions (CES) division of Advanced Thermal Coatings (ATC).

There are many reasons why you should care about aging HEP, but if you’ve recently upgraded your gas turbine for higher output and efficiency, you are likely going to be expending the creep life of your superheater and reheater piping faster than you might have expected. This situation makes HEP components more susceptible to catastrophic failures at the weld areas.

Creep is “time-dependent strain, or changes in dimensions of the material, that accumulates in response to stress such as load and pressure.” Over time, cavities form in the metallurgical grain structure, then begin to align into cracks which represent an “advanced stage of damage.” While creep can manifest as swelling of the pipe diameter, by far the most failures occur at welds, which are omnipresent in HEP systems.

Onset of creep damage of course depends on the type of material and alloy. For Grade 22 material, the values for elevated temperature, according to Section 2, Part D of the ASME Boiler & Pressure Vessel Code, start at 952F. Code fabricated materials should last 250,000 operating hours, Henry said, as long as piping supports are properly maintained, the components are operated within design limits, and the original fabrication was conducted to within specifications. For an aging facility, that’s a lot of caveats.

Inspection is critical to identify piping condition, but indications have to be properly characterized and the root cause understood before an effective repair is executed. In response to an audience question, Henry stated that 50,000 ops hours is a reasonable inspection interval if there are no operating or structural issues. When asked if there are protocols or industry standards, he recommended EPRI’s qualification and certification program for NDE detection in high-energy piping.

Many of Henry’s slides depict damage in six defined areas of HEP welds and are not to be missed if you are responsible for an aging HRSG. Get the details by watching the recorded presentation.

The second presentation, “Casting the Die: Implications of Zinc for Pressure Part Integrity,” was given by Paul James, Uniper Technologies Ltd. Main takeaway: Presence of elemental zinc (not zinc oxides) in paint used to protect weld prep areas before fabrication makes pressure parts more susceptible to creep damage, especially in the weld heat-affected zone (HAZ). Fortunately, according to James, elemental zinc bands, beige-yellow which darkens with exposure to high temperatures, can be readily distinguished from the red lead oxide coating/primer traditionally used.

During the Q&A, an informal poll of HRSG OEM representatives was cited, with several saying they’d never heard of the issue. James’ presentation also is available for viewing at 2022 Recordings (hrsgforum.com).

MD&A webinars focus on inspection, repair, upgrade of retaining rings, turbine valve actuators, fuel-nozzle life extension, plus alarm troubleshooting

By Team-CCJ | May 16, 2022 | 0 Comments

Summaries of MD&A’s spring 2022 webinars on topics of interest to all involved in the operation and maintenance of generating plants powered by gas turbines follow. Both experienced personnel and those new to the industry might benefit from a quick read to identify topics of immediate value and then follow up by listening to recordings of the webinars of interest. All run less than an hour.

To access MD&A’s library of webinar recordings, go to MD&A Webinar Library and register for access.

Take a deep dive into failures, repairs of generator retaining rings, main leads

Retaining rings (RR) and main leads are two of the most stressed components in large combined-cycle generators and thus prone to failures. James Joyce, generator repairs ops manager for MD&A, during a Feb 24, 2022 webinar, covered the basic design and purposes of these two components, along with what can only be called gruesome photos of what they look like when in disrepair or fail from mechanical and/or electrical issues.

MD&A has developed repairs and upgraded components, which should be considered as replacements when maintenance intervals allow. The slides depict the design, manufacturing, and installation process for these upgraded parts.

The many audience questions elicited additional valuable contributions to the presentation, including the following:

  • There is no such thing as “severe” retaining ring cracks. If there are any cracks, the component should be replaced, and preferably upgraded at the same time. Plus, cracks on the outer diameter end means there are cracks on the inner diameter end and it’s time to replace.
  • High-speed balancing is strongly recommended after retaining-ring replacement.
  • Follow OEM maintenance schedules for when inspections are due, but generally every two to three years and during a major overhaul.
  • Standard NDE for RRs is a dye penetrant test; radiographic tests are not normally performed.
  • A complete RR replacement takes five to seven days, depending on whether the size in question is in stock.
  • Damage to the RR from a motoring event will depend on the amp load and length of time; one type of damage mechanism could be arcing on the dovetail slots.
  • Continuous cycling will greatly impact the main leads.
  • MD&A is not aware of cracking issues with 18/18 RRs but cracks could show up in five to 10 years as operating hours are gained.
  • “Top tooth” cracking is rare, but does exist; perhaps 2% to 3% of units are susceptible.

To access MD&A’s library of webinar recordings, go to MD&A Webinar Library and register for access.

Sweat the small stuff when it comes to steam-turbine valve actuators

If you think your combined-cycle steam-turbine valve actuators are one of those “set and forget” components, think again. As Anthony Catanese explains during the Feb 15, 2022 webinar hosted by MD&A, “Turbine Valve Actuator Operational Issues and Upgrades,” even the most robust actuators, such as GE’s “legacy EHC,” running in a baseload plant may last up to 30 years, but “when they fail, they fail spectacularly.”

Actuators all function pretty much the same from a fundamental mechanical point of view, says Catanese—hydraulic force to open, spring force to close. But some designs are more complicated than others by virtue of their many bells and whistles (Rexroth) and/or more components (legacy Westinghouse). Check out the video if you’re looking for a refresher on fundamentals about the various popular designs.

Catanese’s recommendations for spares and maintenance intervals were the heart of the material. Generally, he says, plants should keep half a set of servos and solenoids in stores, although a full set is preferred, and filters, of course, should be changed regularly and oil kept clean. People tend to think less about the LVDTs and switches. Catanese suggests keeping one or two of these handy at all times.

As for preventive maintenance, legacy GE units should be sent to the shop every 10 to 15 years, legacy Westinghouse every five to eight years, and Rexroth and combined-cycle LP actuators every four to eight years. The rest of Catanese’s slides explain, through photographs of typical long-term damage to internal components, why disassembling, repair, and inspection during regular maintenance intervals is so vital: You want to identify issues before the actuator fails.

Insights gleaned from the Q&A:

  • If your actuator is experiencing stickiness or sluggishness, nine times out of 10 the problem will be with the servo.
  • Be sure to test disc springs if/after they’ve been coated—most sites neglect to do this.
  • If one disc spring in the stack cracks, replace them all; otherwise, the forces will not be uniformly distributed during closing.
  • MD&A is the only “sanctioned” non-OEM service firm for Rexroth actuators.

To access MD&A’s library of webinar recordings, go to MD&A Webinar Library and register for access.

Don’t fear the Mark VI Trender in your toolbox: It’s your friend!

If you are leery of using the Toolbox Trend Recorder/Trender function in the Mark VI and VIe control systems when your gas turbine is running, Joe Clappis, senior engineer, MD&A Control System Div, has a message for you: Don’t be! You don’t need a password and you can’t alter the turbine’s control logic. Clappis encouraged his audience during the webinar, “Troubleshooting Alarms and Trips with High-Speed Data Capture,” Feb 22, 2022, to get familiar with Trender, which he calls the “the best tool in the Toolbox.”

Unlike data historians, which typically capture data at rates of once per second or slower, Clappis noted, Trend Recorder takes data as fast as once per 40 milliseconds. Low-speed data capture is best for slow-moving long-term trends—such as bearing metal temperatures and vibration. High-speed data capture allows you to analyze control valves, combustors, inlet guide vanes, exhaust temperature spreads, and other variables which can change far more quickly.

Trend Recorder also captures alarms and events in addition to raw data and all the data can be viewed in graphical form.

“Users often send us screen shots, or smart-phone camera photos of HMI views, and ask us to troubleshoot a particular problem or event, but these are often not helpful,” Clappis lamented. However, data summarized and presented in Trender can be extremely useful. You can study starts and shutdowns, compare “good starts to bad starts,” study DLN combustor mode transfers, and identify intermittent issues. Or Clappis and company can give you a higher-level diagnosis if you send them Trender files.

Many of Clappis’ slides showed the audience how to find Trend Recorder/Trender from the Mark VI home page, create and save a Trend Recorder file in Toolbox or ToolboxST, analyze data, simplify screen views and graphics, and drill down to actionable data. Clappis distinguished between actionable data and anecdotal data, like “I saw this happen and it never happened before!”

For those unfamiliar with data analysis, monitoring, and/or control systems, it’s best to follow along with the recording of Clappis’ webinar with your Mark VI screens in view. He gives explicit instructions for how to navigate within the Toolbox and Trender.

Finally, OEMs typically configure data historians and high-speed data recorders poorly, usually trying to capture too much data too fast, but also often not capturing the right values for certain types of troubleshooting. Factory configurations are not tailored to the site, or require much special training to extract the value from the data. “You have to be dedicated to learning the system,” Clappis stated.

As a caution, Clappis reminded participants that Trend Recorder is not a substitute for long-term data archival and retrieval. In response to an audience question, Clappis noted that the Mark IV does not include a trending program, the Mark V, “sort of.” A feature called View Tools can collect data on a limited number of data points.

To access MD&A’s library of webinar recordings, go to MD&A Webinar Library and register for access.

More attention to fuel-nozzle upgrades, repairs pays huge dividends

Blind faith in your OEM’s DLN fuel-nozzle component repair and replace recommendations could kill your outage budget, and that’s not all. That was the underlying message during the Feb 17, 2022 MD&A webinar, “Gas Turbine Fuel-Nozzle Flow Issues,” led by the tag team of Joe Palmer, general manager, and Pat Murphy, director of the company’s Fuel Nozzle Services Group, formerly ICS.

Fuel-nozzle overhaul is often the lowest cost area of a scheduled outage, and therefore not at the forefront. That’s a shame, stressed Palmer and Murphy, because many combustor issues originate with the fuel nozzles. Thus, there are other important benefits of upgraded fuel nozzles—easier tuning at startup, reduced temperature spreads, and less risk of lean blowout. Improperly maintained fuel nozzles also adversely impact the life of major hot-gas-path (HGP) components.

MD&A has developed, and fully warrants, upgraded fuel nozzle components for 7FA DLN 2.0- and 2.6-equipped engines (and combustors of other models), especially the subassembly wear parts. Remanufactured nozzles from MD&A are warranted as “like new” and can operate nearly “indefinitely.” For example, upgraded outer/center nozzles, using several part calculation strategies, could operate for nearly 148 factored years! Meanwhile, the OEM claims a 48,000-hr lifecycle for its component. The as-new quality parts are a fraction of the cost of OEM replacement components, claims MD&A.

The third-party solutions provider’s new end-cover insert can operate over seven repair cycles. MD&A’s improved brazing process and choice of braze material have greatly improved cover life. Plus, the amount of cyclic insert braze cracking has been reduced. Several of the slides are dedicated to explaining and illustrating the detail of this component “case study.”

The company offers an exclusive “in-situ flow testing” method, which helps pinpoint nozzle issues and solutions. “Component balancing and set balancing of fuel nozzles also can avoid a separate combustor inspection (CI) and extend run time to the next HGP outage.” The exclusive testing is an alternative to a complete nozzle system teardown for pinpointing flow variances and accurately and expediently addressing them.

To access MD&A’s library of webinar recordings, go to MD&A Webinar Library and register for access.

Thermal performance audit key to extracting more dollars from older plants

By Team-CCJ | May 16, 2022 | 0 Comments

The road to net zero carbon by, well, pick your date, 2030, 2035, 2050, is paved with pledges, promises, mandates, and political rhetoric, but the landscape will most surely be dotted with gas-fired combined cycles making megawatt-hours when the variable renewable resources are not, according to Jeff Schleis, gas-turbine product manager, EthosEnergy.

In a recent webinar, Schleis reviewed net-zero-carbon trends at the national level, offered some insight gleaned from Black & Veatch’s Annual Strategic Directions Report (a survey of industry leaders on top-of-mind issues and investment scenarios), and compiled three recent net-zero forecasts on one graph. Register here to view the recording.

Upshot of the last is that variable generation could exceed firm in less than 20 years. That represents opportunity for gas-fired combined cycles, but you have to be intentional about it. Schleis advocates conducting a thermal performance audit (TPA) to identify the gaps in performance, or where an older plant can extract additional value.

Equipment degrades over time, he said; the goal of the TPA is to analyze historical operating data and glean info from the operators to build a plant model that captures current equipment condition. Then you compare existing performance to original design, and individual turbines to each other, to determine where the gaps are, and what investment is required to close those gaps and extract the dollars.

The balance of Schleis’ slides is a deep dive into a case study on a 4 × 2 plant “designed to be very flexible.” High-level results were presented. The one audience question directly relevant to the presentation queried the time it takes to conduct the example TPA and the “timeframe for improvements.” Schleis answered that the study takes six to eight weeks depending on plant complexity.

Plant-network, data-link, communications issues revealed during commissioning

By Team-CCJ | May 16, 2022 | 0 Comments

Mini network connects multiple TCP/IP network devices to the Modbus gateway (port 502) and then converts the signals from Ethernet to the fiber going back to the DCS
Mini network connects multiple TCP/IP network devices to the Modbus gateway (port 502) and then converts the signals from Ethernet to the fiber going back to the DCS

While the industry makes progress towards the fully connected, largely automated powerplant with a meta-organization of onsite staff, remote monitoring and diagnostics (M&D) assistance, and market delivery setpoints, there are some serious and costly gaps that are overlooked in data links and industrial communications. According to Jeff Downen, business owner, Black Start LLC, these gaps are often revealed and corrected during commissioning.

Some root causes of the gaps include the following:

  • Scope irregularities between the automation platform’s OEM and the plant’s EPC, often based on technology design and concepts a decade or two out of date.
  • Insufficient communication between vendors while designing communication links and network paths, usually reflected in the I&C drawings and configurations.
  • Quantum leaps in data points being captured, transmitted, and monitored in sophisticated graphics with data speeds at the gigabit level.
  • EPCs using electrical engineers to do the design, rather than I&C/DCS engineers with IT networking experience.
  • Engineering and procurement documents often don’t address communications protocols, network speeds, connection types, and media conversion.

As Downen said in an interview, “All of these software packages and hardware procured from different vendors are designed so they can communicate, but someone still has to troubleshoot and integrate the systems so they will.”

Here are some of the most common issues Downen and his team encounter during commissioning while working directly for the EPC:

Improperly matched communications speeds. One example is multiple issues with incorrect baud rates on the serial links and 100/1000 base connections for fiber and Ethernet.  An example: SEL (Schweitzer Engineering Labs) 2730 small form-factor pluggable (SFP) ports designed as 1000 base fiber, and designed to connect with Emerson-provided EtherWAN media converters that were 100 base, are incompatible.

Media and cabling. Single- and multi-mode fiber issues crop up from the engineering and procurement phases. Example: A generator step-up (GSU) annunciator panel’s initial design called for an SEL serial device for a Modbus remote terminal unit (RTU). However, the network path only allowed a Modbus TCP/IP via the routers over port 502 and also needed a null-modem serial cable.

This was corrected by adding a mini-network for media and protocol conversion as shown in the photo. Port 502 is the Modbus protocol widely used for TCP/IP communications, allowing Modbus data links and traffic to pass through an IP network.

Another example involved the SEL discrete programmable automation controller (DPAC). The real-time automation controllers (RTAC) in the switchyard were using SEL 273A cables and communicating over a distributed network protocol (DNP). The serial nature of the protocol prohibits the cable from allowing traffic between the devices because the request-to-send (RTS) and clear-to-send (CTS) pinouts on the selected cable were incompatible. For non-IT types, RTS and CTS are data flow control mechanisms which are part of the RS232 standard connector.

This issue was corrected by changing over to the SEL protocol but would never have been an issue if SEL 272 cables were selected in the first place; it has the correct pinout.

IP addressing and subnets. Devices on the same network often are not configured properly, along with incorrect gateway assignments, port configuration issues, and the same subnets being used on the adjacent sides of a field router. An example that Downen found was an Ovation DCS with Ethernet link controller cards on the same subnet with identical IP addresses as some of the relays on an opposing network (each side of a router). This can be corrected by changing either side of the router’s respective devices.  An example:  RTACs and relay network settings to be changed out by reconfiguring the router files and the DCS programming.  Both are costly and time-consuming tasks.

Some ports, especially 80 (HTTP), 502 (Modbus), and 23 (Telnet) are not properly understood during design and end up being used incorrectly on a majority of devices for serial tunneling, web interfaces, and Modbus communications.

Spares and equipped spaces with blank equipment for a plant’s future use typically have a default IP address but are still connected to the same network in use by the plant, causing network collisions, or loss of information and errors while communicating.  This event can be witnessed when a master or client device is confused because an identical subnet is on the other side of the field router with similar device IP addresses.

User presentations: Benefit from your colleagues’ experiences

By Team-CCJ | April 19, 2022 | 0 Comments

Presentations by owner/operators are highly regarded at user-group meetings. The first-hand experience detailing how a particular job was conducted, what worked/what didn’t, lessons learned, etc, can be invaluable to someone considering a similar project. Plus, there’s the opportunity to ask questions and get straight-forward answers.

You should be aware of the six user presentations from the 2016 7EA Users Group meeting profiled here which might provide an assist in work you’re doing or planning. They are accessible to registered users on the organization’s website. The titles, immediately below, reflect the diversity of material shared at a typical 7EA meeting—including HV electrical, generators, gas turbines, valves, etc.

      • Bus replacement.
      • TIL 1398 inspection of stator-end winding axial support system hardware.
      • Hot-gas-path component life.
      • 7EA maintenance strategies.
      • Gas valve upgrade.
      • 7EA compressor issues.
      • Wrapper leak mitigation.

The bus-replacement presentation describes in detail (but few words) the retrofit of 15-kV/4000-amp circular non-segregated (non-seg) bus. More than seven-dozen photos of the components and their assembly and installation, foundations, plus detail drawings, walk you through the project quickly. A companion presentation, made by Bruce Hack of Crown Electric Engineering & Manufacturing LLC, covering circular non-seg bus, switchgear and circuit breakers, also is posted on the 7EA Users’ website.

TIL 1398-2, issued in March 2003, is applicable to all hydrogen-cooled, medium-size generators manufactured between July 1988 and September 2002. Its purpose is to remind users to inspect the tightness of the stator end-winding support hardware for loose, missing, and non-locking fasteners. Photos show damage done by liberated fasteners and how fasteners can be fixed in place with epoxy to mitigate the issue.

A table included in TIL 1398-2 identifies machines susceptible to loose fasteners (such as the GE 324 steam turbine/generator, 9A4, and 7A6), gives part numbers of interest, etc.

HGP component life reflects the experience of three 7EAs, each having a nominal 20 years of cogeneration service. The baseload units had operated roughly 165,000 fired hours and had fewer than 200 starts, respectively. Inspection schedule was combustion every other year, HGP every four years, and major every eight years.


      • First stage. DS GTD-111, 12 cooling holes, GT 33 coating and TBC. Typically repair at HGP and replace at about 100,000 fired hours. Longest demonstrated run was 105,000 fired hours.
      • Second stage. IN-738 and GTD-741, 10 cooling holes, scallop shroud, cutter teeth. Typically repair at HGP or major and replace at 100,000 fired hours. Longest demonstrated run on IN-738 buckets with eight cooling holes was 100,000 fired hours.
      • Third stage. U-500, cutter teeth. Typically repair at HGP or major and replace at about 135,000 fired hours. Longest demonstrated run was about 140,000 fired hours.


      • First stage. FSX-414 with full MCrAlY and TBC coating. Repair at HGP and replace when no longer cost-effective to repair. Longest demonstrated run expected at next outage would be 140,000 fired hours. At the time of the presentation a set of nozzles with about 130,000 fired hours was at a shop for repair.
      • Second stage. GTD-222 with MCrAlY coating. Repair at HGP; replace when no longer cost-effective to repair. Longest demonstrated run expected at next outage would be about 162,000 fired hours.
      • Third stage. GTD-222. Repair at major; may replace at 200,000 fired hours or when no longer cost-effective to repair. Original sets of nozzles still in machines with about 165,000 fired hours of service and two repair cycles.

Shroud blocks:

      • First stage. HR-120 with cloth seals.
      • Second and third stages. Honeycomb.

7EA maintenance strategies. This presentation, rated “must review” by the editors, offers valuable insights based on the extensive experience of both the user and his company. The power producer has 51 7EA peaking units (no baseload) installed at six stations; 39% of the engines have Type 403cb stainless steel S1 airfoils, the remainder GTD 450. The strategies discussed had to do with S1 failure mitigation, post-outage performance loss, and rotor end-of-life.

Regarding S1, the speaker first reviewed inspection options, then discussed the company’s original failure-mitigation program and why some tweaking was required. He then explained the updated plan and reviewed ongoing development of yet another mitigation plan (referred to as the “alternative” plan) based on the efforts of EPRI and its members.

TIL 1884. The speaker addressed TIL 1884 first, noting that the OEM recommends dye penetrant for NDE. The user’s engineering department does not agree, believing greater accessibility is needed for a proper dye-penetrant inspection, excessive application of dye-penetrant chemicals is required, and results are inconsistent. It recommended eddy current (EC), finding it is easier to implement, results have less variability, and helps identify crack indications at a higher success rate. If an indication is found, the engineering department recommends confirmation with FPI (fluorescent penetrant inspection).

For more on TIL 1884 and what others think about the use of dye penetrant to achieve its goals, see the article above focusing on 7EA compressor inspection.

Continuing, the speaker said his company embraces 100% borescope inspection of the R1/S1 area for clashing and of recording clashing damage, if found, with photos and measurements. Mapping of clashed stators also is done.

Here’s how the speaker summarized the company’s S1 failure mitigation observations and efforts:

      • Corrosion of carbon-steel ring segments reduces vane damping and increases stator stresses if a rotating stall is experienced during startup and/or shutdown.
      • At the time of the presentation, S1 failures associated with GTD 450 were airfoil tip liberations; with 403cb, root liberations. The latter failures can occur with no clashing.
      • TIL 1884 recommends dye-penetrant inspections only for units experiencing clashing. It does not address units with 403cb airfoils which may have crack indications without signs of clashing nor does it offer a method for determining the magnitude of indications.
      • The speaker’s company has qualified EC as its preferred method of S1 inspection.
      • The power producer also evaluated its 7EA fleet based on S1 inspection results compared to operational profile and parameters, finding no correlation to predict S1 crack initiation and when an S1 failure would occur.

Post-outage performance loss. A relatively common complaint of owner/operators presenting on their recent major inspection experience is the deterioration of performance following restart. The editors have heard this at several user-group meetings with no particular OEM or third-party vendor singled out.

The 7EA speaker discussed performance loss after a combustion inspection (rare) and HGP. The typical finding: Pre-outage NOx margin was different that post-outage. Engines were tuned to lower firing temperatures to assure environmental compliance. The result was a 3- to 5-MW decrease in output. The user’s company, the OEM, and various third parties believe fuel/air variation explains the performance issues.

The owner has been flow-testing liners and comparing results against post-outage performance to determine allowable flow tolerances—this to maintain firing temperature at the highest possible level and prevent loss of top-end megawatts. Another objective is improved repair processes to achieve repeatable results with vendors and reclaim lost output.

Rotor end of life (EOL). The speaker explained the following four options for rotor failure mitigation:

1. Replace the existing rotor with a new or refurbished one. This is the highest-cost/lowest-risk option but one seriously worth considering if you have majors for multiple units in the same year.

2. Refurbish to regain half a lifecycle. This is a less expensive but higher-risk alternative than the first option.

3. Replace key rotor components to achieve life extension—less expensive than the first two options with less risk than the second.

4. Inspect but do not repair may be the option of choice depending on the strategy for unit retirement. This is the lowest-cost/highest-risk option of the four presented.

The presenter closed by listing critical items to consider before formulating an EOL evaluation plan and selecting a vendor:

      • Availability of rotor discs (OEM or third-party manufactured) if one or more do not pass inspection.
      • Capability of the EOL contractor for replacing one or more discs—if necessary.
      • Candidate contractor’s rotor inspection capabilities and experience.
      • Candidate contractor’s EOL analytical and engineering capabilities.

The gas-valve upgrade presentation provides some project photos, data, calibration settings, operating parameters and other information of value to users considering migration from hydraulic actuation to electric. This information, combined with the experience from a recent Frame 5 fuel-valve upgrade, should help any owner/operator considering a similar project.

7EA compressor issues. A hands-on engineering manager discussed issues experienced during execution of TIL 1884 recommendations. If clashing is in evidence, removal of S1 vanes may be necessary. Options for removing them: Pull the rotor or leave the rotor in place and try to push the lower-half ring segments out of the case. The presentation illustrates how the OEM’s stator removal tool handles the task with the rotor in place.

The speaker said the special tooling was successful on both machines serviced, but the task was challenging. On one unit, the hydraulic power unit developed 3100 psig to free up segments with heat and quench. The other unit required 5200 psi to break loose the ring segments.

Other discussion points: Replacement of a failed R17 blade (TIL 1346), shim pinning according to TIL 1562-R1, and turbine shell-to-exhaust frame slippage (TIL 1819-R2).

Ovation users ponder big issues, knuckle down on knotty plant problems

By Team-CCJ | April 19, 2022 | 0 Comments

Encompassing 1300 GW of global capacity, 450,000 MW of that in the US, and 120,000 MW of combined-cycle capability, the Ovation control system platform, according to Robert Yeager, president of Emerson Automation Solutions Power & Water, is Number One in global power generation control systems. But Yeager, in the traditional “bragging rights” opening remarks at the Ovation Users Conference, clearly wanted to put his competitors on notice that he is gunning for more.

“We’re going to knock the wind out of our competitors,” he said, referring to the relatively new OCC100 product, designed to compete head-to-head with the traditional programmable logic controller (PLC). The OCC100 also forms the backbone for Ovation-based microgrid control systems.

Features now fully integrated into Ovation, such as embedded simulation (Fig 1), vibration and condition monitoring, and predictive analytics obviate the need for separate packages—and separate vendors. Yeager claimed that the company is working on 35 active embedded simulator projects around the world. “In five years, operators will spend more time in the ‘virtual’ plant residing in the ‘cloud’ than with the real plant controls,” he predicted.

Underscoring the challenge cybersecurity poses to highly connected digital systems, Yeager also noted that the Ovation cybersecurity team has ballooned from three to 50 members in the last few years. “We’re providing cybersecurity services on competitor control systems, too,” he added.

Steve Schilling, VP of technology, and head of the Ovation Technology Team, amplified some of Yeager’s comments. Ovation’s “remote node interface module,” a/k/a Ethernet I/O, is in final testing, he said. It can be used, along with the OCC100, not only for wind and solar facilities, but also for smaller, dedicated control systems for skid-mounted process units—the traditional purview of the PLC.

Two other remarks by Schilling were, well, darn right chilling. First, he noted that “storage is the wild card in the power equation.” This is yet one more indication that grid-scale storage is seriously penetrating the power industry “psyche.” Commercial storage facilities are already lopping off the peak of the peak demand in major markets around the country and thus compete with quick-start gas turbine units.

Second, he said that half of one large utility’s 6000 employees are eligible to retire in five years. That’s more than a brain drain; that’s a potential vortex, at least in the time scales the electricity industry operates under.

Yeager had noted earlier that one-third of the attendees at the confab had never attended an Ovation User group conference before. Hopefully, some of those newcomers represent youthful energy, not veterans who had to take over control system duties because someone retired.

Schilling also put turbine vendors on notice, saying that Ovation now offers a “completely integrated turbine control solution incorporating new synchronizer, machinery health, and excitation modules.” He also addressed cybersecurity, stating that certification under ISA/IEC 62443 is underway.

 Modern to mundane. Up next in the general session was Emerson’s Glen Heinl, director of customer services, who addressed mapping your journey with an Ovation system. He said Ovation offers more than 50 formal classes for employee development and advanced skills, and 20 webinars are available without leaving your desk.

One important question he had for the folks on the deck plates: “Are you checking your power supplies?” Because users often add I/O cards and capabilities, the existing power supplies can quickly become overwhelmed. A preventive maintenance guide, addressing power supplies and other critical items for Ovation systems is expected to be released “within six months.”

Speaking of knotty problems, the modern simulator has come to the aid of the age-old mundane problem of inconsistent operator performance at one plant. Personnel there, suffering from the aging workforce challenge, committed to a formal operator training program anchored by the

Ovation embedded simulator, replacing a simulator onsite for eight years but not used.

Plant representatives reported the program led to a 44% reduction in startup and shutdown times. The five operator crews, a mix of veterans and new recruits, had been doing things differently. Following training, the crews are consistently following startup and shutdown procedures, performing tasks simultaneously, getting qualified “expeditiously,” and in general achieving more consistent performance.

Lucky sevens. Replacing seven gas-turbine control systems with Ovation in seven weeks could be like holding your breath at the casino, hoping for lucky sevens. What made this project more white-knuckle is that the seven turbines (at two different locations, one a combined cycle facility, the other a simple cycle peaker facility) were acquired from merchant owner/operators. Lacking experienced personnel in this area, the new owners essentially put their full trust in Emerson as system supplier and engineer—that is, not hiring a separate electrical contractor. All electrical demolition was also left to Emerson.

One of the objectives of the replacement at the combined-cycle facility was to automate the manual power augmentation and water injection NOx control subsystem, dubbed SPRINT™ by the turbine vendor. In fact, this was the core of project justification. At the peaking facility, it was to achieve remote operation.

A few of the candid lessons learned include the following:

      • The due-diligence team for the acquisition did not pay much, or any, attention to field instrumentation. Apparently, this is typical of due-diligence teams, and something others seeking to acquire plants should guard against.
      • While generally pleased with overall outcomes, the site representatives did note the Ovation team’s lack of experience with retrofits of machines from this type—for example, the turbine vendor locates I/O at the GT housing, while Emerson prefers to put the boxes in the control room (Fig 2).
      • Resolving disputes around the HMI (human machine interface) graphics and high-performance screen layouts was also a challenge.
      • The new owners discovered that the air permits for the peaking units were written in a way that prevented them from adequately conducting no-load tests. Only two starts per day were allowed if the units were not going to proceed to full load and compliance operation within 30 minutes.

Actuator acting up. Steam-turbine bypass systems and valves for combined cycles have been giving users fits for years. In one Ovation user’s case

, it was the actuators on the HP and IP bypass valves. It would do little good to show the list provided of what was wrong with the original actuator design, because essentially nothing was right with it. However, in fairness, it should be noted that this combined cycle, which came online in 2003, was originally designed for baseload service, but later began to cycle.

According to the facility reps, “the valve would go nuts” on a steam-turbine trip, and for good reason: It has to go from closed to 80% open (11.2 in. of valve stem travel), then throttle as if nothing happened, all in two seconds! Doing both well is difficult for a valve this size, they conceded. They also conceded that the actuator worked fine the first few years, suggesting that cycling may have been the root cause of their issues.

The original valve was fine, they said, but the actuator was poorly designed. For one thing, it was “full of O-rings, and other parts and pieces” and three derivative boosters (used with a positioner to increase stroking speed). Also, the rapid stem movement repeatedly broke the weld between the plug and stem.

The plant decided to go with pneumatic actuation because it would avoid oil leaks and fire hazards and the parts would be more readily available than for a hydraulic actuator. Emerson designed a bolt-on actuator (Fig 3), leaving the original valve in place, with far fewer parts and all the boosters of the same component. The new booster is three to four times the size of the original one.

According to these plant reps, the valve and actuator “haven’t been touched since” and the weld cracking issue has been resolved. Tuning is much easier and more consistent, and the control loop is more stable during startups.

Sabers for cyber. Protecting against cyber-intrusions and keeping the “bad guys” out consumes more and more of the digital control system community’s energy—and piles on costs. In addition, like environmental restrictions, there are multiple layers of compliance, standards, and jurisdictions.

During a cybersecurity panel, a representative from the US government’s Industrial Control System Cybersecurity Emergency Response Team (ICS-CERT, part of DHS) referred the audience to the C-SET, a cybersecurity evaluation tool. As described in a document available from ICS-CERT online, “it is a desktop software tool that guides asset owners and operators through a step-by step process to evaluate their industrial control system and information technology network security practices.” Available for free, users answer questions and the software generates a report comparing your practices to recognized government and industry standards and recommendations.

In addition to federal standards and recommendations, states are imposing their own, according to a consultant on the panel. New Jersey, for example, has mandated cybersecurity standards. He noted that costs for complying with mandatory requirements could be challenging for power producers in low-price markets. That includes most everyone in today’s world.

An expert from one of the largest combined cycles in the country, built in the early 1990s, explained how his plant went from “25 years of connecting everything to disconnecting from the sins of the past.” His plant had one supervisory control system for the entire plant, because it was designed to deliver all of its 1640 MW of capacity to one buyer as a baseload facility. The plant comprises 12 gas turbine/HRSG trains and three steam turbine/generators and, to complicate matters, two steam hosts and six packaged boilers.

Now they have to comply as a NERC CIPS 6 medium impact facility. “In the early days of compliance, we were patching one workstation every two to three days.” Plus, they are planning to add an 800-MW 2 × 1 combined cycle at the site.

Plant practices reported to the group included these:

      • Create action plans based on vulnerability assessment results.
      • Patch monthly to keep current.
      • Physical and electronic access control is key.
      • Use E-ISAC for threat intelligence.

The electricity information sharing and analysis center (E-ISAC) is operated by NERC but functionally isolated from its enforcement arm. It’s a central repository for physical threats, vulnerabilities, and incidents. According to information available from the program online, the following benefits are described:

      • Identify adversary campaign tactics, techniques, and procedures and share specific mitigation actions.
      • Reverse-engineer malware to better understand events and develop predictive capabilities.
      • Share tactical information to reduce cyber risk for all participants.
      • Cross-benchmark and evaluate with other critical infrastructure sectors.
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