March 2015

Steam turbine valves 10 • Backup oil systems 15 • Thrust collar wear 27

ENERGY-TECH

MARCH 2015

A WoodwardBizMedia Publication

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Dedicated to the Engineering, Operations & Maintenance of Electric Power Plants In Association with the ASME Power Division

Treating cooling tower water

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FEAtUrEs

6

By Brad Buecker, Energy-Tech contributor

10

Aspects of steam turbine valves: Materials, operations and maintenance

By Kuda R. Mutama Ph.D., TS Power Plant, Newmont Nevada Energy Investments

CoLUMNs

15

Maintenance Matters

Best practices for testing, inspecting and maintaining backup oil systems

By Grant Lanthorn, Electric Power Research Institute

27

Machine Doctor

Thrust collar wear in an integrally geared turbocompressor

By Patrick J. Smith, Energy-Tech contributor

AsME FEAtUrE

18

Role of boiling mode and rate in formation of waterside deposits in HRSG evaporator tubes

By David S. Moelling, PE, and James Malloy, Tetra Engineering Group Inc.

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Cooling tower water treatment challenges

iNdUstrY NotEs

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Editor’s Note and Calendar Advertisers’ Index Energy-Tech Showcase

oN tHE WEB Explore Energy-Tech’s new website at www.energy-tech.com. Same excellent information with better navigation. Send your feedback to Andrea Hauser at ahauser@woodwardbizmedia.com.

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MARCH 2015

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Editor’s Note

Springtime start-ups and plans Fresh changes at Energy-Tech.com and in upcoming events Are you ready to put away the shovels? Are you tired of the heavy jackets, hats and gloves needed to brave the single-digit temperatures?

March seems to be the longest, coldest month in the Midwest. It is the only time of year that I question my love of the four seasons, since spring seems to take its time arriving.

But I don’t need to look very far to find the fresh changes I need to get through this final chill – www.energy-tech.com is a great place to start since we debuted our redesigned website in mid-February. I know you might be thinking, “You’ve seen one website redesign, you’ve seen them all.” But this project was a long time coming, and I’m very glad to finally have better navigation tools and resources for our readers online. For example, Energy-Tech’s library of technical webinars is easier to browse, our latest issue articles are front and center and our ability to share articles via social media is effortless.

If you haven’t visited the new site yet, check it out – www.energy-tech.com – and let me know what you think of our new look.

I’m also excited about our first webinar course of the year, Cooling Water Solutions for Power Plant Professionals, on April 28-29 with Brad Buecker and Ray Post. This is a four-hour training event open to anyone wanting to learn more about new water treatment and chemistry issues, including using gray water, new biocide and scale/corrosion treatment programs and zero liquid discharge.Visit https://etu-coolingwater.eventbrite.com to learn more and sign up.

Finally, Energy-Tech will be at Electric Power in Rosemont, Ill., April 21-23.Visit Booth #148 to say hello – we love meeting readers and getting feedback on the magazine.

Our readers’ feedback and engagement makes all the effort behind Energy-Tech worthwhile. Thanks for reading and I hope we see you in the coming months.

Andrea Hauser

4 ENERGY-TECH.com

CALENDAR March 23-27, 2015 Basic Machinery Vibrations (BMV) Knoxville, Tenn. www.vi-institute.org April 19-21, 2015 2015 IEEE Rural Electric Power Conference Asheville, N.C. www.ieee.org/conferences_events April 21-23, 2015 Electric Power Conference & Exhibition Rosemont, IL www.electricpowerexpo.com April 28-29, 2015 Cooling Water Solutions for Power Professionals webinar www.etu-coolingwater.eventbrite.com May 11-15, 2015 Advanced Vibration Analysis (AVA) Houston, Texas www.vi-institute.org June 15-19, 2015 Rotor Dynamics and Modeling (RDM) Syria, Va. www.vi-institute.org June 28-July 2, 2015 ASME Power & Energy 2015 San Diego, Calif. www.asmeconferences.org/powerenergy2015 Sept. 21-25, 2015 Machinery Vibration Analysis (MVA) Salem, Mass. www.vi-institute.org Oct. 12-16, 2015 Balancing of Rotating Machinery (BRM) Knoxville, Tenn. www.vi-institute.org Nov. 30-Dec. 4, 2015 Advanced Vibration Control (AVC) Houston, Texas www.vi-institute.org

Submit your events by emailing editorial@woodwardbizmedia.com.

MARCH 2015

Call For Presentation-Only Abstracts! Deadline: May 12, 2015

JUNE 28-JULY 2, 2015 SAN DIEGO CONVENTION CENTER | SAN DIEGO, CALIFORNIA | GO.ASME.ORG/POWERENERGY

ENERGY SOLUTIONS FOR A SUSTAINABLE FUTURE In 2015, four of ASME's major conferences come together to create an event of major impact for the Power and Energy sectors: ASME Power & Energy 2015. Fossil and nuclear power generation, solar, wind, fuel cell applications and much more will be discussed in each of the four concurrent conferences within this larger event.

The ASME Power Conference delivers the very latest power engineering solutions in plant operations, maintenance and construction with cuttingedge technology.

The ASME Conference on Energy Sustainability is the world class exchange of innovative technology and R&D efforts that offer a path to renewable solutions.

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The ASME Nuclear Forum presents the most recent developments in the Nuclear Power industry.

Call For Presentation-Only Abstracts!

Demonstrate your involvement in this critical industry by submitting your presentation-only abstract (for oral or poster presentation) to a track within the events above. In addition, we welcome case studies and real world applications/ best practices. ASME’s Power & Energy event is the can’t miss event in 2015.

Visit go.asme.org/powerenergy for full track listings and submission details.

Presentation-only abstracts are due May 12, 2015!

SPONSORSHIP & EXHIBITION OPPORTUNITIES ARE LIMITED, SO ACT NOW! GO.ASME.ORG/POWERENERGY About ASME For more than 100 years, ASME has successfully enhanced performance and safety for the energy and piping industries worldwide through its renowned codes and standards, conformity-assessment programs, training courses, journals, and conferences – including the Offshore Technology Conference (OTC), the International Conference on Ocean, Offshore and Arctic Engineering (OMAE), the International Pipeline Conference (IPC), and Turbo Expo.

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FEATURES

Cooling tower water treatment challenges

By Brad Buecker, Energy-Tech contributor

For the many new combined-cycle power plants being constructed in the U.S., cooling towers – or in some cases air cooled condensers – are the choice for plant cooling. Keeping cooling towers free (or relatively so) from microbiological deposits, scale deposition and corrosion has always been challenging. Now, many plants either voluntarily or by mandate are using less-than-pristine water for makeup. A common source is municipal wastewater treatment plant effluent. These supplies often introduce a number of additional impurities to cooling tower makeup, including the microbiological nutrients phosphorus and ammonia, organics and suspended solids. The discussion in this article also in large measure applies to cooling towers in other industries.

A review of some cooling tower basics To quote an excellent reference manual on cooling towers, “Evaporation is utilized to its fullest extent in cooling towers, which are designed to expose the maximum transient water surface to the maximum flow of air – for the longest period of time.” [1] If cooling was only a result of sensible heat transfer, then cooling towers would be enormously large due to mas-

sive air flow requirements.

Evaporation is the key to heat transfer. As air passes through a cooling tower, it induces evaporation. For water to evaporate, it must consume a large amount of energy to change state from a liquid to a gas. This is known as latent heat of vaporization, which at atmospheric conditions is typically around 1,000 Btu/lb.

Perhaps only 2 percent or so of the incoming water evaporates in the tower, but that is quite sufficient to lower the temperature of the return water to the condenser and other heat exchangers.

Critical to maximum efficiency in a cooling tower is intimate contact between the warm inlet water and the air flowing through the tower.

Space limitations prevent a detailed discussion of tower internals, but one technological achievement that has greatly improved heat transfer is film fill, as shown in Figure 1.

Figures 2a, 2b and2c (top to bottom).

As the name film fill [2] implies, layers of this materi- Fouled cooling tower fill. al, placed between the inlet water sprays/distributors and the air rising from below, cause the water to form a film on the material. The filming water exposes much surface area to the air. Fill varieties vary from open splash fill to high-efficiency film fills with very torturous pathways.

Water quality plays the leading role in the type of fill that is appropriate, but in all cases water chemistry must be properly monitored and maintained to prevent upsets. Microbes, and bacteria in particular, love warm and wet spaces to form colonies.

Bacteria, as a protective mechanism, secrete a sticky polysaccharide coating (slime) that traps silt and other debris in cooling water. Entire sections of fill may become completely plugged, greatly reducing heat transfer. Furthermore, the deposits add so

Figure 1. One of many styles of cooling tower film fill. Photo courtesy of Rich Aull, Brentwood Industries.

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MARCH 2015

FEATURES much weight to the packing that structural failures also might result.

Condensers are another ideal location for propagation of bacterial colonies, and in areas of the cooling tower exposed to sunlight, algae growth might be very problematic. Within the tower itself, fungi also can be a significant issue, particularly in wood cooling towers.

Regardless of the potential fouling mechanisms, at any plant with a cooling tower, and especially if extra nutrients arrive with the makeup water, microbiological control is of utmost importance. Common for many towers has been bleach or bleach-activated bromine feed, since bleach is safer, albeit more expensive, than gaseous chlorine. However, ammonia and organics in incoming makeup will consume chlorine, partially or fully destroying the residual concentration that is needed to keep cooling systems clean. In addition, the chemistry might form halogenated organics, which also are unwelcome. Alternative treatments are becoming more popular. One such alternative is chlorine dioxide (ClO2), where generation methods have been greatly improved from the former sodium chlorite (NaClO2)chlorine reaction, and in which large quantities of hazardous sodium chlorite had to be stored on-site. One of the new pro-

Join Brad Buecker and Ray Post for their online technical course, Cooling Water Solutions for Power Plant Professionals, April 28-29. Register at www.etu-coolingwater.eventbrite.com. cesses utilizes a compact generator that combines sodium chlorate (NaClO3) with a pre-mixed blend of sulfuric acid (H2SO4) and hydrogen peroxide (H2O2) to induce the following reaction: Equation 1

Chlorine dioxide does not react with ammonia, nor does it react with organics to form halogenated organic compounds.

Also, and unlike hypochlorite, chlorine dioxide is not affected by pH. This can be an important advantage in those towers (the majority) whose chemistry programs operate in an alkaline pH range.

Some plant personnel have had good success with on-line hypochlorite-generating systems, such as the MIOX process, which via brine electrolysis produces a hypochlorite solution that also contains residual hydrogen peroxide. An advantage of this technology is that the oxidant is produced on an as-needed basis, rather than being stored in large tanks where it can degrade and lose strength.

A precise feed of monochloramine (NH3Cl) also can be effective. This product is much weaker than a free oxidant, but that very property allows it to penetrate slime layers and attack the microbes underneath. Free halogens are typically consumed by the slime layer. The one potential drawback to monochloramine is that it introduces ammonia-nitrogen to the cooling

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FEATURES tion. This chemistry can be effective, but it requires very close monitoring and control to prevent upsets. Accordingly, the major water treatment chemical companies developed sophisticated chemical feed/control systems for phosphate/ phosphonate programs. However, another issue has arisen that is becoming critically important in many areas. With this chemistry, cooling tower blowdown obviously discharges phosphorus in the form of phosphate (PO4). Phosphorus is a primary nutrient for aquatic organisms, including toxic algae and cyanobacteria. [2] Many receiving bodies of water are now considered to be “phosphorus-impaired,” which means that discharges from new plants might be severely limited when it comes to phosphorus concentration. So essentially two choices are available, treat the plant wastewater, perhaps even to zero Figure 3. Common active groups on the polymers being developed for non-P cooling water treatment programs. [2] liquid discharge, to remove impurities, or employ an alternative cooling tower treatment program. With regard to the latter, researchers are working diligently to perfect non-phosphorus (non-P) programs, and some products have been very successful in full-scale applications. The new programs are based on polymer chemistry, where the polymer chains might contain several of the active groups, as shown in Figure 3.

The polymers serve as crystal modifiers and sequestering agents to inhibit scale Figure 4. Schematic of a membrane bioreactor. formation. There also is evidence that the polymers form a thin coating on metal water. If ammonia is limited in the plant’s wastewater discharge surfaces to inhibit corrosion.

A common dosage concentration permit, this treatment method might not be allowed. is 2-10 ppm active in the cooling water. In some cases, an all-P A mechanical treatment technology that is highly recomprogram might be less expensive than an equivalent phosphate/ mended for cooling towers is sidestream filtration. I often see phosphonate program, although every potential application must requests-for-proposals (RFP) that call for direct makeup water [3] be carefully evaluated. filtration. Developers and owner’s engineers often do not recogEven a change to this type of program still does not prevent nize that cooling towers are superb air scrubbers, and that many problems that can occur due to introduction of impurities from particulates are introduced to cooling water by the scrubbing reclaimed water sources. Phosphorus, ammonia and organics are action. Makeup water filtration does nothing to control airborne three of the most potentially troublesome contaminants, and it particulates. A wide variety of technologies are available for sidemight be necessary to remove these impurities upstream of the stream filtration, ranging from conventional multi-media filters cooling tower. to automatic backwash systems with metal screens.

This brings us to an extremely important development regarding general chemistry control in cooling towers.

The phosphorus conundrum For more than three decades, the most common cooling tower methodology has utilized a blend of organic and inorganic phosphates for primary scale and corrosion control, along with a polymer for calcium phosphate scale prevention, and perhaps a small dosage of zinc for additional corrosion protec8 ENERGY-TECH.com

Cooling tower makeup water treatment techniques The extremely well-established technology of clarification might be employed to remove phosphorous and suspended solids from makeup. Common iron or aluminum-based coagulants will remove virtually all phosphorus as a phosphate precipitate. If the raw water contains high hardness and alkalinity, a softening clarifier might be appropriate to reduce these constituents and minimize scale-formation potential before the water reaches the MARCH 2015

FEATURES Engineering and Design Company, Lenexa, Kan. The group provides tower. Lime [(Ca(OH2)] and soda ash (Na2CO3) are the comwater/wastewater and air pollution control engineering and consulting mon chemicals for this process. services. He has more than 33 years of experience in, or affiliated with, If the raw water has a significant ammonia concentration, the power industry, much of it in steam generation chemistry, water then additional treatment might be required. A technology that treatment, air quality control and results engineering positions. He has a bachelor’s degree in chemistry from Iowa State University, with additional is becoming increasingly popular for reclaimed water treatcourse work in fluid mechanics, material and energy balances, and ment is biological processing of the plant intake. Bioreactors advanced inorganic chemistry. He is a member of the ACS, AIChE, and membrane bioreactors (MBR) are two technologies in this ASME, CTI and NACE, the ASME Research Committee on Power Plant regard. & Environmental Chemistry and the program planning committee for the Electric Utility Chemistry Workshop. You may contact him by emailing Via microbes that are seeded and allowed to grow on editorial@woodwardbizmedia.com. internal devices within the reactors, the incoming organics and nutrients are consumed. The MBR outlined in the basic schematic above employs an anoxic zone (oxygen concentration is limited) and an Y O U R C O M P L E T E S O U R C E F O R P R O C E S S B A L L V A LV E S aerobic zone to process the incoming wastewater stream. The final step, which might be external or internal, is filtration to minimize ™ TSS discharge. With membrane bioreactors, where the membranes are of the micro- or ultra-filter variety, effluent turbidities might • 2- piece, 3-piece, multi-port, sanitary, flanged, Direct Actuator Mount be below 0.1 NTU (nephelometric turbidity Ball Valves thru 12” full port units). This is quite satisfactory for general • API-607 Firesafe plant makeup, and even is suitable for feed to reverse osmosis units that produce high-pu• TA-LUFT environmentally friendly stem packing design rity makeup for the steam generator. The • FM-Approved Safety Shut-off Ball Valves waste activated sludge might be very benefi• Metal Seat, High Temperature cial and – from my own experience with an • V-port and segment control valves activated sludge plant – this material can be • Direct mount Electric and Pneumatic Actuation Packages spread on farm fields as a fertilizer.

• Numerous Seat Materials

Conclusion The items outlined above represent just some of the developments for improving cooling tower operation and efficiency. For more information, I invite you to investigate the Cooling Technology Institute website, www.cti.org. Another excellent forum for power plant chemistry learning is the annual Electric Utility Chemistry Workshop, www.conferences.illinois.edu/eucw. ~ References 1. J.C. Hensley, ed., Cooling Tower Fundamentals, 2nd Edition;The Marley Cooling Tower Company (now part of SPX Cooling Technologies, Overland Park, Kansas), 2009.

2. Post, R., and B. Buecker, “Power Plant Cooling Water Fundamentals”; pre-conference seminar for the 33rd Annual Electric Utility Chemistry Workshop, June 11-13, 2013, Champaign, Illinois.

3. Verbal conversation with Ray Post, PE, ChemTreat.

Brad Buecker is a process specialist in the Process Engineering and Permitting group with Kiewit

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FEATURES

Aspects of steam turbine valves: Materials, operations and maintenance

By Kuda R. Mutama Ph.D., TS Power Plant, Newmont Nevada Energy Investments

developed to match new boiler steam temperatures.

Valve components such as stems and seats are greatly affected if the right alloys are not used. Nickel based alloys are promising to be Figure 1. Formation of scale growth with time adequate but are expenfor 12Cr valve parts compared to Stellite bush sive.Valve heads, stems, and Incolloy stem (From Toshiba) seats and bushings should be oxidation resistant and also resistant to contact or sliding wear during operation. Weld deposition of thick layers of wear resistant material as an overlay coating for valve stems and bushings is a cheaper way to retrofit or repair existing valves.

The trend for valve materials is to use nitride material, Incolloy 901, and nitrided 422 stainless steels for stems and bushings to reduce oxide scale build up. Boiler exfoliation from superheat and hot reheat tubes present a challenge to valves and often require that valve stems be equipped with nitrided materials and also chrome-carbide-coatMetallurgical considerations ed materials. Stems can also have a of steam turbine valves Visit our updated website for more Stellite weld overlay for protection.

Materials used in the manufacture Wear and oxidation resistant materials articles on turbines and valves at of steam turbine valve components are used in bushings because of the have to withstand many stress cycles www.energy-tech.com. close tolerances between the stem of steam flow, pressure and temperaand bushings. Figure 1 shows advanture changes. Operating pressures tages of using Incolloy stems and Stellite bushings to reduce and temperatures have increased for new power plants oxidation growth over time, compared to conventional 12Cr in both subcritical and ultracritical units. Plant loads alloys currently used in valve parts.

Nitriding provides a thin, now go up and down continuously on a daily basis. hard wear and oxidation resistant layer to protect valve bushings.

Materials have to be reliable and resistant to General Electric uses Nitralloy 135M – (135M Nitrided), oxidation, solid particle erosion (SPE) and AISI Type 410 Stainless Steel – Nitrided, AISI Type 422 be able to withstand excessive mechanical Stainless Steel – Nitrided, Incolloy 901 – Nitrided, 347 Stainless stresses for long periods of time. More Steel for steam turbine valve bushing material and Stellite linplants are getting retrofitted with ers.

Siemens uses similar materials, including AISI Type 422 better alloy materials on their Stainless Steel, Refractaloy 26 – Nitrided and G18B – Nitrided. valves to extend inspection It is common to use the same alloys for valve bushings and cycles. stems. The 347 SS has high chrome (17-19 percent) and nickel The 9 – 12 percontent (9-13 percent) in it and the G18B alloy is typically cent Cr martensitic 13Cr-13Ni-10Co-3Nb-2.5W-2Mo. A typical metallurgical alloy steels, were Failure to properly composition of Incolloy 901 is C 0.1, Mn 1.0, Si 0.6, Cr 11.0ground rotating 14.0, Ni 40.0-45.0, P 0.03 max, S 0.03 max, Mo 5.0-7.0, Ti equipment can result in 2.35-3.1, Co 1.0 max, B 0.010-0.020, Cu 0.5 max, Fe balance. expensive bearing, seal, & Refractalloy contain the same elements, but has a high cobalt content of 18-22 percent and a chromium content of 16-20 gear damage. percent. Inconel 718 has a much higher nickel content of SOHRE TURBOMACHINERY® INC. 50-55 percent and a high chromium content of 17–21 percent.

The objective of this paper is to review steam turbine valves from the materials used, operations and maintenance. There have been a few incidents of turbine overspeed events caused by valves failing to close, or due to the failure of the overspeed protection mechanism. The weak link still remains the main steam valves. If valves fail to close due to sticking or failing to seat completely, even if the turbine trip mechanism operated properly, a turbine overspeed event will still occur. According to FM Global, their clients experienced 17 steam turbine overspeed events between 1989-2008, with great financial losses due to property damage. In South Africa in 2011, Escom’s 600 MW Unit at Duvha Power Station experienced an event that was very catastrophic. The irony of this event is that it occurred during turbine overspeed testing. Information of these events is not readily available. The published data are usually very limited or guarded. The focus of this paper will be to review and discuss ways of preventing steam turbine valve failures from materials of construction, maintenance and operational considerations.

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FEATURES These alloys have very high tensile and yield strength at high temperatures of 1,050°F or more.

Oxide scale thickness is much smaller for a Stellite inlay bushings, than a nitrided AISI Type 422 stainless steel bushing. A combination of Incolloy 901 stem and Stellite inlay bushing gives excellent oxide growth resistance and reliability, and enables plants to increase maintenance intervals from the two-year cycle to four years, or even longer. Toshiba has been promoting the use of Incolloy stems and Stellite inlay bushings to its customers for a number of years, as Figure 2. Reheat intercept valve showing buildup Figure 3. MSV with excessive oxidation after two years shown in Figure 1. Allowed clearances in bushings are order to increase reliability and time between valve inspections. very small (typically 0.010˝-0.018˝) and with time can be conIncolloy 901 stems, 422 stainless steel, solid Stellite and weld sumed by the oxidation layer. build-up Stellite bushing materials made out of AISI are being Steam turbine valve seat materials should have excellent used. Other choices include Alloy 718 for stems and solid or resistance to galling, wear, oxidation and thermal expansion.

A welded Stellite inlay is used to satisfy the anti-galling and wear requirements. Typical steam turbine valve seat materials are 1C-1Mo-0.25V, 2.25Cr-1Mo, AISI Type 316 H, AISI Type 347 SS, Stellite 6 weld inlay at contact points. Low alloy ferritic steels, stainless steels and cobalt-based super alloys also are used for valve seats, including 316 SS and 347 SS for higher temThe Topog-E perature applications. Stellite 6 material is a cobalt-based and Gasket Company wear-resistant alloy that include the following Stellite 1, Stellite 12, Stellite 21, Haynes alloy 6B and Tribaloy T-800. Stellite 1, 6 produces gaskets and 12 are made from cobalt-chromium-tungsten. These mateto fit every boiler in rials have excellent self-mated anti-galling properties, good wear resistance and high hardness and form a leak tight seal. ASTM production today.

A217 and ASTM A356 specifications are used for turbine and Topog-E® Series valve casing and these are cast materials; 1.25Cr-0.5Mo Grade 180 molded rubber Applications: WC6 and the 2.25Cr-1Mo Grade WC9. ASTM A356 covers • Steam pressure • Compressed air carbon steel, CrMo steels and CrMoV steels at various grades. gaskets are special vessels tanks Typical composition of valve casing materials (Cr-Mo-V) for • Hot water heaters • Filtering units for many reasons.

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Many power plants are performing 1224 North Utica | Tulsa, OK 74110 T: 918-587-6649 | E: info@topog-e.com steam turbine valve W: www.topog-e.com material upgrades in Figure 4. Pressure seal head for RSV showing crack MARCH 2015 ENERGY-TECH.com

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FEATURES valves will not stick during normal and emergency shutdowns.

Units with multiple valves allow for full valve testing from 100 percent open to fully closed. For single valve combinations, valves are slightly closed during testing. Recommended practices should be followed at all times to include (i) testing all the valves once a day, i.e. MSVs, CVs, RSVs and IVs and (ii) inspection of all turbine valves on a daily basis, including extraction non-return valves for any sign of malfunction. On an annual basis, conduct the overspeed trip test and checking valve position on the control system HMI. When shutting down a unit, it is good practice to bring the control valve completely closed and verify that no steam is entering the turbine before tripping the unit. Operators and engineers should review all steam turbine generator and auxiliary logs to identify any abnormal conditions.

In some plants that use austenitic steels for superheat and reheat tubes in boilers, such as types 304, 310, 320 and 347H, it is common during startup following a long shutdown to have boiler exfoliated magnetite carried over through the valves to the turbine. Boiler exfoliated material should be purged before the plant is allowed to go on-line to prevent damage to the steam turbine and its valves.

Figure 5. Lever type actuator valve arrangement (From REXA)

welded Stellite 6 for bushings. The cheaper options involve nitriding and surface anti-galling and wear protection techniques. Stellite weld metal cracking and failure of the seat and disc weld inlay might happen with time in some cases.Valve parts made of solid alloys for high temperature and anti-oxidation application are better.

Steam turbine valve operation practices Well trained steam turbine generator operators are a vital part of a power plant. It is the responsibility of the owner to operate the equipment within specified parameters. Plant personnel should be trained and educated on the safe and efficient operation of steam turbine equipment; for startup, shutdowns, emergencies, normal situations and best practices.

Steam turbines can have one stop valve with one control valve, or two to four main stop valves with several control valves for large machines. Control valves work for full arc admission or in partial arc admission for the introduction of steam to the turbine. At partial load the turbine can operate at partial arc steam admission, and at full load operate at full arc admission.

The current trend is to operate with valves wide open (VWO) with the boiler matching the steam pressure and flow that the turbine requires at that load. In these situations, special provisions have to be made to test these valves periodically so that 12 ENERGY-TECH.com

Maintenance of valves Most valves that are manufactured from less advanced materials are on a two-year inspection cycle that involves complete disassembly, examination, restoration of parts and clearances between bushings and stems, and finally reassembly and recalibration of valve stroke or movement. Steam turbine valves made from newer and more advanced material or coatings are on a four- or six-year maintenance or inspection cycle. These valves employ alloy material discussed earlier, such as Incolloy 901 and Stellite or equivalent.

A valve inspection should employ all methods of nondestructive examination (NDE) to look for damage in parts. The examination should include inspection for defects, foreign deposits on valve strainers, contact areas, bushings, wear on sliding parts, seizure, the cross head, pin, bolts and nuts, valve stems, cracks, inner bypass valve and signs of cracks and defects in the valve body, especially in the welded portions. Figure 2 and 3 show excessive blue blush or oxide scale buildup on an intercept and main stop valve disc after two years of service.

Valves degrade due to the following (EPRI Study), (i) sticking to the valve seat; excessive pull-out, (ii) wear of the seating surface, (iii) disc separation from the stem – broken stem, (iv) excessive friction – corroded stem and oxide growth on valve internal parts in fossil plant applications, (v) bent stem, (vi) loose linkage, (vi) changes in the spring – rate change and preload change, (vii) stem misalignment, (viii) short travel – linkage maladjustment and foreign material on valve seat preventing closure and (ix) localized stem wear Repair damage to stems, valve seats or other parts where possible. Machining or grinding might be involved before welding, followed by smoothing out the surface to the required finish after the welding repair. Replace valve parts if damaged beyond repair.

MARCH 2015

FEATURES Valve actuators should last at least four to five years before Case discussions any major maintenance becomes necessary. During a scheduled The 242 MW TS Power plant has steam temperatures of annual overspeed test in 2012 at TS Power Plant the MSV 1,055°F for both superheater and reheater, with pressures of valve failed to close, even though the turbine had tripped. The 2,415 psi and 582 psi for the HP and IP turbine respectively.

MSV valve was at 23 percent open following the turbine trip, It utilizes type 347H stainless steel tubes both superheater and then went down to 8.1 percent open after more than 24 hours reheater. Magnetite exfoliation was a problem for some time.

(Figures 6 and 7). The CV and the RSV/IV shut the flow of The main stop and control valve (MSV/CV) and the reheat steam completely and prevented the turbine from spinning out and intercept valves (RSV/IV) are combined valves respectiveof control. A review of the historical operating data going back ly. The boiler is in sliding pressure mode with steam turbine six months revealed that the MSV had not been closing comvalves operating wide open (VWO). The valve inspection is on pletely during the previous trips. In all cases, the CV prevented a two-year maintenance cycle. The second inspection on these steam turbine valves, like the first, showed an excessive blue blush layer, or oxidation, ® on valve parts (Figures 2 and 3). The second valve inspection also showed a cracked seal weld on the intercept valve seat and the pressure seal head for the reheat stop valve bushing, as shown in Figure 4. A summary of the first inspection of these valves is given

by Mutama, 2011.

A decision was made to upgrade the valve stems and bushings to use Incolloy and Stellite material at the next valve maintenance in 2014, which also coincides with the first steam turbine and generator inspection outage. Upgrading to superior valve material will alleviate the situation for plants operating at temperatures above 1,050°F. 90° Prism & • Sharp, Clear Photos & Video Close-Focus • Large 5-inch LCD Monitor Steam turbine valve actuator tips available!

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FEATURES

Figure 6. After plant trip MSV remained open (trace 7)

Conclusions This paper has presented ways of preventing steam turbine valve failures from materials of construction, maintenance and operational considerations. New oxidation resistant alloys that withstand impact damage due to solid particle erosion should be used in stems and valve bushings for valve reliability and extended maintenance cycles.

Training of operating personnel also should take priority for power plants to allow only qualified individuals to operate them.

Maintenance of valves should follow strictly the manufacturer’s recommendations and schedules.Valve actuators and EHC oil skids also need special attention because of the increased incidences of failures. The maintenance cycle of these actuators should now be the same cycle as the valve. Heavy duty actuators for high cycle applications should be developed. New superior valve materials result in safe, reliable and profitable power plants in this competitive deregulated power industry. ~ Acknowledgements The author would like to thank NNEI for permission to present this work and Toshiba International Company for their technical support on valve upgrade improvements 2008-2012.

Figure 7. After plant trip MSV remained 8.1% open

the turbine from overspeeding. It was discovered that the MSV actuator had spring discs that had completely rusted or corroded, causing the actuator to fail, as shown in Figure 8. The MSV actuaFigure 8. MSV actuator springs showing excessive tor was later rebuilt. corrosion after only 5 years in service This was a very close call for the plant.

The lesson from this is to inspect actuators at the time of valve inspection, even though there might not be any sign of trouble.

Many plants are now on an aggressive rebuilding schedule to avoid incidences like this.

14 ENERGY-TECH.com

References 1. TS Power Plant Valve Inspection Reports; 2010 and 2012 2. Mutama K.R., Steam Turbine Valve Testing, Inspection and Maintenance to Avoid Turbine Overspeed Events; Proceedings of ASME 2011, Power2011-55150 3. Toshiba Valve Upgrade - On site Promotions 4. Annon. Steam Turbine Failure During Overspeed Test; Eskom Duvha Unit No. 4; 9 February 2011 5. Boyd Davis; Steam Turbine Overspeed Trip Systems, posted on the Web 6. EPRI Report: U.S. Steam Turbine Valve Metallurgy Guide; 1016786, Final Report, March 2009 7. Special Metals Corporation; Product Handbook of HighPerformance Alloys Part 1 pages 2-34.

8. Specials Metals Corporation; Nimonic alloy 901 Editor’s note: A version of this paper was presented during the 2013 ASME Power Conference, PWR2013-98289. You may purchase the full paper at www.asme.org.

Dr. Kuda R. Mutama Ph.D., is the engineering manager for TS Power Plant, part of Newmont Nevada Energy Investments, where he is responsible for plant technical support for operations and maintenance, capital and special projects and improvements, NERC Compliance Program, Outage Planning. He has a Ph.D. from the University of British Columbia, Canada, a master’s degree from the University of Manchester, England, and a bachelor’s degree from Leeds University, England. You may contact him by emailing editorial@woodwardbizmedia.com.

MARCH 2015

Maintenance Matters

Best practices for testing, inspecting and maintaining backup oil systems

By Grant Lanthorn, Electric Power Research Institute

It could happen in your plant — failure of a backup oil system.

A steam turbine suffers loss of oil during coast-down. The unit is an 1,800-rpm turbine with a double-flow high-pressure (HP) rotor, three double-flow low-pressure (LP) rotors, and a hydrogen-cooled generator. It is equipped with a shaft-driven main oil pump. While the unit is at full load, a fault in the main transformer results in the steam turbine tripping. The transformer fault causes an oil fire and consequential damage to other electrical equipment, prompting a partial loss of station auxiliary power. Emergency diesel generators respond, but cannot provide power to all affected essential busses. The steam turbine lube oil pumps are on the dead bus. The dc emergency oil pump starts and supplies oil at 11.6 psi (80 kPa) until its dc supply breaker trips. The steam turbine coasts down from 940 rpm to a standstill with no oil supplied to the bearings. The result: severe rub damage, requiring replacement and repair of major sections of the steam path. Ten bearings are wiped, and oil seals on all bearing pedestals have to be replaced.

The design, maintenance and testing practices of emergency oil systems are mature and well defined. Even so, severely damaging events continue to occur on a surprisingly regular basis in plants throughout the industry when steam turbines coast down from speed without oil to one or more bearings (Figures 1 and 2). Damage can occur to bearings, journals and steam-path components and require significant time and money to repair. If the oil supply failure results in the release of hydrogen gas, explosion and fire might occur, with additional consequential risk to personnel and equipment.

Minimum forced outage duration for loss-of-oil events is generally four weeks, with many requiring six or more weeks. Costs exceeding $25 million per event are not unusual. Often the loss-of-oil event is caused by easily detectable failure or deterioration of trivial components (such as an $18 resistor) and could have been prevented by routine inspection and testing.

A new guide to backup oil systems Over the years, a variety of comprehensive products from the Electric Power Research Institute (EPRI) and other industry documents have been published to document and clearly explain what is required to ensure that the backup oil system will function when needed. However, this information was often part of broadly focused maintenance guides, and the availability of this information has not prevented the continuing occurrence of these events.

Figure 1. Bearing wipe due to loss of lubrication.

Figure 2. Major cracking in thrust bearing revealed during NDE inspection after loss of lubrication.

Recently EPRI has taken a different approach. Using the insights of experts and the experience of plant operators, EPRI researchers have compiled a new guide devoted solely to maintenance of backup oil systems. The guide summarizes principles for developing an effective program for inspection, testing and maintenance of backup oil systems, and lists common causes of oil system failures as reported by insurance companies. It also reviews detailed best practices for inspection and testing, maintenance and personnel training.

Additionally, the guide presents representative case studies of loss-of-oil events, with details on the sequence of incidents leading to the failure and results of root cause investigations that highlight the contributing factors.

MARCH 2015 ENERGY-TECH.com

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Maintenance Matters Backup oil systems Steam turbines and their driven loads (generators, pumps, etc.) require significant time to coast to zero speed during shutdown. Bearings and hydrogen seals require a constant oil supply during operation, coast-down and turning gear operation, and until rotor temperatures decrease below the softening point of the babbit in the bearings. The oil provides lubrication, cooling and retention of hydrogen gas in some generators. If the oil supply is interrupted, serious and expensive damage to bearings, shafts and steam path components occurs. These events typically require long forced outages for repair and return to service.

Steam turbines are equipped with backup oil systems designed to automatically provide the required continuous oil supply in the event that the normal oil supply is disabled or is otherwise unable to provide oil flow and pressure at the minimum required values. The backup system typically uses a dc motor-driven pump that is supplied with electrical power from the station battery.

Common causes of failure The following are some common causes of emergency oil system failure, as reported by insurance companies: • Control schemes that do not provide interlocks to prevent isolation of dc power to the emergency oil pumps and/or ac power to operate battery chargers.

(This increases the potential for operator-error-induced emergency system failure.)

• Emergency oil system controls incorporated into the distributed control system (DCS) without adequate uninterruptible ac control power. (DCS power supply interruption prevents control of the emergency oil system.)

• Use of combined uninterruptible power supply (UPS)/ inverter/battery chargers. (A single point of failure increases the risk of emergency oil system failure.)

• Protection schemes that permit opening of the emergency bus and/or dc oil pump breakers. (Protection of the bus and motor should not take priority over protection of the steam turbine.)

• Emergency oil pump stop switches and control cables not protected from fire damage. (Damage to stop controls can shut down the emergency oil pump.)

General principles The following general principles are useful in developing an effective backup oil system inspection, test and maintenance program: • Never assume that loss of ac station service will not occur at your plant. (Tornadoes happen, blackouts happen, fires happen, etc.)

• Never assume that loss of ac to the turning gear oil pump will not happen because you have it wired to the emergency diesel or some other vital source of ac power. (Fires happen, board shorts happen, breakers fail, motors burn up, etc.)

16 ENERGY-TECH.com

• Never assume that other sources of bearing lube oil or seal oil (main suction pump, auxiliary oil pump or backup seal oil pump) will protect you. This is not their primary design function.

• The only way to verify that the backup systems will work as designed if called upon to do so is by properly testing them. Doing anything else is irresponsible and an invitation for disaster.

Recommendations The turbine’s main oil system contains a number of components and systems, including the lubrication oil, which can require routine monitoring, testing and maintenance.

Routine and effective inspection and testing of the backup oil supply subsystem must be performed if the risk of damage due to a loss-of-oil event is to be minimized.

Unit-specific testing recommendations may vary from one OEM to another due to differences in system configuration.

As a general recommendation, the pump auto-start pressure switches and/or transmitters of the various backup oil supply systems should be annually calibrated to ensure that they function in accordance with the OEM’s recommendations.

Annual thermographic surveys of backup oil system motor starters should be conducted with the motors operating at full load.

The station battery is a critical component of the backup oil system. The battery must be capable of supplying critical plant dc load for the period of time required to safely shut down, coast down and cool critical equipment while maintaining control of all systems and shutting down plant computer systems in an orderly fashion. Station batteries require effective routine maintenance and periodic testing to ensure that the battery will always perform as required during a loss of an ac power event.

Inspection/maintenance checklists should be developed to aid in the effective execution of routine backup oil system tests, including online tests for the ac-motor-driven auxiliary oil pump, the ac-motor-driven turning gear oil pump, the ac-motor-driven bearing oil pump, and the dc-motor-driven emergency oil pump. Likewise, a checklist is needed for the off-line dip test for the dc-motor-driven emergency oil pump.

If the risk of emergency oil system failure is to be significantly decreased, an effective personnel training program needs to be in place, and plant personnel need to be required to perform the necessary activities in a routine and consistent manner. ~ Grant Lanthorn is a senior project engineer conducting research in the area of nuclear and fossil steam turbines and associated auxiliary equipment, with focus on the bearing and lubrication systems. You may contact him by emailing editorial@woodwardbizmedia.com.

MARCH 2015

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ASME FEATURE

Role of boiling mode and rate in formation of waterside deposits in HRSG evaporator tubes

By David S. Moelling, PE, and James Malloy, Tetra Engineering Group Inc.

Waterside deposits in boiler tubes have been an issue since the first steam boilers were designed. Engineering analysis of deposit formation and control began in the late 19th century. The author of a 1906 reference, “Boiler Waters, Scale, Corrosion and Foaming,” stated, “A steam-boiler is a steam-generator, not a kettle for chemical reaction!” [1] Early work focused on obtaining better water quality by treatment in and out of the boiler.

As steam generator technology improved and rapid rises in operating pressures and temperatures were implemented, handling deposit formation and the resulting damage became more urgent and complex.

In modern plants, deposits remain an ongoing problem on the waterside of boiler tubes where evaporation occurs. They are typically a combination of “pre-boiler” contaminants, such as corrosion products and contaminants transported with feedwater into the boiler, and corrosion products formed from the tube metal itself. They can be widespread across the tube wall or highly localized, depending on design and operating conditions.

Industry studies done in the 1960s and 1970s [2-5] confirmed that key elements in deposit formation are heat flux, steam mass fraction (quality) and initial wall conditions, as well as water quality and chemistry controls. Further work was performed by the DOE, EPRI and other international organizations to improve understanding of deposit formation, damage caused by deposits and cleaning methods. [6-7] These studies also indicated that there is sensitivity to total heat absorbed along the evaporator tubes, which is somewhat independent of local steam quality.

When Gas Turbine Combined Cycle (GTCC) power plants (> 100 MW) began

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Figure 1. Heavy deposits in HRSG tube – Horizontal HRSG near bottom of HP evaporator

operation in the 1990s, deposits in evaporator tubes were not considered a significant issue. Operating boiler pressures were low (500-900 psig/35-60 barg) as were GT exhaust gas temperatures. The use of supplemental firing, which significantly increases gas temperatures, was limited.

The rapid increase in HRSG unit size with a concomitant increase in operating pressures and temperatures made the likelihood of waterside deposits increase. Current pressures are all subcritical, but can be up to 2,400 psig/163 barg. Although the underlying deposition mechanisms are similar, the details of boiling in the HRSG are different from a conventional coal/ oil/gas boiler. This leads to some differences in deposition rates and the type of deposits found in a HRSG. It is particularly important in defining the areas of the HRSG evaporators at risk.

Figure 1 shows an example of the extent to which surface deposition can develop in an HRSG evaporator tube; Figure 2 shows a typical deposit cross-section.

Key factors in deposit formation and growth The key factors in deposition in boiling tubes are: • Heat flux at the boiling surface when nucleate boiling is occurring (nucleate boiling is where steam bubbles form directly on the tube inner walls) ASME Power Division Special Section | MARCH 2015

AsME FEAtUrE Table 1 – Range of Operating Pressures High Pressure

Intermediate Pressure

Low Pressure

2 Pressure HRSG

1600-2400 PSIG (105-160 Barg)

200-300 PSIG (13-20 barg)

Gas, Oil

3 Pressure HRSG

1600-2400 PSIG

300-600 PSIG (20-30 Barg)

50-120 PSIG (3-8 Barg)

Drum Boiler

1600-2500 PSIG (105-165 Barg)

N/A

N/A

• • • • • •

Local fluid flow disturbances Electrochemistry of boiler water Local steam mass fraction (quality)/fluid velocity Concentration of contaminants (scale forming species) Initial surface cleanliness Operating pressure/temperature

Heat flux (BTU/hr ft2) controls the rate of boiling at the tube surface, and thus the amount of insoluble material left behind. Figure 3 shows the boiling profile in a horizontal tube with evaporation going to 100 percent (once-through boiler). It is observed in tests [2, 7] that most deposits occur at the onset of nucleate boiling up to the point where steam quality is around 10 percent (mass fraction). This is because above this value, convective heat transfer frequently dominates: the water evaporates from the inner annulus without bubble formation at the wall.

Nucleate boiling tends to be dominant at low vapor qualities and high heat fluxes, while convection tends to dominate at high vapor qualities and mass velocities and low heat fluxes. For intermediate conditions, both nucleate boiling heat transfer and convective heat transfer are important. Thus when heat transfer becomes predominately convective, the deposition will be reduced or halted.

The concentration of contaminants is a fundamental factor known for many years. It combines with the local water pH, temperature and pressures to control the development of scale for deposit buildup.

ASME Power Division: Steam Generators & Auxiliaries Committee

A Message from the Chair The Steam Generators & Auxiliaries Committee addresses the design, testing, analysis and operation of fossil-fired boilers, steam generators and heat recovery steam generators (HRSGs), as well as fossil fuels such as natural gas, fuel gas, coal, fuel oil, biomass and MSW. Committee members include engineers and designers from international boiler manufacturers, fossil-fired power plants and cogeneration facility operators and independent consultants who solicit technical papers to be presented at the annual ASME Power conference. These papers feature topics relevant to modern steam generators, which are reviewed prior to publication.

Topics for recent technical papers included subjects such as candidate materials for advanced ultra-supercritical units (A-USC), thermal fatigue stress limits of thick walled pressure parts, under-deposit corrosion (UDC) phenomena in HRSG evaporators, detailed CFD modeling of some components, such as fans or tubes, detailed design of spray attemporators (desuperheaters) and a panel discussion on the strategies associated with converting coal-fired units to natural gas.

We anticipate interest in the technical solutions for problems associated with the newer challenges of minimizing a plant’s CO2 footprint, reducing the startup time of combined cycle plants in regions with high variability in system power demand, addressing the new EPA mandates in the areas of FGD wastewater and coal fly ash, as well as the ongoing need to improve steam generator’s reliability through improved operations or maintenance practices.

We invite engineers, as well as owners and operators of steam generators, to join our committee as members or as potential reviewers, please contact me for more information.

Best regards, F. David Fitzgerald Chair – ASME Steam Generator and Auxiliaries Committee 508-966-5633 david.fitzgerald@gdfsuezna.com

Figure 2. Deposit cross section – HP evaporator tube with deposits – Horizontal MARCH 2015 | ASME Power Division Special Section

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ASME FEATURE Finally, the initial cleanliness of tubes contributes to the formation of deposits. Tubes with mill scale or other corrosion products are known to accumulate deposits faster than clean tubes.

Figure 3. Boiling in horizontal tubes

Figure 4. Gas flow around finned tube

Figure 5. Distribution of heat transfer around tube

Heat transfer and deposit formation In HRSGs, the heat transfer from the gas is mostly convective with finned tubes. Figure 4 shows hot gas flow around a finned tube. The gas eddies behind the tube have slow velocities, and thus lower heat transfer.

Figure 5 shows the distribution of total heat transfer around a finned tube. The heat transfer is highest at the point facing the flow, and lowest 180 degrees behind the flow. Also, the areas in the rear eddy often accumulate deposits, as seen in Figure 6, further reducing heat transfer. In HRSG evaporator tubes, the greatest heat flux and consequent boiling will be on the upstream side of the tubes.

HRSGs vs. coal/oil steam generators physical comparison HRSGs most often have two or three evaporating pressures, compared to a single pressure for a conventional boiler, identified as the high-pressure, medium or intermediate-pressure and low-pressure systems. The operating pressures are typically in the range shown in Table 1. Currently all HRSGs in operation have high pressures that are subcritical and similar to traditional drum-type utility boiler pressures.

Heat transfer is mostly convective with a moderate radiation component, even with high upstream duct firing in the HRSG. By comparison, furnace wall tubes in conventional boilers have very high radiant heat transfer from the furnace gases and are bare membrane tubes.

HRSGs can be either Horizontal Gas Flow (tubes top hung vertically, Figure 7) or Vertical Gas Flow (tubes horizontal across gas path, Figure 8), although hybrid types exist. Thus the evaporating tubes will have either a vertical orientation with a consequent annular steam/water flow pattern, or a horizontal orientation with a stratified steam/water flow pattern (the flow is often still annular where liquid water surrounds the steam, but the steam annulus is toward the top of the tube, see the small round tube cross-sections in Figure 3.

Tube wall conditions comparison The heat flux at the inner tube wall is the dominant component in deposit rates in the area of nucleate boiling, with the rate proportional to the heat flux as: Deposit Rate α QN The exponent N is estimated to be in the range of 1-1.5 by most studies. Conventional boilers have very high heat rates in the furnace waterwalls (Q > 100,000 BTU/hr ft2 - 315 kW/ m2) which promote high deposition rates. The predominant contributor to this heat flux in conventional boilers is due to radiant heat transfer. The furnace conditions are much higher

Figure 6. Deposits collecting at rear of tubes – Horizontal HRSG – LP economizer tubes

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ASME Power Division Special Section | MARCH 2015

ASME FEATURE (Left to right) Figure 7. Horizontal gas path HRSG and top hung evaporator detail Figure 8. Vertical gas path HRSG and horizontal tube detail

temperatures than any HRSG conditions (>2,000°F/1,093°C) and the emissivity of the flue gas constituents also is much higher. This emissivity is often due to soot and other constituents, while in HRSGs it is mostly due to non-luminous emissions from H2O and CO2 (a small amount of luminous heat transfer occurs in duct burner regions of the HRSG).

HRSGs have much lower heat fluxes due to the predominantly convective heat transfer modes on the gas side (vs. radiation).

However, the amount of additional surface area as fins can contribute a great deal to increasing heat flux at the tube inner wall.

Typically, HRSG heat fluxes average around 30,000 btu/hr ft2 (95 kw/m2) with peak values from 40-60,000 btu/hr ft2 (126 – 190 kw/m2) at the inner wall.

Deposits form preferentially in nucleate boiling regions where each bubble of steam formed can leave contaminants behind.

As steam quality builds, the fluid layer at the wall becomes thinner and convective heat transfer increases. When the convective heat transfer is greater than the boiling heat transfer over the film, nucleate boiling decreases and stops. Waterside deposition then decreases and stops, as boiling at the tube wall slows. This has been clearly seen in many HRSG tube internal inspection videos taken with a borescope. In a horizontal HRSG evaporator there is no steam at the bottom of the evaporator tubes and the steam quality increases with height in the tube. In vertical HRSGs with forced circulation, the steam quality is often quite high (~25 percent) after a very short distance after the inlet in the first pass of tubes.

Observed deposits often occur only in this region.

One criterion for determining the location of this transition is a combination of the boiling number (Bo) and the LockhartMartinelli Number (X), called the Boiling Index as: B1= Bo * X The Boiling Number is: Bo= Q/G hfg MARCH 2015 | ASME Power Division Special Section

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AsME FEAtUrE

Figure 9. Value of Nucleate Boiling Index

Figure 10. Example of local quality calculations in HRSG evaporators

where Q is the heat flux, G is the mass flux and hfg is the evaporation enthalpy. This is the ratio of the available heat vs. the total energy to evaporate all the fluid. The bigger the Bo, the more likely nucleate boiling is to occur.

The Lockhart-Martinelli number (X) is the ratio of the liquid and gas pressure drops as:

Equation 1

If we take the pressure drops using a Darcy friction factor, the value can be estimated as:

Figure 11. Steam quality along tube length for first five rows Equation 2

The greater the density differences between gas and liquid phase and the lower the steam fraction, the greater the value of X. A typical criterion for the transition from nucleate to convective boiling is when the boiling index is less than 0.15 x 10-3. Figure 9 shows the index for an HP evaporator tube.

The nucleate boiling index is more than 0.15 x 10-3 only with steam qualities over 0.04. The actual numeric value is somewhat arbitrary, thus for general tubes an estimate of the inflection point steam quality as seen in Figure 9 is a better indication of where nucleate boiling stops. Figure 10 shows an example of evaporator computer simulations where local steam quality is computed in each tube row. Figure 11 shows the steam quality in the first five tube rows. The subcooled region is small (at the inlet) and the outlet quality is varied depending on the total heat transferred. The fourth row (Evap 2-1) has quality similar to the first (hottest gas) row, since the tube fin area is higher on the fourth row. The combination of the heat flux and Boiling Index calculations is seen in Figure 12, where the zone of nucleate boiling is plotted along with heat flux by each tube row. The high heat fluxes in rows 1 and 2 correspond with Figure 12. Example of heat flux and nucleate/convective boiling transition point

22 ENERGY-TECH.com

ASME Power Division Special Section | MARCH 2015

ASME FEATURE boiling transition points about 35-45 percent up the tube length.

The area of nucleate boiling in this unit is below the Purple Line in Figure 11 (units are in height along evaporator tube). In this zone, excessive deposition can occur in the tube rows with high inner wall heat flux (shown in Green Line).

Field experience with HRSG deposits – General HRSGs have had lower rates of tube leaks due to deposit-related damage (under-deposit corrosion or overheating) than conventional boilers due to the design factors discussed earlier.

Figure 13. Vertical gas path HRSG evaporator

Vertical gas path HRSGs Vertical HRSGs have tubes oriented horizontally as shown in Figure 13, with the gas flow (red arrow) toward the top. The flow path is shown in the schematic of Figure 14. The high heat flux tubes are the lowest at the inlet of the flue gas. Many vertical units have forced circulation with high qualities from the evaporator tubes (~ 15-25 percent). The steam accumulates

MARCH 2015 | ASME Power Division Special Section

Figure 14. Flow paths in evaporator in vertical HRSG

at the top of the tubes and flow is stratified rather than annular.

This promotes deposit formation.

Figures 13-19 show deposit buildup in horizontal tubes with multi-layer deposition and under deposit corrosion and gouging.

Horizontal gas path HRSGs Horizontal HRSGs with vertical evaporator tubes have less risk of deposition than vertical HRSGs. Steam water flow is fully annular at some point, and the range of nucleate boiling is

ENERGY-TECH.com

23

ASME FEATURE

Figure 15. Deposit in sectioned horizontal tube – vertical gas path – HP evaporator tube

Figure 16. Cleaned deposit showing gouging- vertical gas path – HP evaporator tube

Figure 17. Typical gouging and under deposit corrosion in cleaned tube samples – vertical gas path – HP evaporator tube

Figure 18. Micrograph showing deposit and pits or gouges underneath – vertical gas path – HP evaporator tube

Figure 19. Tube with through-wall gouging – vertical gas path – HP evaporator tube

less than around 50-70 percent of the tube length in the hottest tubes.

Figure 20 shows deposits in an HRSG with steam export and condensate return. The deposits form on hot side (upstream) and show extensive tubercule formation. Above the range of nucleate boiling, the tube is clean with no deposits or corrosion damage.

24 ENERGY-TECH.com

As noted earlier, “dirty” boiler tubes accumulate deposits at a higher rate than a clean tube. Figures 21 and 22 show two units at the same plant. The plant is relatively new, but due to start/ stop construction, one unit was acid cleaned prior to operation and the other was not. The resulting difference in deposition levels is clearly seen in comparing photos from borescope inspection of the HP evaporator tubes.

Numerous horizontal gas path units are equipped with duct firing (supplemental firing), leading to higher heat fluxes due to higher gas temperatures at the evaporator (~ 1,300-1,600°F/700-870°C). Many units have high rates of firing to produce large amounts of steam for export. The required high flow rates of makeup water or cleanup of returned condensate can make boiler water chemistry control difficult.

Figure 23 shows the very high levels of deposits found in the HP Evaporator tubes of a unit with this type of firing and steam export.

Figure 24 shows the estimated heat flux levels and deposit growth for the HP evaporator section from computer simulations. Heat fluxes peak in the second row due to more fin surface area, but decline in later rows as the flue gas is cooled, lowering heat flux. Peak heat fluxes are more than 50,000 BTU/ hr ft2 (160 kW/m2) in row 2 and deposit weight densities were predicted to be above 70 g/ft2 ( 76 mg/cm2). This is the area

ASME Power Division Special Section | MARCH 2015

ASME FEATURE

Figure 20. Tube condition above and below nucleate boiling/convection evaporation transition – HP evaporator horizontal gas path

Figure 21. Deposit formation in unit without pre-operational acid wash – HP evaporator – Horizontal gas path

Figure 22. Deposit formation in unit with pre-commissioning acid wash – HP evaporator – Horizontal gas path

Figure 23. Heavy deposits and corrosion in HP evaporator tube – Horizontal gas path

of the most tube failures at the facility and the observed deposit thickness levels.

Design of HRSG evaporators also can help minimize deposits by keeping tube heat fluxes lower than critical values, increasing accessibility for internal inspections and planning for chemical cleaning of in-service units. ~

Summary Deposits in HRSGs tend to form at slower rates than in coal/oil fired boilers due to generally lower heat fluxes and pressures. Tube failures due to internal deposits have increased in HRSGs due to the following factors: 1. General aging of fleet.

2. Increased duct firing capacity in many units, with consequent higher heat fluxes.

3. Many units with no initial acid wash during construction. If residual scale is present, deposits accumulate more rapidly.

Areas of particular risk are: 1. Horizontal evaporator tubes in vertical gas path HRSGs. 2. High heat flux tubes in all units (often areas with high fin area near duct burners).

3. Units in cogeneration service often have high makeup/ cleanup requirements, as well as high duct firing.

MARCH 2015 | ASME Power Division Special Section

References 1. W.W. Christie, Boiler Waters, Scale, Corrosion and Foaming, Van Nostrand, New York 1906.

2. H.A. Klein, J.K. Rice, “Research Study on Internal Corrosion of High Pressure Boilers”, Transactions of the ASME, Journal of Engineering for Power, July 1966, pp 232- 242 3. P. Goldstein, J.B. Dick, J.K. Rice, “Internal Corrosion of High Pressure Boilers”, Transactions of the ASME, Journal of Engineering for Power, Paper No 66-WA/BFS1 1968.

4. P. Goldstein, “A Research Study on Internal Corrosion of High Pressure Boilers”, Transactions of the ASME, Journal of Engineering for Power, January 1968, pp 21-37.

5. P. Goldstein, C.L. Burton, “A Research Study on Internal Corrosion of High Pressure Boilers Final Report”, ENERGY-TECH.com

25

ASME FEATURE

Figure 25. EOR HRSG gas side schema

Figure 24. Heat flux and estimated deposit levels (deposits are dark blue and brown lines)

Figure 27. Observed deposits in evaporator section – Horizontal gas path – oncethrough evaporator – enhanced oil recovery steam generator (HRSG behind gas turbine)

Corrosion in Steam Generators”, VGB Kraftswerktechnik 55, Jan 1975, pp. 26/39.

7. T. Petrova, et. Al. “Deposition on Drum Boiler Tube Surfaces”, EPRI Report 1010186, December 2005.

Figure 26. EOR HRSG waterside schema

Editor’s note: This paper, PWR2014-32106, 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.

David Moelling is the chief engineer at Tetra Engineering Group, with more than 30 years of all types of steam generator experience.

He is a licensed engineer in Connecticut and a graduate of Rensselaer Polytechnic Institute. You may contact him by emailing editorial@woodwardbizmedia.com.

James Malloy is the technical director of Tetra Engineering Europe in France. He is responsible for the technical and commercial activities in Europe, Africa and the Middle East for Tetra Engineering. He is a graduate of Rensselar Polytechnic Institute. You may contact him by emailing editorial@woodwardbizmedia.com.

Figure 28. Heat flux, steam quality per tube row

Transactions of the ASME, Journal of Engineering for Power, April 1969, pp 74-101.

6. W.M.M. Huijbregts, J.H.N. Jelgersma, A. Snel, “Influence of Heat Transport, Deposits and Condenser Leakage upon

26 ENERGY-TECH.com

ASME Power Division Special Section | MARCH 2015

MACHINE DOCTOR

Thrust collar wear in an integrally geared turbocompressor

By Patrick J. Smith, Energy-Tech contributor

Gears are used to transmit power and motion from one shaft to another. In a helical gear, the teeth are machined at an angle to the axis of rotation. This angle is referred to as the helix angle.

In a typical gear set the larger gear is called the bullgear and the smaller gear is called the pinion. A typical parallel shaft, single helical gear arrangement is shown in Figure 1. The meshing of these helical gears produces radial, tangential and axial forces.

The axial force, or thrust, acts in opposite directions on the driving and driven gears. Thrust collars can be incorporated into the pinion design. These collars act against corresponding shoulders on the bullgear to transmit the pinion thrust to the bullgear. The resultant overall axial load is then borne by bullgear thrust bearings, which eliminate the need for pinion thrust bearings. This is a common arrangement with integrally geared compressors.

Properly designed and manufactured thrust collars operate under full hydrodynamic lubrication, which should prevent wear.

Although problems with thrust collar wear are uncommon, there have been instances where it has occurred. These are typically due to operation at adverse operating conditions, or issues with reduced oil flow. The purpose of this article is to present a case study of thrust collar wear in an integrally geared turbocompressor.

cover pinion consists of a pinion operating at 18,934 RPM with a single overhung impeller at one end. The cover pinion is comprised of the second stage of the BAC service. The compressor configuration also is shown in Figure 1.

The gearbox utilizes tilting pad journal pinion bearings.

These are single, non-contacting proximity type vibration probes mounted in the air seals behind the LS and HS impellers.

There is a single non-contacting proximity type vibration probe mounted in the upper gearbox cover that is used to measure radial vibration from the cover pinion. This probe looks at the thrust collar OD on the collar that is adjacent to the BAC second stage pinion bearing. There is no proximity probe on the other side (non-impeller side) of the cover pinion. All of the pinions are fitted with thrust collars, which are used to transmit pinion axial thrust to the bullgear. The thrust bearings are on the bullgear rotor as shown. The bullgear journal bearings are a cylindrical sleeve type and the thrust bearings are a tapered land type. There are no vibration probes on the bullgear rotor.

Introduction This case study pertains to a dual service integrally geared centrifugal compressor driven by a 1,494 RPM, 6,500 KW induction motor. The gearbox consists of a bullgear and three rotors. The low speed (LS) rotor consists of a pinion operating at 9,337 RPM with impellers mounted at each end. The LS rotor comprises the first two stages of the main air compressor (MAC) service.

The high speed rotor (HS) consists of a pinion operating at 15,852 RPM, also with a double overhung impeller configuration. The HS rotor comprises the third stage of the MAC service and the first stage of the booster air compressor (BAC) service. The Figure 1 MARCH 2015 ENERGY-TECH.com

27

MACHINE DOCTOR History During commissioning there was a mechanical failure that resulted in severe damage to the MAC first stage impeller.

However, scuffing/scoring damage also was discovered on the thrust face of the BAC first stage thrust collar and on the corresponding bullgear thrust face that could not be explained by the impeller failure. See Figure 2. It was necessary to remove the bullgear and grind the bullgear thrust face surfaces to correct the wear. The scuffing on the BAC second stage thrust collar was repaired by polishing the damaged areas. Although the damage was relatively minor, it occurred after only a few hours of operation. To determine the cause and corrective action, the pinion and bullgear were inspected, the oil was checked and the thrust collar design and operating trends were reviewed.

Inspection An inspection of the bullgear and HS pinion did not reveal any dimensional or material issues. The oil selection and condition also were checked and no issues were identified.

Figure 2

Thrust collar design The thrust collars are installed near the end of the gear teeth at both ends of each pinion and have a contact diameter greater than that of the pinion tooth OD. Both the thrust collar and corresponding bullgear thrust face have a conical shape (tapered).

In this design, the thrust collars are shrunk onto the pinion. The

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MARCH 2015

MACHINE DOCTOR pinion, including the thrust collar, and bullgear are made from high strength alloy steels. The bullgear is through hardened, while the pinion and thrust collar are through hardened and then case hardened by nitriding. The thrust collars are lubricated from the oil that is sprayed onto the gear mesh. Thrust collars act Figure 3 like hydrodynamic bearings and an oil film prevents metal-to-metal contact. The oil film thickness is primarily a function of load (due to the axial thrust), speed (bullgear and pinion rotational speeds), oil viscosity and thrust collar geometry (taper, contact length, etc.).

The resultant pinion axial thrust is a combination of the differential pressure forces acting on the impellers and the gear axial force. The helical gear axial force is a function of the power, gear pitch diameter, speed and helix angle. The basic equation is: Equation 1

Where: Fa = Axial Force, lbs Ft = Tangential Force, lbs β = Helix Angle PD = Pitch Diameter, in.

In many cases the gear loads can be partially balanced against the pressure loads to minimize the net axial thrust. In this case, the net thrust load for the HS rotor at normal operating conditions is only a small fraction of the manufacture’s design limit.

And the damage that was discovered was on the inactive thrust collar face at the design operating conditions.

Operating trends A review of the DCS operating trends revealed no indication of surging of the machine, operating at excessive power or excessive vibrations prior to the impeller failure or any other time during commissioning. Lube oil pressures and temperatures also were within normal ranges. However, it was noted that the BAC suction pressure at start up varied from 2 barg to 4.5 barg on different startups. Normal suction pressure during steady state operation is approximately 3.5 barg.

Discussion There are no industry standards that specify limits on allowable thrust collar loading or minimum/maximum surface speeds.

However, this machine is a well referenced compressor and the thrust loading was very low compared to the manufacturer’s limits. Also, as stated, the damage on the HS pinion thrust collar

was on the side that would normally be unloaded at the design operating conditions.

As described in the July 2013 Energy-Tech article, “Steam Turbine Driven Integrally Geared Compressor Gearing Failures,” thrust collar damage on that machine was found during a routine gear inspection. The wear also was on the normally inactive thrust collars surfaces of all compressor pinions. In other words, the damage was on the thrust collar surfaces that would not normally contact the bullgear thrust surface during typical steady state operation. There was no damage to the normally active thrust collar surfaces. Thus, it was concluded that the damage most likely occurred during a transient event, such as starting or stopping the compressor. After investigating, it was determined that the most likely cause of this wear was due to loss of oil pressure on several machine • • trips, combined • • with high axial loads • • SELL • RENT• LEASE during coast down.

• • - 24 / 7 • • Many integrally EMERGENCY SERVICE • • geared compressors • • can coast down with • • limited lubrication • • • • from only the shaft • IMMEDIATE DELIVERY • driven MOP and • • not suffer any gear• • ing or bearing dam• • 10HP TO 250,000#/hr 250,000#/hr Nebraska 750 psig 750 TTF • age. However, in this • 150,000#/hr Nebraska 1025 psig 900 TTF • 150,000#/hr Nebraska 750 psig 750 TTF • machine, the thrust 150,000#/hr Nebraska 350 psig • • 115,000#/hr Nebraska 350 psig collar loading was Nebraska 750 psig • • 80,000#/hr 75,000#/hr Nebraska 350 psig high and couldn’t Nebraska 350 psig • • 60,000#/hr Nebraska 350 psig be quickly dissipated • 40,000#/hr • 20,000#/hr Erie City 200 psig Firetube 15-600 psig • • 10-1000HP on an uncontrolled ALL PRESSURE AND TEMPERATURE COMBINATIONS SUPERHEATED AND SATURATED • • shutdown.

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quickly dissipated. However, as noted above, the BAC section was pressurized during start-up. As shown in Figure 3, even though the pressure on both sides of the impeller is the same, the area on the front side of the impeller is greater than the area on the back side of the impeller due to the shaft diameter on the back side of the impeller. So when this stage is pressurized before start-up, the pressure times the differential area from the front to the back of the impeller creates a net axial load. The MAC section is not pressurized before startup. So, there is pressure loading on the MAC third stage impeller on the opposite side of the HS rotor. Thus, the only pressure loading at start-up is due to the BAC first stage. This load also is in the direction toward the normally inactive thrust collar at design steady state conditions. The pressure loading created a load that is higher than the design load, but is still only a fraction of the manufacturer’s limit. Although this load is still low, this load coupled with lower speeds as the compressor is accelerating could explain the thrust collar wear.

To prevent bullgear/thrust collar damage, the start-up procedure was modified to reduce the pressure in BAC at start-up to about 0.5 barg.

Conclusion After the repair and the changes to the start-up procedures, the compressor was restarted and put into service. After several starts, the thrust surfaces on the thrust collars and bullgear were visually inspected and no damage or wear was observed.

The pinion thrust collar and bullgear thrust shoulder damage could not be predicted analytically at the start-up conditions. Also, effects of misalignment, deformation and other factors add more complexity. Acceleration during start-up, oil conditions, surface hardness and surface finish also are other factors. Not every integral rotor that is pressurized on one end before start-up is going to suffer damage like what was seen in this compressor. Even in the case of this machine, there was no damage found on the BAC second stage thrust collars, even though this stage also was pressurized prior to the start-up. However, keeping the thrust loads as low as possible during start-up minimizes the potential for this type of damage to occur. And in general, it is important to evaluate all operating cases, including transient conditions like start-up and shutdown, to ensure there are no adverse conditions that could lead to unpredicted machine damage. ~ References 1. Smith, Patrick J., “Steam Turbine Driven Integrally Geared Compressor Gearing Failures,” Energy-Tech Magazine, July 2013 2. Michael R. Lindenburg, Mechanical Engineering Reference Manual for the PE Exam, 11th Edition, Professional Publications, Inc., Belmont, CA, 2001 Patrick J. Smith is 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. You may contact him by emailing editorial@woodwardbizmedia.com.

MARCH 2015

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