May 2018

Steam Turbine Oil Seal Rub 14 I Optimizing Unit Ramp Rate 19 I Keeping Your Cooling System Clean 23

May 2018

Plan of attack for low pressure turbine rotor stress corrosion cracking: Cost effective analysis, inspection and repair options

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FEATURE 5 Plan of attack for low pressure turbine rotor stress corrosion

cracking: Cost effective analysis, inspection and repair options

COLUMNS

Printed in the U.S.A. Group Publisher Karen Ruden – kruden@WoodwardBizMedia.com General Manager Randy Rodgers – randy.rodgers@WoodwardBizMedia.com

14 Machine Doctor

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Steam turbine oil seal rub

By Patrick Smith, Sheekar S., Air Products & Chemicals

19 Applied Tech

Optimizing unit ramp rate

By Merrill Quintrell and Steve Seachman, Electric Power Research Institute

23 Industry Spotlight

Keeping your cooling system clean

By Brad Buecker - ChemTreat

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ASME FEATURE 9 Rapid H2 purge with CO2 for safer plant operations

Test run results

Ted Warren, Director of Research & Development, Lectrodryler, LLC Larry Morris, Assistant Plant Manager - Spurlock, East Kentucky Power Cooperative John McPhearson, Chief Executive Officer, Lectrodryer

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EDITOR’S NOTE

CALENDAR

Energy-Tech gets a new look Welcome to the spring 2018 issue of Energy-Tech magazine!

As I write this column, the calendar tells us it should be spring even if our weather is 60 degrees one day and snowing the next. Hopefully by the time this issue reaches you, we’ll be enjoying warmer weather, spring flowers and sunshine.

If you are reading this article I’m sure after turning a few pages in our magazine you’ve noticed a slight change in our design. Eric Faramus, our graphic artist, spent some time this winter to freshen up our look and modernize our logo. We love it and hope you like what you see and find the layout more inviting and easier to read. Our content remains the same as we continue to bring you technical articles from leading industry experts each week through our Current News E-newsletter and in our quarterly print publications.

Beyond bringing you a new design, I also have a loaded training schedule for you in 2018. Whether your needs are for online courses or live dedicated symposiums, I’m sure you’ll find one to fit your requirements. If you’re not familiar with the format of our online courses, we try to schedule them in two-hour sessions so that you aren’t taking too much time away from your job. Some may be held in multiple, back-to-back day sessions. And, if you miss a day, no worries. We always record the sessions and send you a link to watch when you have time or to use as a refresher at a later date. Certificates for pdh credit are sent after each course. See the list to the right to find the details on a 2018 course that’s right for you.

The big news for our 2018 training schedule is that we are co-hosting two very intensive live symposiums to meet the needs of those who prefer the format of a face-to-face training session. The first is the Steam and Gas Turbine Symposium by Steve and Tom Reid of TG Advisers offering troubleshooting and outage repair case studies. This symposium will be held June 5-6 in San Antonio, Texas.

We are also excited to be partnering with Environment One Corporation (E-One) again to co-host the biennial Generator Auxiliary Systems symposium. This session will be held at the end of July in Saratoga Springs, NY. Details for both symposiums are available on the right and from our website – www.energy-tech.com under the webinars and events tab.

As you can see, 2018 is shaping up to be a very exciting and productive year. As always, I’d love to hear your ideas about technical content or possible training. Email me at editorial@WoodwardBizMedia.com with your thoughts for topics that you’d like to see covered.

Thanks for reading,

Kathy Regan

Online courses and symposiums June 5 & 6, 2018 Steam and Gas Turbine Symposium – Troubleshooting and Outage Repair Case Studies Hosted by TG Advisers and Energy-Tech Magazine Wyndham Garden, San Antonio Riverwalk, San Antonio, Texas www.energy-tech.com/turbine-symp July 30 – August 1, 2018 Generator Auxiliary Systems Symposium Hosted by Environment One Corporation (E/One) and Energy-Tech Magazine Saratoga Springs, N.Y. www.Energy-Tech.com/Gen-Sym July 10 & 11, 2018 Condenser Performance: Essential Monitoring, Air In-Leakage Valuation, and Reporting webinar Dr. Tim Harpster, presenter www.energy-tech.com/condenserperformance July 25, 2018 Risk-Based Inspection for High Energy Piping Systems webinar John Arnold, presenter www.energy-tech.com/piping

Industry events June 24-28, 2018 ASME 2018 Power & Energy Conference & Exhibition Disney’s Contemporary Resort Lake Buena Vista, Fla. www.asme.org/events/power-energy September 10-12, 2018 Condenser Life Cycle Seminar Royal Sonesta New Orleans New Oleans, La. www.condenserseminar.com September 18-20, 2018 Turbomachinery & Pump Symposium George R. Brown Convention Center Houston, TX tps.tamu.edu December 4-6, 2018 Power-Gen International Orange County Convention Center, West Halls Orlando, Fla. www.power-gen.com

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Designates ETU co-hosted events May 2018

FEATURES

Turbine Tech: Plan of attack for low pressure turbine rotor stress corrosion cracking: Cost effective analysis, inspection and repair options Rachel Sweigart, lead consulting engineer, TG Advisers Stephen Reid, president, TG Advisers

Background Stress corrosion cracking (SCC) of low-pressure steam turbine rotor blade attachments is an industry issue on older fossil, biomass and nuclear units. Many units have experienced forced outages and/or extended repairs due to direct or collateral damage from this time-dependent and chronic failure mechanism. However, risks related to SCC can be mitigated through good inspection and repair contingency planning. Understanding the causes of SCC and available inspection techniques, analytic tools and repair options is key in preventing this issue from impacting unit availability.

Causes SCC will only occur if specific conditions are met. It happens with operational time and high tensile surface stress, material susceptibility to corrosion and a corrosive environment. Because of these boundaries, low-pressure blade attachments that operate near the Wilson line – the location in the steam path where the transition from superheat to saturated steam occurs – are often likely candidates for SCC later in their operational life.

Blade attachments are high stress locations due to the transfer of centrifugal blade loads to the rotor. There are stress concentrations inherent in dovetail or pinned designs and prior to finite element analysis, these designs were unable to be optimized.

As evidenced in post failure analysis of older rotor designs that have experienced SCC, many of these designs allowed peak stresses that exceeded the material yield strength.

They also can be a natural trap for chlorides and other corrosive deposits.

May 2018

Earlier rotor designs often utilized higher yield strength materials then are now recommended. These rotors were more susceptible to SCC because the crack growth rate of SCC is exponentially related to material yield strength. SCC growth rates can vary from 0.005 mils/year to over 0.500 mils/year based on the yield strength and operational temperature. Current industry recommendations are to limit upper yield strength to 120 ksi for a new nuclear LP or fossil LP turbine retrofit.

The Wilson line creates a corrosive environment in a steam turbine. As mentioned previously, this is where the steam transitions from a superheated state to a saturated state. At this point, corrosive salts deposit out of the steam. In a fossil LP, this typically occurs from the L-2 to the L-0 stages depending on load operation.

Because of their lower steam design conditions, the Wilson line in biomass and nuclear units often occurs further upstream between the L-6 and L-3 stages. These rows are generally smaller and as a result lower stressed than the L-2 through L-0 stages. Steam chemistry is important in managing SCC risks as units that have frequent condenser leaks, excursions, or once-through boiler designs are more likely to have poorer steam chemistry control and as a result more contaminants deposited in the steam path.

It is important to note that stress corrosion cracking is a time dependent phenomena.

A unit will not experience SCC crack initiation prior to some operational time and there is no age at which a unit is no longer susceptible to SCC. Any unit that has operated for over 20 years should be inspected for SCC.

Identifying SCC risks To evaluate a unit’s risk for SCC, the first step is identifying the location of the Wilson line. This can be done with an expansion line based off of the unit’s heat balance. The heat balance should be reflective of unit operating conditions – for example if the unit operates at partial load the majority of the time, the steam conditions for full load will not provide an accurate reflection of the Wilson line.

Once the Wilson line location is determined, the stages at risk for SCC can be identified as well. Stages that do not see wet steam will not experience SCC. Once the stages at risk for SCC are identified, they should be inspected. For blades that are side entry design, both inlet and exhaust sides of the disc should be grit blasted and polished. Inspections should focus on the highest stress locations of the blade attachment area. For tangential

Photo 1: Stress corrosion cracking branching characteristic

reverse disc attachments, direct inspection is not an option. Non-destructive examination such as ultrasonic phased array can be used to inspect in these cases. OEMs and other companies offer this as a service.

ENERGY-TECH.com

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FEATURES If cracking is believed to be found, a blade group should be removed and lightly polished if needed to confirm findings. If there is a closing group, the blades on either side of closing blade are higher stressed than other blades in the row and so are likely candidates to exhibit cracking if SCC is an issue. It is important to note that pitting is not the same as SCC although it can lead to crack initiation by the formation of stress concentrations on the rotor surface.

Evaluating SCC Growth rates for SCC are dependent on an exponential relationship between the operating temperature and the material yield strength. Typically, to evaluate the stress in the blade attachment, a finite element analysis is completed. This will identify the locations and magnitudes of the highest stresses in the blade attachment. However, for a less time intensive analysis, it can be assumed that the maximum stresses seen are equal to the yield strength of the material. When a material is stressed to its yield strength it plastically deforms to distribute the stresses; therefore the max stress can only slightly exceed yield strength.

The operating temperature can be determined from the unit heat balance. As mentioned earlier, it is important that the heat balance aligns with the unit’s actual operating conditions because operating at off design conditions can shift the Wilson line and subsequently the stages at risk for SCC. Units that have a cycle heavy load profile see high stresses during startup and shutdown that can significantly increase crack growth rates through combined mechanisms. Because of this, it is important to account for duty cycle when quantifying SCC risks. SCC crack propagation is driven by a combination of growth due to SCC and growth due to low cycle fatigue. For units that are base loaded, LCF would not be expected to contribute much to crack growth.

However, if the unit is experiencing heavy on/off cycling, LCF can be the main driver of crack propagation even if the initial cracking method was SCC. To accurately assess remaining life, an integrated approach to crack propagation calculations must be used.

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Stress corrosion cracking required factors

SCC repair methodology Often SCC cracks are identifiable because of their branching appearance. If cracking is found from SCC, there are a few ways to address it depending on the severity of indications found. The early stage option is removal of local cracks. As a general rule, if the cracks are less than 10 mils deep, they can be polished out. Depending on design and crack locations, cracks of up to 20 mils deep may be able to be removed. It is crucial to ensure any radii added through crack removal is equal to or greater than the original hook fit radius in order to prevent an increase in stress concentration levels. Since the stress intensity of a polished-out area is less than a crack tip and the damaged material is removed creating a clean slate, carefully removing cracks results in improved remaining service life.

Skim cutting can also be an early stage option. However, it is only usable if the cracking is shallow and is usually viewed as a short-term repair. It is necessary to know exact crack depth to assure that recontouring is possible before committing to this method.

If a crack is larger than what can be safely removed, weld repair is generally required. This method is universally used in both fossil and nuclear applications.

All OEMs offer this service which involves removal of the attachment and one of two methods for restoring the blade ring. The first method is to build back up the material with weldment then machine the blade roots into the new material. The second method is to forge a new ring and weld it in place with a fine line process. Either of these methods can allow for reuse of the original buckets or the opportunity for new optimized dovetail geometry. Additionally, there is the opportunity for improved SCC resistance if the new material is of a higher chrome content than the parent material.

May 2018

FEATURES The unit heat balance was used to estimate the steam temperature during operation at the stage where indications were reported.

Stresses at that stage were approximated to be the yield strength of the material. Actual duty cycle data provided operating hours since the last inspection which would have driven crack size through SCC and the stop/ starts since the last inspection which would have driven through LCF. It was found that if the initial reflections had been SCC, the propagation was estimated to be over a tenth of an inch – significantly large enough that the follow up inspection should find it. The UT inspection was completed with additional thoroughness at the location of previously found indications. Findings showed no recordable indications and the previous results were confirmed to not be SCC. However, if cracking was found and was unable to be removed due to time or budget constraints, this same assessment methodology could be used to evaluate the risk of mitigation postponement. â–

Photo 2: Stress corrosion cracking in low pressure blade attachment found by NDE

Long shank replacement involves machining of the blade attachments to a lower diameter in order to remove the damaged material. New dovetail hooks are then machined into the newly cut material.

This method requires machining of new blades that have a longer shank in order to keep the radius the same.

Other options for improvements include shot peening and titanium closing blades.

Shot peening introduces compressive residual stress on the material surface which helps to prevent cracking. If the row design has a closing blade, replacing it with titanium may reduce the stress on the adjacent blades because titanium is less dense than traditional blade materials. However, this may introduce blade frequency concerns.

May 2018

Case study TG Advisers was brought in to assist a client with an updated life assessment of potential SCC on an L-1 blade attachment.

The unit had a prior inspection that found UT reflections which were suspected to be SCC indications. The indications were unusual because FEA modeling of the dovetail showed that they were not in the highest stressed areas. At that time, it was recommended to maintain steam design conditions to ensure the stage did not see wet steam and to re-inspect with UTPA at the next outage.

Before the upcoming outage, a SCC and LCF crack growth assessment was completed to evaluate what size the previously found UT reflections would have propagated to if they were SCC indications.

Rachel Sweigart is a lead consulting engineer at TG Advisers. She has provided life assessment, torsional and fracture mechanic analytical modeling, and troubleshooting services for turbine generators located throughout the country. Sweigart is a mechanical engineering graduate from Lafayette College.

Stephen R. Reid, P.E. is president of TG Advisers Inc. and has more than 29 years of turbine and rotating machinery experience. Reid and his team provide turbine troubleshooting, health assessments and expert witness services to major energy companies in the U.S. and have provided condition assessment evaluations on more than 100 turbine generators in the U.S. Reid also is a short course instructor for EPRI, ASME, Electric Power and POWERGEN, has numerous patent disclosures and awards, and published more than 20 technical papers and articles. Reid was the recipient of the 1993 ASME George Westinghouse Silver Medal Award for his contributions to the power industry and is past chairman of the ASME Power Generation Operations Committee. He is a registered professional engineer in the state of Delaware.

Questions pertaining to this article may be directed to editorial@WoodwardBizMedia.com

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ASME FEATURE

ASME: Rapid H2 purge with CO2 for safer plant operations Test run results Ted Warren, Director of Research & Development, Lectrodryler, LLC Larry Morris, Assistant Plant Manager - Spurlock, East Kentucky Power Cooperative John McPhearson, Chief Executive Officer, Lectrodryer

Abstract Hydrogen cooled generators need to undergo carbon dioxide (CO2) purging before being placed into service and when taken offline.

This process typically takes 4 to 12 hours, and can take as long as 36 hours in extreme cases, to fully and safely purge a generator.

Reducing the volume of hydrogen gas in these generators is essential for reducing the risks of explosions. If these purge times could be shortened, improvements in safety, shorter outages, and increased production could be realized. This paper describes plant testing of a CO2 Fast Degas purging system for hydrogen cooled generators. Results from eight test runs at two different plants are presented in tabular and graphical form.

Mean reduction from pure hydrogen to less than 4% hydrogen was 39.8 minutes, while maintaining CO2 temperatures above 80°F (27°C). This eliminates the possibility of CO2 freeze up, and reduces the stress on the piping and the detrimental effects on the generator from extreme temperature swings that occur when CO2 is de-pressurized.

These rapid purge rates were accomplished while maintaining the generator pressure within a set range. In order to achieve the minimum purge time, it is critical that mixing of the two gases be minimized during the purge operation. By utilizing the slope of the graphs provided, the system was optimized to minimize purge times to reach safe levels.

Tests were performed on both purging operations, replacing hydrogen with CO2 and replacing air with CO2. Samples to analyze the generator gas purity were taken from the vent line using multiple thermal conductivity purity instruments to assure accurate results.

May 9 2018 ENERGY-TECH.com

The system was tested in both automatic and semi-automatic modes of operation. The fast degas system was found to significantly reduce generator purge times, reducing down time, and improve operator efficiency, positively affecting the overall safety profile of the plant.

hydrogen purity. These steps are reversed when taking the generator out of service for scheduled maintenance or emergency. This process is known as purging the generator.

Introduction Large electric generators are cooled with hydrogen due to the physical properties of the gas. Hydrogen has the lowest density and the highest specific heat of any gas, making it well suited for cooling applications. One disadvantage to using hydrogen is its wide explosive range—4% to 75% hydrogen in air [1]. Every precaution must be taken to prevent the hydrogen from mixing with air. To avoid forming explosive mixtures, an inert gas is used as a barrier between the hydrogen and air. The most common inert gas barrier is carbon dioxide (CO2), which is widely available and relatively inexpensive.

Generator startup procedures involve removing air from the generator case by displacing it with CO2. CO2 is denser than air, so it is introduced into the bottom of the generator while the top is opened to the vent, permitting the lighter air to escape. The purity of the exiting gas is analyzed to indicate when the air has been completely displaced. To fill the generator with hydrogen, the flow direction is reversed. Hydrogen is lighter than CO2, so it is introduced into the top of the generator while the bottom is opened to the vent, permitting the heavier CO2 to escape. The purity of the exiting gas is used to indicate when the generator has reached the intended operating

Figure 1: Schematic of the purge process to take a generator offline. Red represents hydrogen. Yellow reprents CO2.

ENERGY-TECH.com 9 May 2018

ASME FEATURE One disadvantage to using CO2 as the purge gas is that the depressurization of CO2 is an endothermic process, causing cryogenic temperatures through the Joule Thompson Effect [2]. When depressurized to atmospheric pressure, CO2 can achieve temperatures as low as -109°F (-78°C).

Under these conditions, dry ice (solid CO2) may form, reducing or even blocking the flow of purge gas into the generator. Furthermore, these cryogenic temperatures may be harmful to piping and generator components. Carbon steel components may become brittle, and widely accepted weld procedures are not intended for applications below -20°F.

Figure 2: CO2 Temperature versus time, EKPC Dale Power Station (8-14-2015)

Figure 3: Percent hydrogen in CO2 versus time at FPL Cape Canaveral, Unit 1 (3-13-2015)

To prevent damage, minimize risk, and reduce dry ice formation, CO2 purging has traditionally been done very slowly. The purging process often takes 4-12 hours, with extreme cases taking 36 hours or longer.

These hours have a significant financial impact through lost revenue and operator expenses, ranging from $10,000 per hour for a planned outage up to $100,000 per hour for an unplanned outage during peak season.

If these purge times could be significantly shortened, improvements in safety, reduced outage times, and increased production could be realized. Access to faster purge capabilities would be invaluable in emergency situations requiring the hydrogen to be displaced quickly (bearing fire, natural disaster, etc.). Furthermore, faster purge capabilities would allow a single work shift to perform purging. This could prevent miscommunication during shift changes—a recognized contributing factor in recent generator accidents.

The purpose of this paper is to present evidence that a hydrogen cooled generator can be purged both quickly and safely by employing the appropriate equipment and procedures. Data presented here is for both CO2 purge steps: taking the generator offline (removing hydrogen) and putting the generator back in service (removing air).

Test data

Figure 4: Percent hydrogen in CO2 versus time at EKPC Dale Station, Unit 4 (8-14-2015)

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Eight tests were performed at two different generating stations using the Lectrodryer CO2 Fast Degas System. The locations were Florida Power & Light Company’s (FPL) Cape Canaveral Energy Center (Cocoa, Florida) and East Kentucky Power Cooperative’s (EKPC) May 2018

ASME FEATURE The purity data from the test runs is shown in Table 1. The generator purge was considered complete and the test concluded when the hydrogen purity reached 4% or lower when coming offline (displacing hydrogen), or when the CO2 purity reach 96% when coming online (displacing air). Previously, purging at Cape Canaveral took an average of 12 hours.

The temperature of the CO2 purge gas was also measured. The outlet temperature from the CO2 Fast Degas System was maintained at 65°F (18°C) or greater during all tests. Figure 2 shows a typical temperature profile of the CO2 during a purge (data from Dale Power Station).

Graphs of the exiting gas’s purity versus purge time are shown in Figure 3 and 4.

These figures can be used to interpret the effectiveness of the purge by analyzing the purity’s slope. By keeping the purity near 100% at the beginning, pure hydrogen is being removed from the generator and minimal mixing is occurring. Once the purity begins to decline, a steeper slope is preferred—this indicates a narrower boundary layer between the CO2 and hydrogen and more effective displacement (less CO2 needed). The graph of testing at Cape Canaveral (Figure 3) reached less than 4% hydrogen (purge complete) within 39 minutes. The tests at Dale Power Station (Figure 4) reached less than 4% hydrogen within 31 minutes.

Conclusion Figure 5: Lectrodry CO2 Fast Degas

Dale Power Station (Clark County, Kentucky).

Cape Canaveral Energy Center is a natural gas fired combined cycle plant, and the data presented here is from units 1, 2 & 3 (265 MW, Siemens 8000H generators). Dale Power Station is a coal fired plant and the data presented here is from unit 4 (80 MW, GE generator). The tests were performed between February and August of 2015 in cooperation with the plant personnel. The generators were on turning gear for these tests.

The results are presented as the percent purity of the exiting gas as a function of time.

The purity measurements at Cape Canaveral were made with two independent instruments, May 11 2018 ENERGY-TECH.com

Siemens Calomat 6s. These instruments measure thermal conductivity relative to calibration span and zero gases to indicate the sample’s purity. The variance between the two instruments was negligible. The purity measurements at Dale Power Station were made with two independent instruments, a portable purity analyzer and a gas density blower. The portable analyzer measured thermal conductivity relative to calibration span and zero gases to indicate the sample’s purity. The gas density blower measures the sample’s density relative to air used in calibration. The variance between the two instruments was negligible.

The data presented supports the claim that generators can be rapidly purged with CO2 by employing the appropriate equipment and procedures (Figure 5). The tests also confirm the ability to purge generators with minimal mixing of the gases. Most generators can be purged in 40 minutes or less by using the same equipment and procedures.

The three tests performed at Dale Power Station used additional equipment to support the purging process. A fully automated system allowed the push of one button to initiate and complete the purge process, going from 98.5% to less than 4% hydrogen in CO2 in approximately 30 minutes. With this configuration, the entire purge process could be done from the control room. Not only does this minimize labor, it removes opportunities for human error (opening/closing the wrong ENERGY-TECH.com 11 May 2018

ASME FEATURE

Table 1: Summary of generator purging at FPL Cape Canaveral and EKPC Dale Power Station.

valves). Furthermore, controlling the purge process from the control room reduces the need to send operators into a hazardous situation to purge the generator in the event of an emergency (bearing fire, natural disaster, etc.) ■

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Editor’s note: This paper, POWER2016-59257, was printed with permission from ASME and was edited from its original format. To purchase this paper in its original format or find more information, visit the ASME Digital Store at www.asme.org.

Acknowledgements The authors acknowledge the following companies for their cooperation and support throughout this investigation.

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nergy tech.indd 1

1. [1] Warren, Peter. Hazardous Gases and Fumes – A Safety Handbook. Elsevier, 1997, p. 96.

2. [2] Burnett, E. S. “Experimental Study of the Joule-Thomson Effect in Carbon Dioxide”, Physical Review Letters, Reviews of Modern Physics, December 1, 1923.

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MACHINE DOCTOR

Steam turbine oil seal rub Patrick Smith, Sheekar S., Air Products & Chemicals

The common causes and associated problems with internal rubs in steam turbines were presented inthe October 2010 Energy Tech article “Steam Turbine Rotor Rubs.” As described in this article, “…A rub occurs when some part of the turbine rotor contacts a stationary component. This

can occur in shaft end seals, interstage seals, inside diameter of bearings, etc.”

Rubs can cause rotor vibration problems for a variety of reasons including a rotor bow due to localized, non-uniform heating of the rotor, excitation of subsynchronous natural frequencies, bearing instabilities, etc.

The purpose of this article is to present a case study of a chronic, intermittent steam turbine vibration problem caused by an oil seal rub. This was a difficult problem to diagnose because many causes of intermittent vibration excursions share common symptoms. In this case, some

Figure 1: Train arrangement

Figure 2: Turbine cross section

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May 2018

MACHINE DOCTOR initial observations led to a possible coupling problem, which was proved later to be incorrect.

Introduction This case study pertains to a 13 stage, 4314 RPM, 54 MW straight condensing turbine that drives an inline compressor on one end and an integrally compressor on the other end. There is a gear type coupling between the steam turbine and the integrally geared compressor, and a flexible disc type

coupling between the steam turbine and the inline compressor. This arrangement is shown in Figure 1. The inlet steam conditions are 35.9 bara and 430°C, and the exhaust conditions are 0.166 bara and 32°C. The entire machinery train is installed in a building.

inlet end bearing housing is also pinned to the casing and both the casing and bearing housing at the inlet end slide axially on fixed surfaces as the steam turbine is heated and grows. The rotor is fixed at the inlet end with a thrust bearing and grows towards the exhaust end.

The steam turbine casing is horizontally split and is fixed at the exhaust end. The inlet and exhaust end bearing housings are separate from the turbine casing, but are aligned to the casing with axial keys. The

The turbine is fitted with elliptical type journal bearings and tilting pad type thrust bearings. The journal bearings are equipped with temperature probes and there are “x” and “y” vibration probes adjacent to each bearing. The thrust bearings are fitted with temperature probes and there are axial position probes adjacent to the thrust bearings. The oil seals are a stationary labyrinth teeth type.

The inlet end and exhaust end gland seals are comprised of stationary J-strips running against a bushing. There is a balance piston on the inlet end which is comprised of alternating rotating and stationary J-strips. A simple cross section is shown in Figure 2.

Note that the control system includes a GE System 1 so that detailed vibration analysis data is available.

History

Figure 3: Trends of Vibration Excursions

The machine train was commissioned and ran for approximately three years without any significant steam turbine mechanical problems. Then, sudden, random steam turbine inlet end radial vibration excursions

Figure 5: Steam Turbine to Integrally Geared Compressor Coupling

Figure 4: Waterfall Plot May 2018

Figure 6: Compressor End of Coupling Guard ENERGY-TECH.com

15

MACHINE DOCTOR started occurring. The excursions would last for approximately 20 to 30 minutes after which the vibration would return to normal levels. A closer look at the trends revealed the following.

2. During the vibration excursions, the “x” vibration would increase to 40 to 54 microns and the “y” vibration would increase to 30 to 36 microns. See Figure 3

1. Since commissioning there had been a gradual increase in inlet end ‘x” vibration from 16 to 24 microns, and an increase in inlet end “y” vibration from 13 to 18 microns.

3. During the vibration excursions, it was observed that the vibration increase was due to an increase in the one times running speed component. See waterfall plot in Figure 4. The phase angle also changed by approximately 30° to 40°.

See Figure 3.

Figure 7: Coupling teeth – Integral geared compressor side

4. There were no process changes at the time of the vibration excursions. The steam turbine was operating at steady state conditions.

5. There were no changes in steam turbine radial bearing temperatures during the vibration excursions. But, the steam turbine axial position would change and the active thrust bearing temperature would increase slightly.

Figure 8: Steam turbine inlet end radial bearing – lower half

6. Also during the vibration excursions, the integrally geared compressor drive end axial position would change slightly and the active thrust bearing temperature would increase by 17°C. The changes in both the inlet end of the steam turbine and the drive pinion of the integrally geared compressor suggested a possible problem with the coupling. During an outage opportunity, the coupling and steam turbine inlet end bearings were inspected.

Figure 9: Drawing showing oil spray and drain orifice on gear-ring

16

ENERGY-TECH.com

Figure 10: Oil spray for geared coupling

May 2018

MACHINE DOCTOR

Figure 11: Vibration trends from one day operation.

Coupling and bearing inspection The coupling guard is fixed to the steam turbine and fits over a ring on the integrally geared compressor side. There is supposed to be a small gap between the guard and the compressor to allow for thermal growth of the guard. However, it was found that this gap was closed and the guard was

contacting the compressor. See Figures 5 and 6. There were also some strange markings on the coupling gear teeth.

Figure 7 is a picture of the teeth from the compressor side of the coupling. Similar markings were observed on the steam turbine end. However, there was no wear detectable wear or damage. These types of markings were not seen before on other gear couplings in similar machine trains.

The inlet end radial steam turbine bearing was inspected and found to be in good condition. See Figure 8. There were some minor indications on the active thrust bearing, but the overall bearing was in good condition and was reused. The compressor to steam turbine alignment was checked and was acceptable.

The coupling guard was cut to increase the cold gap clearance for turbine thermal growth. The steam turbine train was restarted, but the random vibration issues continued.

The information and data was reviewed with both coupling vendor and compressor supplier. With a gear type coupling, good oil supply to the teeth is critical for proper operation of the coupling. Due to the high circumferential velocity, the oil supply nozzles need to be close to the gear teeth and need to be properly orientated to ensure the right amount oil gets into the gear mesh. There are also holes in coupling sleeve for the oil to drain out of the coupling. If these drain-holes are partially plugged, oil can accumulate inside the coupling, which can increase machine vibrations. See Figure 9 and 10.

Figure 12: Oil seal deposits May 2018

ENERGY-TECH.com

17

MACHINE DOCTOR References

During another outage opportunity, the coupling was inspected again. The markings were still present on the gear teeth. The drain holes were inspected and were not plugged. However, the oil spray nozzles on the integrally geared compressor side were not positioned properly. There was not sufficient time to correct the oil spray nozzles during the outage.

Based upon the markings on the gear teeth and the improper position of the oil spray nozzles, it was decided to replace the coupling with a spare and correct the oil spray nozzle orientation. Unfortunately, after replacing the gear-coupling and modifying of oil-spray nozzles, the random vibration spikes persisted.

1. Smith, Patrick J., “Steam Turbine Rotor Rubs”, Energy-Tech Magazine, October 2012 2. Sharma, Pankajkumar, “Vibration Monitoring Identifies Steam Turbine Seal Rub”, Orbit Magazine, Volume 33, July 2013 3. Christofi, Sotirios, “Steam Turbine Seal Rub”, Orbit Magazine, 19 November 2014.

4. © Air Products and Chemicals, Inc. 2018. All rights reserved. This material may not be reproduced, displayed, modified or distributed without the express prior written consent of the copyright holder.

5. Those performing a risk assessment of any given hazardous scenario are responsible for validation of specific hazards and risk estimates used in making management decisions related to personnel safety.

Figure 13: Insulation near steam turbine inlet end bearing

Further problems

Conclusions

About six months after the coupling replacement, there was a step change in the frequency and magnitude of the vibration excursions. See Figure 11, for trends from one day. The vibration levels were fast approaching the trip set point.

Although not discussed several other causes were investigated. These included stuck steam turbine sliding surfaces, turbine hot spots, steam flow instability from the live steam valve, condensate in the seals and other causes. These were investigated and it was determined that none of these likely caused or contributed to the vibration excursions. Although the vibration excursion data was consistent with a light rub, the changes on both the integrally geared compressor and steam turbine, and the coupling gear tooth markings indicated a possible problem with the coupling.

Then, a significant steam turbine inlet end bearing leak developed and it was decided to shut down the train to fix the leak and inspect the bearing. The bearing was fine, but there was significant oil coking in the oil seal. See Figure 12.

A couple of industry references describe problems with intermittent vibration spikes due to deposits in oil seals. See Sharma, Pankajkumar, and Christofi, Sotirios.

When the insulation heat shields at front bearing housing area were removed, some insulation pads were found missing around the sealing steam pipe. During operation, it is likely the heat of the sealing steam pipe and casing transferred to bearing housing and resulted in carbon deposits inside the oil seals. See Figure 13.

Although the symptoms and behavior of these types of intermittent vibration excursions are consistent with several causes, and a coupling problem was incorrectly diagnosed, having the additional vibration data from the GE System 1 was very beneficial in understanding the diagnosing the problem with the oil seal coking and light rubs. ■

THE INFORMATION CONTAINED HEREIN IS BASED ON DATA BELIEVED TO BE ACCURATE AS OF THE DATE COMPILED. NO REPRESENTATION, WARRANTY, OR OTHER GUARANTEE, EXPRESS OR IMPLIED, IS MADE REGARDING THE MERCHANTABILITY, FITNESS FOR A PARTICULAR PURPOSE, SUITABILITY, ACCURACY, RELIABILITY, OR COMPLETENESS OF THIS INFORMATION OR ANY PRODUCTS, MATERIALS, OR PROCESSES DESCRIBED. THE USER IS SOLELY RESPONSIBLE FOR ALL DETERMINATIONS REGARDING ANY USE OF INFORMATION, MATERIALS, PRODUCTS, OR PROCESSES IN ITS TERRITORIES OF INTEREST. AIR PRODUCTS EXPRESSLY DISCLAIMS LIABILITY FOR ANY LOSS, DAMAGE, OR INJURY RESULTING FROM OR RELATED TO THE USE OF OR RELIANCE ON ANY OF THE INFORMATION CONTAINED HEREIN. Patrick J. Smith is a lead machinery engineer at Air Products & Chemicals in Allentown, Pa., where he provides technical machinery support to the company’s operating air separation, hydrogen processing and cogeneration plants.

Questions pertaining to this article may be directed to editorial@WoodwardBizMedia.com

After the oil seal was cleaned and insulation pads were added near the inlet end bearing, there have been no vibration excursions.

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May 2018

APPLIED TECH

Optimizing unit ramp rate

By Merrill Quintrell and Steve Seachman, Electric Power Research Institute

As steam generating units have sought to improve their operational flexibility in today’s energy market, interest has risen in understanding and optimizing unit ramp rates.

If plants are to remain competitive, operators need information and strategies for increasing unit responsiveness, specifically the rate of unit load increase from minimum to full load.

The Electric Power Research Institute (EPRI) recently conducted research to develop a methodology for evaluating and improving unit ramp rate at any steam generating unit.

The research involved reviewing industry experience with unit ramp rate enhancement and methods for revising unit control logic. In 2017, a pilot implementation was performed for a coal-fired, once-through, supercritical generating unit, and the methodology enabled the plant to more than double its previous maximum load ramping rate. In 2018, EPRI will seek to conduct a similar study to improve the load-ramping capability of a combinedcycle plant.

As a consequence, increasingly, steam generating units designed for baseload operation are following system load demand over larger ranges and ramping between loads more frequently. In many cases, however, the operators of these plants have limited experience in providing flexible operations efficiently and reliably without having a detrimental effect on unit life.

One key to improving the operational flexibility of steam generating units is updating plant operations and controls to provide more dynamic response to load changes, consistent with the capabilities of installed equipment and systems. “Ramp rate� is the rate at which an electricity generating unit changes from one power level to another, typically in units of megawatts/minute. This change is typically achieved by controlling the burner firing rate or turbine governor valve position. Fast ramp rates allow more flexibility to power stations

to achieve desired power profiles. These profiles can lead to higher profits from selling electricity in the power market, but they also have associated costs, including fuel cost, emissions cost, and stress on power plant components.

Dynamic operation of steam generating units requires the coordination of a number of systems, equipment, and controls.

Accurate and timely measurement of unit operating parameters under these transient conditions is often a challenge for the installed instrumentation. Control systems, often tuned for stability, not responsiveness to changing operations, may rely on operator action to navigate the changes required. The more rapid the rate of change, the greater the challenge to avoid upsets in the processes for converting the stored chemical energy in the fuel into electrical energy.

Often, existing unit ramp rates were determined when there was limited benefit

The methodology and its pilot demonstration are described in a recent report Unit Ramp Rate Optimization Guidelines: Methodology and Technical Approach (3002011175).

Need for improved ramping The expanding contribution of renewable generation to the power supply has given rise to an evolution in the operation of electrical distribution systems. Renewable portfolio standards promulgated in many states are steadily expanding the generation share associated with renewable generation. The variability of renewable generation, as provided by solar and wind sources, has imposed the need for additional responsiveness from steam generation to support distribution system stability. Competitive pressures are differentiating power generation units based on their responsiveness and generation cost.

Figure 1: Areas to Evaluate to Advance Unit Ramp Rate May 2018

ENERGY-TECH.com

19

APPLIED TECH from ramping operations. The values implemented by the unit controls were based on conservative recommendations from the principal equipment vendors and designed for limited load changes as part of baseload operation. Power plant operators are now recognizing the need to develop unit ramp rates based on the technical capabilities of the installed equipment.

Methodology for improving ramp rate Improvements to ramp rate noted in the literature were achieved through changes to control logic, modification of operating procedures, adjustments in operating limits, and upgrades of equipment. The details of design and operation, as well as unit condition, impact the specific improvement that can be achieved by any specific fossil-fired generating unit. As a result, a methodical approach is required to diagnose and implement individual unit ramp rate improvements.

In improving unit ramp rate, changes can be expected in six areas of unit operation: unit operating limits, operator experience, control loop logic, equipment capabilities, parameter measurements, and reduced-load operating conditions (Figure 1). Changes in one or more of these areas can provide the driver for advancing the unit ramp rate beyond the current limit.

The methodology developed in EPRI research is based on industry experience reported in the literature, specific experience with modifying unit operating conditions, and a pilot implementation of the unit ramp rate methodology.

The methodology involves seven key steps: 1. Define goals. Define project objectives and project starting point.

The documents produced at the end of this step, the Project Charter and the Request for Information (RFI), are intended to support the work going forward.

2. Understand key parameters. Use the data received from the RFI for current condition documents to determine the 20

ENERGY-TECH.com

data points of interest and to develop an RFI for operations data for a recent ramp.

3. Identify potential improvements.

Identify and document poorly controlled parameters in a table of potential improvements.

4. Diagnose ramp rate. Observe multiple ramps, both in the as-found condition, and with changes implemented that test the theories developed in Step 3.

5. Plan implementation. Develop an implementation plan based on the improvement recommendations developed in Step 3.

6. Implement improvement. Implement the improvements and perform a ramp.

7. Evaluate improvement. Gather data to determine the success of the recent changes.

The optimization methodology developed by this research can be applied to any steam generating power plant to provide enhanced ramp rate.

Development of the methodology resulted in the following lessons learned: • Unit control logic. Comprehensive understanding of the unit control logic is vital to diagnosing the limits to the unit ramp rate. The evolutionary nature of the unit control logic makes ramp rate testing a vital tool in developing the necessary changes to increase unit ramp rate.

• Manual operation. Manual operation of specific systems and components will be required during the diagnosis testing to increase the unit ramp rate. Bypassing selected automatic controls is necessary to identifying the control logic responsible for limiting unit ramp rate. Additional operating staff should be provided during the ramp rate diagnosis testing to support the need for expanded manual operation of the unit.

• Personnel biases. Acknowledgement and consideration of personnel biases will be required to successfully examine the technical limits on unit ramp rate.

Developing an understanding of the value of increased unit ramp rate is important in influencing personnel.

• Evaluation. Evaluation time is required between ramp rate diagnosis test runs to develop a complete identification of the step(s) necessary to address roadblocks.

More than one area of the unit operation or control may be simultaneously limiting unit ramp rate.

Pilot implementation and case study A pilot implementation of the methodology was performed at a generating unit, providing a demonstration of the ramp rate optimization methodology through the diagnosis testing step. The pilot test also provided the basis for a case study of the specific improvements necessary to increase the ramp rate of a coalfired supercritical boiler.

The specific findings from the case study of ramp rate diagnosis of a coal-fired supercritical steam generating unit were: • Ramp rate doubling. During the diagnostic testing, the original unit ramp rate was more than slightly doubled.

• Changes to initial conditions. Changes in the initial conditions prior to load changes were important to the improving the ramp rate. These changes included: minimizing the superheat spray flow at the beginning of the load ramp, increasing the bias on the excess O2 trim, firing using the upper mill elevations, and suspending furnace sootblowing at low load.

• Control loops. Permanent implementation of the increased unit ramp rate will require changes to a number of control loops, including updating the mill controls to provide balanced heat input and to minimize heat input spikes, revising the superheater control settings to improve steady state temperature control, and increasing the response rate on a number of control loops, including the ramp rate feedback control loop.

May 2018

APPLIED TECH • Individual steps. Implementation of the control modifications should be performed as individual steps, with provision for additional testing to demonstrate the stability and suitability of each change, prior to implementing the next change.

Additional case studies will be conducted in the future to expand the experience with ramp

rate improvement in other types of steam generating units.

Optimization algorithm In related research, in 2016, EPRI developed a Matlab®-based algorithm to determine the optimal ramp rate for a power plant. The optimization algorithm was designed for power generating units with a

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steam turbine that are participating in the dayahead market (DAM), while taking into account a class of costs associated with ramping.

The inputs to the algorithm included the day-ahead load profile and electricity price signal, as well as numerous parameters relevant to the specific plant of interest.

The algorithm included revenue from the generation of electricity, as well as costs associated with fuel, steam turbine rotor thermal stress, and NOx, SO2, and CO2 emissions. The algorithm and the research that contributed to it are described in the report Determining Optimal Ramp Rates (3002006231).

More recently, the EPRI research team modified the optimization algorithm for generating units participating in the Security Constrained Real Time Economic Dispatch (RTED) market to contribute load balancing on the electric power transmission grid.

This work is described in the 2017 report (3002011175).

Major generating units participating in the DAM may have to, or generally do, participate in the RTED market. Some units also participate in the Regulation market to contribute to the grid frequency control.

All Independent System Operators (ISOs) of electric grids dispatch power of market participating units using the units’ certified and declared ramping capability, as specified by their Load Range and Ramp Rate.

This latest work modified and utilized the concepts of “market distribution function” and “unit flexibility envelope” of a generating unit to probabilistically model, and then evaluate, the expected value of revenue and cost associated with operating in RTED market.

Furthermore, by relating the expected profit of a generating unit to its ramp rate, this work formulated optimizing unit ramp rate for operating in RTED market. ■ Merrill Quintrell is a principal technical leader in EPRI’s Operations Management and Technology Program.

Steve Seachman is a senior technical leader in EPRI’s Instrumentation, Controls, and Automation Program.

Questions pertaining to this article may be directed to editorial@WoodwardBizMedia.com ENERGY-TECH.com

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INDUSTRY SPOTLIGHT

Keeping your cooling system clean

By Brad Buecker, senior technical publicist, ChemTreat

Cooling water systems are critical components at power plants and many other industrial facilities. However, as this author has discovered over several decades, cooling systems and cooling towers are often the neglected children at industrial plants, where frequently most of the focus is on process engineering and chemistry. Then, when a cooling system failure curtails or even shuts down production, plant personnel go into a panic.

slime layer allows anaerobic bacteria underneath to flourish. These organisms generate acids and other harmful compounds that directly attack the metal. Microbial deposits also establish concentration cells, where the lack of oxygen underneath the deposit causes the locations to become anodic to other areas of exposed metal. Metal loss occurs at anodes, with pitting as the result.

Fouling and scaling are the two primary mechanisms of deposition in cooling systems. Particularly troublesome is microbiological fouling. Cooling systems provide an ideal environment, warm and wet, for microbial proliferation. Bacteria will grow in condensers and cooling tower fill, fungi on and in cooling tower wood, and algae on wetted cooling tower components exposed to sunlight.

Biocide treatment is absolutely essential to maintain cooling system performance and integrity.

A major problem with microbes, particularly many bacteria, is that once they settle on a surface, the organisms secrete a polysaccharide layer (slime) for protection. This film by itself will severely inhibit heat transfer, but it also collects silt from the water and grows even thicker, further degrading heat exchange. But, this is just part of the problem. Even though the bacteria at the surface might be aerobic, the

Figure 3. Fouled cooling tower fill.

Fouling control

Figure 2. One example of cooling tower film fill. Various styles from simple to complex are available depending upon the fouling characteristics of the cooling water.

Photo courtesy of Brentwood Industries.

Fouling also will cause significant – and at times devastating – buildups in cooling tower fill. Film fill is common in modern cooling towers, as the large surface area provided by the packing greatly enhances contact between air flowing up through the fill with the cooling water traveling downward.

Fouling disrupts the water-air flow patterns, and may completely plug passageways. In severe cases, deposition has caused structural failure of internal tower components or even complete tower sections.

Figure 1. Under-deposit pitting of a steam condenser tube.

May 2018

Proper microbiological treatment is critical to prevent cooling system fouling. The core of any microbiological treatment program is feed of an oxidizing biocide to kill organisms before they can settle on heat exchanger tubes, cooling tower fill, and other locations. Chlorine was the workhorse for many years, where when gaseous chlorine is added to water the following reaction occurs.

HOCl, hypochlorous acid, is the killing agent, and functions by penetrating cell walls and then oxidizing internal cell components. The efficacy and killing power of this compound are greatly affected by pH due to the equilibrium nature of HOCl in water.

OCl - is a much weaker biocide than HOCl, probably due to the fact that the charge on the OCl - ion does not allow it to effectively penetrate cell walls. The killing efficiency of chlorine dramatically declines as the pH goes above 7.5. Because most cooling tower ENERGY-TECH.com

23

INDUSTRY SPOTLIGHT Chemical

Advantages

Disadvantages

2,2-dibromo-3-nitrilopropionamide (DBNPA)

Fast acting, effective against bacteria, degrades quickly to non-hazardous byproducts.

Degrades quickly above pH 9, not very effective against fungi and algae. Degraded by reducing conditions

Glutaraldehyde

Effective against sulfate-reducing bacteria (SRB).

Incompatible with ammonia and some amines. Weak on algae.

Isothiazoline

Effective against bacteria, particularly nitrifiers, and fungi.

Works well with oxidizing biocides. Active over a wide pH range.

Skin sensitizer. Degraded by sulfide, sulfite, and reducing conditions.

Quaternary amines

Effective against most microorganisms, particularly algae.

Active over a wide pH range.

Can cause foaming. Efficacy reduced by hardness. Interacts with anionic dispersants and fluorescent tracers

Table 1 - Non-oxidizing biocides

scale/corrosion treatment programs operate at an alkaline pH, chlorine chemistry may not be the best choice in some applications. Chlorine efficiency is further influenced by ammonia and organics in the water, which react irreversibly with the chemical and increase chlorine demand.

Due to safety concerns, liquid bleach (NaOCl) feed has replaced gaseous chlorine at many facilities, although bleach is more expensive. Bleach contains a small amount of sodium hydroxide, so when it is injected into the cooling water stream it raises the pH, perhaps only slightly, but if the water is alkaline to begin with, most of the reactant will exist as the OCl - ion.

A popular answer has been bromine chemistry, where a chlorine oxidizer (bleach is the common choice) and sodium bromide (NaBr) are blended in a makeup water stream and injected into the cooling water. The chemistry produces hypobromous acid (HOBr), which has similar killing powers to HOCl, but functions more effectively at alkaline pH. Other alternatives include chlorine dioxide (ClO 2), monochloramine (NH 2Cl), and monobromamine (NH 4Br).

The latter two are weaker oxidizers than the others, but appear to be more effective at penetrating the protective slime layer that bacteria produce, to then directly attack the organisms.

Also to be considered are on-site hypochlorite generating systems, as

exemplified by the MIOX ÂŽ technology, where no oxidizer needs to be stored.

In a recent development, the author has become aware of a new halogen stabilizer/biodispersant that is being offered for those plant personnel who prefer bleach-only oxidizing treatment.

The product itself has no biocidal properties, and thus does not fall under regulatory guidelines, but it helps to stabilize chlorine and reduce losses from irreversible reactions.

Also, the biodispersant portion of the formulation, as its name implies, disperses the biofilm formed by the organisms, improving biocide efficiency.

In many cases, oxidizer feed is limited to two hours per day, which gives microbes time to settle and form colonies during off times of treatment.

A supplemental feed of a non-oxidizing biocide on perhaps a once-perweek basis can be quite effective in controlling biological growth. The following table lists properties of some of the most common non-oxidizers.

Careful evaluation of the microbial species in the cooling water is necessary to determine the most effective biocides. Antimicrobial compounds should not be used or even tested without approval from the appropriate regulating agency. They must be incorporated into the plant’s National Pollutant Discharge Elimination System (NPDES) permit. Also, as with all chemicals, safety is an absolutely critical issue when handling biocides.

Evolving scale/corrosion control methods

Figure 5. Basic structures of important co- and ter-polymers.

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ENERGY-TECH.com

An evolution is underway regarding scale and corrosion control in industrial cooling-tower based systems. For four decades, the most common treatment programs have been based on a core chemistry of inorganic and organic phosphates (aka, phosphonates) that combine with potential scale-forming compounds, and whose reaction products precipitate at anodes and cathodes of metal surfaces to inhibit corrosion. However, of growing concern May 2018

INDUSTRY SPOTLIGHT is the discharge of phosphorus to natural bodies of water, and the effects such discharge has on proliferation of toxic algae blooms. At many locations now, phosphorus discharge is limited if not entirely banned. Also included in discharge regulations is zinc; a common key ingredient in phosphate/ phosphonate formulations for additional

NEW

corrosion inhibition. These restrictions have led to development of alternative, polymer-based programs.

Polymer formulations containing the carboxylate group have been successfully utilized for decades to control calcium carbonate (CaCO 3) scale in cooling water.

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Figure 4. Carboxylate functional group.

However, many other scaling compounds are possible, including calcium and magnesium silicates, calcium sulfate, calcium fluoride, and manganese dioxide, to name some of the most common. The need to combat these and other scale-formers has generated development of co- and ter-polymers, containing more than one functional group.

The polymers inhibit scale formation by two mechanisms, crystal modification and ion sequestration. A low part-per-million residual is often sufficient to inhibit scale formation, but as the figure indicates the choice of polymer or polymer blend is in large part dependent upon the chemistry of the cooling water. That is why, especially for new plants, comprehensive, and ideally historical, makeup water analyses are necessary.

Too often, project designers only receive partial water quality data, which makes it very difficult to select proper treatment chemistry and makeup water treatment equipment.

Enhancements to polymer chemistry have also improved corrosion protection in cooling systems. Particularly effective is a chemical formulation “best described generically as a reactive polyhydroxy starch inhibitor (RPSI).” [1] The chemistry is capable of providing a number of critical benefits in cooling systems, most notably:

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INDUSTRY SPOTLIGHT Corrosion inhibitors such as RPSI contain functional groups that attach to the base metal, upon which the organic components form a passive film. This is much different than corrosion protection in the phosphatebased programs, where the reaction products formed the barrier. These “protective” deposits have limitations, including porosity and a propensity to be washed away by the cooling water flow. Beyond that issue, mistakes in chemical dosage and/or a change in water chemistry have the potential to induce severe deposition, most notably of calcium phosphate. The more recent corrosion inhibitors do not rely on such precipitation reactions.

Brad Buecker is senior technical publicist with ChemTreat. He has 35 years of experience in or affiliated with the power industry, much of it in steam generation chemistry, water treatment, air quality control, and results engineering positions with City Water, Light & Power (Springfield, Illinois) and Kansas City Power & Light Company’s La Cygne, Kansas station. He also spent two years as acting water/wastewater supervisor at a chemical plant. Most recently he was a technical

specialist with Kiewit Engineering Group Inc. Buecker has a B.S. in chemistry from Iowa State University with additional course work in fluid mechanics, energy and materials balances, and advanced inorganic chemistry. He is a member of the ACS, AIChE, ASME, NACE, the Electric Utility Chemistry Workshop planning committee, and the Power-Gen planning committee.

Questions pertaining to this article may be directed to editorial@WoodwardBizMedia.com

Conclusion Keeping cooling systems clean is of major importance at power plants and industrial facilities. The consequences of poor chemistry control can be fouling and corrosion that cost a plant much money in efficiency losses, or may even result in lost production due to equipment failure. New technologies have been and continue to be developed that improve upon fouling, scaling, and corrosion control. ■

References 1. R .M. Post, P.E. and R.P. Kalokodimi, Ph.D., “The Development and Application of NonPhosphorus Corrosion Inhibitors for Cooling Water Systems”; presented at the World Energy and Environmental Congress, Atlanta, Georgia, October 26, 2017.

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