May 2017 by Energy-Tech Magazine

Producing the world's finest heat engine 8 • Impeller Failure 19 • Assessing the life cycle 22

ENERGY-TECH A WoodwardBizMedia Publication

MAY 2017

www.energy-tech.com

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

Choosing economical turbine water induction system upgrades

Our Lean Master certified instructor, Brion Hurley, is principal Lean consultant at Rockwell Collins. He will introduce the history of Lean concepts, derived from the Toyota Production System, and explain how and why they have come full-circle back to the United States. Results of Lean initiatives have led to increased customer and stakeholder satisfaction, reduced costs, reduced risks, increased sales, and more flexible and agile organizations. Perhaps the largest benefit has been more engaged employees, where people enjoy the work they do. Lean is not a new concept, as this approach has been used by many companies and organizations for the past three decades. However, most of the effort over that time has been done at large corporations, and only recently have they been adopted and embraced by smaller organizations and agencies. Examples of lean successes can be found within city and state agencies, utilities, nonprofits, law firms, military, public schools, startup companies, movie studios and even farming!

The course will be broken up into 2-hour webinars over 3 days Session 1

Session 2

June 20: Lean Overview

June 21: Lean Tools Part 1

• Lean History • Lean Principles • Value vs Non-value added • Gemba Walks • 8 forms of waste (TIM WOODS) • PDCA and A3 • Getting Started

• Value Stream Mapping • 5S • One Piece Flow • Kanban • Kaizen • Poka-Yoke • Setting up a kaizen event

Session 3 June 22: Lean Tools Part 2 • Standard Work • Takt time • Standard Work In Process • Work Sequence • Load Leveling • Visual Controls and Management • Cellular Layout • Next Steps

After completing this course, attendees will be able to explain the core principles of Lean, identify waste in their processes, and become familiar with tools and techniques that can help reduce or eliminate the waste in the processes where they work and volunteer. Intended Audience: Engineers and managers, or anyone who is interested in learning techniques to improve efficiency and processes. Continuing Education Units: 0.60 CEUs

Learn more and register at www.Energy-Tech.com/Lean

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Energy-Tech (ISSN# 2330-0191) is published quarterly in print and digital format by WoodwardBizMedia, a division of Woodward Communications, Inc. WoodwardBizMedia assumes no responsibility for inaccuracies, errors or advertising content. Entire contents © 2017 WoodwardBizMedia. All rights reserved; reproduction in whole or in part without permission is prohibited.

FEATURES

By Nathan Ehresman, Valin Corporation

COLUMNS

Editorial Board (editorial@WoodwardBizMedia.com) Bill Moore – Director, Technical Service, National Electric Coil Ram Madugula – Executive Vice President, Power Engineers Collaborative, LLC Kuda Mutama – Engineering Manager, TS Power Plant Tina Toburen – T2ES Inc. Editorial views expressed within do not necessarily reflect those of Energy-Tech magazine or WoodwardBizMedia. Advertising Sales Sue Babin – sue.babin@WoodwardBizMedia.com or call 773-275-4020 Keith Neighbour – keith.neighbour@WoodwardBizMedia. com or call 773-275-4020 Graphic Artist Eric Faramus – eric.faramus@WoodwardBizMedia.com Address Correction Postmaster: Send address correction to: Energy-Tech, P.O. Box 388, Dubuque, IA 52004-0388 Subscription Information Energy-Tech is mailed free to all qualified requesters. To subscribe, go to www.energy-tech.com or E-mail circulation@WoodwardBizMedia.com Media Information For media kits, contact Energy-Tech at www.energy-tech.com or sales@WoodwardBizMedia.com Editorial Submission Send press releases to: Editorial Dept., Energy-Tech, P.O. Box 388, Dubuque, IA 52004-0388 Ph 563.588.3857 • Fax 563.588.3848 email: editorial@WoodwardBizMedia.com Advertising Submission Send advertising submissions to: Energy-Tech, 801 Bluff Street, Dubuque, Iowa 52001 E-mail: ETart@WoodwardBizMedia.com

Machine Doctor

Impeller failure due to low flow stall By Patrick Smith

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

Heat trace inside coal-fired power plants

Maintenance Matters

Assessing the lifecycle cost implications of filtration options for gas turbines By Dale Grace, Electric Power Research Institute (EPRI)

Mr. Megawatt

The big squeeze By Frank Todd

Turbine Tech

Choosing economical turbine water induction system upgrades Dan Skedzielewski, TG Advisers, Inc. James Kugler, PE, TG Advisers, Inc.

ASME FEATURE

Producing the worlds finest heat engine By Bernard L. Koff

INDUSTRY NOTES

4 31

Editor’s Note and Calendar Advertiser’s Index

ON THE WEB Have you seen Energy-Tech’s weekly newsletter yet? If not, sign up at www.energy-tech.com for the latest technical articles, business news and products in the industry.

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EDITOR’S NOTE

What do you like best about Energy-Tech publications? In a recent survey to our readers we asked the question - What do you like best about EnergyTech publications? The response to this question was overwhelmingly positive. I was surprised at the number of respondents that took the time to fill in this openended question. We heard things like relevance of articles, current, up-to-date, practical, short and thorough articles, deals with real world issues, quality presentations, articles, timeliness, nothing I don’t like, insightful. At the recent Electric Power Conference in Chicago I had the opportunity to walk the show and speak with some of our readers and guess what I heard? Most everyone knew who we were and provided similar comments as our survey. This issue is no different. We have some very informative articles again with more to come throughout the year. Look for articles from ASME, EPRI, Mr. Megawatt, Turbine Tech from TG Advisers and Patrick Smith, our Machine Doctor in this issue. I’d like to pass on a congratulations to the authors of the many articles that we’ve provided over the years to our audience.You’re doing a great job of keeping our audience happy and fulfilled with your topics and content. Keep up the great work! Another area that we touched on in the survey included questions about professional development. 69.18% of the respondents said that their job required professional development. Some want free webinars, some attend online training and others prefer live seminars and conferences. Energy-Tech does all three and has always been a great source for your continuing education. We just concluded a turbine online training course which is now available for download from our website – go to the webinars and events tab at www.energy-tech.com to take advantage of this very informative training session. We’ll be emailing soon with the next online training opportunities and a live conference that we’ll be co-hosting in the Fall of 2017 in San Antonio, TX. Watch for the details. As always, if you have an idea for a new online training course or would like to be a presenter for a course, give me a call at 563-588-3857 or look for us at the 2017 ASME Power & Energy Conference in Charlotte, N.C.

CALENDAR May 17-18, 2017 Premier training event: Proven Troubleshooting and repair options for improved steam & gas turbine reliability and operational flexibility Charleston, South Carolina www.tgadvisers.com June 26-30, 2017 ASME 2017 Power & Energy Conference & Exhibition Charlotte, NC www.asme.org/events/power-energy August 22-24, 2017 Feedwater Heater Operation and Maintenance Seminar Sheraton Station Square Pittsburgh, PA Contact Mary Jane Luddy www.powerfect.com September 12-14, 2017 Turbomachinery & Pump Symposium George R. Brown Convention Center Houston, TX www.asme.org/events/power-energy Dec. 5-7, 2017 Power-Gen International Las Vegas Convention Center Las Vegas, Nev. www.power-gen.com June 20-23, 2018 World Nuclear Exhibition 2018 Paris Nord Villepinte – Hall 7, Paris, France www.world-nuclear-exhibition.com Submit your events by emailing editorial@WoodwardBizMedia.com

I’d love to hear your ideas. Thanks for reading.

Kathy Regan

4 ENERGY-TECH.com

May 2017

FEATURES

Heat trace inside coal-fired power plants Nathan Ehresman, director of business development, oil and gas measurement for Valin Corporation

The need for heat trace There are many components and different varieties of instrumentation within today’s coal-fired power generation plants. In order for these components to continue to operate with maximum efficiency, one must do everything possible to minimize the risk of failure. One element of critical preventative maintenance is keeping everything at a temperature that will not cause instrumentation to freeze. If an operator’s instrumentation fails, the consequences can be disastrous. Without certain instrumentation fully functioning, the operator loses his or her “eyes and ears” of the plant. There is certain equipment that is absolutely critical to a power generating plant performing at an optimal level. This heating requirement can be a tricky practice, however, as heating systems need to be designed in such a way that they provide the necessary heat while taking into account any possible safety hazards. Generally, a plant has an ample amount of combustible materials present. If heating is not done in a responsible, monitored manner, there is a possibility of causing costly fires or in some extreme cases, explosions. Most power generating plants’ top priority is always going to be its workers’ safety. When installing a heat trace system to a plant’s instrumentation, it does have to be sized appropriately, with a good amount of thought guiding where its power point is located. When a heat trace system is configured for a specific plant, there is going to be a home run or grid power connection point

voltage drop somewhere. This location has to be well designed so that it is in a logical place. By paying close attention to this, engineers can be assured there are not more circuits present than necessary, reducing the amount of overall amp draw. A well-planned system will also reduce the amount of installation time required as well, ultimately saving on cost.

Proper maintenance Just as critical as proper installation and setup of a heat trace system inside of the power plant is the maintenance of it. Unfortunately, heat trace does, in fact, degrade over time. Generally, one will observe noticeable deterioration on the heat trace system between and five and ten years into its lifespan. These observations should not be taken lightly. Power plant personnel should make a coordinated effort to check the health of the heat trace system on a regular basis, especially when nearing this time frame. Allowing preventative maintenance experts to gauge the relative health of the heat trace system that is in place will provide the plant with an opportunity to perform upgrades and repairs during scheduled outages. By taking advantage of scheduled outages for required maintenance on the heat trace system, the plant will maximize its ability to avoid unplanned outages due to deterioration. Applications A growing trend in the industry is the use of wireless controls for their heat trace system. By utilizing wireless transmitters, operators are able to completely integrate their heat trace system into the vast amounts of data that is being monitored and analyzed. This benefit is left on the table far too often. This practice comes with

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FEATURES special considerations that must be accounted for. For example, sometimes when these systems are set up, there is an output with the heat trace that is simply going nowhere. An operator must understand what kind of integration or communication is associated with their particular heat trace system. If the heat trace is not communicating properly, the operator will have no real idea of what is happening. Most heat trace systems have an alarm functionality built in to it. This allows a signal to be sent to the operator if a certain line is not functioning properly. There are many instances within power plants where an alarm is “sounding,” but that information is not going anywhere, there

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is no way for the operator to know about it and address the situation. If everything is working, an operator should not have to think about it, but if isn’t, he or she needs to know.

Another growing application of heat trace solutions inside of coal-fired power plants has to do with keeping the chute clean. Many power plants will spray down coal with a water-based chemical solution in order to cut down on dust. However, during colder winter months, this solution can often freeze in the chute. Power plant employees are then forced to dedicate valuable time to cleaning the chute, sometimes taking all day. This can be a costly, potentially dangerous job if not taken very seriously. As a solution to this common problem, a heat trace system can be carefully designed and installed to prevent the coal from freezing. This heat trace solution, if properly done, is a low maintenance solution to this issue as it only requires a cold-weather startup once a year before the temperature begins to drop. This startup can be incorporated into a plant’s regular maintenance, and if done properly, will ensure the heat trace system works correctly in future seasons. • Sharp, Clear Photos & Video

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Heat trace technology is continually growing and more applications are being discovered. Each application presents a unique set of challenges that must be overcome. However, the end result is a more efficient coal-fired power plant that communicates effectively with its operator. ■

• Starting at only $8,995 Nathan Ehresman is the director of business development, oil and gas measurement for Valin Corporation, technical solutions provider for the technology, energy, life sciences, natural resources and transportation industries. Valin offers personalized order management, on-site field support, comprehensive training and applied expert engineering services utilizing automation, fluid management, precision measurement, process heating, filtration and fluid power products. Email questions to editorial@WoodwardBizMedia.com

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ASME FEATURE

Producing the world's finest heat engine Bernard L. Koff TurboVision Consulting Group, Inc.

Abstract The gas turbine is the World’s most complex and versatile heat engine used worldwide for aircraft propulsion, marine applications and power generation. The technology evolution developed since Whittle’s first successful demonstration in 1937 is an exciting story of design innovation using many engineering disciplines. This paper, from a designer’s perspective, covers key design and manufacturing innovations that were developed to produce today’s engines with high specific power, efficiency and durability. Introduction For America, the gas turbine began its exciting “career” when Sir Frank Whittle was sent here from England in 1941 to show us how to design and build the engine he invented and tested in 1937. The CORE of the gas turbine, Compressor - Combustor / Reactor - Turbine & Control ------converts the heat to power The General Electric Company was selected to build the first engine since it had experience in rotating superchargers and both Pratt & Whitney and Curtiss Wright were involved building reciprocating engines for the war effort. The GE 1-A was America’s first gas turbine jet engine shown in Figure 11. An upgraded engine, the GE1-5, powered the Bell P-59 aircraft, our first jet fighter.

Advancing high temperature material technology The quest for increasing the power produced by the gas turbine core engine consisting of the compressor, combustor and turbine initially focused on improving the component efficiencies and improved materials to increase the turbine inlet temperature. The first turbine blades were produced using high tensile strength forged materials which also exhibited high fatigue strength. A transition to cast materials with higher creep rupture capability took place to accommodate higher turbine temperatures. However, the lower inherent fatigue strength of castings presented a design challenge for the turbine engineers. Lower aspect ratio blades were introduced to increase cantilever beam strength and modal frequencies to accept the lower strength castings. A historical account of materials progress from the early forgings to castings and then to directional solidification and single crystal materials is shown in Figure 2.2 Over a 50-year period, the temperature capability was increased by more than 500°F (278°C) through innovative research, processing, design and manufacturing technologies.

Overall, the performance of the Bell P-59 was somewhat disappointing since it was outclassed by the propeller driven North American P-51 in service. The British pilots also found it less effective than the Gloster Meteor, their first combat fighter, in 1943. Figure 2 Progression of turbine airfoil material capability [°C= (°F-32)/1.8]

These innovative research and manufacturing processes produced the materials used for today’s cast and forged engine components. The introduction of directional solidification (DS) and single crystal (SC) superalloys produced a contributing breakthrough of ~200°F (111°C) in the metal temperature capability over multigrain equiaxed cast materials for turbine airfoils.4 The composition is shown by % weight for the second generation SC PWA 1484 nickel-based superalloy castings at temperatures up to 2200°F. Figure 1 America's first gas turbine engine

8 ENERGY-TECH.com

59.3 Ni, 10.0 Co, 2.0 Mo, 6.0 W, 9.0 Ta, 3.0 Re, 5.6 Al, 0.1 Hf ASME Power Division Special Section | May 2017

ASME FEATURE As a comparison, IN718 is among the most used nickelbased superalloys for turbine and compressor rotors and casings at temperatures up to 1250°F. 52.98 Ni, 19.0 Cr, 3.0 Mo, 5.1 Nb, .5 Al, .02B, 18.5 Fe The combustor hot streak gas entering the turbine made it necessary to air-cool the stationary vanes on the early engines and X-40 castings became a standard for some 40 years. Because the rotor blades pass through the hot streaks, they experience a lower average temperature. Also, because the rotor blades are moving, they are subjected to a lower relative temperature. This allowed the use of forged alloy blades with both higher fatigue strength and mechanical properties for more than 20 years.5 Increased combustion gas temperatures drove the blade material selection to lower-strength castings but with higher temperature capability. Dampers under the platforms of the cast blades also became standard features to suppress vibratory response Hot Isostatic Pressing (HIP) (Figure 3) was introduced in the early 1970s by a creative materials processing engineer to reduce porosity and increase both ductility and fatigue strength

Figure 3 Hot isostatic pressing (HIP) process

for castings. The parts are placed in an autoclave and subjected to heat and pressure, which effectively removes the internal porosity by compression. The significant reduction in material flaws reduces internal stress concentrations, resulting in improved ductility and fatigue strength. This process is responsible for reducing the failure rate of castings subjected to high local stresses, while also remaining cost effective.6 Equiaxed castings have many grain boundaries surrounding the crystals of the superalloy, forming failure initiation points in fatigue, creep, and oxidation. The DS castings arrange the crystals in the form of radial stalks, eliminating the weaker grain boundaries in the tensile direction, providing improved resistance to creep, thermal fatigue, and oxidation/hot corrosion. The SC casting process goes one step further by completely eliminating all weaker grain boundaries and providing further improvements in resistance to creep, fatigue, and oxidation 9 ENERGY-TECH.com

ASME Power Division: Fuels & Combustion Technology

A Message from the Chair The Combined Cycle Committee was formed to promote the technological science, development, design, construction, operation and maintenance of combined cycle power plants as well as their major components. The members of the Committee come from varying areas of interest such as electric power generation facilities, developers, equipment manufacturers, insurers, engineering services, consultants and others. Gas turbines power plants technology has come a long way from the first generation prototypes adapted from early jet aircraft engines. The paper featured this month is Bernard Koff ’s first-hand account of the developments in gas turbines from the first successful gas turbine model in 1937 to modern industrial gas turbines that have become a key component of the electrical power generation industry. The Combined Cycle Committee meets twice a year, a summer and a winter meeting to coincide with the ASME Power and the Power-Gen International conferences, respectively. Our meetings are an opportunity to network with professionals with similar interests and are a forum to exchange ideas and learn more about gas turbines and combined cycle power plants. Our upcoming summer meeting will be held at the ASME Power & Energy Conference in Charlotte, North Carolina, June 26 to 30, 2016. If you attend the ASME Power & Energy Conference in June and are interested in Gas Turbine and Combined Cycle Technology, please join our Track and Committee meeting. We look forward to seeing you there! Tony Clark Chair – ASME Power Division; Combined Cycle Committee POWER Engineers, Boise, ID Email: clarkt2@asme.org (Figures 4 and 5). This highly innovative process, originally invented by a visionary materials research engineer whose ideas were not initially accepted, has made it possible to cast a complete turbine airfoil, dovetail, and platform in an SC superalloy.7 Realizing that nickel-based superalloys encounter incipient melting at 2420°F (1327°C), work began to develop thermal barrier coatings for hot section airfoils to prevent oxidation. While superalloy development proceeded, aluminide coatings were first applied in the mid-1970s to meet the demand for increased hot section life. Ceramic thermal barrier coatings (Fig. 6) were applied in the mid-1980s after reaching within 400°F (222°C) of incipient melting (shown in red) with the best DS and SC alloys. Thermal barrier coatings are also applied to the blade outer air seals, subjected to higher combustor temperatures ASME Power Division Special Section | May 2017

ASME FEATURE

Figure 4 Turbine airfoil material evolution [°C = (°F – 32)/1.8]

Figure 6 Thermal barrier coatings [°C = (oF – 32)/1.8]

Turbine rotor inlet gas temperatures above 1900°F (1038°C) require air or steam cooled turbine vanes, air seals and blades.

Turbine airfoil cooling – The breakthrough Today, the jet engine turbine blade is the world’s most sophisticated heat exchanger. Until the mid-1960s, there were three basic schools of thought for the design of the first-stage high-pressure turbine blade: uncooled, convection cooled, and film cooled.

Figure 5 Life improvement with DS and SC turbine superalloys

than the moving blades that are not subjected to hot streak stagnation temperatures.8

Achieving higher turbine temperatures Over the years, the evolution of superalloy materials leading up to the development of single crystal castings capable of withstanding metal temperatures over 2000°F (1093°C) has been well documented. However, the premise that material development for the engine hot section has allowed “unprecedented efficiency” is grossly misunderstood. Figure 6 shows the SC superalloys with TBC have been used successfully in aero engines up to 2200°F for stationary turbine parts and 2100°F for rotating blades.

How can you then explain how gas turbine engines are operating at temperatures more than 1000°F higher than the material melt temperature? The turbine design engineers know the answer to this barrier problem and its cooling! As one aero engineer once told me, “You guys are considered heroes and all you did was to blow cold air on hot parts!” Summarizing options to increase turbine inlet temperature: Turbine design options with nickel-based superalloys; •

Higher rotational speed for reduced relative temperature (1968) + 200-300oF • Radial Convection holes in airfoil (1957) + 250-400oF • Hollow airfoils, convection / film cooling (1969) +1500oF 10 ENERGY-TECH.com

Many advocated that putting cooling holes in the highly stressed turbine blades would lead to failures. General Electric demonstrated in the late 1950s that convection cooled blades using radial holes drilled spanwise into the core of the airfoil with a shaped tube electrolytic machining (STEM) process would not compromise fatigue strength. Material removal via the STEM process did not leave a brittle recast layer subject to cracking. This convection cooling produced a 200°F increase in turbine rotor inlet temperature reducing the size of the core engine for the same power output. The GE YJ-93 supersonic turbojet for the B-70 was the first engine to use the STEM convection cooled blades at 2000°F rotor inlet temperature. Curtiss Wright Aeronautical was a “film-only” group advocating that a thin film of cool air should be used as a barrier between the hot gas and metal. Turbine blades were designed and manufactured in the 1950s using a forged radial strut and dovetail with a brazed on porous sheath forming the airfoil. The concept of the porous sheath airfoil was to discharge air on the airfoil surface to achieve transpiration cooling while protecting the load carrying strut. This concept was not successful because of backflow when the hot gas flowed in and mixed with the airfoil internal cooling air. Curtiss Wright engineer Werner Howald came to GE in 1956 and introduced the film cooling concept for turbine blades. Although these early GE film cooled blades also failed, valuable experience was gained which played an important later role in developing successful cooled blading. A key understanding, simple in hindsight, of what caused the early film cooled blades to fail was that the hot gas pressure surrounding the airfoil must not be higher than the internal cooling air. This led to the understanding that “backflow margin” for the cooling air was required with film cooling to prevent hot gas ingestion. ASME Power Division Special Section | May 2017

ASME FEATURE It is interesting that for many years, both cast and fabricated turbine stator vanes successfully used film holes on the airfoil leading edge to cool the combustion hot streaks. Why the film cooled vane leading edge technology was not adapted to blades has been a contentious issue. A likely reason for not considering leading edge film holes to cool the rotating blades was the continuing fear of encountering high cycle fatigue failures. Funding for film cooled blade research was minimal since the focus was on increasing the turbine and compressor efficiency to produce higher power from the core engine. A breakthrough was made in the early 1970s when an U.S. Air Force turbine component supervisor9 at WPAFB in Dayton, Ohio funded GE to develop a turbine blade using both convection and film cooling. The GE engineers (some formally from Curtiss Wright), worked closely with casting suppliers to produce a one-piece equiaxed casting of a convection/film cooled blade, as well as methods for producing both round and shaped film cooling holes. Film/convection cooled equiaxed blades were introduced successfully into the GE CF6 family of commercial engines. Finally, in the early 1980s, the design, materials, and processing came together at P&W with a team of former GE and PW engineers to produce a one-piece convection/film cooled blade using the new SC materials (Figure 7).10 Internal cored passages form the compartments where compressor cooling air flows in a five pass serpentine and a single passage flowing air to a cavity adjacent to the leading edge. The internal passages have cast in trip strips to promote turbulent flow to increase the convection heat transfer coefficient. Film cooling is provided by strategically discharging air on the airfoil concave pressure surface. The film cooling holes at the leading edge are densely spaced to provide both convection and film cooling where the hot gas heat transfer rate is highest. The suction (convex) side of the airfoil has shaped cooling holes to help keep the film attached to the surface. All suction surface cooling holes are also upstream of the airfoil passage throat to minimize mixing losses. The trailing edge has pin-fin pressure side discharge cooling to minimize thickness

Figure 7 F100-PW-220 SC turbine blade with film and convection cooling

11 ENERGY-TECH.com

to reduce the wake loss. A milestone was achieved in the early 1980s when the blade shown successfully passed an accelerated Tactical Air Command (TAC) 4000 cyclic endurance test involving rapid hot starts and throttle retards. For the film/convection blades, there is a well understood high thermal gradient at the thin leading edge caused by the hottest flowpath gas and the internal passage cooling air. For the GE equiaxed high Modulus cast blades, the cooling air was first “warmed” up by passing it through the mid serpentine passages before passing it up the leading edge circuit. This was required to avoid cracks and rupture. Stress = Strain x E (Young’s Modulus) Surprisingly, and unknown to everyone but the design engineers, for many years is that a major advantage of the SC material is that the coolest compressor discharge air could be passed directly up the airfoil leading edge passage instead of “warming” it up by first passing it through the mid serpentine passages. This is because the SC casting has a lower Young’s Modulus relative to multigrain equiaxed castings. With a lower Modulus, the SC thermal stress is reduced in the thin leading edge wall for the same thermal strain. This allows the cooling air to be passed directly through the hottest part of the cooled passage while minimizing the stress to avoid thermal cracks. In the 1960s, the tangential onboard injector (TOBI) concept (Figure 8) was invented by an engineer at Pratt & Whitney (P&W) to lower the temperature of the compressor discharge cooling air before it entered the first-stage turbine blade. The concept developed into an annulus with turning vanes to accelerate the airflow from axial to tangential rotor speed, decreasing the temperature while minimizing the pressure loss entering the rotor. The pressure drop across the combustor and first stage turbine vane accommodates the TOBI pressure drop and also allows the discharge pressure to be set higher than the turbine flowpath to avoid backflow into the airfoil passages. The TOBI decreases the temperature of the compressor cooling air by 125°F (69°C) for the two-stage turbine shown. The TOBI also decreases the turbine pump work required in bringing the air up to rotor speed before entering the blade. For

Figure 8 F100-PW-229 turbine, cooling the blade cooling air with a TOBI

ASME Power Division Special Section | May 2017

ASME FEATURE cooled turbines, the TOBI concept has been used worldwide for the past 40 years.11 The turbine vanes must accommodate combustor hot streaks, depending on the pattern factor, which can be 400°F (222°C) higher than the average gas temperature. Because the vanes are stationary, they are subjected to the total gas stagnation temperature. The turbine vanes (Figure 9) used in a 4000 TAC cycle accelerated endurance test have extensive internal convection and external film cooling to meet the higher gas temperatures. These SC film/convection cooled vanes set a milestone in durability for high-temperature gas-turbine engines and are used worldwide.

and 600°F (333°C) above the 2420°F (1327°C) incipient melting temperature of nickel-based superalloys. This breakthrough in high temperature turbine technology resulted from a dedicated team effort that combined SC material manufacturing processes, innovative casting suppliers, very creative designers, and government support.

Typically, the stationary turbine vanes for aircraft engines require approximately 10% of the inlet compressor flow for cooling with combustor discharge temperatures in the range of 2800-3200°F (1538-1760°C). At the average relative gas temperature, the rotating turbine blades typically use 4-5% of the compressor flow for air cooling. Although the turbine blades Figure 10 Turbine blade cooling technology with SC superalloy materials: Inlet gas temperature vs. Effectiveness [°C= (°F-32)/1.8]

Figure 10 illustrates the importance of film/convection cooling technology since it allows the turbine temperatures of today’s engines to far exceed the melt temperature of the best nickel-based superalloys. Many of the newest industrial engines are using DS and SC turbine blade alloys with the cooling technologies developed in the aero engines.

Figure 9 F100-PW-220 SC turbine vanes using film and convection cooling

operate at lower gas temperatures than the vanes, the metal temperatures must be reduced to account for centrifugal and vibratory stresses.12 For cooled airfoils, the cooling effectiveness shown in Figure 1013 is defined by the ratio of the airfoil heat load to cooling flow, a measure of how well the airfoil is cooled between the hot gas and cooling air temperatures. The turbine rotor inlet temperature (RIT) base for the solid uncooled blade is 1800°F (982°C), representing the mid-1950s technology. Note that without cooling, there is only a 50°F (28°C) improvement in RIT in going from the first to a later generation of SC material. Progressing to convection cooled blades with a cooling effectiveness of 0.4 allows a 400°F (222°C) increase in RIT. The payoff for increased material temperature capability is amplified as the cooling effectiveness level increases. The SC film/convection cooled blade family with effectiveness of 0.6+ has an RIT capability beyond 3000°F (1649°C). This operating temperature is 1200°F (667°C) above the solid uncooled blades 12 ENERGY-TECH.com

What about using refractory alloys with higher melt temperatures? Considerable research was done to develop alloys with a higher melt temperature to reduce the dependency of using air cooling which reduces available power. Turbine blades were made at in the 1950s at GE using Molybdenum (Mo), a refractory metal with a melt temperature of 4700°F. Since Mo is subject to rapid oxidation at 1400°F the blades were tested with a protective coating. The effort was terminated when small loss regions of the protective coating resulted in severe oxidation of the Mo blades. In the mid-1980s P&W implemented an innovative rapid solidification process (RSR) at considerable expense to develop an alloy of Niobium (Nb), another refractory metal with a high melt temperature, but also subject to oxidation. The RSR equipment involved the use of a ceramic melting crucible to mix alloy combinations, a rotating disc to atomize the melt into micron size particles which was then followed by a rapid quench with helium. Since optimistic expectations were high, the equipment was sized for production. The goal of this initiative was to produce an oxidation resistant alloy of Nb that could be used at 2700°F without cooling. Unfortunately, all the Niobium based alloys developed ASME Power Division Special Section | May 2017

ASME FEATURE oxidized and also exhibited very low ductility. Subsequent analysis revealed what should have been understood before implementing the heavy investment. Unlike nickel based alloys, the Nb crystals have a body centered cubic structure without electrons in the faces to resist oxygen penetration causing oxidation. After expending the allocated resources, attempts were unsuccessful getting the U.S. government laboratories interested in a program to deal with the oxidation issue of refractory metals at the molecular level. The RSR initiative was partially successful in developing and identifying a pyrophoric resistant titanium alloy with higher temperature capability for limited applications. However, this was still a disappointment from the initial goal of producing a higher temperature material for turbine applications. The result of this setback launched an aggressive program to further improve film/cooling technology by developing new highly detailed design and casting configurations for improved cooling effectiveness. This program was successful in developing a new generation of airfoil “super cooling” film/convection configurations..

The compression system While the turbine is a “blow down” system expanding gas to lower pressure creating power to drive the core compressor, the compressor must efficiently pump the inlet air from low to higher pressure. In the early days, critics of the gas turbine concept advocated that the inefficient compressor would absorb all the power that the turbine could produce leaving no useful

Figure 11 Compression system stability audit

net power. This somewhat popular belief lasted until Whittle tested his engine and later flew it in the Gloster aircraft also viewed by invited guest U.S. General Hap Arnold. All major gas turbine manufacturers know that the multistage axial compressor represents the greatest risk to the engine program. Corrective actions required to fix compressor problems are usually extremely costly, and the root cause is often very difficult to determine. Although there are problems that can arise in the hot section, these generally can be fixed by simply increasing cooling flow. As a result, the compressor is widely considered the “heart” of the engine. 13 ENERGY-TECH.com

Air must be pumped to discharge pressure at high efficiency without encountering failures or stall instability induced by inlet distortion, Reynolds number effects, engine transients, acceleration back pressure, and control tolerances. The normal compressor operating line and stall line (a compression limit) is shown as a function of pressure ratio and airflow in Figure 1114. Lessons learned have demonstrated that it is essential for the engine compressor to accommodate the factors shown in the stability audit that have the potential for causing a flow breakdown. Inlet distortion caused by flow separation and Reynolds effects due to the lower air density at altitude decreases the stall line. Control tolerances and acceleration fuel flow that increase combustion backpressure both raise the operating line. Transient thermals, deterioration and hardware tolerances lower the stall line and raise the operating line. The key is to have enough compressor stall margin remaining for safe engine operation. Higher rotor tip speeds, low aspect ratio airfoils, and axial inlet velocity to average wheel speed ratios (Cx/U) in the range of 0.4-0.5 have substantially improved operability. The Cx/U ratio is a key parameter in providing the ability of the compressor to recover from a stall. This parameter was developed experimentally making a major improvement in fighter aircraft subjected to high maneuvers as well as commercial engines subjected to cross wind inlet distortion at takeoff.

Rotor design The major aircraft engine companies were initially polarized on the optimum compressor configurations in the 1950s. GE developed the J79 single rotor engine with a 17 stage compressor using variable geometry stator vanes with a pressure ratio of 13.3. P&W developed the J57, with a two spool fixed geometry compressor. The first (low pressure) compressor had nine stages and the second (high pressure) compressor had seven stages for a combined pressure ration of 11. RR also used fixed geometry stator vanes in two spool and later three spool compressors. Large industrial engines are predominately single spool using multiple compression stages with variable inlet guide vanes followed by fixed geometry stator vanes. A single spool engine operating at 3000 or 3600 rpm can direct drive a generator to produce 50 or 60 cycle alternating current for power generation. Based on lessons learned, the design evolution of the aero engine compressors improved performance, durability, reliability and weight by closely integrating the aerodynamic and mechanical design. A 20-year evolutionary design process is illustrated by comparing the configuration differences in the GE J79 versus the GE F101/CFM56 compressor rotors.15 (Figure 12) The 17- stage J79 compressor rotor has 39 structural parts and 22 flange joints bolted together at the disk rims on the forward 11 stages with dual bolted flanges and redundant load paths on the rear stages.

ASME Power Division Special Section | May 2017

ASME FEATURE The blades have axial dovetails and aft of stage four are retained by the smooth spool spacers forming the flowpath. Blade removal and replacement requires a complete disassembly of the rotor. By comparison, the inertia welded 9-stage F101 (and CFM 56) compressor rotors have only five structural parts and two bolted flange joints. The first three stages have axial dovetails whereas stages 4-12 have circumferential dovetails. All of the blades can be removed without disassembly of the rotor spool. The nine-stage F101 compressor has a pressure ratio of 12, which is only 10% less than the J79, with almost twice the number of stages.

Since the turbine must supply the power to drive the compressor, the focus has always been to increase the efficiency while still meeting the challenging operability requirements. Figure 15 shows the past, current and future projections for the polytropic efficiency as a function of the compressor stage pressure ratio.

An example of this technology adopted at P&W for the PW F100-229 compressor is shown in Figure 1316. The rotor construction also featured internal cooling and one flange connecting the forward three titanium stages with seven inertia welded IN718 stages.Â Today, inertia welded rotors are in service providing maximum beam rigidity in bending and shear for balance retention while ensuring defect free welds and low maintenance. Inertia welding is a forging process that can eliminate defects and achieve

Figure 13 Koff and PW President Richard Coar viewing PW F100-229 compressor rotor

Unlike the adiabatic efficiency, the polytropic efficiency is independent of pressure ratio and is very useful as a measurement tool to evaluate and compare compression systems. The higher polytropic efficiencies contribute directly to increasing the core engine power by reducing the turbine work which increases the pressure and temperature of the exhaust gas. A more recent paper presenting a detailed method was developed for estimating the upper limits of compressor stage efficiency at 95% including losses from surface friction, wake turbulence, wall boundary layer and airfoil tip clearances.18

Figure 12 J79 and F101 GE compressor rotors

strength and ductility within the weld joint that is higher than the parent metal. Energy is stored in a flywheel where a rotor part is mounted, spun, and then moved into contact with a stationary mating part. Forging of the rotor takes place as the flywheel energy is dissipated. When the parameters are set properly there is no melting and resolidification to produce defects such as voids and microcracks.

The combustion system The early aero engines had relatively long axial length combustion sections presumably to achieve complete mixing of fuel and air to minimize hot streaks into the turbine. This resulted in also increasing the axial distance between the compressor and turbine and the need for mid bearing support. With a multistage compressor, a long combustion section and a multistage turbine, these core engines required a minimum of a three bearing rotor support system to meet critical speed requirements.

Increased pressure ratio For turbofan engines, the core compressor is supercharged by the fan and/or low compressor stages raising the pressure ratio. Regardless of the engine configuration, increased pressure levels during either subsonic or supersonic flight are limited to compressor discharge temperatures of 1250Â°F. This is a barrier problem for the forged nickel-based superalloy blades and disks. The progress in turbojet and turbofan aircraft engines is shown in Figure 14.17 Figure 12 J79 and F101 GE compressor rotors

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ASME Power Division Special Section | May 2017

ASME FEATURE Early aero combustor liners were either annular or cannular constructed of sheet metal using spot and seam welded over lapping louvers. The Rolls Royce Adour core engine annular combustor, with the fuel injector system (on left), combustor outer casing, a sheet metal liner and turbine inlet guide vanes, is shown in Figure 16.19 As aero core engine life requirements increased, design efforts focused on improving combustor durability with reduced emissions while still retaining the required engine relight at altitude. The emissions programs were successful in reducing the smoke, carbon monoxide, unburnt hydrocarbons and NOx

Figure 15 Polytropic efficiency vs. equivalent stage pressure ratio

Figure 16 Rolls Royce Adour combustor sheet metal spot and seam welded liner

a tip speed of 1800 ft/sec.23 The compressor was developed over a 10-year period in the Air Force funded Advanced Turbine Engine Gas Generator (ATEGG) program. The compact design allowed the rotor to be straddle mounted on front and aft bearing supports and a departure from other three bearing rotor support configurations. (Fig. 20)

The key core engine component to increasing power The efficiency of the core engine components determines the specific fuel consumption, a key measure of performance. For transportation applications enough fuel must be carried to complete the mission. It is common for aircraft to use flight refueling to extend range.

while also improving the combustion efficiency as shown in Figure 17. 20 The reduction of NOx emissions became the focus in 1990 due to its contribution to ground level ozone and smog, acid rain and atmospheric ozone depletion. This effort continues as a primary challenge for gas turbine applications for aircraft, marine and industrial power generation engines. The durability of the combustion liner enclosing the hot gases became a major challenge for the designers. Several configurations were developed with machined ring and shingle or “floatwall” construction. The concept of having a separate panel as a barrier between the hot gases and the casing shell was invented at GE and funded by the Air Force materials group. PW adopted the concept using cast segments with both film and convention cooling which is being used for both military and commercial core engine combustors.21, 22 Reduced emissions combustors have been significantly reduced in axial length, fuel delivery nozzles have eliminated fuel coking and overall durability has been increased by orders of magnitude as shown in Figures 18 and 19.

Creating a new concept for core engines In 1970, GE developed an advanced turbofan engine for the North American B-1 bomber. The core engine was also used in the CFM-56 commercial turbofan, a cooperative venture with SNECMA of France. This core engine used a highly loaded nine stage compressor at a pressure ratio of 12, a short reduced emissions combustor and a single stage high speed turbine with 15 ENERGY-TECH.com

Figure 17 Reduction in combustion emissions

The core engine turbine produces the power as a function of the inlet temperature. The exhaust gas from the core engine can be used for thrust or converted to power. For large single shaft industrial engines additional turbine stages are added to provide direct drive power. Smaller aero derivative core engines turn at higher rpm and generally use separate power turbines to convert the exhaust gas to power. These power turbines operate at 3000 or 3600 rpm to produce 50 or 60 cycle current. In the early 1980s, a formal initiative was created to understand and define the future path of the gas turbine to reach higher levels of power. Using all the core component improvements previously developed, a convenient data correlation was “discovered” showing that the specific power

ASME Power Division Special Section | May 2017

ASME FEATURE

Figure 20 GE F101/CFM56 common core engine: A new concept in turbomachinery (circa 1970) GE Figure 18 Combustor durability improvements

Figure 21 Core engine performance [°C = (°F-32)/1.8] Figure 19 Relative combustion liner life

(hp/lb/sec airflow) was a function of the turbine inlet temperature shown in Figure 21.24 An innovative design engineer also confirmed that the Brayton cycle ideal performance is a function of the inlet turbine temperature as shown by the formula. It took some time to understand that the power also depends on the compressor discharge temperature which controls the fuel stoichiometric limit. This benchmark correlation launched the famous government sponsored Integrated High Performance Turbine Engine Technology (IHPTET) program contributing needed resources for the advancement of gas turbine research and development. The results of this 20-year program created technologies used in gas turbines throughout the world. The PW5000 demonstrator engine which became the F119-PW-100 turbofan powering the F-22 aircraft was funded by IHPTET. At the formal presentation to Director of Defense, Research and Engineering (DDR&E) to fund the proposed IHPTET program, a goal was identified at a 2X increase in thrust/weight ratio. The design engineers recommended that the program goal should be core engine power, as shown in Figure 21, which impressed the congressional staffers and congressmen. Over the years the thrust/weight ratio goal became difficult to monitor since the engines increased in size, lighter weight materials to replace titanium and superalloys were not developed and other features like stealth were added. However, the power of the core

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engine increased by more than the 2X and this should have been the IHPTET goal that the design engineers recommended and successfully achieved.

Control system evolution The control system is the brain of the gas turbine translating throttle signal requests into single or multiple commands to the various components. For many years complex hydromechanical analog control systems using levers, cams, springs and valves were used to position the variable geometry devices including throttle setting and rotor speed. By the 1970s the complexity of these controls made it very difficult and costly to maintain. The digital electronic control technology underwent significant development before it were considered reliable enough to be used on the commercial B-727 aircraft as an electronic trimmer to the hydraulic control. In the mid-80s, P&W developed the DEEC, a single channel Digital Electronic Engine Control, to be used in conjunction with a small backup hydro mechanical control for “get home” capability. The DEEC was a huge success allowing the F100 engines to be trimmed to maintain thrust to offset deterioration. By the 1990s the P&W engineers designed the Full Authority Digital Electronic Control (FADEC) with sufficient redundancy to eliminate the hydromechanical backup unit. 25 The FADEC has the ability to incorporate many more control features, detect engine failures and both isolate and accommodate them for safety while providing get home capability and quick maintenance. (Figure 22)

ASME Power Division Special Section | May 2017

ASME FEATURE

Figure 25 9HA.02 gas turbine for power generation at 50Hz (courtesy of GE)

Figure 22 Engine control system evolution

Figure 23 F119-PW-100 fighter engine with dual FADEC for the F-22 supercruise aircraft

Industrial gas turbine engines The successful development of the aero engines and their derivatives was transitioned to the large industrial engines that produce much of the world’s power generation. As an example, the new GE 9HA gas turbine (planned 2015 introduction) is among the largest and most efficient of the current generation of large dual fuel gas turbines as shown in Figure 25.27 The 9HA.02 uses the turbine film/convection cooling air system, single crystal materials, aero compressor design, low NOx emissions combustors and electronic control technologies developed for the military and commercial aero engines. At a pressure ratio of 21, the engine produces 470 MW simple cycle with 41% efficiency and 710 MW combined cycle at 61+% efficiency. The reported turbine firing temperature is 2900°F (1600°C). The “A” in 9HA represents the air cooled turbine and a departure from previous turbines using steam cooling. The government sponsored IHPTET program and Independent Research & Development (IR&D) for aero engines deserves recognition for the many major contributions to the advancement of the world’s finest heat engines. It took all the engineers in design, manufacturing, material suppliers, forging and casting houses, testing and validation and marketing and sales to make this happen.

Figure 24 F119 in two pitch vectoring modes

The future

Applying higher core engine power The core engine of the F119-PW-F100 turbofan applied technologies developed over the past 50-years including dual channel FADEC and a pitch vectoring nozzle for enhanced maneuverability on the F-22 stealth aircraft. 26 (Figure 23) The 7 stage core engine with a short axial length compressor, combustor and single stage high pressure turbine is straddle mounted on two bearing supports. The compressor blades are machined integral with the disks to eliminate dovetail attachments, reducing leakage and weight. The F119 core engine produces the power that should have been the goal of the IHPTET program that provided much of the resources. Figure 24 shows the turbofan in two pitch vectoring modes at full afterburning thrust. The core is the world’s most powerful heat engine enabling the F22 aircraft to operate supersonically at the military (non-afterburning) throttle setting.

May 2017 | ASME Power Division Special Section

Figure 26 At the Smithsonian 50th Anniversary of his first engine run in 1937 Sir Frank tells the author how he designed his engine

ENERGY-TECH.com

ASME FEATURE If Sir Frank Whittle (Figure 26) were still here, he would be proud of what his invention created! Both Whittle and von Ohain (the German inventor) were impressed with the technological progress made but were also very knowledgeable about barrier problems that we haven’t yet overcome. To make an attempt on predicting the future, we need to realize that insight is the first step in projecting foresight. Gas turbine power can be increased in the future only if current identified barrier issues are overcome. Based on lessons learned, it takes funding and innovative engineering to work the limiting issues to design and manufacture improved products. Barrier problems that have been with us for many years that limit future progress for the world’s finest “heat engine” can be summarized as follows: • Both forged or cast nickel-based superalloys begin melting at 2420°F (1327°C) • Titanium is a pyrophoric alloy that can self ignite at temperatures of 600°F (316°C) and • Higher combustion gas temperatures produce increased NOx emissions Learning from the past, government support to solve these barrier problems is required and scientists and physicists must be integrated to the conventional gas turbine engineering ranks. Realization that “you don’t know what you don’t know”

and keeping many options open are important to consider in tackling these progress limiting issues. The future ---will be more exciting than the past — Sir Frank Whittle ■

Biography Bernard L. Koff is a pioneer whose leadership in the gas turbine industry produced a host of innovative breakthroughs in design and development. With General Electric and Pratt & Whitney, from which he retired as Executive Vice President, Engineering and Technology, his contributions impacted the design and development of more than half of all jet engines flying. His patents and highly regarded technical papers cover the entire spectrum of jet engine design and manufacturing technology. The score of honors and awards he has received are among the highest that his industry can bestow and include the ASME/AIAA/SAE Daniel Guggenheim Medal, Air Force Association Theodore von Karman Award, AIAA Reed Aeronautics Award (its highest), AIAA Air Breathing Propulsion Award, AIAA Engineer of the Year, AIAA & SAE William Littlewood Memorial Lecture Award, ASME Tom Sawyer Award, SAE Franklin W. Kolk Air Transportation Progress Award, the GE Perry Egbert Award, the P&W George Mead Medal and the Garrett Turbomachinery award. Mr. Koff was also awarded positions of Fellow and Honorary Member of the ASME, Fellow of both the AIAA and SAE and member of the National Academy of Engineering. He graduated in 1951 cum laude from Clarkson University with a BS in Mechanical Engineering and earned an MS in the same field from New York University (1958). Clarkson University granted him an Honorary Doctor of Science Degree, having also recognized him with the Golden Knight Award as a Most Distinguished Alumnus. He is currently a consulting engineer for companies involved in gas turbine design and has published many papers dealing with gas turbine design and development. Questions about this article may be sent to editoral@WoodwardBizMedia.com

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References 1, Univ. of Southampton, Highfield, Southampton, England, U.K. 2, Koff, B.L. Gas Turbine Technology Evolution, AIAA Journal of Propulsion & Power, vol. 20, No. 4, July-August 2004. 3, 8 Ibid 2 9 Jack Richens was awarded a commendation from the secretary of the Air Force for his insight. 10, 14 Ibid 2 15 Rosen, C., Koff, B.L., and Harman, M., Airbreathing Propulsion Component Technologies, AIAA Journal,Vol. 18, No. 6, 1980. 16 Koff, B.L. From Fordsons to Jets, SAE International Power Systems Conference, Phoenix, AZ, October 30, 2012 17 Ibid 16 18 Performance Limits of Axial Compression Stages, Hall, Greitzer & Tan, ASME Turbo Expo, June 11-15, 2012, Copenhagen, Denmark 19 Musee de l’Air, Paris, France 20, 26 Ibid 2 27 GE brochure on 9 HA industrial gas turbine

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ASME Power Division Special Section | May 2017

MACHINE DOCTOR

Impeller failure due to low flow stall Patrick Smith

There are many destructive forces in centrifugal compressors and these machines are more prone to failure when operated at off design conditions. The purpose of this article is to present a case study of an impeller failure that is suspected to have been caused by operating at incipient surge or stall, where unsteady aerodynamic forces excited higher order impeller natural frequencies leading to several blade failures. Introduction This case study pertains to a 3 stage integrally geared centrifugal compressor driven by a 1481 RPM, 6300 KW induction motor. This machine is the main air compressor for an air separation unit (ASU). The gearbox consists of a bullgear and two rotors. The low speed (LS) rotor consists of a pinion with overhung impellers mounted at both ends. The high speed (HS) rotor consists of a pinion with an overhung impeller mounted at one end. All the impellers are a semiopen type. In this design the front side of the impeller is open and the vanes run against a close clearance, non contacting stationary shroud. See Figure 1. The gearbox utilizes tilting pad journal bearings for both pinions and there is a single non-contacting proximity type vibration probe adjacent to each bearing. The pinions are also fitted with thrust collars which are used to transmit Figure 1: Compressor configuration 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. The compressor protection system includes high pinion vibration alarms and high high pinion vibration shutdowns. Compressor performance and surge The compressor performance map is shown in Figure 2. These are a series of performance curves at different inlet guide vane (IGV) angles. For each IGV position there is a curve of discharge pressure verses flow. As shown, for each curve, the discharge pressure increases as flow is reduced. The highest pressure, lowest flow point on each curve is the surge point. Surge is an unstable operating condition in which flow reverses direction somewhere in the flow path. When this happens, the discharge pressure drops and flow reverts back to the normal direction. This cycle of oscillating flow continues until the low

Figure 2: Performance curve

Figure 3: P&ID

flow, high pressure condition is corrected. Although surge starts in one stage in a multi-stage compressor, the flow reversal affects the entire machine. Surge causes high noise, high rotor vibration, and an increase in inlet and interstage suction temperatures. The pressure fluctuation results in significant changes in rotor thrust load and direction which can cause thrust collar and/ or thrust bearing failures. While surge is characteristic of all turbocompressors, it is a condition where, if not corrected via process changes, will lead to machine damage and possible component failure. Variable inlet guide vanes are an efficient method to control the flow of a centrifugal compressor. IGVs pre-whirl the gas entering an impeller which reduces the flow and head (pressure rise) of the compressor stage with little loss in efficiency. While some machines incorporate IGVs on every stage, it is more common to have an IGV on only the 1st stage. The compressor described in this article included an IGV on the 1st stage only. The compressor performance curve in Figure 2 also shows how the flow and pressure change as the IGV is closed. Note how the surge point changes with IGV position. The line connecting the surge points for the different IGV positions is commonly called the surge line. Stall is a localized flow reversal that occurs in a compressor stage. Stall cells typically start to form close to the surge point and so stall is sometimes referred to as incipient surge. Stall is not severe enough to cause a complete flow reversal. Although stall does not generally have as much destructive energy as surge, stall is a potential source of excitation which can also cause an impeller failure. It is more difficult to detect than surge because the overall machine performance and vibration typically remain

May 2017 ENERGY-TECH.com

MACHINE DOCTOR stable. Although stall cells start forming close to the surge point, the margin and magnitude vary from one design to another. Compressor control system The P&ID is shown in Figure 3. The primary control devices include a 1st stage IGV and a discharge vent valve. The primary controls include a 3rd stage differential pressure indicating controller (DPIC), a discharge pressure indicating controller (PIC), and a flow indicating controller (FIC). The controllers are part of the DCS (Distributed Control System) which is used to control the IGV and discharge vent valve. In this application, the compressor capacity is controlled with the IGV based on a signal from the flow indicating controller. This flow is the measured flow downstream of the air clean-up system. The machine discharge pressure is a function of the system back pressure. The 3rd stage differential pressure measurement is the difference between the pressure at a point along the contour of the impeller and the 3rd stage inlet pressure. See Figure 1. This differential pressure measurement is sometimes referred to as a stage tap. The square root of this differential pressure is proportional to flow. Although this is not calibrated flow device, it provides a repeatable signal that can be used for surge control. When the machine was commissioned it was surge tested. At different IGV positions, the machine was surged and the 3rd stage differential pressure and discharge pressured were measured at each surge point. A surge line was then programmed into the DCS based on the square root of the 3rd stage differential pressure and discharge pressure at different surge points. Based on the measured discharge pressure, the surge flow based on the square root of 3rd stage differential pressure is determined in the DCS. This value is compared with the square root of the operating 3rd stage differential pressure. A minimum flow margin to the actual surge flow is maintained which establishes a surge control line. If the compressor flow approaches the surge control line, the control system starts to open the discharge vent valve to prevent the machine from surging. The surge control line for this compressor is set up based on a 10% margin to the actual surge line.

the other stages. Over the next 2 years there were 2 more step changes in 3rd stage vibration. The machine was shut down and the 3rd stage was inspected. The 3rd stage impeller was fouled with moderate amounts of deposits. These deposits were not uniform and caused an unbalance condition which caused the higher vibration levels. These deposits were cleaned off and the compressor was re-assembled and re-started. The vibration levels were significantly reduced and only slightly higher than the levels at the time of commissioning. However, the following year there were several step changes in 3rd stage vibration and the compressor was shut down again to inspected the 3rd stage. However, this time several impeller vanes were found to broken in the exducer section (at the OD). See Figures 4 and 5. Altogether, four blades had pieces that were liberated. The location of the breaks were similar, but some the size and shapes varied somewhat. Discussion The 3rd stage in this compressor controls surge, meaning that this stage surges before the other stages over the entire operating map. This stage also incorporates a vaned diffuser. A vaned diffuser provides a source of excitation which can excite different impeller natural frequencies. This was reviewed with the compressor supplier and it was concluded that the shape of the blade failures was more consistent with frequencies well above one times and two times blade pass frequency. These higher modes are more difficult to predict. However, the nibble shape of the liberated blade material is consistent with these higher order modes. An aerodynamic instability such as surge or stall can produce broad band excitations throughout the impeller. These

History The compressor was installed, commissioned and put into continuous service. The machine ran trouble free for 2 years until there was a step change in the 3rd stage vibration. There were no changes in the vibration in Figure 4: Impeller blade failure

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May 2017

MACHINE DOCTOR compressor was within 4% of the shop tested surge line. It is possible at these low flows that there could have been some aerodynamic instability, such as stall, that excited different blade modes leading to blade failures. A field surge test is primarily based on an audible indication of surge. A destructive instability like stall can occur before surge and can be difficult to detect in the field. Stall might not cause an increase in the rotor vibration or unstable performance, and it may not make a noticeable change in sound.

Figure 5: Impeller blade failure

instabilities can produce random pulsations that can generate very high stress levels in thin blade impellers and excite these higher order impeller blade modes. A close look at the operating trends over a 1-year period prior to the discovery of the broken blades did not reveal any evidence of unstable operation. There were no periods of unstable vibration, flow, pressure or power. However, over a 6-month period there were 4 step changes in vibration. The compressor was shut down after the fourth step change. It is likely that each step change coincided with a blade failure. This compressor is regularly ramped up and down and a closer look at the operating trends over the previous 6-month period showed that the compressor was turned down to lower flows than had been in the previous years. As stated above, the surge line was established based on field test using the square root of the 3rd stage differential pressure and the discharge pressure. Since the square root of the 3rd stage differential pressure is not a true flow measurement, it is not easy to compare a field tested surge curve with a shop tested surge curve. However, using the actual flow measurement from the flow meter downstream of the air clean up system (assuming the discharge vent valve is closed) and the 3rd stage differential pressure, a relationship can be established which will allow for an estimation of the flow from the 3rd stage differential pressure. This was done and is shown on Figure 1 as the “Estimated DCS Surge Line.” As shown, this line is to the left of the shop tested surge line and is a steeper slope.

While it might be possible to thicken the impeller blades to reduce the stress levels and shift the natural frequencies, broad band random exciters like surge and stall could still excite the blades and cause failures. Thicker blades would only address the symptoms of the problem, not the cause, and may only buy more time until the next failure. The corrective action is to operate the compressor further away from the low flow conditions that caused the destructive forces. Conclusions Following the inspection, the 3rd stage rotor was replaced with a spare and the compressor was restated and put back online. Since it is suspected that an impeller failure occurred due to operating the 3rd stage in stall, the short term corrective action is to operate with a higher distance to surge set point. In the future, the machine will be surge tested again and the vibration and performance will be carefully scrutinized for any sign of an instability prior to audible surge. The final data will be compared with the shop tested surge with the intention that the more conservative surge line will be put in the DCS. This case study shows the potential destructive forces that can come from stall and the importance of having a robust surge control system and a good surge test. ■

References 1. Smith, Patrick J., “Destructive Forces in Centrifugal Compressors”, Energy-Tech Magazine, March 2012. 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

Operating Points 1 and 2 shown on Figure 1 are the typical low flow and high flow operating points. Operating Point 2 is about 7% away from the shop tested surge line. Looking at the trends in more detail there were several periods where the May 2017 ENERGY-TECH.com

MAINTENANCE MATTER

Assessing the lifecycle cost implications of filtration options for gas turbines By Dale Grace, Electric Power Research Institute (EPRI)

Selecting the appropriate level of filtration for a gas turbine is a key consideration in minimizing overall unit costs. Appropriate selection of inlet air filters and conditioning can have a multimillion dollar impact on plant profitability over time. In recent years, the Electric Power Research Institute (EPRI) has conducted research to better understand inlet air filtration and conditioning technology for gas turbines and how the matching of filtration technology with gas turbine models and operating scenarios can affect performance and costs. This research has produced several technical reports on filter technology and procurement guidelines for inlet air systems. The research has also led to the development and recent release of EPRI’s Air Filter Life Cycle Optimizer (AFLCO) software for complete life-cycle economic analysis of filter selection as it interacts with gas turbine fouling and performance impacts. The overall goal of this air filtration research and the AFLCO software is to assist plant operators in reducing life-cycle costs and improving plant performance. Air filtration Gas turbines, fired by readily available natural gas, provide the majority of new power generation worldwide. Gas turbines require clean air, virtually free of dirt and particulate, to prevent fouling of the gas turbine compressor. Current state-of-theart gas turbines operate at higher pressure ratios and operating

temperatures. Reduced fouling helps to maintain compressor surge margins, and reduced particulate ingestion helps to keep low-tolerance cooling air passages fully open. The goal of inlet air filtration is to capture the largest amount of particulate by the filter media in the airflow path of the gas turbine, but with minimal impact on pressure drop and change-out frequency. With gas turbines operating at higher temperatures and with downstream components that are more susceptible to problems associated with harmful contaminants, the need for good inlet air filtration in this newest generation of gas turbines is more important than ever. The three chief harmful threats to air turbine compressors are: • Fouling. Solid deposits on compressor airfoils alter the shape and increase roughness. Caused by particles less than 5 microns. • Erosion. Particles wear away airfoil material, altering the shape and increasing roughness. Caused by particles greater than 5 microns. • Corrosion. Alteration of metal surface due to chemical reaction. Occurs with sodium chloride, sulfur compounds, and oxidation at high and low temperatures. Damage is irreversible. The associated maintenance costs of poor inlet air filtration can be thought of this way. Sixty to seventy percent of overall plant expenses are fuel costs. Dirty compressors increase fuel costs up to 5%. Gross revenue is dependent on power output. Fouled compressors can cause an output drop of up to 10%. Related costs may include increased scheduled downtime and maintenance, and potentially unplanned power interruption. Two-stage panel filters are commonly used. At the inlet, weather protection is used to shield against snow, rain, birds, and large debris, and an inertial separator may remove moisture and particles greater than 10 microns. A pre-filter then removes large (2-5 microns) particles, and may be combined with a coalescer to remove excess moisture. The final high-efficiency filter removes small contaminants (< 2 microns). Single-stage conical/cylindrical pulse filters are also often used in high dust environments. See Figure 1 and the sidebar on Filter Media Materials.

Figure 1: Inlet air filters for gas turbines.

22 ENERGY-TECH.com

May 2017

MAINTENANCE MATTER Compressor water washes may also be used. Online washing is somewhat effective at restoring capacity but can lead to erosion if not properly configured. Annual offline washing is highly effective but requires unit shutdown. EPRI air filtration research To help utilities better understand inlet air filtration technology, EPRI conducted a study of filtration options. The research team first surveyed utility members of EPRI’s Combined-Cycle Turbomachinery Program to determine the variability of filter types and brands used in their fleets. Listings were prepared of filter media types and their applicability, as well as filter suppliers and the styles of filter elements they provide. Independent filter testing organizations were surveyed to identify standard tests. Finally, new and used filters were tested in the laboratory, and used filters were inspected and assessed for remaining useful life. The results were published in a technical report (Inlet Air Filtration Assessment: 2016 Update, 3002008665). The report provides a comprehensive description of various styles of filters used in gas turbine inlet air applications as well as a listing of the various filter manufacturers and their styles and brands of filters. Several remaining useful life assessments of filters removed from service are also included, along with a large number of laboratory test results, based on ASHRAE 52.2 and EN 1822 standards, on new filters and used filters removed from service. Specific recommendations are provided for addressing more difficult environmental challenges, such as cold, arctic weather, high humidity, and dusty, dry conditions. EPRI also developed a procurement guideline for inlet air systems (Inlet Air System Procurement Guideline and Specification for Gas Turbines in Power Generation Applications, 3002008666). Information was gathered from various sources, including the open literature and material from gas turbine original equipment manufacturers (OEMs). The guideline identifies key aspects of inlet air systems and provides a comprehensive specification that contains all of the important elements needed to purchase this type of equipment. In addition, it describes best practices for defining the functional design requirements for such equipment. The specification was developed to reflect the most current capabilities and characteristics desired by the utility industry.

Also, when selecting a filter type and configuration, plant operators must consider the initial costs, operational costs, and ongoing maintenance costs for both the filter and corresponding changes in unit performance. Calculations are complex, and a fully functional framework is needed to properly account for all aspects of the life cycle and to provide an opportunity to optimize filter selection and water wash scenarios for specific plant operating conditions. As a result, EPRI developed a software tool (Air Filter Life Cycle Optimizer [AFLCO], v1.01, 3002009696), to assist plant operators in evaluating air filtration options. The AFLCO provides gas turbine operators with an accurate, easy-to-install, easy-to-use program for assessing the life cycle cost implications of various filtration options prior to installation. Utilities can use it to help in selecting appropriate filtration options for their site conditions. The AFLCO provides a comparative analysis between three filtration and operational scenarios. This capability allows users to investigate the most cost-effective options under a range of future operational and environmental scenarios for a broad range of filter types. Operational scenarios include unit load profile, offline and online water wash strategies, cost of fuel, financial assumptions, price of power sold, and filtration options. The AFLCO software program: • Assesses different scenarios side-by-side with different filter configurations • Assesses variations in online and offline water wash schedules • Includes built-in models for a wide range of filtration options • Includes built-in gas turbine performance models • Allows users to create new filter and gas turbine models by changing data directly in the spreadsheet

EPRI’s AFLCO software Optimization of filtration and/ or water washing is site specific. Gas turbines may face different dust concentrations, different types of pollutants present in the air, and different climatic conditions. Figure 2: AFLCO compares NPV of alternative scenarios with base case over time. May 2017 ENERGY-TECH.com

MAINTENANCE MATTER

Figure 3: AFLCO estimates the NPV of case scenarios for the analysis timeframe.

The AFLCO was developed to provide end-users with an intelligently chosen set of default assumptions, but with the ability to customize all key aspects of plant type, operation, operating and maintenance costs, and filter types. This enables a more realistic cost assessment when choosing filtration for a site. Key inputs include gas turbine model and quantity, cycle type (simple cycle or combined cycle), operating profile (service factor, full load, part load), economic parameters (electricity

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price, fuel cost, inflation, and present value discount factor), air filtration (environment, filter selections based on rating, changeout criteria, filter replacement costs), and water wash (online wash, offline wash, frequency). The software allows users to compare a base case, plus two alternativesâ&#x20AC;&#x201D;varying filter ratings, replacement schedule, and water wash schedule, and maximizing net operating revenue to find the optimum scenario.

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MAINTENANCE MATTER Filter Media Materials • Resin-Impregnated Cellulose— Natural fiber media cellulose impregnated with resin, and then thermal-set-cured to provide additional structural stability. • 80/20 Blended Media—80% cellulose and 20% synthetic blended (cellulose and polyester). Media used in majority of pulse (cylindrical/conical) applications— very durable and efficient. • Spun-Bonded Polyester—Formed by thermally bonding continuous finedenier fibers to form a stiff and very smooth surface. Makes a superior cakerelease-efficient media. • 100% Synthetic—Man-made polyester media has superior moisture resistance, different pore sizes, and thickness fibers. Can be electrostatically charged.

Performance modeling includes ambient air particulate loading and size distribution, fractional collection efficiency, compressor fouling and efficiency, and gas turbine output and heat rate degradation. Cost and revenue modeling includes filter costs, water wash costs, fuel costs, gross revenue, and net revenue. Economic modeling includes Life Cycle Cost Analysis, time step integration, inflation and discount factors, and Net Present Value (NPV) of revenue. The objective is an accurate relative NPV comparison of alternatives. See Figures 2 and 3. ■ Dale Grace (dgrace@epri.com) is a Principal Technical Leader in EPRI’s Combined Cycle Turbomachinery Program. You may contact him by emailing editorial@WoodwardBizMedia.com.

PERPETUAL MOTION

• Wet-Laid Fiberglass—Micro-glass fiber produced by a wet-laid process (non-woven) synthetic or comes in single- or dual-phase from 45% ASHRAE to HEPA and ULPA. Optimum pleatability—used in majority of V-bank static barrier filters. • Nano-fiber Media—Fine fibers 0.3 to 0.5 microns (nano-fiber) sprayed onto the substrate of media, forming a web-type micro-porous structure. Great surface-loading media. • HEPA Grades—High-efficiency Particulate Air filter media that removes 99.7% of particles with a size of 0.3 microns (MERV ratings of 17-20). E10E14 ratings—variety of synthetics, nonwoven fiberglass and ePTFE membrane media available. • ePTFE Membrane—Polymer (polytetrafluoroethylene) teflon membrane media. High strength-toweight ratio—(carbon-fluorine) nonsticking hydrophobic—can be laminated to woven and non-woven media and polyesters.

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May 2017 ENERGY-TECH.com

MR. MEGAWATT

Mr. Megawatt: The big squeeze By Frank Todd, True North Consulting

Mrs. Megawatt and I have just entered into the unique world of owning an RV. I believe that RV stands for Recreational Vehicle but sometimes it seems more like Revenue Vaporization. I have noticed that almost everything associated with such an endeavor is an order of magnitude times the cost of what it normally is: “Oh, an RV screw costs $5.00.” Another thing I have deduced is that not all RV parts are the same even with the same manufacturer. I am not sure if more money is spent going back and forth to the store or just the price of the part. This is especially the case for the newbie who does not have the lingo down. Sometimes this can happen to us in the power plant world but the consequences are typically more severe (of course that look of disapproval on Mrs. Megawatt’s face from your last RV toilet modification is pretty severe.) This is a story of a power plant that ended up with significant problems mostly because they did not ask the right questions. There I was being amazed by how the setting sun shines back on the snowcapped San Juan Mountains and getting ready for a nice evening with Mrs. Megawatt, some non-fat pizza and a really old British Mystery when just as I was closing the laptop

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their effects on plant efficiency Prioritize outage activity to ensure the right valves are repaired at the right time Recover lost megawatts and Improve heat rate Reduce fuel use and CO 2 emissions Organize valve information and activity

TP-Plus can be used in these applications Nuclear ● Fossil ● Combined Cycle 970-964-2757 rcd@tnorthconsulting.com www.tnorthconsulting.com 26 ENERGY-TECH.com

that little sound beckoned me to look at the latest email that popped in. I should know better, but I gave a quick glance from my office over to the house and…… clicked. Fortunately I did not have to jump on a plane that evening to somewhere out in the middle of the desert or the windswept Midwest. Katie Kelvin (AKA KK) the thermal performance engineer at the Land of Horizontal Snow (LOHS) Nuclear Power station and one of the best kilowatt hunters in the Serengeti of power plants wanted to chat at the megawatt hunter’s conference that we would both be attending in two weeks. Two weeks later Richie Reynolds and I were standing behind our six foot table with our logo emblazoned on the tablecloth (along with some stains from cheap cabernet,) our pullup banner behind us, little cheesy trinkets strewn among our brochures trying as hard as we could not to look like the slimy car salesmen of the power industry. KK came up and rescued me from the frozen smile stance wanting to discuss a delicate problem at their power station (I could have kissed her but Mrs. Megawatt would not approve.) They had just installed a shiny new high pressure turbine and for some reason they could not pass enough flow to get the plant to full load. Of course in these kind of situations the most common method of solving the problem is to utilize the age old management tool - FPA (Finger Pointing Analysis.) The FPA may be satisfying but rarely solves the problem. I looked over at Richie, with some amount Discover what you’re missing with of guilt, and asked him to hold the fort while Katie and I went TP-Plus CIM over to a table with a fountain pen and moleskin in tow. I knew Isolation Monitoring Software that there wouldCycle be a payback involved but really, nothing on earth could be as bad as watching people make like they really Calculate leakages and were interested■in our services whilevalve all the time having their their effects on plant efficiency eye on our world famous Megawatt pens.

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KK gave me the lowdown the right problem. A monthare ago ensureonthe valves LOHS came up from the outageat in which they had installed the repaired the right time turbine and the great joy of the outage being over was totally megawatts and eclipsed by the ■ fact Recover that they couldlost no longer get to full power. Improve heat rate Flipping open my little book I started asking questions. I asked ■ Reduce use andandCO to look at the design specificationfuel for the turbine some 2 plant data from the emissions cycle before the turbine was replaced. It all became clear as■I started perusing the spec. and the data. Organize valve information and

activity

There are a few reasons why this kind of thing can happen and to put it in FPA terms some are the turbine vendors fault and some areTP-Plus the utilitiescan and be some are nobody’s fault. What it used in these applications gets down toNuclear is the ability●of the turbine to pass mass flow Fossil ● Combinedat Cycle the design conditions. If the turbine area is too small then the turbine becomes the throttling point instead of the throttle (or admission) valves. If that happens then the plant970-964-2757 cannot achieve its design power. rcd@tnorthconsulting.com Another way to discuss this is in terms of valve flow margin. www.tnorthconsulting.com The valve flow margin indicates in percent the available effecMay 2017

MR. MEGAWATT

Figure 3: AFLCO estimates the NPV of case scenarios for the analysis timeframe.

tive flow passing capability of the valve. A flow margin of zero is what us thermal performance engineers call Valves Wide Open (VWO). Flow margin is not to be confused with percent valve opening since the valve position to flow is not a linear relationship.

the reactor. This can account for as much as 1% power over what the reactor is putting in. So you can see that if the turbine was designed for 1% less power than what was actually being delivered that could be a problem. Fortunately LOHS got it right and provided the correct thermal power.

This kind of thing can happen to a fossil, combined cycle or a nuclear plant. Each plant has its own variables that have an influence on what is called the flow passing (or swallowing) capability of the turbine. This plant happened to be a nuclear plant of the PWR (Pressurized Water Reactor) flavor. In a PWR the steam pressure is a function of the primary (reactor) side temperature and the heat transfer capability of the steam generator. There are various things, other than the vendor getting the turbine area wrong that can result in the plant’s current situation.

Moisture separator efficiency – If the moisture separator efficiency is better than anticipated then the amount of steam required to obtain the low pressure turbine inlet temperature is less and that steam has to go somewhere so it wants to go into the high pressure turbine. This of course, changes the available valve margin.

Way back when the plant was making the decision on the turbine replacement, they would have sent a set of design conditions to the turbine vendor that they would use to help with their turbine design. Some of the more important of those conditions are as follows. See figure 1 for reference. Total thermal power – Sometimes this gets confusing with a nuclear plant because there is typically a difference between total thermal power and reactor power. Total turbine power is what the plant can use to spin the turbine and is determined by an enthalpy drop across the steam generator. Reactor power is just that- how much energy is being added by the reactor. The difference between the two is everything added to or taken away by the processes required to operate the reactor. The largest reason for the difference is the reactor coolant pumps which are very large and inject a lot of energy into the fluid going through

Moisture separator reheater terminal temperature difference – Nuclear plants typically (except for once through steam generators or gas cooled reactors) operate on saturated steam into the HP turbine. In most plants the LP turbines receive superheated steam. This LP steam is superheated by main steam. What happens is that some of the steam coming from the steam generators is diverted to the tube side of a large tube and shell heat exchanger and is used to superheat the steam exiting the high pressure turbine. This HP exhaust steam is sent through a moisture separator before it enters the reheater bundles. The amount of steam diverted to the MSRs can affect the amount of steam going through the HP turbine. If the MSR uses less steam than the design flow rate, then more steam is available for the HP turbine which you would think is a good thing until you run out of HP turbine area and the valves are fully open. Feedwater temperature – Since nuclear plants are limited by the core thermal power, if feed temperature provided to the vendor is lower than the actual feedwater temperature then the enthalpy entering the steam generator is higher than what was

May 2017 ENERGY-TECH.com

MR. MEGAWATT expected and therefore the enthalpy rise is lower. Since power is basically the enthalpy rise multiplied by the flow and if the enthalpy rise is lower the steam flow will be higher and thus reduces the valve margin. Steam pressure – The ability to pass mass flow through a restricted area is also a function of specific volume. If the pressure is lower than expected then the specific volume is higher and thus the valve margin reduced. At many PWR stations when the plant comes out of an outage the steam pressure is sometimes lower than the pre outage value by 5 to 15 psi. About 7 psi is equivalent to approximately 1% margin so you can see that if pressure is lower and there is not very much margin left then the plant may be at VWO.

work that Richey Reynolds got us from the megawatt hunter’s conference. ■ Mr. Megawatt is Frank Todd, manager of Thermal Performance for True North Consulting. True North serves the power industry in the areas of testing, training and plant analysis. Todd’s career, spanning more than 30 years in the power generation industry, has been centered on optimization, efficiency and overall Thermal Performance of power generation facilities. You may email him at editorial@WoodwardBizMedia.com.

There are other influences on the valve margin but these are the big hitters. So what happened at LOHS? In a nutshell the turbine design was based on the original heat balance developed in 1865 when Rankine was still alive. His picture was even on the thermal kit (look closely at Figure 1.) Since things have changed since William John Macquorn Rankine was around the poor turbine vendor had the wrong data to develop their new turbine. The more recent plant data would have alleviated much of the problem and excuses for the condition. I suggested that they look into sending more steam to their MSRs by throttling their first stage reheaters. Throttling the first stage reheaters would increase the load on the second stage reheaters and reduce plant efficiency but it would help the valve margin. Choosing between getting LOHS back to 100% power and losing a little in plant efficiency is pretty easy. There are other ways to deal with the valve margin issue such as raising primary temperature, reducing final feedwater temperature or modifying the MSRs but they require more paperwork. I gave KK all my notes and she gathered up her courage to discuss with her management team when she returned to LOHS power station. Katie thanked me for spending so much time with her on this problem and was sorry that I missed out on most of the vendor show. I told her that it was the sacrifice one had to make to help a fellow megawatt hunter and that Rich was probably doing fine without me. As I landed at the San Juan National airport I had a text from Mrs. Megawatt asking if water was supposed to be dripping out of the RV and knew that we would need the 28 ENERGY-TECH.com

May 2017

TURBINE TECH

Choosing economical turbine water induction system upgrades Dan Skedzielewski and James Kugler, TG Advisers, Inc.

Background The accidental introduction of water in any part of a steam turbine can cause serious damage requiring extended outages to make costly repairs. A proliferation of such incidents in the electric power generation industry prompted the American Society of Mechanical Engineers (ASME) Standards Committee to develop a uniform set of design criteria to alleviate the problem. With the recent update of ASME Turbine Water Induction Protection (TWIP) standards and the continued focus on fossil plant reliability, TWIP system upgrades have gained increased focus as capital improvement projects in the Industry. TG Advisers has identified many clients that have experienced major water induction turbine outages, resulting in millions of dollars of damage. In the extreme case, full blade replacements and rotor straightening technologies have been employed to return the unit to service. Forced outage durations can extend to 6 months or greater. The following photo was taken after an LP heater level control failure on a 1960â&#x20AC;&#x2122;s vintage General Electric LP rotor design. Extensive LP blade damage resulted in full last stage blade replacements.

In more severe water induction incidents, turbine rotors have been permanently bowed. Repairs in these cases could be as extreme as full rotor replacement or a combination of weld repair or heat treatment of the bow location in the rotor.

Causes of water induction There are many sources of water induction in a steam turbine. The following is a list of the most common sources that are addressed in the ASME TDP-1 standard: 1. Motive steam systems 2. Steam attemperation systems 3. Turbine extraction/admission systems 4. Feedwater heaters 5. Turbine drain systems 6. Turbine steam seal systems 7. Start-up systems 8. Condenser steam and water dumps (steam bypass) 9. Steam generator sources

Extensive LP blade damage resulted in full last stage blade replacements

May 2017 ENERGY-TECH.com

TURBINE TECH

Figure 1 Extraction steam to FWH

Generating units which were designed and built prior to the development of the design criteria are consequently at risk. To properly assess the status of steam cycle piping systems with regard to the current design criteria, a Steam Turbine Water Induction Protection Unit Checklist is used. Input for the program can be completed by plant and engineering personnel who are familiar with the plant’s configuration. The analysis then compares plant equipment to the ASME standards and identifies where additional protection schemes are required. For example, typical shortfalls which have been identified on vintage steam turbine generator feedwater systems include the following: • Upgraded level transmitters and associated modifications of the digital control system to include inputs and new alarm outputs. • Installation of alternate feedwater heater drains to the condenser with power operated block valves. Typically feedwater heater systems are equipped only with normal cascading drain lines to the next lower pressure heater. Alternate drain lines in many cases are required to meet ASME code requirements.

• Installation of feedwater block and bypass power operated valves where extraction steam line power operated block valves are not practical. Many low pressure feedwater heaters were equipped only with manual block and bypass valves. Upgrading turbine water induction systems can be a very cost effective way of ensuring long term reliability. This is the case not only for older conventional units but also combined cycle plants which have been recognized by the new ASME TDP-1 standard, such as units with axial exhaust LP turbine and condenser configurations. ■ Dan Skedzielewski and James Kugler, PE are Senior Consultants at TG Advisers Inc. You may contact them by emailing editorial@ WoodwardBizMedia. com.

• Installation of extraction steam line power operated block valves. Most units have power assisted non-return valves installed in the steam extraction lines; however, these valves are not leak tight and were originally installed for overspeed protection, not water induction protection.

Figure 2 Low pressure FWH in condenser neck

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May 2017

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