december 2014

Optimize your chute systems

ENERGY-TECHDedicated to the Engineering, Operations & Maintenance of Electric Power Plants

In Association with the ASME Power Division

DECEMBER 2014

www.energy-tech.comA WoodwardBizMedia Publication

New plant water treatment 5 • Steam condensers 8 • Compressor vibration 26

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DECEMBER 2014 ENERGY-TECH.com 3

FEAtUrEs

5 Getting it right the first time: Specifying water treatment equipment and chemistry for new plantsBy Brad Buecker, Energy-Tech contributor

8 Steam condenser – More than just tubes!By Thomas J. Muldoon, American Exchanger Services

CoLUMNs

13 Maintenance MattersTransfer point productivity: Is your chute system optimized?By Matthew J. Koca, Flexco

26 Machine DoctorReciprocating compressor vibration problemBy Patrick J. Smith

AsME FEAtUrE

18 Nuclear plant performance improvements with application of longer LP last stage bladesBy Mike Jones and Robert Crossland, Alstom Power

iNdUstrY NotEs

4 Editor’s Note and Calendar

30 Advertisers’ Index

31 Energy-Tech Showcase

oN thE WEB

Check out Energy-Tech’s new website, www.energy-tech.com! It has a whole new look and new features to help you find the industry expertise you need.

Cover photos contributed by Flexco. Photomontage created by Hobie Wood.

ENERGY-TECH

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Editorial Board ([email protected])Bill Moore – Director, Technical Service, National Electric CoilRam Madugula – Executive Vice President, Power Engineers Collaborative, LLCKuda Mutama – Engineering Manager, TS Power Plant

Editorial views expressed within do not necessarily reflect those of Energy-Tech magazine or WoodwardBizMedia.

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Address CorrectionPostmaster: Send address correction to: Energy-Tech, P.O. Box 388, Dubuque, IA 52004-0388Subscription InformationEnergy-Tech is mailed free to all qualified requesters. To subscribe, go to www.energy-tech.com or contact Linda Flannery at [email protected] InformationFor media kits, contact Energy-Tech at 800.977.0474, www.energy-tech.com or [email protected] SubmissionSend press releases to: Editorial Dept., Energy-Tech, P.O. Box 388, Dubuque, IA 52004-0388 Ph 563.588.3857 • Fax 563.588.3848 email: [email protected] SubmissionSend advertising submissions to: Energy-Tech, 801 Bluff Street, Dubuque, Iowa 52001E-mail: [email protected].

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4 ENERGY-TECH.com DECEMBER 2014

Webinar wunderkindsEnergy-Tech’s online education opportunities grow

Editor’s NotE CALENdAr

During the last two years Energy-Tech has expanded its online technical webinar courses, and the numbers show that you – our readers – like what you’re seeing.

In 2014 we offered six technical webinars, primar-ily presented by long-time Energy-Tech contributors, several sponsored by individual companies and one technical course that was presented over the course of six days and was also our first event requiring paid

registration. Recordings of all of these sessions are available on Energy-Tech’s

site, www.energy-tech.com/webinars, and the majority are free to download.

Considering the growth and success of our webinar program so far, we wanted to make sure we continue to offer the best technical material possible in 2015, so we reviewed it and made some changes.

For example, our presenters often commented that it was a challenge to fit a quality technical presentation into a 45-minute timeframe. So in 2015 we will expand our technical webinar offer-ings to include more multiple-day courses. These will require paid registration, but also will expand our ability to help you train from the comfort of your desk.

We also will work on bringing in more sponsored webinars from companies and consultants in the industry. While these will not require paid registration, they still offer quality technical infor-mation and are valuable to our audience.

And we’re continuing to explore our options using webinar technology as it develops. As companies scrutinize training budgets and look for new ways to save, we are confident that our techni-cal webinars are a solid training option – all the information and expertise without the expense of travel, hotel and food.

So let us know what you would like to see, which topics you need information about or which contributors you would like to hear more from – we’ll make it happen.

And keep an eye out for Energy-Tech’s upcoming webinar dates, particularly in the February 2015 issue.

Thanks for reading and have a great holiday season!

Andrea Hauser

Dec. 3-5, 2014Turbine-Generator Troubleshooting and Failure

Prevention, with Energy-Tech UniversityChicago, Ill.www.energy-tech.com/ETU

Dec. 9-11, 2014Power-Gen InternationalOrlando, Fla.www.power-gen.com

Feb. 16-20, 2015Introduction to Machinery Vibrations (IMV)Tempe, Ariz.www.vi-institute.org

March 23-27, 2015Basic Machinery Vibrations (BMV)Knoxville, Tenn.www.vi-institute.org

April 21-23, 2015Electric Power Conference & ExhibitionRosemont, ILwww.electricpowerexpo.com

May 11-15, 2015Advanced Vibration Analysis (AVA)Houston, Texaswww.vi-institute.org

June 15-19, 2015Rotor Dynamics and Modeling (RDM)Syria, Va.www.vi-institute.org

June 28-July 2, 2015ASME Power & Energy 2015San Diego, Calif.www.asmeconferences.org/powerenergy2015

Sept. 21-25, 2015Machinery Vibration Analysis (MVA)Salem, Mass.www.vi-institute.org

Oct. 12-16, 2015Balancing of Rotating Machinery (BRM)Knoxville, Tenn.www.vi-institute.org

Submit your events by emailing [email protected].


FEAtUrEs

Getting it right the first time: Specifying water treatment equipment

and chemistry for new plantsBy Brad Buecker, Energy-Tech contributor

During my 18 years at two power utilities and another two at a chemical manufacturing plant, I observed firsthand the criticality of proper makeup water treatment and boiler water/steam chemistry control. Even seemingly minor excursions in water chemistry can lead to problems that cause forced outages due to steam generator failure. These failures can cost an owner hundreds of thousands to millions of dollars in lost generation and repairs, and a number of failures have caused fatalities. Injury and death are the ultimate cost.

My colleagues and I regularly review requests-for-proposals (RFP) for new combined-cycle projects, and we prepare water balances and water treatment equipment specifications for these projects. In many cases, it is obvious that the project developers (and often the owner’s engineer) simply do not understand the importance of water treatment issues, particularly with regard to plant reliability. Often, insufficient raw water quality data is pro-vided at the outset, which makes precise design of the makeup water system difficult to impossible. Also, in the competitive business of bid preparation, regularly the project as a whole or in individual components is awarded to the lowest bidder with-out considering whether the design or equipment offered is satisfactory. Then, when systems under-perform or even fail, the owner and operators are placed in a severe bind. Specification language should state that the award will be based on the “best evaluated bid” to weed out systems that do not meet the specs. Matrix programs are a popular method for determining the best evaluated bid.

Finally, we see many RFPs that continue to call for out-of-date or discredited chemical treatment programs. A primary case in point for heat recovery steam generators is a continued belief in the need for oxygen scavengers (a more accurate term is reducing agent) as a feedwater treatment. This article explores these issues.

Makeup water treatment designFresh water supplies are no longer ubiquitous for power

plant makeup. Increasingly, plants may have to use treated municipal wastewater, poor quality groundwater or some other less-than-ideal supply. Raw water quality greatly impacts the design, and often the sizing or redundancy, of the makeup water treatment system and pre-treatment equipment. The list below outlines a number of the constituents in raw water that must be accounted for in system design.

• The hardness ions, calcium and magnesium (Ca and Mg): These can react with alkalinity and silica in the water

to form scale in reverse osmosis (RO) systems and ion exchange units.

• Bicarbonate alkalinity (HCO3-): As the concentration

increases in an RO unit, or as temperature increases in a heat exchanger, alkalinity can react with calcium to form calcium carbonate (CaCO

3 ) deposits.

• Silica (SiO2 ): Silica chemistry is very complex. Silica can

form scale on its own, but more often combines with magnesium and sometimes calcium to form silicate scales, which are very difficult to remove. Silicate scale forma-tion becomes much more pronounced with increasing pH; however, if no hardness ions are present, higher pH will keep SiO

2 in solution. The latter chemistry is the

basis for a membrane-based wastewater treatment tech-nology that is becoming more popular. [1]

• Chloride (Cl): Chloride is a notorious pitting agent of stainless steels, especially underneath deposits.

• Sulfate (SO4 ): Sulfate will combine with calcium to

form deposits, although the solubility of CaSO4 is con-

siderably higher than CaCO3. However, the deposits are

difficult to remove. Sulfate also will form tenacious scales, particularly in RO systems, with barium and strontium. These metals typically exist in only trace quantities in raw water, but if present in large enough concentrations can cause problems.

• Iron and manganese (Fe and Mn): These metals exist in a number of valence states, but if they enter treatment systems in dissolved form can cause serious fouling and sometimes corrosion.

• Suspended solids: Suspended solids can be death to RO membranes and must be removed prior to RO treatment.

Raw water analyses for any new project should include these elements or compounds, as well as pH, total dissolved solids (TDS), phosphorus, fluoride, ammonia, oil & grease and total organic carbon (TOC). Also, for any systems using reverse osmosis, silt density index (SDI) tests are a requirement for the RO feed. The SDI is a filtration test that provides an idea of the particulate loading to the reverse osmosis unit. A recommended guideline is an SDI <3.

A single snapshot analyses set is not sufficient, rather multiple and historical data are needed. Consider raw water taken from a surface source, particularly a river. Heavy rain can increase the suspended solids concentration by one to two orders of magni-tude. Conversely, droughts can increase the dissolved solids con-


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centration in a lake to the point that once-through condensers began to experience scale formation that had never been seen before. Supplies of treated municipal wastewater often show large fluctuations in ammonia, phosphorus and suspended solids concentrations. Some water sources are at the juxtaposition of fresh water and brackish or seawater. Water movement between the sources can cause very pronounced fluctuations in such impurities as chloride and sulfate.

The upshot of this discussion is that historical data is an absolute requirement for proper design of the makeup water system.

In the era of large power plant construction in the last cen-tury, a common treatment design was clarification/filtration, followed by ion exchange. While this technology was often very effective, problematic issues sometimes arose. These included:

• Changes in flow, temperature and other factors caused solids carryover from clarifiers, which in turn induced downstream fouling.

• Clarifiers were large structures, often circular or cone-shaped, that had broad footprints. A common design criteria for clarifiers is the rise rate, which is gpm of flow divided by the area of the water surface. A reasonable rise rate for an older clarifier is 1 gpm/ft2.

• A common arrangement for the demineralizer was cat-ion-anion-mixed bed ion exchange, although variations on this scheme were not infrequent. Regardless, clarifica-tion basically does very little or nothing to remove dis-solved solids, so the TDS loading on the cation and anion beds was quite substantial. Resins will quickly exhaust in these conditions, and must be regenerated regularly with acid (typically sulfuric) and caustic. Storage and use of acid and caustic introduces additional safety issues, plus frequent regenerations can be expensive.

For these reasons, makeup water treatment evolved consid-erably. A very common scheme nowadays is micro- or ultrafil-tration (MF, UF) for suspended solids removal, two-pass RO for primary TDS removal and portable mixed-bed ion exchange, or electrodeionization (EDI), for final polishing. These technol-ogies have greatly improved makeup system reliability and final water quality, but they are not foolproof. Issues that might arise include:

• Excessive surges in suspended solids can foul MF and UF membranes.

• Use of cationic polymers for coagulation or flocculation ahead of membrane systems has caused severe prob-

lems, as the polymers will coat the (typically) negative-ly-charged membranes.

• For MF and UF membranes, the choice of outside-in vs. inside-out flow through the membranes may have significant consequences.

• Membrane cleaning methods may induce scale formation depending on the concentration of some impurities in the dilution water.

• Although some vendors claim otherwise, in my experi-ence and others, EDI requires feed from a two-pass RO, not single-pass RO only.

Another critical issue is equipment sizing. Redundancy is very important, but this must be coupled with plant operation. The power industry has changed in that there are many more cycling units, as opposed to base-loaded units of the past. Thus, many makeup water systems must provide a variable output. Choices that provide redundancy include 2 x 100 percent systems, 3 x 50 percent systems, 4 x 33 percent systems and so forth. These are issues that must be decided early on in the project. Another point that often is not recognized until too late is that over-design can be as problematic as under-design. A classic example concerns combustion turbines, and these can be simple- or combined-cycle units designed for dual-fuel firing with either natural gas or fuel oil. Fuel oil firing often requires a very large water injection rate for NO

X control. Sometimes RFPs are written with a require-

ment that the makeup treatment system be specified to provide this flow rate. Then, when the units are up and running on natural gas, the equipment sits idle for long periods of time. Besides the excessive capital cost of the system, the massive over-design can cause operational problems, not least of which is dealing with stagnant water in the system that induces microbiological foul-ing. A solution is to install storage capacity to handle those times when water requirements are large.

One final comment on water treatment is important. The author has encountered projects at existing plants where plant personnel plan to modify perhaps just one aspect of the water treatment system, say wastewater treatment, without changing other equipment. The belief sometimes is that only information about the particular system to be modified is necessary for the designers. However, power plant water systems from makeup to cooling to wastewater have to be examined holistically, and not piecemeal. Without a complete set of data, proper evalu-ation of modifications to even unit operation becomes much more difficult.

Forget the oxygen scavengerUnlike coal-fired power plants, the condensate/feedwater

system of an HRSG does not have feedwater heaters, other than perhaps a deaerating heater. Thus, the entire run from the condenser to the low-pressure evaporator is all steel, with no copper alloys present. Yet, this author can attest to the fact that many HRSG specifications call for oxygen scavenger feed to the condensate. This chemistry has been discredited, as it is known that conditions produced by the reducing agent help to

More InformationFor those readers who are interested in learning

more about utility and industrial steam generator makeup water treatment, cooling water chemis-try, lay-up and effluent issues, consider attending the annual Electric Utility Chemistry Workshop, www.conferences.illinois.edu/eucw, and the annual International Water Conference, www.eswp.com/water.


propagate and induce single-phase flow-accelerated corrosion (FAC). Yet, the mindset simply will not go away.

Single-phase FAC occurs at flow disturbances such as elbows in feedwater piping and economizers, locations downstream of valves and reducing fittings, attemperator piping and, most notably for the combined-cycle industry, in low-pressure evap-orators. The effect of single-phase FAC is illustrated in Figure 1.

Wall thinning occurs gradually until the remaining material at the affected location can no longer withstand the process pressure, whereupon catastrophic failure occurs. Temperature and pH also influence single-phase FAC, with maximum cor-rosion occurring at 300°F, and as pH drops toward and below 9.0. In an HRSG, flow-accelerated corrosion will be most prevalent in the low-pressure economizer and evaporator of the unit, with the many short radius elbows and temperatures in proximity to 300°F. However, the corrosion can occur in other locations, including intermediate-pressure circuits. Also, equip-ment such as deaerators that see a mixture of water and steam may be subject to two-phase FAC.

Continued research is improving the battle against FAC. For those in the industry who have grasped that the old AVT(R) program (ammonia or amine feed for pH control and reducing agent feed for oxygen removal and metal passivation) is no lon-ger valid, the popular replacement is AVT(O), which stands for all-volatile treatment (oxidizing). In AVT(O), the small amount of oxygen that enters via condenser air in-leakage is allowed to remain, and may be supplemented with a small, pure oxygen feed if needed. Ammonia, or in some cases amine, is still utilized to elevate the feedwater pH. With feedwater specific conductiv-ity below 0.2 µS/cm, this chemistry causes the magnetite layer on carbon steel to become interspersed and overlayed with a stronger, denser layer of ferric oxide hydrate (FeOOH), which essentially eliminates FAC in those locations. New guidelines recommend a dissolved oxygen concentration of 5-10 ppb at the LP economizer inlet, since lower concentrations might allow gaps to form in the FeOOH coverage. ~

References1. B. Buecker, “Lessons Learned from a High Recovery

RO-Based ZLD System”; CTI Journal, Vol. 35, No. 2, Summer 2014.

Brad Buecker is a process specialist with Kiewit Power Engineers, in Lenexa, Kan. He has more than 30 years of experience in, or affiliated with, the power industry, much of it in chemistry, water treatment, air quality control and results engineering positions with City Water, Light & Power in Springfield, Ill., and Kansas City Power & Light Company’s La Cygne, Kan., station. He has a bachelor’s degree in chemistry from Iowa State University with additional course work in fluid mechanics, materials and energy balances, and advanced inorganic chemistry. He also has written many articles and three books on steam generation topics. Buecker is a member of the ACS, AIChE, ASME, CTI and NACE, as well as the ASME Research Committee on Power Plant & Environmental Chemistry, and the program planning committee for the Electric Utility Chemistry Workshop. You may email him at [email protected].

Figure 1. Photo of tube-wall thinning caused by single-phase FAC. Photo courtesy of ChemTreat.

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Tubing, cleaning and coatings are often the primary operating focus of steam surface condenser operations. There are many articles about cleaning and plugging due to the fact that these actions contribute to the operating cost of the condenser. The total cost of tube fouling and plugging when the corrosion takes place includes not only direct costs of mate-rials, service, etc., but also the availability and efficiency of the condenser. Loss of efficiency means more fuel and more emissions.

The condenser is one of the largest expense items in a steam power plant, since it is the piece of equipment where the final exchange between the operating fluids and the ultimate heat dump occurs by condens-ing the steam and creating a vacuum. As each pound of steam that occupies a large volume collapses into a pound of water that occupies a very small volume, it pulls steam from a higher pressure location. In the power plant, this occurs by pulling the steam to the cold condenser tubes from the boiler and through the turbine. The energy needed to condense the steam (i.e. keeping the tubes cold) is transferred to the water. The water is then disposed of in a lake, river, ocean, cooling towers or the air. In this way, steam can be thought of as a chain you can pull, but not push.

The colder the tubes, the more steam they can condense, or the greater pressure differential will occur as the volume of the collapsing steam is reduced to the volume of the condensed water. The lower the pressure, the greater the differential volume between the steam volume and the condensed water. This dif-ferential between the steam specific volume and the condensate is what drives the steam flow and pulls the steam through the turbine. The colder the water, the lower the backpressure. It also means that as the tubes condense more steam, they build up a thicker layer of condensate, which tends to reduce the heat transfer rate or “condensate loading” of the tubing.

In a typical Rankine Cycle Power Plant (Figure 1), the final heat rejected to the water or air is shown as the area in blue.

While much is made about tube fouling and the need to keep the tubes clean, the main driver to condenser performance is the temperature of the heat sink. Modern condensers are designed with a relatively small difference in the cooling water and condenser temperature, at which the steam is intended to condense. In northern locations, the heat sink temperatures can vary by 50°F or more.

In other areas, the cooling water temperature is more con-stant. Along with the amount of fouling, the amount and fre-quency of subsequent cleaning can be very important, or unim-portant if the water is cold.

Modern condensers have several components. The tubing in the condensers is extensively covered in the literature. In addi-tion to the tubes, the condensers have many additional compo-nents such as tubesheets, waterboxes, support plates, air removal sections, high energy drains, transition sections, supports and expansion joints.

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Steam condenser – More than just tubesBy Thomas J. Muldoon, American Exchanger Services

Figure 2. Rankine Cycle

Figure 1. Condensation


TubesheetsIn normal operation, the tubesheet incurs significant opera-

tional challenges. The edge of the tubesheet acts as a very large, flat-faced

flange, often with one side permanently gasketed to the high vacuum of the shell. The other side of the tubesheet sees the cooling water pressure. Gasket leakage on either side can be a significant issue.

Tubesheets also see the same water as the tubes. Therefore, they are subjected to the same corrosion concerns. Since the tubes and tubesheet are coupled by conductive water, concerns about the galvanic potential between the tubes and tubesheet exist. Impressed current systems or anodes might be required for cor-rosion protection. When the tube material and the type of impressed current or anode systems are improperly coupled together, consequences can include premature failure of the tubes or damage to the tubesheet. Improper selection of the anodes for the tube material also can result in more damage instead of protection.

Rolling tubes into tubesheets is critical to the operational integrity of the condenser. During production by quality manufacturers, great attention is given to the size and finish of the tube holes. With constant attention to wall reductions using actual wall thickness and actual hole inside diameters instead of averages, long term leak-tight tube joints can be achieved. In each of these joints, however, is some small expansion of the tube hole. If there was no such small increase in the tube hole, the tube sheet would not “hold” the tube tight. While the amount is very small, it does add up over thousands of holes. The net effect is to grow the tubesheet in size. When the size is constrained, the tubesheet wants to bulge. The tubesheet is kept from bulging by way of the tubes, which act as stays. This tends to put a longitudinal load on the tubes, which might be compressive and/or tensile.

While two-piece tube plugs are becom-ing more common, taper pin plugs are still often used. When these pins are hammered into a tube or tube hole, they can dra-matically increase the tube and tube hole diameter, in addition to changing the shape of the hole to a taper. Such deformations can add substantially to the stresses in the tubesheet and the tubes. A large quantity of taper pin plugging can essentially destroy the functionality of the tubesheet if a condenser retube is warranted. On a second retubing, this can become an even greater problem, since the tube joints are being rerolled (i.e.

expanded tubeholes) and paired with the accumulation of two sets of plugging deformities. Thankfully the differential pressure that tube joints need to seal is often only 100 psi or less. Poorly rolled or over-rolled tube joints can seal well enough to pass the shell-side standing water tube joint test normally performed after retubing.

Tubesheets tend to “want” to deform, which is resisted by the tube joints and transferred to the tubes. When strain in the tubesheet rises, the tubes and tube joints also experience an increase in strain.

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During retubing, the condition of the tubesheets and tube holes needs to be evaluated. Sometimes rolling the tubes into oversized tubesheet holes is necessary. Leakage might require secondary rolling, and in the case where the hole is severely damaged, it may require plugging.

Tubesheet repair When considering a retube with a new tube material, it is

important to also consider the replacement of the tubesheets. This affords the opportunity to replace the support plates to upgrade and/or modify the design, as well as the material. Such replacements may be performed as complete bundles (modular replacement) or packages (tubesheets, support plates and inter-nals) when space is limited. It is key to work with a company with field experience, design and fabrication expertise when going beyond stripping old tubes and stuffing new tubes.

When tubesheet replacement is being executed, it is often advisable to replace the gasketed condenser shell to tubesheet joint with a welded joint. Welding the replacement tubesheets to the condenser instead of gasketing will minimize the long-term potential for the shell/tubesheet gasket to be a source of air in-leakage. Sealing a tubesheet to shell flange-type leak is difficult.

When welding the tubesheet to the condenser shell, it often becomes a question of the “weldability” between the carbon steel shell and the tubesheet. For some combinations of tube/tubesheet, this might not be possible. Favored tubesheet materi-als such as Muntz are leaded to facilitate drilling, but make the material virtually impossible to weld. Welding Copper Nickel to the steel is possible, but requires skilled welders and proce-dures to make it work, particularly in an overhead position. In the shop, such welds, along with the requisite quality controls and ability to position, make these welds more achievable. Some Titanium tubed units will have an explosively clad Titanium layer on carbon steel, which makes the final weld carbon steel-to-carbon steel. When using a superferritic tube material, such as SeaCure™, high strength Duplex alloys such as 2205 for fresh water and 2507 for seawater are often provided as tubesheets, which can be welded to the carbon steel condenser shell.

High energy drainsIn addition to tubesheets, another operational concern in the

steam condenser are the high energy drains. Usually, these drains are from the feedwater heaters. The flashing of the drains as they enter the very low pressure in the condenser can cause signifi-cant damage to nearby tubes and internals. This should normally enter against some impingement device. In condensers built by Am-Ex, the energy from these drains is usually dissipated by an internal heavy Cr-Mo diffuser sleeve. It is designed for the sig-nificant amount of differential thermal expansion that these inlet lines can experience. This design is highly erosion proof, and provides volume for expansion prior to the entry of these drains into the open portion of the condenser.

When high energy drains are poorly positioned or open without impingement, they can damage the internal supporting

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Figure 3. Equivalent Fouling

Figure 4. Tubesheet corrosion

Figure 5. Flanges can be poorly designed and fail.


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structure under the bundle and weld repairs may be necessary.

Air removal sectionThe condenser’s air removal sec-

tion is critical to both the operation of the condenser and plant. Erosion damage or lack of cooling surface in the zone can significantly increase the steam pressure in the condenser shell. Any increase in the back pres-sure can be an expensive proposition. As non-condensables accumulate, the partial pressure of the steam decreases. This in turn decreases the saturation temperature and lowers the LMTD, decreasing the amount of steam that is condensed or drawn through the turbine for generation. The air removal section is usually a separately shrouded portion of the tubes. Tubes in this section knockout non-condensables and allow egress of the remaining vapor to the lower pressure provided by the air ejectors or vacuum pumps. The air removal section is exposed to the more corrosive non-condensables, such as amines and

oxygen. The outer diameter of the tubing in this section may exhibit additional corrosion concerns and the shrouds might suffer premature failures. Loss of full performance of this section can significantly impact thermal performance.

Figure 6. Supporting structural damage

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Another advantage of the tubesheet replacement option (in which the supports also are replaced) is the ability to modify the air removal shroud design. This allows for the venting system in

the condenser to be replaced or modified, enabling better performance.

WaterboxesMoving the cooling water

into the tubes requires the waterboxes, placed on each end of the condenser. They are often coated with a coal tar or other coating for cor-rosion protection. Holidays in these coatings can result in rapid perforation of the waterboxes and require downtime and weld repairs.

Cooling water nozzles also are a source of corrosion and occasionally need replace-ment. Of particular concern is the expansion joint in the

piping. When they are perforated, the entire waterbox needs to be removed and the replacement made. These are large diameter pipes and expansion joints that are designed for relatively low pressures.

The other expansion joint on the condenser is usually between the transition dome in the top of the condenser and the turbine. This joint sees the high vacuum and responds to the cycling of the condensers during operation. The corrugations in some of the transition joints can suffer from fatigue cracking and corrosion. The rubber joints can become hard and brittle during years of operation.

When installed, there might be substantial welding involved which might be subjected to flow erosion, pitting or cracking. Weld repairs can be difficult to make due to tight clearances.

ConclusionModern steam condensers are critical to steam plants. They

provide the motive source to draw the steam through the tur-bine. While tubing is the focus of much of the heat exchanger service market, it is imperative to focus on several key items when contemplating a major repair or retube. Tubesheets must be examined, air removal shrouds evaluated, cracks and dam-age to the high energy drain lines repaired, waterbox linings repaired and expansion joints checked for cracks and damage. Performing these tasks in a repair or retube greatly improves performance and availability. In order to perform these tasks along with the option of installing new tubesheets and/or bundles, it is crucial to enlist a service contractor that possesses design and fabrication expertise. ~

Thomas J. Muldoon is president of American Exchanger Services, www.amexservices.com. You may contact him by emailing [email protected].

Figure 7. High energy drains tube erosion

Figure 8. Leaking Inlet CW Nozzle Expansion Joint

Figure 9. Corrosion on inlet by expansion joint


Obtaining optimal belt loading Maximum productivity is the goal of every operation.

And while some operations strive to make their equip-ment run faster or accommodate more material, others are simply taking another look at their belt conveyor system. Maintenance teams often don’t realize that the system could be running more efficiently until they notice decreased production or there is a work stoppage, but the truth is that optimizing the performance of the conveyor system could save time, money and headaches.

Transfer points are among the most important parts of a conveyor system. Getting materials from one belt to the other is important, and getting them there without spillage, material degradation and structural wear is paramount to the productivity of an operation. That’s why optimizing belt loading is so important. By considering a few factors when evaluating your system, you could not only avoid the situa-tions previously mentioned, but reduce dust and extend the equipment life of your idlers and impact beds.

What to look for Many transfer points consist of a standard chute, where

the materials go through the chute, hit up against the inside wall and drop onto the belt. In many of these cases, the load point is not optimized.

Dust, spillage and belt mistracking are just a few of the signs that your load point is not optimized. A big indica-tion that your system is not performing efficiently is when material on the belt is not centrally loaded and material is being conveyed on one side of the belt. This results in lost productivity, since not as much material travels on the belt.

There are many factors that should be considered to obtain optimal belt conveyor loading:

• The discharge angle and the balance between the fac-tors involved with discharge angle selection.

• Overall transfer chute geometry to minimize or elimi-nate off-center loading of the conveyor belt.

• The need for ancillary equipment based on the level of controlled flow and containment provided by the design.

Chute discharge angles

In designing the lower chute section, the primary focus is on delivering the product onto the receiving conveyor efficiently in all operating conditions. One of the critical design issues that needs to be considered in this process is the chute discharge angle.

There are four variations to the discharge angle of the chute: Straight Back Angle, Small Included Angle, Medium Included Angle and the Large Included Angle.

What is a sub-optimal angle?

Higher belt cover wear will result from the direct impact alone. Add to this the higher force of impact,

Transfer point productivity: Is your chute system optimized?

By Matthew J. Koca, Flexco

MAiNtENANCE MAttErs

Figure 1. Optimized belt loading transfer chute with skirting.


combined with the differential velocity of product, and belt cover wear increases even more. The product bounces, slips and scuffs the belt cover while trying to accelerate and con-tinues until the material has reached belt speed.

A sub-optimal angle can be especially troublesome when adding a combustible material like North American Powder River Basin Coal to your system. Low-impact angles were utilized in the chute system design of a power plant that was adding PRB coal to its fuel mixture. Reduced material degradation was realized as the coal was smoothly redirect-ed instead of impacting the belt, which also decreased the

combustion hazard. An added plus was that the material stream was encapsulated by the wear surfaces, which keeps all the fines entrained within the flow and resulted in mini-mal dust generation as well.

What is an optimal angle?A higher discharge angle results in the material impact-

ing the belt faster and at a higher angle. Also, the product velocity after impact is slower than the belt velocity, so the product will slip and wear the belt cover until it reaches the belt velocity. A port on the East Coast of the United States

MAiNtENANCE MAttErs

Figure 2. Traditional chute impacts with material stalling.

Figure 3. Optimized belt loading with higher discharge angle.


MAiNtENANCE MAttErs

experienced this exact problem with their transfer chute. Not only was the belt wearing, but the coal was degrad-ing as it hit the belt. By simply reducing discharge angle, much better results were obtained without damage to the belt or materials.

A lower discharge angle slows the material down as it travels around the curve. As the flow rate is not changing, the depth of material will increase around the curve as the material slows down. This slower, deeper stream is at more risk of stalling and blocking, so there is a balance required between optimizing belt loading and minimizing the risk of blockage. This is particularly critical with stickier product and/or with liners of higher frictional value and irregular sur-faces and joints.

There is a target range where the best combination of these values lie. This is calculated by taking into account many factors, including materials, drop heights, belt speeds, etc. This delicate balance is usually best determined by an experi-enced chute designer.

Higher impact angles and perpendic-ular velocities increase the risk of impact damage by foreign objects and larger product sizes. Shallower angles allow the objects to be better deflected.

How the spoon affects center loading

Loading the receiving conveyor cen-trally requires the product to enter the spoon in a controlled manner. The spoon can correct a certain amount of asym-metrical loading, but the entire transfer system should be designed to allow the spoon to perform its prime function of loading the belt as softly, centrally and close to belt speed as possible.

When a chute operates at a capacity less than it was designed for, the objects do not act as a continuous stream of material. It won’t load symmetrically into the spoon and it will begin to behave more like individual particles, resulting in a loss of controlled flow and potentially spillage. The need for skirting

Higher impact angles, velocities and differential velocities also will increase the spread of product on impact. This will

Figure 4. Optimized belt loading with lower discharge angle.


cause the material to lay flat in the belt trough, rather than piling up in the trough at its natural surcharge angle. By reducing the height in the belt trough, the material must get wider, since the flow rate does not change. As the material profile gets wider, it gets closer to the edge of the belt, and will require the use of skirting to keep the material on the belt, which is then another wear and cost item to maintain.

The need for skirting can vary. Most times, the need for skirting depends on if you have controlled flow in your trans-fer or not. While the need for skirting is minimized when you have a quality controlled flow transfer solution, if your transfer does not control the flow from one conveyor to another, there will be a need to skirt the receiving belt to contain the materi-al and prevent spillage.

If needed, skirting is sealed between the lower edge of the skirt boards and the belt to prevent dust leakage. Two ways to make this seal are straight and tangential.

A straight seal is typically a vertical rubber sheet that has the edge of the rubber pushing straight down into the conveyor belt. A straight seal can be compromised by belt sag, and it is often necessary to use an impact bed to eliminate the sag and maintain the seal. Straight seals also require additional mainte-nance to ensure that the edge of the rubber sheet is always in contact with the belt, since the belt will wear away the edge of the rubber seal.

A tangential seal is typically a rubber sheet that has the face of the rubber laying on the trough of the belt to create a face-to-face seal rather than an edge seal. This type of seal can accommodate belt sag, since the face of the rubber seal will

MAiNtENANCE MAttErs

Figure 5. Feeding the spoon in a controlled manner for optimal belt loading.

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conform to the belt sag profile. Tangential seals require less maintenance since they require less adjustment to maintain con-tact between the rubber and the belt. The only downside to a tangential seal is if the belt mistracks too far, the rubber seal can disengage and will not re-engage automatically on its own.

In extreme cases where near-zero dust is required, such as power plants, it might be necessary to have a fully enclosed skirting system that creates a transition section that will allow the dust to settle.

Proper design is keyBecause of the critical nature of transfer points and how they

complement the rest of the belt conveyor system, many issues can be prevented by having a properly designed transfer chute. That’s why it’s important to continually assess your belt convey-or system in a holistic manner. Taking a look at the system both before and after the load point also is important when it comes to evaluating the efficiency of the transfer point.

Taking each variable into account is important to obtain a properly designed transfer point. And while all these factors are important, the true success of the system can be attributed to the technical expertise of whoever is designing it. ~

Matthew J. Koca is a principal flow path engineer for Flexco. You may contact him by emailing [email protected].

MAiNtENANCE MAttErs

Figure 7. Properly designed controlled flow transfer chute.

Figure 6. Flat profile on belt due to improper belt loading.

Decreasing dust with lower impact anglesThe transfer chute at a North American coal-fired

power plant was experiencing dust generation levels that were too high and were violating OSHA (Occupational Safety and Health Administration) allowable standards for respirable dust. In addition to not meeting regulations, it was causing a health hazard for the plant workers.

A new system that utilized low-impact angles allowed material to be redirected gently, reducing material deg-radation and dust levels. In fact, testing was done on the old system and the new system and an 89 percent decrease in dust generation was realized just by rede-signing the chute.

18 ENERGY-TECH.com ASME Power Division Special Section | DECEMBER 2014

Nuclear plant performance improvements with application of longer LP last stage blades

By Mike Jones and Robert Crossland, Alstom Power

AsME FEAtUrE

During the last decade, the authors’ company (Alstom Power) retrofitted the steam turbines in 34 nuclear units on a diverse range of half- and full-speed machines, powered by Pressurized and Boiling Water Reactors. Some of those projects have been described in other papers, with an explana-tion of the novel laser measure-ment and fast-track installation techniques that have been developed to meet the onerous demands of nuclear plants and authorities.

The aging global nuclear fleet has suffered reduced levels of reliability and performance due to effects such as Stress Corrosion Cracking (SCC), moisture erosion and shaft line torsional faults. Alstom has developed a range of steam turbine retrofit solutions that are resistant to SCC and erosion, have extended maintenance

intervals and deliver high levels of efficiency. A portfolio of rear stage blades is available, from which an optimum

design can be selected to suit each project.This paper focuses on the improvements in thermal performance and reliability of a num-

ber of recent nuclear steam turbine retro-fits. It outlines the existing designs and

some of the challenges faced by the plants concerning reliability, oper-

ation and efficiency, and then describes the approach to

addressing those issues by retrofitting with mod-

ern designs. The paper describes

the blading

design and the techniques that are used to evaluate exhaust performance. It also will show the methods that have been used to integrate longer Last Stage Blades into existing LP frames.

The paper concludes by presenting the experience, in terms of performance and installation, of some of the projects.

IntroductionThe authors’ company executed a large number of nuclear

retrofit projects during the last 10 years, including 16 half-speed units in North America and an additional 18 units globally. A total of 114 retrofit cylinders have been installed. (Figure 1)

The main reasons and targets for nuclear steam turbine retrofits can be summarized as follows:

• To introduce a design that is resistant to stress corrosion cracking and moisture erosion.

• To provide a new shaft line that is designed to be clear of hazardous torsional frequencies.

• To reduce maintenance costs by increasing the interval between major inspections.

• To install the retrofits within aggressive timescales, dictat-ed by the reactor re-fueling schedule.

• To facilitate power uprates.• To improve thermal performance and reliability of the

plant.

North America :6 BWR + 10 PWR units1800 rpm10 HP + 37 LP cylinders

Central America :2 BWR units1800 rpm2 HP + 4 LP cylinders

Europe :2 BWR + 7 PWR units3000 rpm and 1500 rpm9 HP and 34 LP cylinders

Africa :2 PWR units1500 rpm 6 LP cylinders

Asia :5 PWR units1800 rpm5 HP + 6 LP cylinders

Figure 1. Distribution of Alstom Nuclear Retrofit Projects for the period 2003-2013.

AreShaftCurrentsDestroyingYour Machinery?Failure to properly ground rotating equipment can result in expensive bearing, seal, & gear damage.

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DECEMBER 2014 | ASME Power Division Special Section ENERGY-TECH.com 19

AsME FEAtUrE

Case study: A 1,245 MWe BWR LP retrofi tThe authors’ company recently retrofitted two units at a

Boiling Water Reactor plant in Pennsylvania. This retrofit was a series of six LP installations performed

for the utility (Refs. 1 & 2). The LP retrofit turbines were designed with a future uprate in mind and are mechanically capable of operating at an output of more than 1,400 MWe. The Last Stage Blade was selected on this basis, operating with higher mass flow to deliver the increased power.

Those LP retrofits are used as a case study in this paper and the LP retrofit solution is shown in Figure 2.

The original rotors were suffering from SCC and the car-bon steel LP inner casings were severely eroded, with holes appearing through the walls that required frequent repair. Failure of LP extraction pipe bellows was becoming more fre-quent, requiring forced shutdown of the units for repair.

The salient features of the retrofit design are as follows:• • A 10-stage design using reaction type blading, designed

for conditions of the +14 percent EPU project.• A 57˝ L-0 blade. The rear stages used in this solution are

designated ‘RS56R’.• Welded rotor construction.• 12 percent CrMo blading, 1.25 percent CrMo inner

casing and 10 percent CrMo blade carriers.• Designed for resistance to SCC and water erosion.• Designed for rapid installation within an outage of 24

days duration, with minimum impact on the retained LP outer frame and hood.

• A shaft line tuned to be clear of hazardous torsional frequencies.

• Replacement of the extraction pipe bellows units.

Some of the design features of this blade include the following:

• High efficiency profile.• Large increase in last stage annulus area, which reduces

‘leaving loss’ and improves performance.

ASME Power Division: Turbines, Generators and Auxiliaries Committee

A Message from the ChairThe ASME Power Division’s

Turbines, Generators & Auxiliaries Committee (TG&A) is comprised of a dedicated group of industry and academic professionals. This group volunteers its skills, knowledge, experience and time in the pursuit of enhancing the understanding and promotion of new developments in technology relevant to Steam-Driven Turbines, Generators and associated

Auxiliary systems. TG&A sponsors an interest driven track along with other Committees within the Power Division, at the ASME Power Conferences each year at locations through-out the country. Our next event will be during the ASME Power & Energy Conference in San Diego, Calif.

Our most recent conferences have included sessions pre-senting peer-reviewed technical papers covering, “Steam Turbine and Generator Repairs, Refurbishments and Retrofits,” “Design and Analysis Topics Pertaining to Turbo-Machinery” and “Turbine Integrity and Protection.” Additional offerings frequently include a 16-hour pre-conference, turbine and generator workshop, tutorials based on current industry concerns, panel discussions with leading subject matter experts from industry, academia and OEM representatives. In 2014, we presented a newly minted workshop on writing, editing, reviewing and publishing papers that was open to all confer-ence attendees, and this will become a standard offering for conferences going forward. We also celebrated with our com-mittee member, Harry Martin, who was elevated to ASME Fellow status this year. Congratulations Harry!

If you are interested in joining us, we generally meet twice each year, roughly six months apart during the ASME Power Conference, and the PowerGen Conference. The committee is open to discussing topics of immediate and long-term interest to the industry, and we often find the conversations to be stim-ulating and energetic. Following initiatives within the ASME itself, TG&A has opted to informally retain our governance by-laws for the committee; guiding our actions through vari-ous situations including leadership progression and volunteer-ing for organizational roles for the annual conferences.

We look forward to meeting you at the 2015 ASME Power & Energy Conference!

Jesse J. ShuttPrincipal ConsultantCygnature Consulting, LLC+1 (610) 308-5866 - Mobile+1 (610) 790-9016 - [email protected]

Figure 2. LP retrofit solution for the 1,245 MWe BWR plant.


• Integral snubber design for blade interconnection.

• Predictable vibra-tion characteris-tics validated by spin pit tests and designed to avoid in-service exci-tation.

• Curved side–entry fir tree root fastening.

• 12 percent CrMo steel forging.

Laser scanningThe authors’

company laser-scanned the existing condensers, LP frames and hoods of the units at each of the three plants involved in this project (each plant has two identical units) and constructed 3D CATIA models of the structure (Figures 5 and 6). The models were used for the design of the retrofit equipment (Refs 1, 2) and also for the performance evaluations described in this paper.

The laser scan (Figure 4) is converted to a 3D model (Figure 6).

Modification of the LP frameThe output of the units in this case study was being

increased significantly – by about 30 percent – from the original rating of the plant. Alstom selected its RS56R solu-

tion to deliver the increased output and optimize the efficiency. The original units had 43˝ L-0 blades and it was identified during the tender phase of the project that some modifica-tion would be required to the LP frame to accommo-date the longer L-0 blade.

A standard feature of this type of LP frame is a ‘keel plate,’ which runs along the axis of the structure in the lower half and also along the inside of the hood. Some localized areas of the keel plates were re-profiled to provide clearance to the L-0 blade and diffuser of the retrofit equipment (Figures 3 & 7).

Profiled templates were prepared for the installation

to facilitate accurate flame cutting and grinding of the keel plates. A minimum of material was removed to limit the effect on the LP structure and also minimize the impact on schedule.

The LP frame and hood was modeled by 3D FEA, with the original geometry and with the re-profiled geometry. The stresses and deformation were evaluated, which confirmed that the modifications would have no significant impact on the structural integrity and behavior of the LP frame (Figure 7).

Physical features that influence performanceFigure 8 shows a typical retrofit Nuclear LP retrofit solution

of the authors’ company. There are three principal physical fea-tures that influence thermal performance:

• Rear Stages – last and penultimate stages; for most manufacturers these are standard stages, identical in each application.

• Front Stages – all stages other than the rear stages; these are designed specifically for each application.

• Diffuser and Exhaust Hood – different for each applica-tion; the main purpose is to match the available geome-try to the flow characteristics leaving the last stage blade.

The essence of making a design for an LP retrofit is to select the size of last stage blade to suit the exhaust conditions over the course of a year, and also to take account of possible future conditions, e.g., a power uprate.

The technology (impulse or reaction) is then selected on the basis of cost and performance. This determines the number of stages to suit the available axial space.

The original machine usually defines exhaust hood geom-etry since it is normally impractical to consider any change to the bottom half of the LP outer casing, since this would affect

AsME FEAtUrE

Figure 3. A 57˝ last stage blade.

Figure 4. Raw laser scan model of one of the nuclear turbine condenser struc-tures of this retrofit project.


AsME FEAtUrE

the connection to the condenser. Some minor modifications are often made, but without significant change to the overall structure.

The diffuser is usually adapted to suit the flow emerging from the last stage blade to enhance performance. The design of the diffuser also is affected by the method of retrofit instal-lation.

Figure 9 shows the typical operating range for last stage blades. It is desirable to have an exhaust velocity in the range of 500ft/s (150m/s) to 1,000ft/s (300m/s). Operation outside of this range is possible and will not compromise the mechan-ical integrity of the blading, but the performance will suffer and it is strongly recommended that no guarantee should be made of performance outside the design envelope.

At very low annulus velocity, performance drops quickly due to high leaving energy and gross separation. At a high annulus velocity, performance drops due to limit loading.

To put this in context for a 1,000 MW machine, the differ-ence in exhaust loss between 200 m/s (650ft/s) and 300 m/s (1,000ft/s) is approximately 17 MW.

Front stage bladingThe design of the front stage blading is determined by the

following factors:• Choice of technology; reaction or impulse.• The authors’ company normally uses reaction-type blad-

ing for LP modules, particularly for cases with multiple double-flow modules where the blades in the first few stages are relatively short.

• Use of reaction technology usually results in more stages, each with a smaller pressure drop than the equivalent impulse stage so the blades can be narrower (Ref 3).

• Short and narrow blading generally has a better perfor-mance than short, wide blading.

• The root diameter of the front stages depends on the number of stages determined by the available axial space. The tip geometry of the L-2 stage is selected to give a smooth flare in the expansion from the L-2 stage to the fixed blade of the L-1 stage.

• The number and size of the front stages is chosen to match the extraction slots in the casing. Ideally the pres-sure is similar to the original (probably within 0 to -10 percent variation at the same load) to ensure the heater design remains valid.

DiffuserModeling of the diffuser and exhaust hood is a two-phase

process:

Figure 6. Re-profiling of the Keel Plates (circled in red).

Figure 5. A 3D CATIA model of a typical nuclear turbine LP frame and condenser.

Figure 7. Evaluation of LP frame and hood by 3D FEA.


1. CFD model of the last stage and diffuser treated as axisymmetric;

2. Full 3D model of the exhaust hood and condenser.

Exhaust hoodIn previous times it would often have

been thought sufficient to analyze the

diffuser, assuming that the exhaust pres-sure applies at the diffuser exit. However, recent experience has demonstrated the importance of knowing the exact loca-tion of exhaust pressure measurement. Typically, this measurement point is in the duct between LP hood and con-denser tubes.

The flow in this duct is often chaotic; it is influenced by an asymmetric pres-sure distribution at the diffuser exit, as the flow path to the condenser is “easi-er” in the lower portion of the hood.

Furthermore, there are often struts, pipes and other obstructions in the duct that all represent blockages to impair the smooth flow to the condenser.

Figure 10 shows a typical result for the overall analysis, showing the pressure recovery in the diffuser followed by a pressure loss in the exhaust hood.

Retrofi ts with 57˝ LSBTo date, the authors’ company has

used the 57˝ LSB in the retrofit of nine nuclear units that were originally designed and constructed by other tur-bine OEMs. One further unit, originally supplied by the authors’ company, is currently in the retrofit design and man-ufacture phase.

Figure 11 shows the cross-section for a retrofit with 57˝ LSB in anoth-er OEM’s frame (a different OEM to the case study presented earlier in this paper). Comparing this cross-section with Figure 8, it is clear that the casing has much more radial space. This has a significant effect on the performance of the diffuser and exhaust hood.

The pressure recovery factor is usual-ly better in this type of larger LP frame.

Overall performanceLP retrofits are often part of com-

plex projects involving HP retrofits and power uprates. Sometimes the per-formance is measured with pre- and

AsME FEAtUrE

Figure 9. Operating range for last stage blades.

Figure 10. Pressure variation through diffuser and hood.

Figure 8. Cross-section of typical LP retrofit solution of the authors’ company for half-speed nuclear applications.


post-retrofit tests, while some projects have only one post-retrofit test.

Thus it is difficult to be precise in assessing the contribution to an over-all power uprate from an LP retrofit. Nevertheless, an attempt is made in Figure 12.

In Figure 12, the plants labeled G, H & I are units in which the design was similar to the case study presented earlier in this paper (Figure 8). The lower LP contribution and gain is partly attribut-able to the tighter exhaust space in those designs. The plants labeled A-F were other retrofits of nuclear units with a variety of half-speed designs.

The general conclusion is that an LP retrofitted with a 57˝ L-0 blade should bring a gain in output of between 3 percent and 5 percent, by virtue of the improved blade efficiency and the opti-mized diffuser design.

Experience and conclusionsThe authors have described else-

where (Refs 1, 2) techniques that have been used for recent fast-track nuclear installations, with a focus on the LP ret-rofit project for a particular utility. That series of six installations was successfully completed in September 2013 with the following highlights:

• The durations were reduced with each installation by improving the techniques and efficiency through a learning process. The final instal-lation of that series (a 1,000 MWe BWR plant in Illinois) was com-pleted in less than 18 days (Figure 13).

• The LP rotor vibration levels were low; typically 1-2 mils shaft abso-lute peak-to-peak. No rotor had to be balanced in-situ, which is normal for modern retrofits.

• Torsional tests were performed on some units. The results correlated very well against the analysis and confirmed that the shaft lines were clear of the hazardous frequencies and compliant with the client’s requirements.

• The performance guarantees were achieved for all units, with uplift

in generator output typically 4 percent.

• The retrofits used rear stage designs chosen from a portfolio of blading to suit the conditions of each plant. In the case study presented earlier in this paper, the blade was selected on the basis of annual condenser data, which will enable the plant to operate in the future at the EPU condition.

• The snubbered blades are proven by 25 years of successful service experience and the vibration char-acteristics were verified by spin pit tests on these rotors.

• Laser scan models proved to be invaluable in the mechanical design of the retrofit equipment and in assessing the aerodynamic performance of the exhaust system, where 3D modeling was used to investigate the interaction between the blading, diffuser and hood, and then optimize the design.

• The use of reaction-type blading, with more slender profiles, con-tributed to the improvement in performance.

In common with all nuclear steam turbine retrofits, this project was particu-larly challenging and required extraordi-

nary levels of effort, resource and expen-diture. However, the demanding tech-nical requirements and schedule were fulfilled. The authors’ company is now executing a follow-up order to retrofit

AsME FEAtUrE

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Figure 11. Typical retrofit in another OEM LP Frame.


AsME FEAtUrE

the HP turbines on the 1,245 MWe BWR units described in the case study earlier in this paper. ~

Thanks are extended to Dr. G. Singh, Group Head (Aero & Thermo), Steam Turbine Retrofit & Upgrade Integration, Alstom

Power, Rugby, UK, for the CFD calculations used in this paper.

References1. “The Steam Turbine Retrofitting of

Six Boiling Water Reactor Units Using Innovative Engineering and Laser Scanning Techniques”, Proceedings of ASME Power 2009, July 21 - 23, 2009, Albuquerque, New Mexico, USA, Jones & Nelmes, Alstom Power, UK,

2. “Fast-Track Installation of Nuclear Steam Turbine Retrofits”, EPRI TGUG Workshop, April 15 - 19, 2013, Rome, Italy, Jones & Nelmes, Alstom Power UK

3. “Conceptual Mechanical Design of a Steam Turbine Project”, Alstom Retrofit Conference 2006, Chicago, USA, Hogg & Glover.

Editor’s note: This paper, PWR2014-32072, 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.

Mike Jones has led the engineering team in the retrofit of six half-speed nuclear BWR units in North America since 2008, consisting of 18 LP inner modules and two HP inner modules, with an order value of around $600 million, a project he will continue to work on until 2014 while also overseeing work on other fossil steam turbine retrofits in North America and China. Jones began his career with a five-year engineering apprenticeship with Rover Cars and later graduated with a degree in Mechanical Engineering from the University of Birmingham (UK) in 1989. You may contact him by emailing [email protected].

Robert Crossland is a global tender manger in Alstom’s Retrofit Business, working mainly on large nuclear retrofits, specializing on the performance aspects. He graduated in Mechanical Engineering from the University of Birmingham (UK) in 1979 and also completed a Graduate Apprenticeship with British Steel. You may email him at [email protected].

Figure 13. Final stages of a 1,000 MWe BWR LP retrofit installation, four days before completion.

Figure 12. LP retrofit – effect on output

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In a centrifugal compressor the compression process is continuous. In a reciprocating compressor the com-pression process is intermittent, or done in steps. Gas is drawn into a cylinder, trapped, compressed by the moving action of a piston, and then discharged. The pressure forces acting on the pis-ton vary throughout this process. In addition, as the piston accelerates and decelerates during back and forth in the cylinder, non-steady state inertial forces are created.

The combination of pressure and inertial forces create varying forces during each revolution of the com-pressor, which are transmitted to the main crankshaft compressor bearings, then through the frame to the founda-tion. In a horizontal-balanced opposed reciprocating compressor, these forces can be balanced by an opposing piston and further optimized by manipulating the weights of the rotating parts.

But there will always be some unbalance, which also will create

moments. These unbalanced forces and moments are one of the causes of reciprocating compressor vibrations. Loosening of bolts, cracked piston rods, bearing damage, grout deterioration, etc., can cause the vibration to increase. If not corrected, these faults can eventually lead to a sudden catastrophic failure.

Crankcase vibration monitoring and protection has been used for decades to identify deterioration in the mechanical condition of reciprocating compressors and to prevent cata-strophic failures. However, reciprocating compressor vibration trends can be difficult to evaluate. Many faults in reciprocating compressors, such as mechanical looseness, create very short duration pulses that have little or no effect on the overall vibra-tion. Changes in machine operation can result in different vibration behavior, and if the vibration protection methods and/or shutdown threshold limits do not accommodate this, spuri-ous vibration trips can result. If this happens too often, then the system is not effective in identifying a machine problem.

In this article, a case study of a problem with spurious recip-rocating vibration trips will be discussed. Different vibration sensors, vibration limits and installation of vibration sensors on reciprocating compressors also will be discussed.

Reciprocating compressor vibration problem

By Patrick J. Smith

Figure 1.

Figure 2.


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Compressor configurationThis case study pertains to a 4-throw, balanced opposed

reciprocating compressor. The drive train consists of a 7,200 HP, 327 RPM synchronous motor directly coupled to the com-pressor. The drive train does not include a flywheel, but there is a large worm gear mounted on the drive side of the compres-sor that is part of a barring device. The compressor cylinders are all double-acting. This is a multi-service compressor consisting of medium- and high-pressure process gas services feeding two different pipelines. This compressor was originally fitted with head end cylinder port unloaders, head end clearance pockets and recycle valves for both services. The unloaders were used for step capacity unloading and the recycle valves were used to recycle the excess compressed gas. An infinite step unloading system was retrofitted two years later to reduce compressor power by eliminating recycle.

The compressor is fitted with two earth-quake type vibration switches mounted on the crankcase. The controls are configured to shut down the compressor if either switch activates. The compressor configura-tion is shown in Figure 1.

Vibration problemThree months after retrofitting the

infinite step unloading system, there were several spurious vibration trips. In each case, no problems were identified and the com-pressor was successfully put back in service.

Reciprocating compressor vibration limits

There are no universal reciprocating compressor frame (crankcase) vibration limits. Manufacturers and third party con-sultants have difference criteria. What is important is that the vibration levels are not high enough to cause fatigue failures or premature wear of compressor components. So this can be different from one machine to another. It also is important that the vibration is measured at a location and ori-entation that is aligned with the unbalanced forces and moments. In a horizontal, bal-anced opposed compressor, the unbalanced forces and moments are transmitted to the main bearings. For a 4-throw compressor, it is common to install frame mounted vibration sensors on each end of the crank-case about halfway up in line with a main bearing. In some cases the vibration sensor might be mounted in line with another

main bearing in the middle of the crankcase that is adjacent to pair of opposing throws.

The allowable vibration limits for the compressor that is the subject of this article was 0.4˝/second, measured at the vertical centerline of the crank case in line with any main bearing.

Vibration sensorMost reciprocating compressor frame vibration is at a fre-

quency corresponding to the operating speed. Since these machines operate at relatively slow speeds, a velocity transducer or a low frequency accelerometer are routinely used to measure

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vibration. However, impact events in the compressor can cause short duration pulses, which can have little effect on the over-all frame vibration, especially at an early stage of a developing problem. Vibration levels also vary throughout the rotation of the crankshaft and can vary with different loading steps and dif-ferent process conditions. This can lead to insufficient warning and machine damage if the vibration trip point is set too high, and false trips if the vibration set point is set too low.

Measuring vibration on the crosshead or distance piece of each cylinder and using an impact transmitter that mea-sures shock pulses can be a more effective way to monitor the

mechanical condition of the machine, and provide protection in case there is a fault. There also are some impact trans-mitters that include some signal condi-tioning that further enhances condition monitoring. However, either approach requires more vibration sensors, which increases cost and the potential for more shutdowns due to instrument issues.

The machine that is the subject of this article incorporated two mechani-cal “earthquake” switches. The location of the switches is shown in Figure 1. A seismic switch is an accelera-tion sensitive device that responds to acceleratory shock. The switch can be adjusted to activate at a level above the normal vibration level. These mechan-ical switches respond well to sudden changes in vibration due to instanta-neous shock loads that are typical of mechanical faults in reciprocating com-pressors, and can be set at a level that should protect the machine and prevent a catastrophic failure. The switches that

were used on the machine that is subject of this article did not incorporate any vibration output signal. So vibration levels could not be trended and the switches would simply activate at a present value above the normal operating level and trip the compressor.

InvestigationDuring commissioning of the compressor, a portable vibra-

tion meter was used to measure vibrations at various load conditions and at various locations along the crank case aligned

Figure 3.


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with the main bearings. The highest measured vibration level with the machine when it was fully loaded was 0.23˝/second.

As mentioned earlier, the compressor ran for two years without experiencing a vibration trip – but three months after retrofitting the infinite step unloading system, the machine experienced a vibration trip. The switch in the middle of the machine (switch “B” on Figure 1) tripped the compressor. The operating trends were carefully reviewed, the machine was barred over, some minor inspections were performed and the vibration switch was inspected. No issues or concerns were uncovered. However, the vibration switch was replaced just in case there was an issue with the switch. The machine was test run on nitrogen before it was converted over to process gas and put back into service. At full load, the measured vibration adjacent to the switch that tripped the machine was 0.21˝/second. This was a little higher than the 0.15˝/second that was measured at this same location during com-missioning.

The vibration switch trip point was increased slightly to minimize the chance of another spurious trip. However, switch “B” activated again, and again nothing was found wrong. A temporary vibration transmitter was then installed adjacent to the switch to be able to trend the vibration. The DCS scan time for the transmitted vibration sig-nal was 0.5 seconds. The measured vibration trended between 0.13 and 0.20˝/second depending on loading. During another trip, no discernible vibration change was seen.

The mounting of the switch was reviewed. As shown in Figure 2, the switch was mounted on a cover plate in the middle of the crankcase and not in line with a main bearing. In this picture, the temporary vibra-tion transmitter also is shown. The location on the crankcase and cover plate mounting is not as rigid as a location on the crank-case in line with a main bearing. A minor change in machine vibration due to changes in load or operating conditions could result in a larger vibration response at this loca-tion. It also is possible that the infinite step unloading system that was retrofitted might have had an impact on the overall vibration levels and a higher vibration response at this location. The switch was moved to the other side of the pair of opposing throws, at the one end of the machine, and was mount-ed solidly to the frame. See Figure 3. After making this change, there were no more vibration trips. The compressor has now

operated for more than 5 years without experiencing another vibration trip.

ConclusionsAs described in the article, troubleshooting reciprocating

compressor problems can be challenging. In some cases, find-ing the problem is easy and in other cases it can be difficult to determine if there is a machine problem or a vibration mea-surement issue. The problem described in this article dealt with a vibration switch mounting issue. Reciprocating compressors vibrate and the measured vibration is a function of the rigid-

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ity of the vibration sensor mounting. A similar issue can occur with mounting vibration sensors on brackets, which is commonly done on smaller machines. The picture in Figure 4 shows a seismic switch mounted on a bracket. The sensitivity on the switch had to be adjust-ed to the maximum level to prevent the switch from activating during compressor operation. Using a hand held vibration meter, the vibration on the bracket was found to be significantly higher than on the crankcase adjacent to the bracket. After the bracket was replaced with a more robust bracket, the vibration switch could be adjusted to a more reasonable position that better reflected the crankcase vibration.

Vibration protection is used to prevent catastrophic failures in reciprocating compres-sors. Vibration monitoring also can be used to evaluate the mechanical condition of the compressor. However, there are no universal vibration limits, and various vibration sensors and monitoring systems can be used. Some machines might be fitted with simple seismic switches and some with more sophis-ticated impact transmitters. Some also include the use of a key phasor probe to monitor vibrations with crank angle position. Cost, machine design, application, reliability requirements and other parameters all affect the decision on what type of vibra-tion protection and monitoring is appropriate for a specific machine. ~

References1. Lickteig, Charles A., and Parchewsky, Robert, “Reciprocating

Compressor Condition Monitoring,” Proceedings of the Thirty-Sixth Turbomachinery Symposium, 2007

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 [email protected].

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Sohre Turbomachinery Inc. www.sohreturbo.com 18

Unimar -Light & Control Solutions www.unimar.com 11

Wabash Power Equipment www.wabashpower.com 23

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