How to make sense of a water analysis report

In successful powerplant projects, either in the early project bidding or the engineering execution stage, before designing any water distribution, production or treatment system, you must know the water. The only way to fully understand the water type and its characteristics is with a thorough study of the water analysis report, says Wendy Wong, a senior process engineer at SNC-Lavalin. 

You must recognize the reliable parameters, know which data need re-examination, and understand the water’s traits. Working early in the planning stages with good data from the water analysis report reduces engineering risks and ensures reliable water systems will support plant operations.

Water can be defined by its physical appearance (for example, color, suspended solids, and turbidity) and its biological and chemical properties. Water analyses should be performed by certified water laboratories. Be mindful that not all laboratories can perform all the tests required. This can be an issue when specific toxicity tests (such as for the surfactant Triton X-100) are needed, or when a minimum detection limit is required.

This was the case for a combined-cycle plant in Connecticut. A zinc detection level of two decimal points or better was required for the water supply to the cooling towers because the plant’s towers had a zinc limit for wastewater discharge of 1 mg/L or less.

Best practices to mitigate water collection challenges:

    • Properly collect, sample, or preserve samples for accurate water quality to avoid plant design errors.

    • Obtain sample bottles and preservatives from the laboratory conducting the required analyses.

    • Use glass containers where oil or grease is present.

    • Use amber-colored plastic containers (where use of plastic containers is permissible) to protect sample constituents, which can break down in sunlight.

    • Pack samples in a cooler with ice for immediate shipping to the laboratory.

    • Confirm maximum holding time with the lab to ensure representative results from the tests.

Another lesson learned: Sample residual chlorine, pH, and temperature at the sampling point with calibrated instruments to best reflect actual properties. Residual chlorine may be consumed by the living organisms in the water sample during shipping.

Water analysis report. To make sense of the water analysis report, it’s important to know the water source that feeds the sampling points, and where and when the samples were taken. All the physical characteristics should be examined together to provide an overview on corrosivity, particle’s physical size, scaling potential, and fouling tendency of the water. The biological and chemical properties indicate the choice of chlorination, biological organism activities, dissolved salts content, scaling potential, fouling potential, reactivity, salinity, and toxicity of the water.

Missing parameters. Many powerplants in the US and Canada use a city water supply. Unfortunately, only a few parameters are required to be reported to the public—such as residual chlorine, conductivity, coliform, etc. So even if the water supply comes from a city’s potable water network, which is a good and clean water source, use of a water-treatment-system design based on a limited water analysis can spell disaster.

For example, the system may not satisfy power requirements under all operating conditions, perform the various operations needed, or hold to certain parameter limits in the wastewater discharge permit because the concentrations of some constituents in the water supply are unknown.

Quality variance. Seasonal and weather-related changes and facility production schedules (for grey and wastewater) can impact water quality. While drastic changes in water temperature occur between the cold and warm months, not checking water temperature onsite can create problems, especially when designing the biological treatment, cooling water, and reverse osmosis (RO) systems, or any treatment process that depends on water temperature. 

To illustrate: The capacity of high-pressure RO pumps/motors may be insufficient when operating in winter if the design temperature is based on warmer samples taken in summer. The design team should obtain at least one water sample per season or at varied days/times to ensure representative samples are collected. 

The design engineer also should consider weather-pattern changes and the future impacts to water quality when designing a new plant and using surface-water data 10 years or older. They may not be representative of the current water condition. New land developments in the area can impact surface water analysis as well.

Worst-case scenario. The design’s technical specifications in a request for proposal sometimes summarize historical water analyses and provide only the worst-case scenario based on the peak value of each constituent without providing the individual water analysis. Result: Water-treatment bidders likely will offer larger or more complex equipment than necessary, and it will cost more.

Also, when the source water’s characteristics and trends are not fully understood, unnecessary equipment and more complex, high-maintenance systems could be added to a new plant and they may produce more wastewater.

When design engineers have sufficient water data and recognize the trends, they can design a plant to accommodate the worst-case scenario with minimum impacts to costs. Whether by recirculation, blending, providing temporary storage, or operating the standby water-treatment trains, they can provide sustainable, cost-effective solutions.

Other general guidelines. A water analysis report can be unreliable. Typos, use of the wrong units of measurement or confusing nomenclature (for example, mg/L versus mg/L as CaCO3), expired samples, or simply the wrong analysis can result in incorrect reports.

Guidelines circulated in the industry for verifying the reliability or plausibility of a water analysis report that you may find helpful are provided below. Listed in decreasing order of reliability, they were published in 1991 by G Solt under Dewplan (WT) Ltd, which later became part of Veolia Water.

1. Natural water from the streams, ocean and underground where pH is around neutral, the water shall be chemically balanced—that is, the sum of the cations equals the sum of anions. 

2. Conductivity should roughly equal the total cations multiplied by 1.6 if in ppm CaCO3. If a total-dissolved-solids (TDS) value is given, it should equal the total cations, assuming equivalent weight of between 50 to 70.

3. Bicarbonate, HCO3, is often about the same as the calcium ions, Ca2+.  If it is more than the total hardness (Ca2+ and Mg2+), be suspicious.

4. Ca2+ concentration is generally between four to eight times the Mg2+.

5. In the absence of reliable data, Na+ and Cl concentrations can be assumed the same, especially if either of them is high.

In sum, designing water distribution, production and treatment systems requires reliable and accurate data. Bid requests with limited parameters or insufficient water analyses may bring in proposals with big cost differences from water treatment vendors based on assumptions and their experience with the water source, with some proposals possibly being double the cost of others.

Taking the time to work early in the planning stages with experienced engineers, studying the water trends, and defining sampling parameters and frequency pays off. The good, reliable, and representative water analyses become the foundation of an adaptable and sustainable system to support long-term powerplant operation for both normal and upset water supply.

Wendy Wong, PE, a senior process engineer at SNC-Lavalin, has 26 years of global experience in chemical and water-treatment processes for the power, oil and gas, and pharmaceutical industries. Her expertise includes treatment of cooling water and demineralized water, plus seawater desalination and cycle chemistry for boilers. 

Posted in Generator Users Group | Comments Off on How to make sense of a water analysis report

Vendor presentations cover the waterfront of O&M information needs for 501F users

The 501F Users Group Vendorama program gives attendees access to live presentations by dozens of products/services providers offering O&M solutions. The program matrix for the 2019 meeting allowed each attendee to participate in up to seven presentations, vetted for technical content by the organization’s Board of Directors. There were seven sessions, each featuring five concurrent half-hour presentations.

Abstracts of Vendorama presentations by CCJ business partners follow. These summaries attest to the quality of information disseminated. Owner/operators with access to the 501F Users Group’s website can retrieve the PowerPoints online and dig into the details.

Articles on other portions of the 2019 meeting of the 501F Users Group were published in the last issue of CCJ ONsite. Connect to that information via the following links:

Advanced Turbine Support LLC, “501F compressor NDE, impact damage, tip liberations, and in-situ blending capabilities” and, together with PSM, “In-situ torque-tube inspection and prediction methodology” 

Blending of compressor blades and vanes damaged in service, but repairable, removes stress concentrations or cracks that otherwise might lead to metal liberation with downstream consequences. Significant time and cost savings result when blending can be done in-situ.

A couple of years ago, in-situ blending was considered viable only on the first stage or two of the 501F compressor. Advanced Turbine Support’s Mike Hoogsteden, director of field services, told attendees that blending was now possible from the variable inlet guide vanes to Row 7 and showed the results in a series of photos. 

AGTServices Inc, “The negative impact of increasing cyclic duty on electric generators” 

Jamie Clark, a frequent speaker at user-group meetings, strongly recommended to 501F owner/operators that they schedule baseline condition assessments for their generators as soon as possible—this to avoid unplanned repairs resulting from the frequent starts/stops characteristic of powerplant operations today.

Correct any deficiencies identified quickly, he added. Make sure repairs are done right the first time—even if it means taking a major to do so. Then consider robotic inspections for future inspections in lieu of field removal, he said.

Be mindful of significant changes in operating duty because they likely will require changes to your outage schedule, Clark continued. Cycling units warrant shorter intervals than baseload and seldom-run machines.

AGTServices has found that, compared to outages conducted only a few years ago, today’s most involved repairs are related to problems caused by cycling. Clark mentioned the following examples:

    • Endwinding loosening and insulation damage.

    • Core and belly-band loosening.

    • Winding migration, which can block off cooling.

He closed by urging the sharing of generator experiences during open user discussion forums. Some units (OEM, model, etc) suffer common problems, Clark said: It’s in your best interest to know what they are.

ARNOLD Group, “Technical differences between optically similar single-layer insulation systems”

Pierre Ansmann told attendees that ARNOLD Group’s single-layer insulation system is state-of-the-art technology capable of solving all known insulation-related problems associated with the operation and maintenance of gas and steam turbines. Particularly important given the challenges created by today’s demanding operating paradigms is that the company guarantees reuse of its insulation system for 15 outages without a decrease in efficiency. 

During operation, ARNOLD insulation enables users to decrease compartment temperatures significantly—by more than 50% in some cases—while decreasing fuel consumption and increasing power production.

During maintenance activities, the single-layer system reduces outage time and related cost because there are fewer blankets to remove, repair, and replace. Plus less local insulation labor and less scaffolding are required for outages.

Ansmann closed his session by describing the company’s design innovations in 2017 and 2018 to improve on the insulation of turbine bearing tunnels. As the slides in his PowerPoint explain, the ARNOLD substructure bracket system assures ease of maintenance access while protecting against damage from both engine vibration and from oil that might leak into the tunnel.

C C Jensen Inc, “Big data in oil conditioning and monitoring”

With owner/operators becoming more comfortable using online data collection and analysis for large capital equipment, C C Jensen’s Axel Wegner spent his Vendorama session explaining to plant personnel why they should consider doing the same for turbine oil. Storing retrievable lube-oil data in PI or similar system allows users to adopt a “big data” approach for identifying off-normal conditions, monitoring their development, and taking appropriate corrective action in a timely manner.

Online particle counting was one example he gave for identifying component-specific problems before they caused a breakdown or operational emergency.

Wegner’s presentation was a good overview of the effects of oil contaminants on machine life, oil sampling, oil analysis, and online condition monitoring, while providing real-life examples.

CECO Peerless, “Importance of ammonia injection grid design to SCR performance” 

Attendees were told that the company’s ammonia injection grid (AIG) is designed and optimized to provide the desired reagent distribution across the duct to assure expected SCR efficiency and performance. The square cross section of CECO Peerless’ EDGE™ AIG lances are said to promote better mixing, thereby improving NOx reduction, reducing ammonia slip, promoting longer catalyst life, and reducing the cost of operation.

A lab comparison of EDGE and an AIG with traditional lances revealed better performance from the former in half the distance from the AIG grid to the catalyst. A 30% reduction in ammonia consumption was reported by a plant after conversion of it AIG to EDGE.

Three brief case studies are provided in the presentation. 

Doosan Turbomachinery Services, “501F rotor Class III inspection, new torque tube/air separator accomplished in 69 days of shop time” 

The company’s capabilities are explained by way of a Class III inspection of a 501F rotor with 116,000 fired hours and nearly 2000 starts. The project, which took 69 days in the shop, included complete reverse engineering and manufacture of the torque tube, air separator, and four rows of compressor blades, as well as complete disassembly, inspection, and reassembly.

A Class III inspection in the Doosan shop includes the following steps:

    • Deblade and unstack compressor and turbine sections.

    • Inspect and analyze all rotor components.

    • Make engineering recommendations on any life-limiting factors.

    • Install new belly bands.

    • Reassemble, balance, and ship to site.  

Digging into the details of a turbine unstack illustrates the depth of discussion and level of detail presented. The six steps here are these:

    • Put rotor in vertical position.

    • Measure and record stretch of turbine bolts.

    • De-tension 12 bolts.

    • Remove turbine disks.

    • Photograph and visually inspect curvic couplings.

    • Prep parts for cleaning.

A checklist of important items to remember during reassembly of the compressor and turbine, including balancing tips, was a valuable primer for anyone unfamiliar with the guts of the engine or anyone looking ahead to a lifetime evaluation of his/her machine. Attendees were reminded that in-depth planning for a Class III inspection is critical and that both bolting and parts are long-lead-time items.

Testifying to the success of this project was that the rotor required only 271 grams of balance weights on the turbine end with all blades installed. Further, that there was less than 1-mil vibration at full load and no need for a field balance.

Emerson Automation Solutions, “Benefits of incorporating hardware/software that provides total plant solutions provided by MHPS and Emerson collaboration” 

Presentation focused on the capabilities and achievements of the Mitsubishi Hitachi Power Systems/Emerson alliance formed in 2008 to provide state-of-the-art turbine (gas and steam) and controls solutions. Successful projects completed since the alliance was formed include logic improvements, tuning, and dual-fuel conversions with full Ovation upgrades. Emerson reported having completed over a hundred upgrades of Siemens TXP systems.

Ovation is much more than a traditional distributed plant control system. In addition to native advanced applications for optimizing plant operations, it now supports integrated machinery health monitoring and generator excitation, as well as embedded simulation and enhanced cybersecurity solutions.

For more on Ovation’s capabilities and owner/operator experience with this controls platform, read CCJ’s report on the 2019 meeting of the Ovation Users Group elsewhere in this issue. 

Environex Inc, “Advancements in CO and NOx control technology” 

Andy Toback regularly shares Environex Inc’s knowledge of CO and NOx control technologies with CCJ readers. You can access some of this information with a keyword search of the magazine’s archives at At the 501F Users Group’s 2019 Vendorama he focused on four advancements in CO and NOx control that owner/operators should be aware of. They are:

    • Dual-function catalyst, which combines the functions of the SCR and CO catalysts into a single catalyst.

    • Sulfur-tolerant CO catalyst, a modified CO catalyst formulation that provides greater resistance to performance loss from sulfur poisoning than conventional CO catalyst.

    • Low-pressure-drop catalysts. The increased performance requirements for SCR systems require higher catalyst volumes of traditional designs, which, in turn, causer higher backpressure and efficiency losses.

    • Improved reagent mixing made possible by retrofits to improve ammonia-to-NOx distribution before the SCR catalyst.

Get the details by accessing Toback’s presentation. 

EnvironmentOne Corp, “Hydrogen auxiliary system upgrades” 

Chris Breslin’s 50-slide Vendorama presentation with the title “Hydrogen auxiliary system upgrades” clearly exceeded expectations. It was more like a short course on the care and handling of hydrogen (read “safety”). Most welcome considering a couple of high-profile explosions in the last decade and the general lack of knowledge about, and respect for, this gas by many of the relatively inexperienced personnel being hired at powerplants today.

You might want to consider downloading Breslin’s presentation, giving your employees a copy—it’s easy to understand and to the point—and then using it as the basis for a “lunch and learn.”

Breslin begins by answering the question of “Why hydrogen?” then explains the properties of the gas, moving quickly into safety best practices. The safety and efficiency reasons for hydrogen purity monitoring are included along with the reasons for upgrading existing equipment: Safety is Number One!

There’s a section on generator condition monitoring and another on hydrogen dryers. The benefits of automated purge also are examined.

Hilco Div of Hilliard Corp, “Combined cycle oil filtration and conditioning”

The Hilco team explained to users how its products bring fluid contamination problems under control, cost-effectively. The company offers full-service fluids management—including sample-taking, fluid analysis, equipment consulting, field techs, startup help, etc.

Conditioning equipment discussed included coalescer/separators for removing moisture and contamination from steam-turbine lube oils, reclaimers for restoring contaminated oil to a like-new condition, gas filters in both simplex and duplex arrangements for gas-turbine fuel systems, and oil-mist eliminators for reclaiming the oil found equipment vent air—coalescer only and coalescer with blower and silencer.

Hy-Pro Filtration, “Turbine oil tests and frequencies; water contamination mitigation and control” 

A presentation on lubricant maintenance and analysis is particularly helpful during the Vendorama sessions which precede the vendor fair at 501F User Group meetings. There always are several companies in the exhibit hall offering turbine oils and conditioning services and it’s tough to remember all the standards and reasons for requesting the various tests you should be conducting. Without a primer like that presented by Scott Howard you might not remember the questions you should be asking on the show floor.

He began by introducing (re-introducing to many attendees) the turbine-oil testing guidelines published in ASTM 4378-13 and then moved quickly to test frequency. Regular analyses (appearance, viscosity—ASTM D445, total acid number—ASTM D664, ISO particle count—ISO 446, MPC—ASTM D7843, moisture—ASTM D6304/D7546, metals—ASTM D5185), he reminded, should be done every one to three months, periodic analyses (Ruler—ASTM D69071, RPVOT—ASTM D2272, rust—ASTM D664 for steam turbines) every three to 12 months. But be sure to run a battery of tests within 24 hours of any lubricant change.

Analyses to conduct as required include the following: FT-IR—ASTM E2412, rust—ASTM D664 for gas turbines, foaming—ASTM D892, air release—ASTM D3427, demulsibility—ASTM D1401, insoluble—ASTM 2273, and flash point—ASTM D92.

Measurement of varnish potential was discussed in two parts: one for mineral oils, one for phosphate esters. Course notes for this portion of the presentation were provided by EPT; learn more at

JASC, “The science of liquid-fuel-system reliability in dual-fuel applications”

Reliable operation of dual-fuel gas turbines on oil demands that owner/operators protect against coking in fuel-system valves and piping. Active cooling is one solution available to users for assuring both reliable starts on liquid fuel and reliable fuel transfers from gas to oil.

JASC offers several cooling options that are easy to retrofit on turbines at plants concerned about liquid fuel system reliability. One of these, the so-called “thermal clamp,” introduced only about two years ago, is rapidly gaining industry attention. Results from the first few commercial installations confirm success in both protecting against coking and eliminating the need for “verification” firing of oil every month to confirm liquid-fuel system operability.

The company’s latest system configuration, which involves moving fuel piping off the hot casing and installing thermal clamps, water-cooled fuel valves, and controls, enables owner/operators to extend the intervals between runs on back-up liquid fuel to six months or longer without sacrificing reliability.

To illustrate, a 7F gas turbine operated on liquid fuel during commissioning of its fuel-system upgrade and then burned gas exclusively for the next nine months. After a shutdown, the turbine started and operated on distillate without incident.

A typical F-class unit needing to confirm oil firing capability would have paid approximately $30,000 each month the test was conducted.

Presentation gives details on thermal clamps and other water-cooled liquid-fuel system components. The schematics and case studies included in the slides can help you get started on your project today.

Mee Industries Inc, “Benefits of wet compression”

Thomas Mee may be the industry’s foremost expert on fogging/wet compression, having decades of analytical and plant-level experience on the technology. He encouraged attendees to consider this cost-effective method of power augmentation for delivering additional megawatts virtually instantly in times of need.

Fogging/wet compression systems are easy to integrate with gas-turbine controls, he said, adding that his company can deliver the necessary equipment in 12 weeks or less and can connect the new system to existing equipment within a favorable outage window—perhaps in only 24 hours.

Responding to a question, the speaker said erosion risk is reduced with small droplet size—a distinguishing characteristic of Mee systems. Droplet size and its impact on equipment received significant air time.

TOPS Field Services, National Electric Coil, and Doosan Turbomachinery Services, “Non-OEM solutions”

TOPS Field Services, National Electric Coil, and Doosan Turbomachinery Services co-presented on the subject of non-OEM outage solutions and the advantages offered by their collaboration. TOPS Toby Wooster took the lead, explaining that OEMs have been marketing an all-under-one-roof outage approach to powerplant owner/operators, where the engine manufacturers supply the field service, parts repairs, and engineering as a package.

This consortium’s presentation reminded users that the all-under-one-roof solution lacks the ability to deliver consistent quality, turnaround, and, most importantly, partnerships for plants that, for the most part, are unique.

TOPS and its partners have found through discussion with many users across the industry that vendors lack the partnership approach in their proposals: They don’t work with owner/operators to help solve their maintenance problems; their goal is to complete the outage at the lowest possible cost and move on to the next job.

The presentation suggested that the solution of greatest value came from working closely with a pure-play vendor that invests in relationships, flexibility, quality, and transparency, and responds quickly to the unique challenges every plant faces.

Wooster next explained how TOPS and its partners can deliver on their outage solution at a competitive price:

    • They invest heavily in the personnel who work onsite. The result: team members have been with their respective company for years and bring that experience to bear on your project.

    • They work with the plant well in advance of the outage to identify early risks that can impact cost and schedule—risks not identified in the RFP.

    • The development of solutions to improve outage performance, reduce duration, and minimize risks is ongoing in the back office.

Pioneer Motor Bearing Co, “Developing an innovative bearing radial load sensor”

The session opened with a review of how babbitted fluid-film bearings work and the types of sensors available to track their health—including thermocouples and RTDs to monitor temperature, proximity probes and accelerometers to track vibration, and load cells and strain gauges to monitor load. Temperature is important, of course, because the higher it is, the thinner the oil film. Vibration is measured to prevent bearing contact and to detect machine operating anomalies.

Progress is being made in the development of embedded strain gauges to accurately measure the load on the bearing train. The expectation is they will be able to detect wipe events without visual inspection, detect metal-to-metal contact/surface friction faster than a temperature sensor, and assist owner/operators in run/repair decisions.

A roadmap with critical objectives is included in the presentation. 

SVI Dynamics, “GT exhaust system repair and upgrade considerations”

SVI Dynamics is, perhaps, best known for its aftermarket design, engineering, and field services work from the gas-turbine exhaust to the stack exit. Scott Schreeg made a few points in his Vendorama presentation particularly worthwhile considering by plant O&M personnel. They are:

    • Most gas-turbine exhausts are fine until there is a hiccup and the project must be expedited, limiting options and flexibility to achieve the optimal repairs and/or upgrades.

    • If inspections are an option, typical failure modes can be monitored using thermography, noise surveys, and visual inspections to provide the information and time necessary for proper outage planning.

    • Upgrading gas-turbine exhausts using CFD analysis to improve aerodynamics will provide a longer-lasting system by reducing velocities and pressure drop, while using current methods and materials for maximum durability.

    • Project specifications can include parameters for acoustical, thermal, and aerodynamic guarantees to ensure the owner/operator has the opportunity to meet its project goals.

    • Turnkey contracts—including engineering, material/equipment supply, demolition, and erection—can mitigate risks and streamline project execution.

Posted in 501 F&G Users Group | Comments Off on Vendor presentations cover the waterfront of O&M information needs for 501F users

Ovation Users Group: Automation rises to platform for ‘trusted’ services

Intel, the venerable computer chip maker, is often lauded by marketing gurus for its “Intel Inside” stickers. The strategy allowed a supplier of invisible “pieces and parts” to be brand-recognized by the end user.

Emerson’s Power & Water Solutions business might consider “Ovation at your side.” At its annual Ovation Users Group conference, the Emerson leadership, and rank and file, made it clear, without overt reference, that Ovation will be more than control systems, automation, and plant knowledge management; it is evolving into a platform for a variety of enhanced services within a “trust domain” established with the customer (Fig 1).

Jim Nyquist, Group President, Emerson’s Systems & Solutions organization, opened the meeting by proclaiming this to be the “most challenging environment in history for power and water.” He reported that Emerson corporate restructured by selling off one-third of the company over the last three years, even as the firm made key acquisitions, most notably GE Intelligent Platforms.

Nyquist’s most insightful comment, though, was that its Power & Water Solutions business is becoming “a trusted advisor to the industries it serves.”

Robert Yeager, president of that business, as he does every year, next assumed bragging rights, noting that Ovation is now installed on well over one-third of the electricity generating capacity in the US, and close to one-fifth of the capacity around the world.

The group has its sights on a remote monitoring and digital collaboration center, a “collaborative work environment of the future,” said Yeager. When built out, it is expected to anchor enhanced services in cybersecurity, cloud-hosting, remote M&D, troubleshooting by subject matter experts, and real-time control and advisory services to operators and engineers on the customer side.

“The ‘live’ digital twin (not a “snapshot,” Yeager emphasized) means the simulator and plant control system share an integrated database, same DNA, and same engineering tools,” he said. This is what allows “trusted advisors” remote, real-time visibility into the facility, to support the plant staff as necessary and desired (Fig 2). Over 125 embedded simulators, the core of the “digital-twin” concept, are now installed or proceeding through the factory, Yeager reported.

Luke Williams, Executive Director, NYU Berkeley Innovation Lab, delivered the “out of the box” TED-talk type lecture, noting a transition in economic thought from the scarcity mindset to a “non-rival” goods paradigm. He used a lot of concepts from economics and social science to, essentially, describe the “sharing economy” (think Lyft, AirBnB).

“A chair is a thing, but the idea of a chair can be used by everyone,” Williams argued, you can “re-arrange things to satisfy other objectives, to disrupt path dependence and historical continuities.” Message between the lines, perhaps: Emerson is re-arranging the “ingredients” of its Ovation platform to deliver value-added services.

Progress with the Ovation backbone technologies was delineated by Steve Schilling, VP, Technology, including:

    • The scalability of the Ovation controller (OCR) continues with the release of the simplex version of the OCC100 compact controller and progression towards the next-gen OCR and micro-controller (Fig 3).

    • Software defined networks for fast fault detection and healing, and improved visibility into network health and security.

    • Integration of trusted corporate domains and security groups into the Ovation domain.

    • Models constantly being added to the live digital twin.

    • Machinery health protection and prediction as well as Ovation plant prognostics.

    • Major focus on cybersecurity.

Glenn Heinl, VP Lifecycle Services, Jaime Foose, Director Lifecycle Shared Services, and Mike Brown, Manager Lifecycle Proposals, rounded out the opening session, discussing all the ways their organization will be supporting customers in the months and years ahead, including advanced support programs, performance optimization support, programs to assist sites with replacing PLC-based and skid-mounted controls and integrating them into Ovation; the availability of subject matter experts; remote diagnostics; monthly support webinars; quarterly informational newsletters; and dozens of Ovation engineers who take calls 24/7.

Emerson recently invested in Dragos, a Hanover, Md, cybersecurity firm, and its CEO, Robert Lee, kicked off the second morning’s general session. His main theme was that owner/operators have to transition from relying solely on passive defenses against cyberattacks to a more active defense based on intelligence-informed actions. Adversaries, he said, set the stage for attacks months and years before they actually occur. He distinguished between intrusions, like phishing emails, and an incursion in which the adversary steals the information that assists in the later attack.

In one case overseas, Lee said, the adversary was able to install new logic into the safety system controller at a petrochemical complex. In other words, the adversary pre-staged malicious software on the DCS three years before the attack occurred in 2017.

In another event, the adversary spent six months “learning” the industrial environment, developed electric transmission capability, installed protocol-capable software, created malicious services, and coordinated action via a timer to de-energize a critical substation. While the entity responsible for the substation claimed it was “back up” within six hours after the attack, what they did not report was that they were operating in manual for six months afterwards.

Yet, despite these events, he noted that defending industrial systems is in a much better place than people realize.

In another general presentation on the second morning, Glen Wagner, VP North American Projects and Sales, noted that Emerson completed 52 gas-turbine retrofit projects in 2018, mostly to help users achieve flexibility in capturing high-value services in the organized electricity markets. Interestingly, he also noted that hydroelectric facilities are seeking modernization and optimization solutions for similar reasons—to capture market value filling in around must-take renewables.

Consistent with the overall emphasis on services, Wagner stated that Ovation experts can help on the front end as well, such as delivering return-on-investment analyses for contemplated upgrades and retrofits.

Application briefs

Minutes matter. That’s true in obvious situations, like when someone is shot, injured, or having a heart attack. It’s also true when capturing additional value in the organized electricity markets. One presentation described successful results leveraging Ovation controls in eliminating 20 minutes from the gas-turbine start cycle by implementing the HRSG purge credit.

Of the three general options described in National Fire Protection Association NFPA 85 (2015 edition), the one selected (Fig 4) was retrofitted in a week during a 14-day steam turbine/generator retrofit outage, with $170,000 additional revenue expected. The project included replacing six-year-old duct-burner controls, adding an air skid to monitor pressures, adding a third vent valve to the duct burner, and a third vent valve and second block valve to the gas turbine. Programmable logic controllers (PLCs) were replaced with redundant Ovation OCC100 controllers.

According to a representative knowledgeable about the plant, they “never know when the next dispatch will come.” The facility experiences 250-300 starts annually, has to hot-start within one hour, and cold-start within three hours, or pay up to $300,000 in penalties. Thus, avoiding penalties is worth more than gaining revenue.

Not as easily calculated is monetizing the reduction in thermal stresses on the HRSG, a design which includes two superheaters, but no reheat section. Plant reps estimate a factor of 10 reduction in hot/warm start contribution to superheater fatigue. Importantly, the retrofit moves superheater repairs out of the 10-year PPA window. As well, a three- to five-factor reduction in fatigue damage to the steam drum, downcomers, and outlet nozzles was calculated.

There is also a reduced risk of water hammer and low-cycle fatigue damage now that less condensate is produced. The original condensate removal drains were not sized for the operating modes the facility currently experiences, in other words, not for frequent starts and purge cycles.

Beyond training. Three users presented on how they have used their Ovation embedded high-fidelity simulator and benefits therein. One of the facilities, a combined cycle, is new, experiencing “first fire” the week of the Ovation confab. Note that none of the three is yet being used as a “live” digital twin.

Uses and benefits include the following:

    • Assist in engineering and in validating operator procedures.

    • Detect design flaws in transitional operating states, especially with a “complex auxiliary steam system with multiple operating modes” presented by the EPC.

    • Validate “intent of design” by running startup, ramping, baseload, and shutdown scenarios.

    • Validate setpoints and alarms.

    • Represent interactions between turbine controls and balance of plant.

    • Aid engineers in vetting logic and HMI graphics, trained operators, and optimized plant controls.

    • Detect superheater spray logic flaws.

    • Revise and update operating data and procedures.

No operator, no dog. Even two decades ago, automation specialists joked that in time, only an operator and a dog would be onsite at power stations and the dog’s job was to keep the operator’s hands off the controls. David Cicconi, Emerson Turbine Business Development Manager, reviewed a variety of technology enhancements now available to completely monitor and operate a multi-unit simple-cycle gas-turbine facility, even ones with HRSGs for cogeneration, remotely, with no personnel dispatched unless issues arise.

Cicconi distinguished a remote start from remote operation, stating that the former involves, among other things, personnel dispatched to the site for continuing operations and limited intelligence available following a failed start. Many other industries are already running complex energy systems remotely, such as unmanned mine sites, he noted.

Categories of enhancements covered include these:

    • Expand remote monitoring and control beyond the gas turbine (already completely automated) to BOP systems and skids.

    • Add vibration monitoring to BOP pumps and motors.

    • Add wireless transmitters to monitor remote equipment.

    • Deploy advanced pattern recognition to detect onset of performance deterioration and reliability events (such as cracked GT combustor transition pieces).

    • More tightly integrate BOP and auxiliaries.

    • Add cameras for site surveillance with thermal monitoring software for critical locations.

    • Shift from periodic to continuous monitoring (Fig 5).

Faster, less stressful ramping. Emerson worked with a utility user (2 × 1 combined cycle), EPRI, and a consulting firm to evaluate advanced steam-temperature control for HRSG applications. Ultimate goal is a control mode that allows faster, less stressful ramping, especially for units originally designed for baseload service and now experiencing daily start/stop, more rapid ramping, and/or operations over a wider load range.

Of the three options evaluated (Fig 6), the model predictive control (MPC) scheme proved superior, with 25-50% less standard deviation in superheat and reheat temperatures, 35-60% improvement in integrated error, consistently stable and fast response, and a straightforward tuning process. Two MPCs (controllers) were able to handle the entire HRSG load range.

The benefits are as follows:

    • Reduced deviations allow faster ramp rates when steam temperature variations are limiting factors.

    • Better stability reduces thermal stresses especially under automatic generation control (AGC), and reduces valve actuator activity.

    • Closer operation to setpoint may enable base steam temperature setpoint to be raised without suffering additional creep life cost, and may improve steam-cycle efficiency by up to 0.1% for additional fuel savings worth $20K annually.

Fewer rounds. Emerson’s Business Development Manager Juan Panama offered a compendium of technology applications to “build the utility of tomorrow.” Perhaps the most eye-opening one is to significantly cut operator rounds and make better use of limited manpower by installing wireless devices at all points where data are now taken manually. One combined-cycle site estimated that it could avoid 58 man-hours per week per power block in applying this approach and keep staff more focused on the important business of repairing what the sensors detect.

Panama also noted that Emerson offers a device that connects to any wired device to convert it into a wireless device, allowing additional HART information to be collected.

Other ideas (those not covered in earlier presentations) include remote monitoring for continuous operation of critical valves, especially around the steam cycle; wireless acoustic listening devices to detect the onset of HRSG tube leaks; wireless corrosion and erosion monitoring in areas prone to oxygen pitting and flow accelerated corrosion; wireless pressure transmitters to give insight into when tube bundles show signs of fouling; and continuous electrical condition monitoring on equipment rated less than 40 kV.

The last could eliminate the need for periodic IR measurements on live equipment with personnel in arc-flash suits, third-party partial discharge testing, and heater and insulation failures in isophase bus ducts.

Panama provided some rough estimates showing that sites in the low end of maintenance costs—ranging from $3.53/MWh in the top third of performers to $8.59 for the bottom third—apply many of these latest technologies discussed.

Your long-lost twin. You may not know it yet but your Ovation system could have a twin, a digital twin, the real-time “live” version of the Ovation embedded simulator when it is pulling data from and synced to the control system database. Emerson’s James Thompson and Shen Zhang provided an update on digital twin technology, noting that 180 models in eight “suites” (base, electrical, turbine, flue-gas desulfurization, selective catalytic reduction, combined cycle, boiler, and balance of plant) have now been validated and included in the algorithm library.

Without repeating the benefits and tools available from what was mentioned previously, the digital twin capability is being integrated into the Ovation services model, especially in its Emerson “cloud-hosted” configuration, meaning it is entirely offsite in the Emerson-controlled cloud. As such, it becomes an engineering simulator with the attendant fidelity and graphical realism, as well as the platform for real-time process and controls optimization (for example, root cause analysis and upgrades), autonomous control (instead of operator assisted control), and loop testing and validation.

As the presenters stressed, full-scale adoption of the live digital twin will require maintenance beyond just keeping the simulator updated and synchronized with the control system. Consideration will have to be given to cybersecurity, NERC-CIPs regulatory compliance, recalibration of the models to gain higher fidelity, and installing additional sensors in plants that are not properly instrumented or want to generate additional data for higher-level prognostics tools.

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Together again: 501G users to share meeting space with 501F users in West Palm, Feb 9-13, 2020

The 501G Users Group traditionally has conducted two meetings annually, the first early in the year, the second about six months later. For many years, the winter meeting was held in the same venue and at the same time as the 501F Users Group’s annual conference, the organizations coming together on safety, presentations by third-party suppliers, vendor fair, and meals.

The G users hosted winter meetings on their own from 2016 through 2019 but decided to rejoin the 501F users in 2020 because of the benefits that accrue from having a larger group of owner/operators sharing experiences. The 501G summer meeting will be conducted during the Siemens Customer Conference for F, G, and H Technology, as it has since 2016.

When conference registration opens for the winter meeting at the Hilton West Palm Beach, Feb 9-13, 2020, in a few days, all members of the 501G Users Group will be emailed a registration link. The summer meeting, hosted by Siemens, will be held at the Renaissance Orlando at SeaWorld, the week of June 15. It will be co-located with the T3K Annual Conference.

501G Users Group steering committee

Chair: Steven Bates, plant manager, Wise County Power Plant, Vistra Energy
Vice Chair: Mark Winne, plant manager, Millennium Power Partners (operated by NAES Corp)
Scott Wiley, outage manager, Vistra Energy
Guy Taylor, plant engineer, Lakeland Electric
John Wolff, technical support/compliance manager, Ironwood, LS Power

The G Users Group is a small, but proud organization of engineers and technicians who have “grown up” together—so to speak—and understand each other’s perspective. The first G, installed by Lakeland Electric, began commissioning operations in April 1999, but COD wasn’t until March 2001—only one month before the second machine began commercial operation at Millennium.

Fleet size is small by industry standards—24 Siemens (Westinghouse) engines at 13 sites in the US and one in Mexico (sidebar). Four plants are equipped with one engine each; seven have two gas turbines; two are equipped with three machines each, arranged in 1 × 1 combined cycles.

W501G fleet: 13 plants, two-dozen units

  • Ackerman Combined Cycle Plant, TVA, Ackerman, Miss
  • Athens Generating Plant, Talen Energy (operated by NAES Corp), Athens, NY
  • Ennis Power Plant, Vistra Energy, Ennis, Tex
  • Fuerza y Energia Naco Nogales SA de CV (FENN), Gas Natural Fenosa México, Agua Prieta Sonora, México
  • Granite Ridge Energy Center, Calpine Corp, Londonderry, NH
  • Harquahala Generating Facility, operated by NAES Corp, Tonopah, Ariz
  • Hillabee Generating Station, Exelon Power, Alexander City, Ala
  • Ironwood, LS Power (operated by EthosEnergy Group), Lebanon, Pa
  • Magic Valley Generating Station, Calpine Corp, Edinburg, Tex
  • Magnet Cove Generating Station, Arkansas Electric Cooperative Corp, Malvern, Ark
  • C D McIntosh Jr Power Plant, Lakeland Electric, Lakeland, Fla
  • Millennium Power Partners, Talen Energy (operated by NAES Corp), Charlton, Mass
  • Wise County Power Plant, Vistra Energy, Poolville, Tex

User meetings typically host roughly one-third to one-half first-timers, so many discussions are similar from year to year because newcomers have to be brought up to speed. There’s not much turnover in the top positions at G facilities which means each meeting pretty much picks up where the last one left off, especially regarding the OEM’s presentations. This certainly contributes to presentation efficiency because there’s a minimum amount of repetition.

Most users groups serving GT owner/operators organize their technical programs by sections of the engine—for example, compressor, combustion section, turbine, etc. The G users begin with an “annual report” from each plant and follow that half-day program with user presentations on emerging and significant plant-wide issues of importance to the fleet. Notes taken during the plant reports at a recent meeting follow:

Plant 1 with three 1 × 1 combined cycles reported on the steps considered for the layup of one unit because of low demand—something affecting many power producers nationwide. Two units suffered Row 1 turbine-blade failures in the previous six months and one of the steam turbines required replacement of L-0 blades.

Plant 2 found TBC (thermal barrier coating) loss on two R2 vanes during the borescope inspection of one of its two engines and replaced them. A R1 vane was replaced in the sister unit as well. At the time, both machines had operated for less than 40k equivalent baseload hours (EBH) and had fewer than 900 equivalent starts (ES).

Plant 3 found damage to Row 1 turbine blades during a borescope examination at about 90k EBH and fewer than 1000 ES, replacing the entire row and five transition pieces during a modified hot-gas-path (HGP) inspection. A hot-reheat tube failure in the HRSG also was noted.

Plant 4 took a major early to deal with a broken through-bolt and compressor hook-fit wear on one of its two gas turbines. A steam-turbine major for this 2 × 1 facility included rotor replacement and new bolting for the low-pressure cylinder. Generators were re-wedged.

Plant 5 reported on the HGP and generator major conducted for one of its two units, plus its experience during a steam-turbine valve overhaul.

Plant 6 was forced into an economic shutdown and shared key aspects of its layup plan.

Plant 7, with two engines having slightly more than 80k EBH/1750 ES, presented its experience conducting a double combustion inspection for the first time, and replacing Row 1 vanes. Also shared were plans for installing NextGen hardware during an upcoming outage.  

Plant 8, a 2 × 1 combined cycle with just north of 50k EBH/700 ES on its gas turbines, spoke about a CI on Unit 1 that went to a modified HGP and included replacing four Row 4 blades. Balance shots also were installed to reduce vibration. Unit 2 required an HGP, plus rotor removal to address seal issues. New R1 NextGen vanes were installed. In addition, HP and IP valves and actuators were replaced on the steamer.

Plant 9, approaching 100k EBH/2700 ES on its 1 × 1 combined cycle, shared details of a lost-time accident and replacement of the gas-turbine generator’s step-up transformer. The speaker said the following were on his mind: turbine through bolts, HRSG fouling and its impact on gas-turbine backpressure, and Row 1 blades and vanes.

Plant 10, a 2 × 1 combined cycle, reported on the replacement of the exhaust expansion joint for one of its gas turbines and on SCR catalyst replacement in the HRSG for that engine. A steam-piping crack was mentioned as well.

Plant 11 said its gas turbine was closing in on 100k EBH and 2750 starts, reporting that the unit was running well. The only hiccup was rotor-air-cooler leakage at the inlet tubesheet which required plugging six tubes. The takeaway: probably time for a replacement tube bundle.

Plant 12 borescoped its gas turbine and received a clean bill of health.

Plant 13 had nothing but good news to report since the previous meeting. Planning was underway for majors on both of its gas turbines in the following year.

The open discussion portion of the meeting began with safety topics, including the following:

    • Outage planning. Consider outsourcing confined space rescue; one plant reported this as less expensive than using staff. A user suggested bringing in colleagues from other facilities several weeks prior to an outage to review and comment on your plans and procedures. Might also be a good idea to bring in representatives from selected contractors for the same purpose. To police for safety violations during the outage a user suggested hiring an outside contractor experienced in this work.

    • Grinders/saws/buffers. Be aware that grinding wheels can explode (don’t forget face shields) and that any rotating cutting/grinding tool has a “coast-down” time during which it remains hazardous to operators and others in the work area. One attendee said he surveyed some of this plants tools and found coast-down times of 11 to 17 seconds. Unacceptable!. Quick-stop tools are available and they cease rotating in 1 sec. A contractor contacted after the meeting suggested to the editors that reciprocating saws are an alternative to centrifugal tools. They’re safer, he said, but they take longer to make the cut and the cut is not as clean as with centrifugal tools.

    • This is an area that begs for experience. Many experienced riggers have retired and the number of reported near misses and dropped rotors is increasing and very concerning. Be sure no personnel are under any lift and that ground and crane people are in constant contact during the lift, and that the component being lifted is visible for the entire lift.

    • Color coding. Have vests and/or hardhats of different colors to facilitate identification of critical personnel and to be sure the proper person is working on a particular issue. Example, one color for riggers, one for confined-space rescue, etc.

    • Identify near misses during the outage, get RCAs done quickly and circulate findings among all who should know about them.

User presentations/discussions focused on turning-gear preventive maintenance, a main relay protection failure and findings, high-vibration trip and findings, and a few other topics. Such discussions often morph into self-help clinics with colleagues offering the benefits of their experiences to anyone who has a concern and is unsure of what he/she should do given a particular set of circumstances. In some cases, users share experiences for “awareness” purposes—situations to avoid, and why. Learning from the experiences of others is a primary goal of all users groups. Avoid mistakes already made.

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Klamath reroutes fuel-gas piping above-ground, cuts inspection cost dramatically

TransCanada, Klamath Energy’s fuel-gas supplier, installed its control, filtering, and metering station at the plant fence. The piping network on plant property, serving the gas turbines, auxiliary boiler, and plant heaters, was buried, and expensive to inspect.

Buried gas lines serving the facility’s 501F-powered 2 × 1 combined cycle had to be inspected every five years. Cost was $400,000 per inspection—including rental launchers, rental receivers, inspection equipment, labor, restoration, and cleanup. Additionally, a site outage of 10 days was necessary to conduct the required inspection.

Plant management (Dennis Winn, plant manager; Greg Dolezal, maintenance manager; and Bruce Willard, operations and engineering manager) engaged an Oregon firm to help with the engineering aspects of a project to consider the design, seismic, routing, and structures for moving fuel-gas piping above-ground. With the firm’s assistance, plant personnel developed a scope of work with the required bill of materials. Responsibilities for the project were split: Klamath personnel purchased all pressure components and ensured that the pipe and material test reports were correct while the contractor selected and provided support structures and their materials.

Metallurgy. Engineering review of the project identified a problem with using standard A106 grade B pipe. There was a risk of brittle fracture because of the material’s insufficient manganese-to-carbon ratio for cold-temperature service. The typical fuel-gas temperature at Klamath is less than 40F.

An article in the National Certified Pipe Welding Bureau’s May 2016 Technical Bulletin, discussing developments in the steel-making industry over the previous five years, suggested that purchase orders for seamless carbon-steel pipe, fittings, and flanges specify a manganese-to-carbon ratio of 5:1 or greater, and a grain size of 7 or finer, to avoid failures. Klamath elected to adhere to a manganese-to-carbon ratio greater than 5:1 as a requirement for all of its steel pipe, fittings, and flanges.

Above-ground fuel-gas piping. After developing a scope, construction contractors were contacted, and the scope of work was publicized for solicitation. Bids were received and the construction company was awarded.

The road crossing was a main concern given the potential of something striking the overhead piping. A pair of W12X30 beams was installed on both sides of the piping, with the piping set well inside the protective structure (photo). The bottom elevation of the wide-flange beams has a clearance of 19.5 ft.

Additionally, valving was installed on the piping so nitrogen purges could be executed during times when fuel-gas outages dictated such use on the 10-, 4-, and 1.5-in. piping.

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Inlet fogging pump upgrade reduces O&M cost, increases revenue at Fremont

Costly fogging-pump failures and consequent maintenance repairs had negatively affected Fremont Energy Center’s summer peak season performance and its maintenance budget. Plant personnel realized the need to prevent premature pump failures and avert costly fogging-system downtime.

The plant maintenance staff began investigation of multiple issues linked to premature failures of the station’s fogging pumps. In the process, personnel learned that the low lubricity of demineralized water was causing pump seals to fail.

They devised a plan to upgrade the fogging system. It included the use of service water to flush pump seals, thereby cooling and lubricating them. This was accomplished by retrofitting all of the fogging pumps with flushed manifold heads. The result was increased seal life plus dramatically lower maintenance cost and fogging-system downtime.

To implement this solution, the maintenance staff and site engineer hot-tapped the service-water headers for flushing liquid, routed the service water through two particulate filters to a manifold near the fogging skid, and branched off those lines to each of the pumps (Fig 1).

Technicians then installed solenoids on the service water supply and tied them into the fogging-pump start logic to begin supplying flushing water before the fogging pumps start (Fig 2). Lastly, they tied drain lines from each pump into one common plant drain (refer back to Fig 1).

This solution saves the 501F-powered 2 × 1 combined cycle approximately $100,000 annually by reducing fogging-system downtime and increasing power output. Steve Greene is the plant manager for operator NAES Corp.

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