Gas Turbines a Handbook of Air, Land and Sea Applications 2nd Edition by Claire Soares

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Preface The current models of aviation engines on transpacific flights develop about 90,000 pounds of thrust, power generation gas turbines have broken the 450 megawatt gas turbine barrier, and gas turbines are now being used on cruise ships. Gas turbines have come a long way since my first meeting with them. At that point over thirty years ago, we waited a day for the casing on an old 20 kilowatt Brown Boveri to cool sufficiently for us to be lowered by rope harness into the intake for an inspection. Most end users do not part easily with their old work horses, so many of them are still around. The Rolls Royce Avon fleet on the Alaska pipeline, the huge number of globally installed General Electric Frame 5s (the original version, not the newly introduced model), the myriad of Solar Centaurs and Saturns everywhere in the world that needed “just about 3,000 or 1,000 horses” for a pipeline or oil and gas application, the many models of Pratt and Whitney’s JT8D that still make up one of the world’s largest commercial aircraft engine fleet. They work reliably, if inefficiently by today’s standards, surrounded by a work force that can often hear the slightest whimper of distress from their machine—often because they rarely hear one. To some extent, these turbines owe their longevity to the continual design development in the form of service bulletins, decreed “mandatory” or “optional” by their manufacturers. I use quotation marks, as sometimes there are manufacturers who have used the “mandatory” label as a means of upgrading end-user fleets for their own revenue extension. Rather than actual end-user power requirements, the OEM’s motivation was to lower the number of configurations that required a stock of spares, and other profit-motivated objectives. And then other times, as with the JT8D, the bulletins developed took a generic 9,000 pound thrust engine, born in the 1950s to just under 20,000 pounds thrust by the 1980s with one of the most enviable safety records for a gas turbine fleet. Many land based gas turbines, like the old GE Frame 5 have a proven record of specific steam injection designs raising their power output by 20 to 25%. There are many types of basic applications of gas turbines. There are land, sea, and air gas turbines. On land, there are power generation and mechanical drive gas turbines. In aviation, there are large commercial, high performance military, mid range commercial, small fixed-wing, and helicopter engines, maintained to commercial or military specifications. At sea, there are large vessel turbines and smaller ferry turbines. There are offshore applications that must incorporate the sturdiness associated with land use turbines, with the light weight associated with aviation applications, with the corrosion resistance associated with marine applications. There are many types of engineers who are fortunate enough to work with gas turbines. There are end users and OEMs (original equipment manufacturers). Gas turbine specialists and turbomachinery specialists who work on all rotating machinery. Overall systems and project engineers. And manufacturer design specialists who will work on one major turbine component all of their working lives.

There is an indefinable quality about gas turbines that favors those that who somehow develop an instinct for them, regardless of working years spent or formal education accumulated. I have watched humble mechanics point the way for befuddled technical gurus. There are brilliant design engineers who can miss a misalignment source that a millwright can spot blindfolded. There are some engineers who can actually troubleshoot a practical problem, and others who can’t. With gas turbines, there are systems design and specification, commissioning, troubleshooting, failure analysis, retrofit and reengineering, training, technical writing, design development, repair and overhaul, fleet management, and regular operations functions. I have been singularly fortunate in that I have run that entire gauntlet back and forth in power generation, oil and gas, process, military aviation, and commercial aviation on three different continents. No credit to my astuteness: the state of the world kept moving me on (politics is a good thing sometimes). One flash of discernment however, did make it possible for me to hold all of that exposure together not just as a cohesive whole, but one where all sectors could gain from each other. Then in the Canadian Air Force, I was about to take on all the six helicopter engine fleets the Canadian military branches flew. The presentation before me at the 1984 annual American Society of Mechanical Engineers International Gas Turbine Institute meeting (ASME IGTI’s “TurboExpo”) featured an offshore oil & gas man who was displaying the control panel that ruled a platform. In Canada, we had just “piggybacked” on the US F-18 fighter program with a few of the same. The F-18’s F-404 General Electric engine had a condition monitoring system that was, to say the least, intriguing. It occurred to me that the panel displayed on the screen was very similar to the one on the HUD (head up display) of the F-18. And so a “joint” ASME IGTI session that I ran annually from 1985 through 2003, patiently assisted by luminaries like Jim Hartsel (one of the General Electric turbine engineers most responsible for the superior performance of the F-404 and the T700), was born. The committee sponsors included the Aircraft Engine, Controls, Instrumentation & Diagnostics; Materials, Metallurgy & Manufacturing; Marine, and Electric Utilities committees. The idea is to get land, sea, and air people to learn from each others’ experiences. It works. The panel has hosted some of the best brains from commercial and military aviation, power generation, oil and gas, manufacturing, process and petrochemical, performance analysis, marine applications, metallurgical development, and controls instrumentation and diagnostics. Those attendees who are fortunate enough to show up have benefited enormously. It has given aspects of my work a rare flair that is attributable to the company I have been blessed to keep. This book represents much of the expertise in the gas turbine field available today. It is 80 to 90 percent adapted and edited from many brilliant sources and about 10 percent is original writing. That latter portion serves to give the



reader a point of reference that they can measure the extent of their agreement—or disagreement—against. It’s practice for when you have to make decisions that your underwriters, insurance company, and mechanics may challenge. The book avoids the just-one-application bias (say just mechanical drive or just power generation or just aviation or just plain theory) that all other gas turbine books I know of, adopt.

Gas turbine engineers in all sectors, disciplines, and specialties, who looked at the draft, have told me they found its contents useful. Just as importantly, they gleaned information from others’ applications. So besides imparting applications and basic design knowledge, this book is meant to get readers to think across disciplines, across land, sea, and air to the heart of this demanding, powerful and infinitely variable mistress—the gas turbine.

Introduction In the gas turbine world, it is essential for all industry sectors to learn from each other. Despite how expensive reinventing the wheel might be, this does not happen enough or sufficiently. The extent to which it does happen however, is owed largely to the inception of the aeroderivative gas turbine engine. In part fostered by the offshore industry’s need for a lighter-than-industrial-engine-frame, OEMs (original engine manufacturers) took specific aircraft engines and placed them on a light, strong, and flexible base. Some of industry’s largest fleets are aeroderivative. The land based Rolls Royce RB211, Trent, and Avon all had mothers who fly (or flew). A General Electric CF6-80C2 eventually “produced” an LM2500 on the ground. In fact the metallurgy of contemporary General Electric Frame 7 and 9 engines is quite similar to that used for the CF6 mature models. The Rolls Royce Olympus and Spey that are used so effectively in marine, offshore, and conventional land based applications have aero roots. The logic for the panel that I discussed in the Preface continues. When the General Electric first released their F404 engine triple redundancy architecture was relatively new to industrial users. It is now commonplace in modern power plants. The concept of a cycle of gas turbine life used versus a calendar hour evolved from realizing that the leader of an aerobatics squadron might only develop one twentieth of the wear on his engines, as compared with the engines of his followers who have to “hunt and follow” a specific distance from his wings. Algorithm development uses the parameters of time, temperature, and speed essentially, to calculate cycles. Unless the engine is among specific models of Rolls Royce that can use just time and speed parameters for the most part. Additional cooling may cost in some ways but pays off in others. Land based users slowly caught on with experimental work on how much a stop and start to a conventional industrial machine (such as an original General Electric Frame 5) versus a much smaller workhorse (such as a Solar Centaur) was worth. Profit margins are directly affected by how quickly different sectors can learn from each other. The sheer size of GE’s aviation CF680C2 fleet and their land based LM2500 fleet, (the stimulus of GE’s unparalleled financing program notwithstanding) can attest to that. As can the sizes of the Rolls Royce RB211 (land and air fleets). As can the success of the Alstom (once ABB) GT35 both on land and at sea. Note also that as personnel and technology travel across national boundaries, proprietary technical innovations follow them. The wide chord fan blade is an acknowledged Rolls Royce “first.” It was an enviable one as its performance attributes, both in terms of aerodynamic performance and bird (FOD or foreign object damage) chopping ability, verified. The latter rang the bell at 24 pounds of bird (a vulture over the Indian Air approach in Calcutta). In fairly short order, the wide chord fan blade has appeared on other OEM’s models, albeit with different “internals.” Gas turbines and their development are plagued with the whims and dips of global finance and politics. Rarely do

all sectors have the development money required for their progress at the same time. Military aviation engines may have large budgets at a time when funds in the land based sector are scarce. In times of peace, certain military engine development programs may be totally suspended. In more recent wars, the priority with military engines may shift from performance to longevity. The end-user parameter throws the OEM a variable and sometimes exasperating curve. Not all end users are as astute as they’d like to believe. Many of them “shoot from the hip” with unfortunate “brainwaves.” Even when OEMs phase out a model by refusing to service it, some less affluent user generally salvages it, illegally or otherwise. The fact that they might not know the meaning of terms like “not under the stress endurance curve” or “hydrogen embrittlement” does not stop some from midnight raids on the scrap heaps of legitimate shops. That brings us to the “buyer beware” issue. I have spent a little space discussing cases that books rarely touch, such as the case where 5 JT8Ds were sold to a hapless U.S. courier service by a trusted U.S. ally that claimed the engines had undergone “ESV2” (major overhaul complete status). The engines were missing significant components such as inner air seals on the low pressure turbine. The diffuser cases (that have to hold significant pressure) had cracks long enough in them that they should have been scrapped. “Zero timed” overhaul may thus be a function of who’s making that claim. One way the end user can get leverage with OEMs is by joining an end-user group: a lobby of sorts. This is discussed in some detail in Chapters 14 and 17. In the mechanical drive land based world, one former group that did this was called the Gas Turbine Users Association. It was the strength of this forum that persuaded a major manufacturer of 3,000 and 1,000 horsepower turbines to back off obliging many end users who had no use for a specific service bulletin to “adopt it or void warranty.” It was similar “users’ strength in numbers” that had Rolls Royce developing cycle use algorithms for the major hot section components in their Spey and Olympus models, which gave the end user a hefty additional lease of life. In the power generation world, each major model has their own end-user group. Alstom’s (formerly ABB) GT11N group will meet separately from the Alstom GT24 group and so forth. Here the division between end user and OEM can get blurred. Many OEMs now own large shares of power stations. Or they may participate in “BOOT” (build, own, operate, transfer) contracts. Another notable advance is that oil & gas giants are now entering the independent power generation business. Exxon-Mobil, Chevron, and Shell are among those who have moved in a big way on the opportunity to build their own power plants, to whom their refineries and gas fields could then sell their own fuel. I say “in a big way.” When dictated by demographics, oil companies have always made their own power. I cut my power generation teeth at the first Syncrude tarsands project which has always sold excess power back to the public grid. In military aviation, there are CIP (component improvement meetings). In my military chopper days, I recall a



number of CIPs with the U.S. Coastguard most in attendance. In terms of mandate and mission profile, the Canadian helicopter fleets (army, navy and airforce) most commonly resemble the U.S. Coastguard for search and rescue and smuggling/ drug enforcement patrols. In fact some of those profiles might sometimes be more demanding than conventional military operations impose. And so to get maximum benefit for this book, although you might scour the index for mention of “your” model, the more useful stuff you learn may be from applications that run 40,000 feet higher—or lower—than yours. Or a wartime pressed version of “your” aeroengine at sea that had to use heavier fuel than the manufacturer specified. Or a power generation version of your mechanical drive application whose end users happen to have a great deal more budget for financing new repair development or performance analysis system development. OEM design development that also considers the results from these meetings may include optimized controls and

diagnostics (Chapter 9), performance methods (Chapter 10), environmental strategy (Chapter 11), repair and overhaul (Chapter 12), improved testing and installation (Chapter 13), business methods (Chapter 14), and manufacture (Chapter 15). Chapter 19 deals with the design and calculation strategy used by OEMs. The chapter on education also deals with OEM and agency participation in gas turbine educational programs. Hybrid systems (Chapter 16) are taking on a larger profile for energy conservation and other reasons: combined cycle power generation for instance. Fuel cells and microturbines are proving to have their place, independently and in combination with more conventional machinery. The book contains detailed discussion of all gas turbine components (Chapters 1 and 2) and elements of a gas turbine system including instrumentation, monitors, filters and other accessories (Chapters 3 through 8). Specific landmark and case histories on interesting contemporary applications in plants have been included.

Acronyms This is a short list of acronyms that are commonly used in this book. It is not exhaustive and all acronyms are explained where they first appear as well. AMB ATF ATS ASME BAT BOP C&D CB CC CDP CDT CHP CMS CO DDA DOE ECMS EGT EOH FAA FCF FHV GT GTCC HAP HCF HGP HGPI HP HPC HPT HRSG HSI HUD IAE I,C&D IGCC IGTI IGVs IPP LCA LCF

active magnetic bearings altitude test facility Advanced Turbine Systems Program (Siemens) American Society of Mechanical Engineers best available technology balance of plant controls and diagnostics circuit breaker combined cycle compressor differential pressure compressor differential temperature combined heat and power condition monitoring systems carbon monoxide direct drive alternator Department of Energy (U.S. Federal) engine condition monitoring systems exhaust gas temperature equivalent operating hours Federal Aviation Authority fuel cell flexible fuel heating value gas turbine gas turbine combined cycle hazardous air pollutants high cycle fatigue hot-gas-path hot-gas-path inspection high pressure high pressure compressor high pressure turbine heat recovery steam generator hot section inspections head up display International Aero Engines instruments, controls, and diagnostics integrated gasified combined cycle International Gas Turbine Institute (an arm of ASME) inlet guide vanes independent power producer life cycle assessment low cycle fatigue


liquefied natural gas low pressure low pressure compressor liquefied petroleum gas low pressure turbine linear variable displacement transformer molten carbonate fuel cell Mitsubishi Heavy Industries, Ltd. merchant power producer maintenance, repair, and overhaul mean time between failures Motoren Turbinen Union natural gas inlet guide vanes newly industrialized/industrializing countries nitrogen oxides original equipment manufacturer performance analysis programmable logic controller particulate matter pressure ratio reliability-availability-maintainability resistance bulb thermometer relative humidity return on investment rotary variable displacement transformer Society of Automotive Engineers specific fuel consumption solid oxide fuel cell standard operating practice stator outlet temperature small power producer steam injected gas turbines test bed analysis thermal barrier coatings time between overhauls tungsten inert gas turbine inlet temperature vibration analysis variable IGUS vibration monitoring volatile organic compounds water fuel ratio

Notes to the Reader

From the author: 1. For 19 years, I ran a panel session at ASME’s IGTI annual meeting that resulted in attendees considering the gas turbine (GT) experience of end users in other sectors. My own time in gas turbine industry has gone from power generation to mechanical drive to aeroengine and back again, so it is second nature to be able to apply the theory, applications, and experience from one sector to another. As this book covers “land, sea, and air,” my suggestion to the reader is that he or she use this book to do the same, if that’s not already “standard.” 2. Case studies in this book are generally adapted extracts from academic papers that are included with the authors’ or the authors’ parent companies’ permission. If the reader decides to get the complete original paper, I suggest contacting the originating or originating OEM company or authors (if the authors are “independent”). The publisher of said work may be an academic society. As such, its technical work may be run by volunteers. Its core staff may be entirely non-technical and would not be as seasoned as the writer of the work or the OEM company involved. The latter may, for instance, point out that there have been more papers on that same subject, which they may have presented at another society’s venue. Academic society or conference/ publisher offices however, can sell overall proceedings of a meeting, generally supplied on a CD Rom. They could also be a source of archived papers that the originating OEM, whether because of new technology and information attrition through joint ventures and acquisitions, has lost. Most OEMs however, carefully safeguard their “old” material and one ought to consider contacting them first. 3. The global economy and consequential mergers and acquisitions have complicated the gas turbine sector technically, sometimes for the better. One may note that the cross section of a Siemens W501 resembles the equivalent Mitsubishi (MHI) turbine. This is logical if one recalls that Siemens acquired Westinghouse (a US company), which prior to its acquisition, had worked on the forerunner to the W501 in a joint venture with MHI. So in considering any engine, one needs to recall who did the original development engineering and of what the system or component most of interest, comprises. This is especially true in joint venture engines. Purchasers of IAE’s V2500 were heard to sigh with relief when they heard that the oil system was a Rolls Royce design. Rolls Royce is known to not skimp on their cooling whether it be via internal air or lubrication. 4. The changing gas turbine world has also created logistical issues. Brown Boveri (BB) became Asea Brown Boveri (ABB), which still exists and very healthily too. ABB now deals with fans, control systems, and many other critical GT system features. The part of ABB that made gas turbines and GT CCs became ABB Alstom, and then later Alstom (Alstom Power). ABB originally had two





main branches that made entirely different size ranges of turbines. ABB Stal was in Sweden and built the smaller GTs. ABB Switzerland built the larger machines. Siemens (after it had acquired Westinghouse) acquired parts of Alstom Power that essentially included ABB Stal. Soon thereafter, Siemens developed a standardized numbering system for all its GT models that essentially changed the designations of the acquired engine lines and Siemens existing gas turbine model numbers. Due to the complexities that come with item 4 above, I have done the following with respect to all case histories included here. If a paper was originally written by “ABB” for instance, I have left that name as is in the text, even if that engine line now is, for instance, part of the Siemens engine line. This does no disservice to Siemens, as the “change over in model numbers” key by Siemens is included both in this text* and on (potentially updated) the Siemens website. This way, the reader can assess the chronological state of the technology at the time the case was written. Although items 4 and 5 give the reader some responsibility for checking the logistics of the equivalent current model numbers, this avoids the far more serious alternative of confusion on technical issues. If for instance, in the future, the acquiring OEM were to institute a technical modification to a model that may then change the outcomes noted in the subject case, the reader then understands the chain of technical development custody. This is crucial when making decisions regarding, for instance, independent facility repairs or retrofit engineered systems. Most end users (provided they are engineers and not accountants or lawyers) would rather wade through logistical records than acquire a technical problem because they did not understand the design development history of their engine. The other reason I favor this approach is it gives credit for the original case study to the individual people who wrote it. The company they worked for at the time may still be their employer or they may have moved to another OEM, via an acquisition. Or they may work for yet another employer or have retired as “independent(s).” Gas turbine engineers would favor this approach, because they can then read the case about the engine they are interested in, as well as recognize the original authors by name, if they were to meet them at some future date. In the interests of making this book affordable, several source illustrations that were originally in color were adapted to be readable in gray scale. The reader has a choice here; to make future reference easier, I get my students to use colored markers as a learning exercise and for future clarity. The reader can also purchase a copy of all the source documents in which these figures appear in color.

*Siemens standardized model numbers (as per Siemens catalogues) are currently as in the tables below. Consult Siemens catalogues for additional model number details.


NOTES TO THE READER Industrial Applications

Product Type Siemens Gas Turbines



Typhoon Typhoon Single Shaft Typhoon Twin Shaft Tornado Tornado Single Shaft Tornado Twin Shaft Tempest Cyclone GT35 GT10B GT10C GTX100 W251 V64.3A

SGT-100 SGT-100-1S SGT-100-2S SGT-200 SGT-200-1S SGT-200-2S SGT-300 SGT-400 SGT-500 SGT-600 SGT-700 SGT-800 SGT-900 SGT-1000F

Large-Scale Power Applications

Product Type


Siemens Gas Turbines Examples:



V64.3A V94.2 V94.2A V94.3A Examples:

60 V64.3A V84.2 W501D5A V84.3A W501F W501G


SGTS-PAC (GT Driver) SGT-1000F SGT5-2000E SGT5-3000E SGT5-4000F SGT6-PAC (GT Driver) SGT-1000F SGT6-2000E SGT6-3000E SGT6-4000F SGT6-5000F SGT6-6000G

About the Author A professional engineer registered in Texas, and a Fellow of the American Society of Mechanical Engineers (ASME), Claire Soares has worked on rotating machinery for over twenty years. Soares’ extensive experience includes the specification of new turbomachinery systems, retrofit design, installation, commissioning, troubleshooting, operational optimization, and failure analysis of all types of turbomachinery used in power generation, oil and gas, petrochemical and process plants, and aviation. The turbines (gas, steam, or combined cycle; land or aero applications) in question were typically made by General Electric, Alstom power, Siemens Westinghouse, Rolls Allison, Solar, and the companies they formerly were, before some of them merged. Her career experience also includes intensive training programs for engineers and technologists employed by heavy industrial clients. Her specialty areas include turbomachinery diagnostic systems as well as failure analysis and troubleshooting. In her years spent with large aircraft engine overhaul and aircraft engine fleet programs in the United States and Canada, Soares worked on turbine metallurgy and repair procedures, fleet asset management, and aeroengine crash investigation. She also was engineering manager for the first overhaul program in the United States for the V2500 engine (commissioned in 1991).

Gas turbines, land, air, and sea, are Soares’ primary area within the turbomachinery field. Her perspective with respect to gas turbines is that of an operations troubleshooter with extensive design experience in gas turbine component retrofits and repair specification as well as retrofit system design development. Claire has authored or co-authored four books for Butterworth-Heinemann and McGraw-Hill on rotating machinery. See the links below for book details. She also writes as a freelancer, for various technical journals. Ms Soares has an MBA in International Business (University of Dallas, TX), and a B.Sc.Eng. (University of London, external). She is a commercial pilot. Her scuba diving certification and training were in high altitude conditions. She has lived and worked on four continents. Her “non-engineering” time is partly spent on cinematography and still photography. United+States&ref=&community=listing&mscssid=0589M7 ACKL658H5QPFMW2650RBQ26XGD soares&template=&subjectarea=113&search=Go

Gas Turbines: An Introduction and Applications


“The farther backwards you can look, the farther forward you are likely to see.” —Winston Churchill


Gas Turbines on Land 2 Direct Drive and Mechanical Drive 2 Applications Versatility with Land Based Gas Turbines Aeroengine Gas Turbines 5 The Relations between Pressure, Volume, and Temperature Changes in Velocity and Pressure 8 Airflow 8 Gas Turbines at Sea 11 Gas Turbines: Details of Individual Applications 12 Major Classes of Power Generation Application 12 Automotive Applications 17 Marine Applications 18 Aircraft Applications—Propulsion Requirements 23

4 6



The gas turbine is the most versatile item of turbomachinery today. It can be used in several different modes in critical industries such as power generation, oil and gas, process plants, aviation, as well domestic and smaller related industries. A gas turbine essentially brings together air that it compresses in its compressor module, and fuel, which are then ignited. Resulting gases are expanded through a turbine. That turbine’s shaft continues to rotate and drive the compressor which is on the same shaft, and operation continues. A separate starter unit is used to provide the first rotor motion, until the turbine’s rotation is up to design speed and can keep the entire unit running. The compressor module, combustor module, and turbine module connected by one or more shafts are collectively called the gas generator. Figure 1–1 illustrates a typical gas generator in schematic format. The second half of this chapter will deal in more detail with different applications and their subdivisions. At this time, we will look at some typical examples of land, air, and sea use.

Figure 1–2. The basic gas turbine cycle. (Source: Kiameh, Power Generation Handbook. New York: McGraw-Hill, 2003.) Direct Drive and Mechanical Drive

Gas Turbines on Land

The gas turbine itself operates essentially in the same manner, regardless of whether it is on land, in the air, or at sea. However, the operating environment and criticality of the application in question, may make design and system modifications necessary. For instance the gas generator shown in Figure 1–1 may be operating in mechanical drive service to drive compressors that move gas down a pipeline. Essentially the same machine can be used to generate power. It can also be used as a power plant on an aircraft. However the layout, the other turbomachinery supplied with the gas turbine, and optional systems will vary in each case. Let us first look at the basic gas turbine cycle (see Figure 1–2). A comparison can be drawn between the gas turbine’s operating principle and a car engine’s (see Figure 1–3). A car operates with a piston engine (reciprocating motion) and typically handles much smaller volumes than a conventional gas turbine.

With land based industries, gas turbines can be used in either direct drive or mechanical drive application. With power generation, the gas turbine shaft is coupled to the generator shaft, either directly or via a gearbox: “direct drive” application. A gearbox is necessary in applications where the manufacturer offers the package for both 60 and 50 cycle (Hertz, Hz) applications. The gear box will use roughly 2 percent of the power developed by the turbine in these cases. Power generation applications extend to offshore platform use. Minimizing weight is a major consideration for this service and the gas turbines used are generally “aeroderivatives” (derived from lighter gas turbines developed for aircraft use). For mechanical drive applications, the turbine module arrangement is different. In these cases, the combination of compressor module, combustor module, and turbine module is termed the gas generator. Beyond the turbine end of the gas generator is a freely rotating turbine. It may be one or more stages. It is not mechanically connected to the gas generator, but instead is mechanically coupled, sometimes via a gearbox, to the equipment it is driving. Compressors and

Figure 1–1. Schematic of gas turbine. (Source: Bloch and Soares, Process Plant Machinery, Second Edition. Boston: Butterworth-Heinemann, 1998.)


Figure 1–3. Comparison of the gas turbine and reciprocating engine cycles. (Source: Rolls Royce, The Jet Engine. UK: Rolls Royce Plc, 1986.)

pumps are among the potential “driven” turbomachinery items (see Figure 1–4). In power generation applications, a gas turbine’s power/ size is measured by the power it develops in a generator (units watts, kilowatts, Megawatts). In mechanical drive applications, the gas turbine’s power is measured in horsepower (HP), which is the torque developed multiplied by the turbine’s rotational speed. In aircraft engine applications, if the turbine is driving a rotor (helicopter) or propeller (turboprop aircraft), then its power is measured in horsepower. This means that the torque transmission from the gas turbine shaft is, in principle, a variation of mechanical drive application. If an aircraft gas turbine engine operates in turbothrust or ramjet mode, (i.e. the gas turbine expels its exhaust gases and the thrust of that expulsion propels the aircraft forward), its power is measured in pounds of thrust. What follows are examples of operational specifications for land-based gas turbines.

GT26 (ISO 2314 : 1989)

Alstom’s GT 24/ GT 26 (188MW 60Hz, 281MW 50Hz). Both Used in Simple Cycle, Combined Cycle, and Other Cogen Applications. (Source: Alstom Power.)

Alstom’s GT 11N2, Either 60Hz or 50 Hz (with a gear box). Used in Simple Cycle, Combined Cycle and Other Cogeneration Applications. (Source: Alstom Power.)

GT24 (ISO 2314 : 1989)

GT11N2 (50Hz)

Fuel Frequency Gross electrical output Gross electrical efficiency Gross heat rate Turbine speed Compressor pressure ratio Exhaust gas flow Exhaust gas temperature NOx emissions (corr. to 15% O2,dry)

Natural gas 60 Hz 187.7 MW* 36.9 % 9251 Btu/kWh 3600 rpm 32:1 445 kg/s 612 °C < 25 vppm

Fuel Frequency Gross electrical output Gross electrical efficiency Gross heat rate Turbine speed Compressor pressure ratio Exhaust gas flow Exhaust gas temperature NOx emissions (corr. to 15% O2, dry)

Natural gas 50 Hz 281 MW* 38.3 % 8910 Btu/kWh 3000 rpm 32:1 632 kg/s 615 °C < 25 vppm

*In combined cycle, approximately 12 MW (GT26) or 10 MW (GT24) is indirectly produced via the steam turbine through heat released in the gas turbine cooling air coolers, into the water steam cycle.

Fuel Frequency Gross electrical output Gross electrical efficiency Gross heat rate Turbine speed Compressor pressure ratio Exhaust gas flow Exhaust gas temperature NOx emissions (corr. to 15% O2,dry)

Natural gas 50 Hz 113.6 MW 33.1% 10,305 Btu/kWh 3600 rpm 15.5:1 399 kg/s 531 °C < 25 vppm




Figure 1–4. A typical free power turbine. (Source: Bloch and Soares, Process Plant Machinery, Second Edition. Boston: Butterworth-Heinemann, 1998.)

GT11N2 (60Hz) Fuel Frequency Gross electrical output Gross electrical efficiency Gross heat rate Turbine speed Compressor pressure ratio Exhaust gas flow Exhaust gas temperature NOx emissions (corr. to 15% O2,dry)

Natural gas 60 Hz 115.4 MW 33.6% 10,150 Btu/kWh 3600 rpm 15.5 : 1 399 kg/s 531 °C < 25 vppm

SGT-600 Industrial Gas Turbine—25 MW (Former Designation, Alstom’s GT10) (Source: Siemens Westinghouse.)

Technical specifications: Dual fuel Frequency Electrical output Electrical efficiency Heat rate Turbine speed Compressor pressure ratio Exhaust gas flow Exhaust gas temperature NOx emissions (corr. to 15% O2, dry)

Natural gas and liquid 50/60 Hz 24.8 MW 34.2% 10,535 kJ/kWh 7,700 rpm 14.0:1 80.4 kg/s 543 °C 150 m and no base material attack, as was the case with the chromized type. Therefore, with this enhanced coating, comparable to the Tla1 the useable life of the Tla2 has been extended by 100% from one to two HGP inspection intervals including the refurbishment after 33,000 EOH. The enhanced coating is not only applied on new blades but also available for the blades of the original design. Stator Blades Stage 1 and 2 These rows are also supplied with the above mentioned SICOAT 2231 coating to meet the refurbishment intervals of 33,000 EOH. The refurbishment includes cleaning of the oxidized outer surface, by the SICLEAN® method, recoating of the outer surface and potential repair of thermally caused cracks at the trailing edge. During refurbishment the internal cooling passages also require nondestructive surface testing. With increasing operating time, degradation of the internal cooling channels accumulates and also repair measures might not be allowed several times on the same blade. Therefore the scrap rate increases with the number of refurbishment cycles and refurbishment after reaching the 100,000 EOH milestone is considered to be not realistic for these blades. Stage 3 and 4 of the Turbine Blading and Hot-Gas-Path Casings Stator blades in stages 3 and 4 undergo residual life assessment when reaching the 100,000 EOH milestone, as they have potential for continued service. Highly influenced by the operating and repair history and also depending on the material and design variant, the inner casing and the mixing casings are assessed for their residual life after 100,000 EOH.

Tia1, V94.2, Material temperature evaluation after ≈ 33,000 EOH. (Source: Siemens.)

M A I N T E N A N C E , R E PA I R , A N D O V E R H A U L


Repair methods and protective coatings have been continuously improved for those hot components that need regular life extension measures during hot-gas-path inspections. The investigations for life extension of hot-gas-path components after the long operating period of 100,000 EOH have revealed, that several hot-gas-path components have definitely reached the end of their useable life, while others, e.g. rear rows of the turbine blades, may be useable for one more 33,000 EOH period or even longer. Plant life extension including hot-gas-path life extension of V94.2 gas turbines has been applied on 11 gas turbines V94.2. Also a large number of additional plant life extensions are due to take place in coming years. While the basic statements for life assessment and life extension are valid for the whole V94.2 fleet, it must be emphasized, that each gas turbine needs to be evaluated individually because of its individual operating conditions. Up to now, life extension projects involved the early versions of V94.2 with relatively low turbine inlet temperature (TITISO) × 1000°C and with the original hot component design, while many of the future projects will involve a higher TITISO > 1000°C for base load operation with different hot component design. The most profitable plant life extension projects: ●

include not only residual life assessment of the hot-gas path components, but also focus on strategic maintenance aspects to use upgraded hot components for higher durability, longer inspection intervals, lower scope of inspection and overhaul work and subsequently higher plant availability, and also care for modernization opportunities to improve the performance and competitiveness of the operating plant.

Figure 12–60. Upgraded rotor blade row no. 2, V94.2, coating condition after ≈ 33,000 EOH. (Source: Siemens.)

In summary, life extension options for hot components during regular HGP inspections and after long operating periods 100,000 EOH were studied.

The best way is to evaluate these items in a joint project involving the electric power producer and the gas turbine manufacturer.



“Throw your dreams into space like a kite, and you do not know what it will bring back, a new life, a new friend, a new love, a new country.” —Anais Nin


Installation of Aircraft Engines 550 Power Plant Location 550 Air Intakes 551 Engine and Jet Pipe Mountings 552 Accessories 554 Cowlings 555 Installation of Land Based and Marine Engines




Installation of Aircraft Engines*

When a gas turbine engine is installed in an aircraft it usually requires a number of accessories fitting to it and connections made to various aircraft systems. The engine, jet pipe, and accessories, and in some installations a thrust reverser, must be suitably cowled and an air intake must be provided for the compressor, the complete installation forming the aircraft power plant. *Source: Adapted, with permission, from Rolls Royce. The Jet Engine, 1986, Rolls Royce Plc: UK.

Power Plant Location

The power plant location and aircraft configuration are of an integrated design and this depends upon the duties that the aircraft has to perform. Turbo-jet engine power plants may be in the form of pod installations that are attached to the wings by pylons (Figure 13–1), or attached to the sides of the rear fuselage by short stub wings (Figure 13–2), or they may be buried in the fuselage or wings. Some aircraft have a combination of rear fuselage and tail-mounted power plants, others, as shown in Figure 13–3, have wingmounted pod installations with a third engine buried in

Figure 13–1.

Wing-mounted pod installation. (Source: Rolls Royce.)

Figure 13–2.

Fuselage mounted pod installation. (Source: Rolls Royce.)

Figure 13–3.

Tail- and wing-mounted pod installation. (Source: Rolls Royce.)



the tail structure. Turbo-propeller engines, however, are normally limited to installation in the wings or nose of an aircraft. The position of the power plant must not affect the efficiency of the air intake, and the exhaust gases must be discharged clear of the aircraft and its control surfaces. Any installation must also be such that it produces the minimum drag effect. Power plant installations are numbered from left to right when viewed from the rear of the aircraft. Supersonic aircraft usually have the power plants buried in the aircraft for aerodynamic reasons. Vertical lift aircraft can use either the buried installation or the podded power plant, or in some instances both types may be combined in one aircraft. Air Intakes

The main requirement of an air intake is that, under all operating conditions, delivery of the air to the engine is achieved with the minimum loss of energy occurring through the duct. To enable the compressor to operate satisfactorily, the air must reach the compressor at a uniform pressure distributed evenly across the whole inlet area. The ideal air intake for a turbo-jet engine fitted to an aircraft flying at subsonic or low supersonic speeds, is a short, pitot-type circular intake (Figure 13–4). This type of intake makes the fullest use of the ram effect on the air due to forward speed, and suffers the minimum loss of ram pressure with changes of aircraft attitude. However, as sonic speed is approached, the efficiency of this type of air intake begins to fall because of the formation of a shock wave at the intake lip. The pitot-type intake can be used for engines that are mounted in pods or in the wings, although the latter sometimes require a departure from the circular cross-section because of the wing thickness (Figure 13–5). Single engined aircraft sometimes use a pitot-type intake; however, because this generally involves the use of a long duct ahead of the compressor, a divided type of intake on each side of the fuselage is often used (Figure 13–6).

Figure 13–5.

Figure 13–4.

Pitot-type intake. (Source: Rolls Royce.)

The disadvantage of the divided type of air intake is that when the aircraft yaws, a loss of ram pressure occurs on one side of the intake, as shown in Figure 13–7, causing an uneven distribution of airflow into the compressor. At higher supersonic speeds, the pitot type of air intake is unsuitable due to the severity of the shockwave that forms and progressively reduces the intake efficiency as speed increases. A more suitable type of intake for these higher speeds is known as the external/internal compression intake (Figure 13–8). This type of intake produces a series of mild shock waves without excessively reducing the intake efficiency. As aircraft speed increases still further, so also does the intake compression ratio and, at high Mach numbers, it is necessary to have an air intake that has a variable throat area and spill valves to accommodate and control

Wing leading edge intakes. (Source: Rolls Royce.)



Figure 13–6.

Single engined aircraft with fuselage intakes. (Source: Rolls Royce.)

the changing volumes of air (Figure 13–9). The airflow velocities encountered in the higher speed range of the aircraft are much higher than the engine can efficiently use; therefore, the air velocity must be decreased between the intake and the engine air inlet. The angle of the variable throat area intake automatically varies with aircraft speed and positions the shock wave to decrease the air velocity at the engine inlet and maintain maximum pressure recovery within the inlet duct. However, continued development enables this to be achieved by careful design of the intake and ducting. This, coupled with auxiliary air doors to permit extra air to be taken in under certain engine operating conditions, allows the airflow to be controlled without the use of variable geometry intakes. The fuselage intakes shown in Figure 13–10 are of the variable throat area type.

Figure 13–7.

Engine and Jet Pipe Mountings

The engine is mounted in the aircraft in a manner that allows the thrust forces developed by the engine to be transmitted to the aircraft main structure, in addition to supporting the engine weight and carrying any flight loads. Because of the wide variations in the temperature of the engine casings, the engine is mounted so that the casings can expand freely in both a longitudinal and a radial direction. Types of engine mountings, however, vary to suit the particular installation requirement. Turbo-jet engines are usually either side mounted or underslung as illustrated in Figure 13–11. Turbo-propeller engines are mounted forward on a tubular framework as illustrated in Figure 13–12.

Loss of ram pressure in divided intakes. (Source: Rolls Royce.)


Figure 13–8. External/internal compression intake. (Source: Rolls Royce.)

Figure 13–10.

Fuselage intakes. (Source: Rolls Royce.)

Figure 13–9. Variable throat area intake. (Source: Rolls Royce.)




Figure 13–11.

Typical turbo-jet engine mountings. (Source: Rolls Royce.)

The jet pipe is normally attached to the rear of the engine and supported by the engine mountings. In some installations, particularly where long jet pipes are employed, an additional mounting is provided, usually in the form of small rollers attached to each side of the jet pipe. The rollers locate in airframe-mounted channels and support the weight of the jet pipe, while still allowing it to freely expand in a longitudinal direction.

Figure 13–12. Engine accessibility, turbo-propeller engine. (Source: Rolls Royce.)


An aircraft power plant installation generally includes a number of accessories that are electrically operated, mechanically driven, or driven by high pressure air. Electrically operated accessories such as engine control actuators, amplifiers, air control valves, and solenoids, are supplied with power from the aircraft electrical system or an engine driven dedicated electrical generator. Mechanically driven units, such as generators, constant speed drive units, hydraulic pumps, low and high pressure fuel pumps, and engine speed signaling, measuring, or governing units are driven from the engine through internal and external gearboxes. Air-driven accessories, such as the air starter and possibly the thrust reverser, afterburner, and water injection

Figure 13–13. Engine accessibility, turbo-fan engine. (Source: Rolls Royce.)


pumps, are driven by air tapped from the engine compressor. Air conditioning and cabin pressurization units may have a separate air-driven compressor or use air direct from the engine compressor. The amount of air that is taken for all accessories and services must always be a very small percentage of the total airflow, as it represents a thrust or power loss and an increase in specific fuel consumption.


in the skid surface). Care is taken to not leave any voids in the grout to lessen the chance of “soft feet” below a critical gear box or bearing mount. How much of an issue weight is on marine applications depends on the particular application and size of the marine vessel. The main issue on land and at sea is space. The end user needs to ask a few questions:


Access to an engine mounted in the wing or fuselage is by hinged doors; on pod and turbo-propeller installations the main cowlings are hinged. Access for minor servicing is by small detachable or hinged panels. All fasteners are of the quick-release type. A turbo-propeller engine, or a turbo-jet engine mounted in a pod, is usually far more accessible than a buried engine because of the larger area of hinged cowling that can be provided. The accessibility of a podded turbo-fan engine is shown in Figure 13–13 and that of a turbo-propeller engine is shown in Figure 13–12. Installation of Land Based and Marine Engines

The installation of land based and marine engines is different from that of aircraft engines in that they generally come with a base or skid on which the entire system is mounted. The system may be mechanical drive or power generation, on a ship, ferry, or offshore platform. The essential difference for offshore packages with the same gas turbine (as an equivalent land based system) is that weight is curtailed as much as possible on offshore platforms. On land applications, weight is not an issue. Generally, the base is grouted (filled with grout through grouting holes left

How much space does the total installation/skid take up? (See Figures 13–14 and 13–15). If weight is critical, what are the weights of all the system components Is it likely that future additional propulsion requirements will need another gas turbine package? Can the skid be situated so that all plant components, such as inlet and outlet piping to the driven equipment in mechanical drive applications be routed so as to not cause excessive or cantilevered loads on the machinery flanges?

Other siting issues include items such as, does the gas turbine package need a “house” or will the system skid sit on the plant floor “as is?” Is the site appropriate for the potential needs of safety systems, such as risk posed by fluid moved by the driven equipment? My Process Engineers Equipment Handbook (New York: McGraw-Hill, 2001) has a section on the risk of explosion on power generation gas turbine trains. The exception to permanent siting requirements is the mobile gas turbine package, which is frequently used by merchant power producers.

Weights and dimensions SGT-100 Generator Set Diagrams, weights and dimensions are for typical standard equipment.

Figure 13–14.

Length (with package mounted controls)

10.0m (394ins)

Length (without package mounted controls)

8.0m (315ins)


2.40m (94ins)

Height (to top of enclosure)

3.2m (126ins)


35,460kg (78,175lbs)

SGT-100 Turbine for Power Generation (ISO) 4.35/4.70/5.05/5.25MW(e) (Source: Siemens).



Layout from side

Layout from above

Figure 13–15.

SGT-800 Industrial Gas Turbine—45MW Layout (Source: Siemens).

The Business of Gas Turbines


“Hear reason, or she’ll make you feel her.” —Benjamin Franklin


The Contemporary Business Climate 558 Culture 559 Repair and Overhaul Shop Culture 559 End User or Operator Culture 561 OEM (Manufacturer) Culture 561 Conglomerate and Joint Venture Cultures 563 Educators and Training 563 Integration with Environmental Technology Culture 563 Risk 563 Selection and Specification Process for Gas Turbines and Gas Turbine Systems 563 Risk Factors and Their Mitigation in Gas Turbine Design and Operation “Shifting Target” Data during Project Development, Negotiation, and New Model Introduction 567 Risk in Negotiating IPP Projects 568 International Negotiation 568 Market Assessment Risk 568 Plant Siting 569 Design Development and Operational Assessment by Both OEMs and End Users 569 569 Case 1 572 Case 2 577 Case 3




Business*† decisions in any sector involve much subjective thought, most of it rooted in the decision maker’s personality, culture, and life exposure to that point. Both personal experience and statistics offer many opportunities for brilliance or failure. Also, what is “right” one year is “wrong” 10 years from now, as technology, corporate, and national alliances change. This chapter includes some excellent studies that detail the economics of specific cases. However, technical papers tend to leave out all but the bare technical and economic bones. Any business is far more complex than that. It involves cultures, alliances, rivalries, combatants, both old and new, seen and unseen. The “macro” business picture is dictated by wars (for instance large new orders of turbomachinery slated for the United States’ rebuilding program in Iraq), trading bloc protocols (EEC, ASEAN, NAFTA), or in the case of the United States, a national penchant for moving toward countries with cheap labor (migration of manufacturing jobs to China and India). The “intermediate” business scene is painted by larger corporations taking on smaller ones (for instance GE buying Rotoflow and Bentley Nevada to name a few), large corporate role expansions (like OEMs becoming IPPs, oil companies becoming IPPs), and expanding global presence (like the major OEMs’ growing presence in NICs, like China and India). However, the detailed (“micro”) business scene is dictated by the working engineers, regardless of their function: design, operations and maintenance, and so forth. This, of course, is to some extent limited or promoted by circumstances beyond our control. The field of operations (including maintenance, R&O, and troubleshooting/failure analysis), however, is where the most visible and controversial examples of engineers affecting corporate business occur. For most turbomachinery engineers, some of their work, particularly if they are in operations, has direct, immediate (or almost immediate), and major impact on their customers’ net operating profits. Selected at random, some of my cases in point stretch from a purge oil system that threatened to shut down a 120,000 oil barrels a day plant, to an aeroengine failure that threatened to ground a world fleet, to small(er) issues like an aeroengine that had failed the postoverhaul test six times. Solving each one involves far more than just technical facts. So, before the case studies in this chapter, a summary of what that paper’s title means in the context of work in the power generation, oil and gas, and aeroengine sectors is probably useful. Note that the experience and observations that follow are based on my experience, and the reader’s experience may differ. However, the points where a reader differs are just as helpful to as those that concur. The overall subject of business is highly subjective. Disagreement and controversy broadens one’s frame of reference. The Contemporary Business Climate

The world is a tumultuous place a few years into a new century. At the ASME IGTI TurboExpo 2002, in the year *[14-1] Claire Soares, "Separating the Elements of Plants, Process, and Personnel," 1994, Turbomachinery Congress, Bangkok, Thailand. † [14-2] Claire Soares, working notes 1975 through present; and Proceedings ASME IGTI panel sessions, "Engine conditioning monitoring systems as they relate to life extension of gas turbine components," 1985 through 2003. Chair: Claire Soares.

prior to the second U.S.-Iraq war and the year after the 2001 U.S.-Afghanistan war, the large OEMs (original equipment manufacturers) admitted to a major downturn in orders for the following two years. Major unrest in the Middle East, Afghanistan, India, and Pakistan continues. Current U.S. leadership continues to make war noises in Iran’s direction. Iran’s national pride in having enough centrifuges to make power-generation-grade uranium is evident. Estimates as to when they will have enough centrifuges to get that up to weapons grade vary. Meanwhile, a section of Pakistan has reverted to Taliban life philosophies and North Korea is reputed to be working toward nuclear missiles. Central Europe remains uneasy and poor. The unofficial reaction to all of these happenings by some OEM personnel has been “if it takes war[s] to make up for our lost orders of a few years ago, then bring on war.” In some cases, such as in Iraq, the need to develop some infrastructure hastily is so great that there are orders for old models. Some of these may have been “lying around” in some “excess equipment yard” waiting to turn a larger profit margin than possible if the buyer were a poorer country or one not being funded by the United States. The gas turbine business demands a massive investment for new or expanded installations. The lead times with gas turbines and gas turbine systems are much larger than they are with turbines for “renewables” such as wind (partly because the unit power sizes are on a ratio of anywhere from 1 to 300 compared with a typical wind turbine). Also, unlike energy sources like wind turbines, one cannot just buy major components from other manufacturers, assemble them (partially on site), and start producing power. With gas turbines, the extent of integrated assembly of controls and hardware, as well as systems testing, that has to occur in the OEMs facility, prior to shipping, places the gas turbine at a disadvantage in an unstable and fragmented world. Such will remain the case, even if U.S. gasoline prices drop. ASME's IGTI annual conference frequently heralds shifts in the gas turbine business. The IGTI annual conference in 2002 saw an exhibit with relatively small participation from large OEMs (it had been shrinking for several years), and when they did appear, it was with a niche-market developed component, such as Pratt and Whitney exhibiting new brush seals it developed. Smaller firms with cutting edge products that give OEMs an edge, such as optical pyrometers, and new twists to on-line condition monitoring systems fared well. The content of papers at the 2002 IGTI conference underlined a changing atmosphere in the gas turbine business. Even in the applications area, the presenters with an academic background formed an unusually large part of the overall content. OEM and end-user originated papers made up a smaller percentage of the overall technical paper roster. The end-user and OEM papers tended to be on newer technology, such as hybrid systems. Fuel cell technology, in combination with gas turbines, is favored by legislative trends toward more environmentally friendly technology. Indeed legislation dictates that the energy mix in the United States should aim for 10% renewables. Other countries will follow suit. The message from this is perhaps that the OEMs and customers are keen to absorb as much in the way of hightech niche products that will save them engineering R&D


time, when the market comes back. And come back it always does, if often in unsettlingly short spurts that do not always match the lead times required to turn out a gas turbine, especially ones over 200 MW. Around 2004, the IGTI gave up trying to hold its design and end-user communities together in one meeting. Deciding that end users preferred a more practical meeting, IGTI started end-user annual meetings, generally in the same location as a larger meeting, such as Penwell’s PowerGen. The “design types” IGTI meeting is held separately. The significance of this to the engineering world is that IGTI is one of the few engineering associations that present juried papers, each with three preprint reviews. This fact served the gas turbine community (and IGTI) well in the 1980s and 1990s. It provided an optimum climate for mixed industry sector attendees (land-based both mechanical drive and powergen, marine, and aviation) at the panel session we ran for 19 years: ECMS as They May Be Used to Extend the Lives of Gas Turbine Components. Attendees were keen to learn from other sectors and “not reinvent the wheel” in their own. The balance of overall engineer populations continues to shift. China turned out five times the number of engineers that the United States in 2005. That figure rises to 10 times if you adjust the U.S. number for foreign students that cannot get U.S. work visas in wartime. India graduated about half the engineers China did. Especially with what were once U.S. jobs in manufacture (of items that include gas turbine systems) reaching their shores, it is likely that the Asian engineers will come to know what the insides of turbomachinery look like sooner than some U.S. counterparts. In terms of the mechanical-drive gas turbines used in gas and oil production, the overall global gas turbine market is likely to stay stable to growing for at least the next decade. Business gurus promise that the U.S. consumer will feel “pressured enough when gas goes from $3 to $4 and $5. That’s when you’ll see a massive change in the U.S. consumer.” Currently however, it looks like the U.S. consumer is more inclined to ignore photovoltaic household power cells in favor of blaming the leaders they elected for gas prices and continuing to run their SUVs. The small (smaller in MW) gas turbine market for ferry, naval ships, small power generation applications (including offshore platform and merchant power “portable skids”), and mechanical drive applications, as the “news items” sections in the trade journals indicate. The military aircraft engine market is stable to growing in wartime-induced sales, but that does not do much for improved R&D being realized in the optimized design of aircraft engines as a whole. Not that long ago, the flow of technology went from NASA via military aircraft engines to commercial aircraft engines to aeroderivatives to industrial models. At some point in the last decade, commercial aircraft engine development got ahead of military engine development and recent wars have not changed that. Where is this taking the world? Inside of the next three decades, probably to the age of smaller distributed landbased power, and ultimately the personal turbine (PeT). PeTs, at some point, will become as prevalent as PCs now are. The rest of the global power mix will consist of some large plants, particularly in the newly developing countries, such as India and certain countries in Latin America, where


the power wastage with faulty and badly designed transmission systems is currently as high as 10–30%. The gas turbine, in all sizes and models, will continue, wars notwithstanding, to flourish because of their application potential in all sizes of aircraft and marine vessels. The ability to take an aeroengine model and adapt that for ground- based application will continue with a shorter time span for designing the transition. There may be some grassroots land-based designs that can be adapted for fitting into an aeroengine nacelle. However, more about all this in the chapter on the future of gas turbines. Culture

In part because gas turbines are expensive items to manufacture, operate, and overhaul, many gas turbine manufacturers are bought out by or merge with larger manufacturers. Rolls Royce bought Allison. Siemens merged with Westinghouse. Brown Boveri became Asea Brown Boveri (ABB), which merged with European Gas Turbine (which once was Ruston), which then merged with Alstom to form ABB Alstom, which then changed its name to Alstom, the Swedish division of which was bought by Siemens. Profit margins are hard won. Costs per pound of thrust (or horsepower or kilowatt) with manufacturers, costs per fired hour with operators, and percentage net profit per overhauled engine with repair shops are watched closely by eagle-eyed “bean counters.” As frequently happens in a highly technical business, the value of the guidance financial gurus provide is directly proportional to their technical knowledge. With gas turbines, engineers, particularly those with a broad background that includes design, repair, and operations, make the best marketing or business guides. Historically, European and Japanese firms drew their business analysts and sales force from those with engineering backgrounds, the broader the better. U.S. firms have been more inclined to employ business or finance “purists,” often to their detriment. Europeans are now trending more toward the U.S. management model, which may not help increase long term profits. Repair and Overhaul Shop Culture

Gas turbine overhaul companies are constantly reorganizing, changing ownership, “going under,” or all three. It is possible to have a “small” repair shop. The shop may deal with only one or two repair processes, such as heat treatment or welding, and not have to accumulate the capital overhead an OEM needs for a comprehensive shop. When the shop gets successful, particularly if it developed some unique process, a larger shop or an OEM may buy the shop to extend its potential in-house work scope. The other important factor in the business of gas turbines is one’s network. The gas turbine world, for all of the gas turbine industry’s growth, is basically small and, in any one specific subsector, for instance, aircraft engine repair and overhaul, all the main players know each other. Each subsector has its own unique culture. Some subsectors are friendlier than others. In aircraft engine overhaul, for instance, I always found that rival shops would sell each other a spare part that the other needed desperately (and expect the favor to be remembered and returned). In the oil patch, however, I recall a rival company flatly refusing to sell my company a couple of gas turbine packages that it had no use for and left



sitting in the desert, even for a most reasonable sum. (The two oil companies recently merged, which makes the tale all the more ironic.) In this contemporary global village, recognizing culture is crucial to business success. The 1980s and 1990s saw the turbulent demise and ascendant of many overhaul facilities, particularly in the aviation business. Those shops managed by staff who had prospered through the 1960s and 1970s, some of them getting away with a “local” client base (say, U.S. domestic only) and bullying their small, foreign client base (“behave yourself or I won’t fix your engine”) were bewildered by what the 1980s brought. Excess equipment facilities made it possible for small repair shops and “fly by nights” (short lived) to turn a profit and exert “guerilla warfare” tactics in some cases. They might dent the work order load of one of the large shop’s business centers, say, the plating shop or the heat treatment department, or they might form an alliance to get work items that the large shop could not perform more profitably. I recall the massive aeroengine overhaul shop I worked for in the late 80s, subcontracting some EDM drilling work to a tiny local shop. We had the equipment in-house, we just took too long and used too much time and personnel to get it to the right work stations in our shop. In the U.S. business climate of the 1980s, it became critical to observe the cultural preferences of international clients during all phases of the relationship, to remember that European and Asian clients ask technical questions that may be beyond the capability of a nonengineer sales force. Rival European, Asian, and Canadian facilities knew this and had adapted. It was essential to know that the equivalent of U.S. “blue-collar” workers in Europe were “craftsmen,” who were probably in the same union as their engineers. It was fatal to not realize that U.S. mechanics, many of them veterans of Vietnam, needed their management to properly motivate as well as train and compensate them. Unlike the traditional postwar Germans and English, they would not shift into “autopilot” if they disrespected their management, just so everyone could keep their jobs. Japanese executives roll up their sleeves, get on the floor with their people, and start suggestion boxes toward which they demonstrate a commitment. The U.S. workforce is poorer in this category of executive. However, when they have a “people’s person chief,” it shows. As was evident to all who watched Herb Kelleher of SW Airlines offer his shareholders a three for one split, even as rival airlines, overhaul shops, and support businesses were forced to close their doors. In these days of mega-corporations, portfolio diversification, takeovers, and mergers are common. Sometimes, successful large corporations are tempted into an acquisition or set of acquisitions that gets away from their core competence. As the stock exchange “graveyard” and “just treading water” lists reveal, acquisition is not always an exercise in prudence. Some such ambitious ventures did not get as far as mergers or joint ventures with OEMs. Instead, companies like Ryder concentrated on acquiring aircraft engine overhaul shops. After all, a gas turbine overhaul shop is really just part of the transportation business right? Wrong! Besides, the “products” from aeroengine overhaul shops are vastly different from the orderly sameness of a manufacturing facility or the routine of truck rentals. This feature is amplified in the case of an independent overhaul shop that

has a dogs breakfast of small customers who may own just a few engines (sometimes, only one plane) and a few large airline customers who sometimes grace them with their “overflow.” Then, you not only have a different culture “on the shop floor” but every customer, from Chile to Thailand, adds its own cultural profile to daily operations. Operational mandates make different cultures, too. If there is an engine in from Airforce One, no expense is spared. The one on my former nightshift beat also came with an NCO (non-commissioned officer) who watched it faithfully and mopped up a grease spill if he saw one. On the other hand, a freight hauler like Federal Express may want to only “make the 500 operating cycles that’ll take us past the Christmas season.” Degree of knowledge can create major cultural barriers. I was once berated for scrapping a critical turbine disc that someone had forgotten in the acid bath. It should have been out of there in about half an hour, but it was not. I didn’t like my hydrogen embrittlement odds. Another engineer said “it looks just fine” and took it off scrap status. He did not want further dialogue. Sure the disc looked fine—on the outside. The decision makers were not degreed engineers, and those that were may not have had to study metallurgy. The good news is that, if hydrogen embrittlement does not “get you” in fairly short order, the “heat treatment” from just the gas turbine hot section operating temperatures will cause the troublesome ions to lose their problem potential over time. I never heard about that particular engine failing, so that customer, and the shop, were lucky that time. It is always a customer’s responsibility to “beware” as a buyer; in other words, never assume your seller has the same values as you. The customer may be someone who “sticks to the work scope (or contract)” but his seller may be of the school that “sells what [it] can get away with.” As a case in point, I once suggested we ask for a work scope extension on some used engines that had been bought by a customer, after I had seen a couple of them opened up. The seller of said engines had claimed it had completed an “ESV2” overhaul on all of them. ESV2 is Pratt and Whitney shorthand for a very thorough overhaul. So those engines ought to have looked, if not new, then very clean. However, when we opened them, we found cracks in the diffuser case, missing internal turbine air seals, and a bunch of other transgressions. If that was an ESV2, the claimants of same were, no doubt, tooth fairies. The unsuspecting customer had specified a quick “look see” work scope, which demonstrated great trust and a complete lack of knowledge of the seller. My overhaul shop employer could comply with that work scope and be, technically at any rate, within his rights to not inform them of the mess. At that time, I was sole engineering support to an entire second shift of about 250 mechanics. We worked when all the other engineers, customers, and other staff had left for the day (except for about a two-hour common timeslot). My own “culture” could not let what a couple of floor supervisors politely called “ratshit” slide. Despite the flimsy work scope that essentially asked me to do nothing, I provided many graphic photographs that the customer’s contact engineer could include in his final report. I also stuck a copy of the pictures in the turnover log, as my position did not liaise directly with the customer or write final reports. Whether the customer had enough technical background to read the glaring evidence in the photographs or removed the


engines from service henceforth and shut up to save face, I do not know. Sense of community within each company varies globally. An overhaul shop in Scotland does not think or react like one in Texas. If acquired by the same owner, the executives may see themselves as jockeying for position. Frequently they do. When Tony Burns, chairman of Ryder, decided to buy Aviall, then the largest global independent overhaul facility for aircraft engines (and prior to 1986, the firm serviced industrial engines as well) to extend Ryder’s reach within the global transportation sector, all of the above may have been news to some of his key decision makers. When he added what was the former British Caledonian Airways facility in Scotland, to Aviall’s assets, much of this potential melee might still have been a mystery to key personnel. So it was that an overhaul facility with a combined shop capacity of about 1000 engines a year and a stable share value of about $24 at the end of 1991, was divorced by its Ryder parent in the face of abysmal losses a few years later. The “new” corporate stock that fetched about $14 on initial offering would have difficulty raising between $5 and $7 just a year later. A relieved and helpless management sold out about then. The new Miami management struggled with what was residual debt load, but no doubt inherited customer bad will, a different worker culture, or both. It, too, sold out. The new owner, General Electric, had other shops to farm the work to, if it pleased. The aircraft engine overhaul world rumbled, raised eyebrows, found alternative shops, or used more than one shop; then all was “business as usual” again. In May 2005 or thereabouts, GE closed that shop’s doors forever. Assets that supported their CFM line overhaul were probably transferred to their other shops. The tooling for the V2500 engine line (I had commissioned that program in 1991 with the first engine input from Indian Air), a rival to the CFM56, was sold to Pratt and Whitney. End User or Operator Culture

Can such a stew of cultures be managed and turned to advantage? Southwest Airlines is living proof that it can. Whether you’re an overhaul shop, an end user/operator, or OEM, the answer is emphatically, “Yes.” The proviso is, however, that you must have the leadership of a Herb Kelleher or a Robert (“he’s a son-of-a-bitch, but he’s our son-of-a-bitch”) Crandall to make it happen. With end user/operators, commercial size and global business affect the worker’s life and therefore the corporate success and synergy. Before conventional oil prices hit the floor in the early 1980s, I enjoyed working for them. Even in the more stringent tax environment in Canada, money spent on maintenance came off pretax gross revenues, and as long as oil prices stayed high, we never had to stay in less expensive hotels or rent the smallest cars. Even for the environmentally friendly types, car size was a consideration if you were driving out to fields over a mix of snow and black ice and you wanted a car that would “hold” the road. It behooves employers to recognize synergy potential with its individual employees and their working circumstances. Employees need to return the favor. Some people thrive on pioneer type field projects. The more difficult the circumstances the better. Syncrude’s first synthetic crude (oil sands) 170,000 barrels-a-day facility in northern Alberta, Canada, worked through eight-month winters with average temperatures of −30°C to get commissioned on schedule in 1977/78. The average age in what was then a 35,000-people strong boom town was 15. A boy scout troop made its money for


airfares across the country by collecting empty beer bottles that littered the highway between towns and the weekend playground (all things are relative) that was Edmonton. I went to the local pub only if I had many friends for company. They had shooting matches in there, not all of them friendly. The workforce stuck together through years of 16-hour days and went cross-country skiing or curling on Sundays. We were rock solid as a community, in and out of work. The plant cost about $4 billion in 1970s terms and most of the critical machinery was a prototype in some way. Many of us had some of our most valuable working years on that project. The learning intensity on subsequent projects, under more “structured” environments, curiously, often is reduced. Those of us involved with rotating machinery at the Syncrude of the late 1970s found ourselves rewriting the Exxon, Shell, and Gulf bibles for prototype machinery. That machinery is no longer “different” today. Faced with the “oil down pipeline” date, as well as OEM puzzlement and caution in the face of unanticipated obstacles that would require machinery design changes, we made swift, sweeping changes to machinery and plant systems. That may have cost us heavily in warranty costs, had they not worked. Today, Syncrude is building other plants, but the early 1980s saw a temporary setback in oil sands and all nonconventional energy development because of the global oil prices crisis. Had this not happened, the use of nonconventional fuels, such as orimulsion (the Venezuelan equivalent of synthetic crude) in gas turbines, would be much further along. Money Makes Attitudes

As a propulsion systems manager for the Transport Directorate in Air Command for the Canadian Air Force, I had six aging helicopter engine fleets. Later in my threeyear term, there would be a budding engine program newcomer (the Pratt and Whitney PW100) to be part of the Kiowa replacement program, as well as studies into the Sea King replacement program. That notwithstanding, we still had to make old chopper engines operate safely. In that, we found the U.S. Coast Guard’s operations (whose budget does not match those of other U.S. military branches) repaired most engine problems. Canadian military choppers were overhauled to commercial standards, so they could all do grueling pipeline service, if necessary. This was appropriate, as the Canadian military in peacetime performs like a U.S. Coast Guard, chasing smugglers and illegal aliens, as well as performing search and rescue. In other words, there is no room for error during overhaul of engines that must then be put through mission profiles as demanding as those imposed by wartime service. To illustrate the difference financial resources make to operations: once, I asked a U.S. naval lieutenant colonel how they had handled a bearing failure on one of those aging fleets (the T58 engine). He informed me, laughing, that they did not bother. “We just remove the engine, leave it in the Arizona desert and put a new one in.” This was then the mid-1980s and all things may, of course, be subject to change. OEM (Manufacturer) Culture “Customers Buy Whole Engines Not Components”

Operator response to two engines I learned to admire in my military years has been consistently positive. The engines are General Electric’s F404 on the F-18 fighter/bomber jet and the T-700 helicopter engine. The latter was one of the candidates for a power plant in the Canadian Forces Sea King



replacement study, so I had occasion to study it thoroughly. I read everything I could on the F404’s condition monitoring system (CMS) and triple redundancy controls architecture, all of which was to prove handy for some power generation project work years later. Triple redundancy controls are increasingly observed on critical land based installations. The lesson here is that industry developments in one sector eventually visit the others. As mentioned elsewhere in this book, I ran an annual condition monitoring session that five committees in ASME IGTI’s annual TurboExpo cosponsored, from 1985 through 2003. The session aimed at pooling the best brains in condition monitoring (land, sea, and air; OEM; end user; repair shop; whatever) to link CMS systems that monitor an engine’s condition to changes in gas turbine operating hardware effective lives. One of the members of the design team of both the T-700 and the F-404 engines also became my vice chair at those panel sessions. The additional cooling that gives the F-404 and the T-700 engine part of their edge in service was a contribution this colleague insisted on making, in the face of opposition from the “efficiency freaks.” Given the war being continuously waged to better one another’s efficiency, many enthusiastic designers shave the safety margin on cooling air very close to the bone. When adverse circumstances arise in unexpected combination, a pilot may be on the quick road to oblivion. This gentleman told his team that he would rather have just a little less efficiency and less of a chance of “meeting someone’s angry widow. … I realized a long time ago that people don’t buy turbine sections. They buy engines. Whole engines. And not just an efficiency figure.” The Ruggedness School

Operators and end users like rugged. If you are a pilot facing possible death, you can get downright passionate about it. The pilot of an early V2500 (Airbus A321) flight over Calcutta airport’s approach path may not have realized one of his engine’s had just ingested a 24-pound vulture. The approach takes aircraft over a garbage dump, so the vulture was where he or she belonged. Its weight was confirmed by the size of a few leftover feathers. The engine just broke two of its wide chord Rolls Royce-designed fan blades and kept steadily on. I have seen one of the V2500’s rivals “corncobbed” by a two-pound pigeon. This has much to do with the effectiveness of the wide chord fan blade design (which some years later “appeared” on other engines, such as the GE 90). However, ruggedness is a school of thought, a culture. It followers are generally those who add items like an extra margin of cooling air or oil to their equations, over and above those dictated by accepted insurance-worthy calculations. The V2500 has four (originally five) quite excellent design partners, but a sigh of relief went up among overhaul shops and savvy pilots when we knew that the oil system was Rolls Royce designed. Rolls does not stint on its cooling. Its algorithms for calculating engine cycle usage (in the late 1990s) on engine models like the Spey and Olympus engines confirm that. So did some of my “overhaul witness” work. When witnessing teardown of the Rolls Avon engines that drove Cooper RBB barrel compressors (the first prototype application machines in high-pressure, high-volume natural gas reinjection service in northern Alberta), I expected to see a noteworthy amount of wear and tear. The load on the barrels varied to some extent as with all mechanical drive applications and I did not expect things to look as clean as with

a similar unit in power generation. I expected to develop a substantial "to-do" list. With those Avons, I felt about as useful as another star in a tropical sky. The engines were almost embarrassingly clean. So was MTU’s (Motoren Turbinen Union’s) low-pressure turbine section on the repeatedly shock tested (accelerated cycles accumulation) V2500 that was bared in 1990 in Munich. There were many engineers at that gathering, and all of us just wandered and wandered around in circles trying to find a nick, a scratch, anything. If the objective for that meeting had begun as “let’s see what flaws may occur early with this V2500,” it ended as “let’s have a good dinner so the trip’s not wasted.” Interestingly enough, those turbine manufacturers who prefer gaining efficiency points to providing extra cooling, may end up with hot sections that look every bit as clean during overhaul, provided nothing tips the scales. If there is no unanticipated flashback with sophisticated burner design having quality control problems, or no partial blockages for oil to the bearing closest the turbine inlet temperatures, or no upstream compressor blockage caused by seasonal bugs hardened on compressor airfoil passages, the scales stay even. If, if, if. Operators and end users would, in general, be unequivocal about getting the “extra” cooling—if that choice was theirs to make. Market Entry Monopoly

Conventional gas and oil production was busy in the 1950s and 1960s. Production fields might be large or small, with many years of supply or just a few. The gas molecular weight was prone to change, as these were mixed fields, with the onset of heavier- molecular-weight components an unknown variable. End users/operators needed a set of small compressors with adaptable staging and gas turbine drivers that could tolerate a wide range of loads. Efficiency was not a key requirement, stable operation within load ranges and easily available rental units were essential. The manufacturer who filled this bill, and stood relatively unchallenged at the time, was Solar turbines. While not high on efficiency ratings by current standards, much of that original Solar fleet is likely to be around after most readers of this first edition book have expired. End users like the machinery they are familiar with, even if it has faults. Justification of new machinery may just not be there, given declining field economics. Aware they had a giant grasp of the 1000- to 3500-hp mechanical drive gas turbine market, Solar was, for some years, not the best ear for its customers to approach. The original Centaur was about 3300 hp. Uprate kits took it to about 3500 and then 3800 hp. Solar told its customers their warranties were void unless they adopted the additional horsepower, regardless of whether their application needed it or not. Everyone understands that spare parts are expensive to stock and service, but when the uprate kits cost upwards of 25% the cost of a new machine, customers squeal—and with the help of end-user lobbies, such as CIPs (component improvement programs), roar. The once noteworthy Gas Turbine Users Association (GTUA) is no more, at least for the time being, but it gave the late 1970s user base a good sounding board. Its early monopoly over, Solar immersed itself in much progressive development, DOE programs, quality control award programs, and other successful endeavors. Its sophisticated current R&D work outshines its late 1970s to early 1980s image, where it faced an aggressive end-user


community bent on optimizing their own costs per fired hour. Both OEM and end users benefited. Conglomerate and Joint Venture Cultures

When giant OEMs absorb smaller OEMs, OEM divisions, or support systems/accessories manufacturers, it is inevitable that cultures will change. Whose culture governs is both an obvious and subtle answer. The larger company officially has the edge. The actual dynamics depend on the personalities on a per-department or perdivision basis. The same is true of joint ventures. For instance, the companies involved in the V2500 success are very different. The Japanese Aeroengine Consortium (JAEC) is a consortium of three large Japanese manufacturers with aeroengine manufacturing potential, making the V2500 low-pressure compressor module, complete with wide chord fan blades, to a Rolls Royce design. Rolls Royce makes the high pressure compressor; Pratt and Whitney, the hot section; MTU, the low-pressure turbine. Every other engine assembled is put together in Rolls Royce, Derby, England, the alternating engine(s) in the Pratt and Whitney facilities in the United States. Four more-different partners it would be hard to find, and yet the synergy works. Selecting tooling for a joint-venture engine can be interesting. At module interfaces and for some other functions, both OEMs involved at that interface would design tooling for the same functions. I recall a Germandesigned balancing tool (to be accurate, it was designed by a German balance machine manufacturer, not MTU) that cost $55,000. The Japanese equivalent cost $17,000. I never did get to try the Japanese version, as for a variety of reasons, we had opted to buy the German manufacturer’s balance machine package as a whole, for the Dallas-based V2500 overhaul program. However, both tools worked. In summary, when synergy is on your side, even the most unusual international conglomerates work wonderfully. It is the same with overseas subsidiaries. All the major manufacturers—GE, Pratt and Whitney, Siemens Westinghouse, and Alstom—have low-laborcost subsidiaries overseas. Many are in China and India. Many, much to some people’s surprise, have gained ground by directly employing or promoting the education and training of formerly illiterate women. These subsidiaries have put “home” (U.S.- and European-based) labor out of work and face much political opposition, but they continue. There are a growing number of international joint ventures in power generation. An example is the one between Siemens Westinghouse and Malaysia’s YTL (an IPP company operating in Malaysia). The two companies actually continue to own and operate these assets, versus a BOOT (build, own, operate [for some years while they train the locals], and transfer) project. Most of the major OEMs were quick to set up components manufacture in NICs (newly industrialized countries). Siemens and GE are among those that provided a great deal of local training in China, India, and a host of other countries, so their locals can make everything from blades to composites to relays. However, when they form these joint ventures that train local people to operate their own power infrastructure, that is an even more valuable contribution.


Educators and Training

There is a separate chapter on training, so I will not dwell on this much here, except for a few facts. The first is that economic deprivation breeds an almost frightening level of ambition. Sometimes, that ambition seizes responsibility at what others may call a premature point in history. A good example is the Chinese aerospace industry workforce, which covered in 10 years what it took the Western world 60 years to cover. The key factor in training is always the students themselves. I have faced students on both sides of the Pacific and Atlantic who did not understand why, in the course of a week’s training, I could not give them the content of all my years of experience. And they did not like “homework” for that week either. This is a common frustration with trainers. I have met others who were angry that I would attempt to give them a snapshot of performance analysis systems when they did not want to be bothered to learn more than the basics of Process Plant Machinery (or whatever the course was called). I met still others who were angry that I would present the basics of a gas turbine (and I firmly believe that there can be no comprehensive engineering career in power generation, energy production, or process engineering, which makes up 80% of global activity, without knowing about gas turbines) because they currently owned only a few steam turbines. Again, as we say in Texas, go figure. Integration with Environmental Technology Culture

With the wisdom that comes from a good bottle of wine, a colleague and I once reasoned that the Scandinavians were “so much better at all this environmental stuff” since they were Vikings at heart and used to not wasting anything on long sea voyages. Much of their economy with resources stemmed from their early roots. You rarely have to sell a Scandinavian on emissions taxes. A holistic perspective of gas turbine operations must acknowledge that cooler TITs mean longer TBOs, not just lower emissions. Some things are hard to collect enough data to prove conclusively. Nevertheless, we must make our best judgments in the absence of all the facts. I therefore state that I believe a design that best favors optimal environmental performance from a gas turbine (discounting other factors like design development costs and other one-time only costs) also favors optimal costs per fired hour and TBO for a given engine. So, environmental performance ought not to be considered as an item separate from overall performance but more as an ally in attaining optimum design and operation of any engine. Promoting an environmentally admirable design is part of optimizing gas turbine performance (see the chapter on optimizing gas turbine performance), even though it may seem that you are “throwing” away a few efficiency decimal points. Risk Selection and Specification Process for Gas Turbines and Gas Turbine Systems

In global engine population terms, the main reason any gas turbine (GT) OEM is successful during any major bid process is not an engine’s overall design attributes, but the finance packages offered. General Electric makes fine



engines, but the main reason it sells so many more engines than its competitors is the strength of its financial services corporate arm. During a bid where the V2500 and the CFM56 were squaring off for an order with a large Chinese customer, the customer noted the V2500 model had 4% greater efficiency than its current rival’s model. Fuel is an issue with China. The only fossil fuel China has its own large supply of is coal, and the only other one it can access easily due to a global glut is residual oil. The CFM team paid the Chinese the difference in fuel efficiency costs over the stated official life of the engines. It essentially gave away the initial capital cost free to the customer. The losers sniffed their disappointment and remarked that the less rugged (in terms of FOD), lesser cooling air (in terms of cooling air per pound of engine thrust) of the winner would soon recoup their outlay in spare parts costs. They may have had a point, but the lesson is clear. Particularly in the developing world, he with the deepest pockets wins, regardless of any risk inherent in a customer's financially driven choice.

In terms of gas turbine system (such as the engine condition monitoring system) selection, whether new or in retofitted/reengineered applications, the selection and risk factors are varied and several. They are discussed at some length in this book’s Chapter 9, “Controls, Instrumentation, and Diagnostics.” Risk Factors and Their Mitigation in Gas Turbine Design and Operation

Risk in gas turbine design and operation is defined differently depending on the audience in question. Nonetheless, three key components of risk to profit margin, when a system is being analyzed by potential financiers and end users are ●

The Luxury of Choice, Maybe

Large oil companies are among the few gas turbine customers who can make their gas turbine selections independent of financial factor considerations. However, very often, if the warranty package offers good enough security to result in the effective per fired hour they need, they opt for either the best financial choice or one driven by deliverable dates. Deliverable dates count, because all manufacturers of power generation machinery can generally sell every machine they produce. They are heavily backlogged, and that will remain a factor in the future of the gas turbine business for the foreseeable future. The aircraft engine and naval gas turbine market can be more competitive. I say “can,” because if the commercial aviation business is in a recession-goaded slump, the fortunes of commercial aviation gas turbine manufacturers follows the curve. If the year is 2001 or 2003 and war is once again the best business to be in, military engine (aviation and naval) programs are hastily taken out of mothballs and given massive infusions of cash. A California comedy show host pointed out sometime in April 2006, that the Secretary of Defense need not worry about his generals hitting him with their collective lack of confidence with respect to his performance in the Iraq war. “He’s still got lots of friends: General Dynamics, General Electric …” The times when gas turbine selections are made on design merit alone are therefore rare. Reliability and end-user comfort level are two main deciding factors, if the end user does not need OEM financing. I recall power-plant selection for power production in Esso’s Norman Wells proposed project. I chose the GE Frame 5 (old model) although it was vastly oversized for the project’s needs. The year was 1980 and I did not want to tangle with the then-new Frame 3’s rash of cross tube and other problems. I did not want a still relatively new Solar Mars. I needed a stolid, reliable design that had worked well in another sub-Arctic site (the Syncrude project) I had experienced. For the $500,000,000 (1980s dollars) proposed Judy Creek expansion,* I chose Solar Centaur-driven sea water pump packages. Esso was the largest Solar turbines operator in Canada and the operators knew the machines well. Spare rental machines would not be a problem.

*Both the Judy Creek and the Norman Wells expansions were put on hold in the face of the oil price crisis in the early 1980s but both were revived later in better oil market times.

Unavailability (as may be caused by unscheduled shutdowns) and inconsistency of supply (as may be caused by “brownouts”). Fuel costs (which may be affected by political and market factors). The costs of spare parts (which are affected by items such as design complexity, operational component lives, design reliability, vulnerability to untrained operators, and so forth).

An increasingly competitive market demands that every iota of potential increased efficiency be squeezed out of a power plant, particularly a new project that seeks financing. The return on investment (ROI) figures ultimately look much better to bankers this way. Operations engineers sometimes groan when they work with the hard reality of the turbine outages that result. Their main job is to keep the plants running constantly and they know that some of the design methods used to raise efficiency are going to make their maintenance lives very difficult. This dichotomy poses several interesting questions, depending on the turbine design philosophy in question. To some extent, it also depends on the consistency of the quality control program enforced by the manufacturer. The Higher Turbine Inlet Temperature School

The greatest risk in raising efficiency is the risk of unexpected outages. The way better efficiencies are primarily achieved is by increasing the turbine inlet temperature (TIT). This is increasingly evident as manufacturers like General Electric introduce their G- and H-series gas turbine technology, which then gains several design-calculated efficiency points over their last closest-equivalent designs, by raising TITs. Some progress has been made in increasing the coolingsystem efficiency of turbine blades and vanes, using elaborate blade design, and steam cooling. If we consider General Electric’s aeroderivatives such as the LM series, the technology for design features like active clearance controls (ACC, a cooling design feature) was already developed by the aircraft engine CF6-80C2 team. Now MHI has its version of ACC using steam cooling. MHI uses both a closed loop and an open loop, where the steam is reinjected back into the gas path for a power boost. The closed loop was a tricky feat to pull off, and it does MHI considerable credit. (See the case study on MHI's steam cooling technology in Chapter 4.) The exposure of hot gas parts to the higher turbine inlet temperatures will naturally shorten the lifespan of the exposed parts. This effect is limited by the use of aviation engine metallurgy and manufacturing processes.


Both Siemens and MHI have pointed out that they use aeroengine developments to their advantage. The targets for combined cycle efficiency of percentage points—60% plus by the turn of the century—as laid out for suggested targets in the 1990s by the U.S. DOE (Department of Energy) proved to be attainable. All the OEM “major” ” have new blade designs and cooling schemes, but these efficiency levels are far from easy to achieve with consistent high availability for every OEM. Certain OEMs have tested their steam cooling systems on their –H machines, and they did not leak then or later in operation, under full load. It is always the end user's responsibility to check technical claims made by bidder OEMs as they might apply to the application in question. Manufacturers’ (OEMs’) Guarantees

Increasingly, manufacturers are taking over the maintenance of their own machines, usually with power-by-thehour contracts. Some, like ABB and Siemens-Westinghouse are also buying large stakes in power generation stations globally. Overseas, where training is an issue that can directly affect unscheduled outages and brownouts, manufacturers are contracting their involvement in BOO (build, own, and operate), BOT (build, operate, and transfer), and BOOT (build, own, operate, and transfer) projects. Both for overseas projects in NICs and in industrialized areas, such as the United States and United Kingdom, manufacturers frequently base their contracts on availability and outage figures. For instance, for the first year, the OEM may base contract prices on an availability of, say, 87% with a fixed number of unscheduled shutdowns, say, 10 to 15. If that target is exceeded, the OEM gets bonus points, if the reverse is true it pays penalty points. If all goes well, the next year’s contract may be based on perhaps 91% availability and 7 to 9 unscheduled shutdowns. Thus, the OEM and its customers negotiate the share of increased risk with newer designs. Supply of New Machines

In a rapidly burgeoning deregulation climate, most customers cannot always base purchase selections on an analysis of potential OEM designs. There simply are too few machines being made to fill global demand growth. California is one of the best examples of a U.S. state that no longer has enough power. It also has industries that can be crippled by power outage, as in Silicon Valley; loss of power means more than lost production time. It could also mean losses of huge amounts of data. Therefore, customers have to buy from the OEMs that can supply them faster than anyone else and manage their risk with contract clauses, power-by-the-hour contracts, peak purchase agreements, emergency power purchase from MPPs (merchant power producers) as well as spares and spare machine strategy. Effect of Design Factors

When the market is thriving, it is tough for OEMs to keep up with new orders, even with improvements in manufacturing technology. That notwithstanding, the design philosophies adopted by various manufacturers do affect availability of existing machines. Exactly how much depends on human factors that involve operators, as well as the level of service available and demanded by, a certain design. If one considers ABB GT 24 and 26 technology for instance: These designs operate at lower TITs than their


competitors’ designs. This means less NOx emissions in pounds per megawatt (lbs/MW) even though ppm (parts per million) NOx levels might sound not that different from competitors. The SEV (sequential environmental) burner design, in essence, can be said to have two hot sections (and two TITs) because it uses the reheat concept. Ultimately, it needs less air flow for both cooling and reaction with fuel, which also means less greenhouse gas emissions. That being said, the increased number of parts involved may affect repair and availability adversely. The reduced number of discs in ABB's first -11N2s meant much higher bearing loads with resultant availability (reduced) potential consequences. Today the 200+ MW machines pose the main questions with respect to all the three major aspects of risk—availability, spare parts costs, actual fuel costs. There is a larger amount end-user information available on mature machines in the 100–130 MW size and still more on small machines that make up the 10–35 MW range. However, as temperature is arguably the single worst promoter of hot section deterioration, in the bigger machine sizes, Alstom, for instance, can be considered to have managed risk well from the operator’s perspective, with specific reference to its cooler-running engines. This permits the use of cheap residual fuel in the case of certain models and allow a wide variety of low BTU fuels. Bankers and lenders look at fuel bill calculations that fall with increased theoretical efficiency and TIT values. However, they may weigh that third risk factor (cost of and fluctuations in the cost of fuel) just as heavily as risks from unscheduled power outages and higher spare parts requirements, in the ultimate derived figure of cost per fired hour. Another contributing factor to availability and reduced component life (or increased spare parts costs) is the low NOx combustion burner. With some of these burner designs, low NOx combustion is achieved without steam or water injection. The disadvantage of this technology, however, can be high pulsation levels in the combustion section. The vibrations of the parts exposed to the high inlet temperature accelerate wear significantly and contribute to early component failure. Machines using the single-burner technology combined with water injection to achieve the NOx requirements have lower pulsations, which affects the parts’ lifetimes positively. There are far fewer failures with these designs. Alstom has been proactive in this regard, with water injection options designed into its –13E (and formerly –13D, now –11N2 with a gearbox to service the 50 Hz market) designs. The alternative is to have a series of burners as Siemens-Westinghouse does with its V94.3 designs, and as ABB has designed a retrofit for, with many of their smaller models, like the GT8. These designs can then be run without water injection. (From an operations perspective, the worst problem with water injection is that it requires boiler feedwater quality, which then means an additional system that can be prone to problems). Critical attention to quality control details by the OEM is also a major factor. When this is not done, small inconsistencies in well-proven designs can add up to operational unavailability. In other words, sacrificing 1 or 2 % efficiency and choosing a proven burner concept with low combustion pulsations and reduced or no tendency for backflow does pay off in the long run with high availability of the machine. In “peaker” applications starting reliability and availability are crucial.



Increasingly, CC (combined cycle) power plants are stopped and started more frequently. Reliability and availability, for startup and continued operation, are increasingly important for CC plants. Life-Cycle Assessment

It says a great deal about an OEM’s faith in the cooling features of its turbine hot section if its algorithms that tally the life cycle count only measure rpm (revolutions per minute) against time. In Rolls Royce’s case, the development of these algorithms and the retrofit of life-cycle assessment (LCA) counters was outlined in a service bulletin (SB) for a couple of its models. It was instigated by end-user pressure and high costs of replacement parts. The SB has been successful in extending hot section component lives by factors of up to 200% from the previous standards (which had specified a fixed number of operating hours for each component). Most LCA algorithms take into account temperatures (whether peak, base load, or both), rpm, and time. The development of LCA is another item first pioneered with aviation engines and slowly handed down to industrial and aeroderivative gas turbines. LCA counters are being refined constantly, as are materials and instrumentation for temperature measuring systems, in the constant fight to bring down the cost of spare parts. For more information, see Chapter 9 “Controls, Instrumentation, and Diagnostics” in this book. Performance Assessment

Performance assessment (PA) systems basically monitor the gas path of a turbine in terms of flow versus pressure. Temperature readings are also taken. Some systems compute parameters derived from measurements versus parameters calculated from predictive formulas and end conditions. These PA systems then compare the two and can troubleshoot problems that may affect both reliability and availability. In competent hands, PA systems can be used to design retrofit modifications that can raise availability. One example is retrofitted steam injection (for cooling) that took critical GE Frame 5 (old version) turbine discs out of the crack range, for several thousand more cycles. PA systems can also be used to make new design changes that can extend component lives and thus reduce the cost of spare parts. PA systems can be used to monitor emissions and changes in emissions resulting from component deterioration. Ultimately, they measure aerodynamic performance and indicate the source of losses that can be corrected. About a 0.5% difference in turbine section efficiency on one GE Frame 7 can make as much as an $800,000 difference in an annual fuel bill (based on 1995 Alaskan gas prices). PA systems are then a major tool in risk assessment and limitation. Although vibration analysis (VA) can be considered part of the reliability and safety aspects of machine operation (versus availability), VA is often incorporated into an overall condition monitoring system by either the OEM or a contractor hired by the end user. Especially when they work well (which largely depends on how suitable the package components are for the application), reliability and safety systems contribute indirectly to availability and the cost of spare parts. For more information see Chapter 9 “Controls, Instrumentation, and Diagnostics” in this book.

The Push from War, Emergencies, Politics, and Policies

Design Compromise War sometimes breeds design compromise. One of my six gas turbine fleets in the Canadian Air Force was the Kiowa engine, that had been so active in Vietnam. The compressor section of what was the C-18 model of Allison’s 250 series could not, in the “raw metal” state, withstand the centrifugal loads during operation independently. To get the tensile stress to within allowable limits, a layer of compressive stress was imposed by glass bead peening on the rotor blades. The rotor had to be turned and peened again, so that both sides of the compressor blading received benefit of the compressive stress layer. This engine might not have entered service with this design feature had the aircraft not been needed that badly when it was introduced. When two engines in the Canadian fleet failed (the pilot safely autorotated in both cases), alarm bells began in the global Kiowa community. Well past the Vietnam days, the fleet was still active commercially in many countries. When a third engine failed and this time its aircraft crashed, killing pilot and passenger, the fleet was held within a hair’s breath of being grounded, pending the results of the investigation I was sent to complete. The situation was worsened by the fact that it had been discovered that some personnel at the overhaul facility we used did not realize that the rotor blades had to be peened on both sides. We had no way of knowing how many “bad” rotors were out there. We did not know if a failed engine had fatally disoriented the pilot for vital seconds during his practice exercises (night landings using the tail lights of a jeep). The world fleet was taken off “potential grounding” status after I was able to prove that the engine, at any rate, was operating as per specification when it hit the ground. Later, X-ray diffraction performed by the manufacturer revealed that this rotor was one of the “good” (both sides peened) ones. Nevertheless, an immediate recall was initiated for our fleet and every rotor “redone.” As the only way, at the time, that we could be sure stress levels were what they should be, was destructive X-ray diffraction, we had no choice but to recall the entire fleet. The design compromise that left a fleet open to deficiencies at the overhaul stage is never one that makes OEMs comfortable. It may be one that they come up with, based on the needs at the time (war, politics), however. As soon as possible, they upgrade the design, try to pressure the end-user base into upgraded models (consider the T 55 fleet changes discussed earlier) and move on. Allison’s later model C-30 series, and for that matter their earlier (post C-18) C-20B engines (in the Jet Ranger fleet), did not require the peening “safety umbrella.” In today’s economic climate, most operators in the Western hemisphere operate newer models with superior technology. However, in the working lifetime of anyone reading this book, these older models with their flaws and compromises are out there, some of them in the developing, struggling world, some of them closer than affluent society would like to have. Without the appropriate knowledge or records, telling “good” from “risky” is not possible. When the Canadian Department of Defence called for a Kiowa replacement program, the designated power plant manufacturer was the Canadian-based small engine division of Pratt & Whitney. Political convention required that a Canadian manufacturer be chosen. Pratt & Whitney designed the highly successful Pratt & Whitney, PW100. The core was then used to scale up to other equally successful models, like the PW300, an example of political influence buying positive results and products for the gas turbine community. Operational Compromise The Falklands war revealed that the Rolls Royce “Peggy” (Pegasus) could withstand the temporary


(limited hours) invasion of heavy fuel that her British designers might not have anticipated (and then again they might, having seen two world wars fought on their home turf!). In the mid-1980s, I was collecting information on NATO studies of gas turbines using “off spec” fuels. The Canadian navy had a fleet of LM2500s on its vessels. The TITs in the LM2500 were not conducive to using fuel with high vanadium content. So fuel treatment (which is expensive) was a must. Then, too, the gas turbine must be run at temperatures low enough to not have the compound that results from fuel treatment destroy the turbine blades. Regular washing is also a must (see the chapter on fuels). The engine fleet extension studies I was tasked with in the mid-1980s are another example of the requirement for contingency measures. The six aging engine fleets in my care were being asked for “another potential 20–25 years.” The overhaul shop promptly returned their verdict of “yes we have enough spares.” I submitted this statement to the management, with a warning, referencing the T-55-Cs that the OEM did not want to continue servicing the -C model. Why would other OEMs not eventually (and much sooner than 20–25 years) take the same position with old models, I asked. Flatly calling the fleet extension programs “pipedreams” due to logistical problems was not something my rank could pull off. The initiative I’d started to upgrade the -C’s to -D’s (which would also have brought the first stage turbine blades under the stress endurance curve) was dropped. The Secondhand Merchants There are many “good” secondhand merchants out there. There are many gas turbine packages, both power generation and mechanical drive, that have gathered dust but never been commissioned. Others have been used, but especially since they were well maintained and all critical component records on them carefully preserved, they have useful life in them. There are many excess commercial aircraft on sale, some of them “cheap.” But, “not all that still gleams …” If the rates are “fire sale” that is likely for a reason. Entire 747s for $0.75 million very likely have “no useful cycle” JT9s in them. What will it cost to zero time them? Hush kit them if they are to be used where noise regulations matter? Who will provide future spares and service? As always, “let the buyer beware.” Some news sources have claimed that well over $1 billion worth of bogus and “useful-life-ended” parts are in global commercially operating flight engines. The “$1 billion” is hard to prove. That it happens is unquestioned. “How” is simple. Instead of permanently scoring the part surface when it is deemed scrap during overhaul (as a bartender would do to a bottle of name brand hooch), the parts are left some place where the nocturnal “elves” might carry them away. Aircraft are not the only recipients. One of those nolonger-serviced-by-the-OEM engines I mentioned earlier ended up in a power boat. When cruising along the water’s surface, one of the turbine wheels came flying through the side of the hull. Again, many secondhand merchants are reputable. Excess or partially used power generation machinery from the Western hemisphere is being installed and commissioned in growing areas like Latin America and Asia. Aside from knowing with whom you are dealing, technical knowledge obviously helps steer these dicey waters. Whether the seller will also agree to provide some kind of warranty, parts and service as well as commissioning service for its wares (via subcontractors it will back) is the acid test of a vendor’s reliability. It’s also hard to find.


Technical Risk Mitigation What follows are short paraphrased extracts from EPRI work on technical risk mitigation.* The fleet studied is in a land-based power generation application, but the methodology used for calculations is statistical, thorough, and worth consideration (with any required modifications) for all applications of gas turbine. In this EPRI work, the major areas of uncertainty related to technical risk are addressed: scheduled maintenance frequency, unplanned maintenance frequency, costs, and outage duration. Key unplanned maintenance-dependent variables (outage hours and maintenance costs) can be represented as statistical distributions determined from the failure rate (i.e., events per time period), outage hours, and cost distributions. Unplanned outage hours and unplanned maintenance costs are calculated from three levels of event statistics (i.e., minor, major, and catastrophic) for the selected duty cycle by summing as follows (for 8760 hours per year): Unplanned outage hours = Σ [(Failure rate)Type × Service factor × 8760 × (Outage hours per event)Type] Unplanned maintenance cost = Σ [(Failure rate)Type × Service factor × 8760 × (Cost per event)Type] Note that, in this EPRI study, Minor is $800 per event. Major is $10,000 per event. Catastrophic is $240,000 per event. Technology risk primarily affects scheduled maintenance and unplanned maintenance. Variability in these areas can affect plant net revenue and profits considerably. The Combustion Turbine Project Risk Analyzer results, combined with an overall plant financial analysis, can represent data on variables of interest. For example, variations in plant profitability can be represented as a function of the variability in maintenance frequency. “Shifting Target” Data during Project Development, Negotiation, and New Model Introduction†

Promising gas turbine powered projects are negotiated only to die later. They may be reborn a while later. Depending on how opportunistic the culture is, this cycle might be swift indeed. In an article I wrote for a power generation periodical that specialized in the Chinese market, I mentioned the demise of a specific project. The cancelled project was owned by a specific partnership at the time of cancellation. Cancellation was due a variety of circumstances: permitting, financing, and ROI negotiations (the exact mix I no longer recall and is not germane to the issue at hand here). The information I had was current at the time of going to print as confirmed by a well-known, reputable Hong Kong source. About a week later, a new IPP Hong Kong firm called the editor I had written the article for, complaining wrathfully. The project was going ahead they said, they now owned it. They neglected to add how recent their acquisition was. As much publicity as they could find for their new “baby” would raise the success of their new public offering on it, so their wrath was financially driven, if not entirely justified. *Reference: D. Grace, Technical Risks and Mitigation Measures in Combustion Turbine (Design) Project Development, IGTI 2001-GT-0472. † [14-1]



Aircraft engine programs have long been the victims of “on again, off again” financial romances. Their success often depends to a large extent on the potential for or presence of war. The Osprey tilting rotor helicopter program’s fortunes dipped in the climate that cost the Dallas–Fort Worth area well over 50,000 jobs in the early 1990s, as what was then General Dynamics, a USAF base, and Bell helicopter slashed budgets and workforce. Does some of the lost momentum or staffing changes that such projects get put through translate into small design deficiencies and oversights later? Much depends on how well documentation was kept. In the case of changing partners for specific power plant joint ventures, just philosophical design differences between differing OEM partners on issues such as damage made by tooling limit levels that trigger component replacement and can initiate massive warranty cases later. So can potentially differing quality control methods among licensees. During GE’s 9F problem in the mid-1990s (the model was newly introduced on the market), end users debated long and hard about whether –9F problems were greater with U.S. assembled or GEC licensee assembled models. It took $1 billion, the involvement of about 400 GE engineers, and new quality control methods in rotor assembly that applied to all GE manufacturing and licensee facilities to stop set the rash of –9F vibration problems. Risk in Negotiating IPP Projects

Currently, the United States is the largest consumer of power globally. That is expected to change as China and India fulfill their growth potential. Research figures (arguable, given Southeast Asian monetary crises and change in many economies brought on by 2001’s recession and war) say that Asia, which used just 14% of globally produced power in 1992 by 2010 will use 33%. Asia is then the largest target for IPPs. As it is home to many of the world’s oldest and complex cultures, which then have to be the recipient of the swift, sometimes brash cultures of the occidental hemisphere, conflict and confusion can result. The gas turbine business reveals and is revealed by the circumstances of IPP growth.

● ●

This is a short list of a mesmerizing array of possibilities. Only upon successful negotiation of all these factors, does a gas turbine or a gas turbine package (combined cycle or other option) get revealed in its most advantageous light, in terms of efficiency and costs per fired hour. At this level, environmental standards maintained by the OEM are not an issue. Most end users, including many of those in the Western hemisphere specify “emissions to be compatible with BAT or better, but not to exceed [some easily attainable figure given contemporary technology].” Environmental standards maintained by the end user, however, do make a major difference to project operating costs. Does the OEM anticipate NOx and SOx taxes? Does it anticipate a CO2 tax? Does it care about CO2 sequestering? Does its plant offer potential for the gas turbine system to have ● ● ●

International Negotiation

International negotiations in the gas turbine (or combined cycle business) are fraught with many conflicting factors:

The end-users’ financial circumstances, which then dictate the terms of financing, joint venture percentages, controlling interests, potential for countertrade, and so forth. Level of technical expertise of the end user. This will dictate the extent to which the end user can opt for specific turbine features, refuse others with conviction, know exactly what options contribute to his application and which should stay with other users. Bargaining power of the end user. If the two preceding factors are ones in which the end user is poor, then he may find himself paying more for certain items. For instance, a study I was doing on costs per fired hour and the cost of spare parts on a specific OEM’s turbines revealed that lesser educated clients were charged more (as they were prone to operate turbines erroneously then claim “warranty” when failures occurred). Joint venturing potential of the end user. If an end user has enough financial strength or bartering power to be “almost” equal partners with an OEM in project development, then as in the case of the Siemens Westinghouse

YTL project (also see next chapter), a joint venture company can be formed. The end user can get training from the OEM as well as eventual transfer of all operational duties (see BOOT projects in the next chapter) as part of the deal. Political climate offered by the end user. Financial exchange facilities offered by the end user. Can the IPP, OEM, or IPP OEM receive payment in some international currency? Countertrade? Infrastructure offered by the end user. The fact that China’s current infrastructure is superior to that in many areas of India, makes China a preferred choice despite its politics and difficult exchange problems. What, if any, are the main cultural barriers in the end-user’s culture that also present legal hurdles to the developer? For instance, if middlemen negotiators in the Middle East are used to “baksheesh” what does a U.S. business person faced with the Corrupt Practices Act do?

Compressor inlet cooling? Compressor intercooling? Reheat within the turbine module? Additional waste heat recovery? A land-based “afterburner” (see the chapter on performance optimization)?

Is the end user ambitious enough or sufficiently trained and supported to work with any combination of these? Or is he potentially an increased warranty risk to the OEM, if the OEM supplies the option. Market Assessment Risk

Market assessment of various factors, of which market entry timing is particularly critical, can make or break the progress of a gas turbine. If that turbine’s core is applicable to many growth models, then market factors can make or cripple an entire family of engines. The gas turbine’s potential has changed dramatically as it crossed first the 200 MW barrier and, in 2002, the 450 MW barrier. The excuse to stay with “steam only” diminishes drastically with these entries on the power train stage. And yet ironically, steam remains a player, because of the technology refinements that come with combined cycles, steam reinjection for power augmentation and NOx reduction, supercritical steam production for efficiency increments, cogeneration applications, and a variety of other embellishments.


The GE LM series, heralded by the entry of the LM 2500 series, was well served by the success of commercial aviation’s CF6-80C2. The aeroderivative LM series model is essentially the CF6 parent sitting on a base with an oil console. That CF6 model was, in turn, well timed and well served by rivalry with the Pratt and Whitney PW4000 and the Rolls Royce RB211 series, which pushed it to all levels of excellence in the scrap for every last decimal point of incremental efficiency. Solar, back in the 1950s, could not have picked a more optimal market entry time for its initial Saturn and Centaur 3300 offerings, which would, in part because they filled a much needed market hole that no one else came close to, lead to its prime positioning today. The finances for the development of its vastly more modern Mars and Titan technology came on the backs on these more humdrum, humble workhorses that made no claims on breaking any efficiency barriers. The Rolls Royce Avon was well served by being “on time” for being the power plant on the Alyeska pipeline. Despite being the prototype land based aeroderivative of a successful aeroengine power plant called the RB211, the Rolls group picked its aeroderivative market entry timing to coincide with TransCanada pipeline’s needs for an aeroderivative gas turbine fleet. Plant Siting

Determining the site of a plant involves several factors. Among the most critical in a complex infrastructure, like the United States’, are environmental standards, consequential permitting requirements, and emissions trading potential. This is a subject that almost merits a separate book. However, a few links are provided for the reader’s perusal. Government or government-funded organizations such as EPRI (Electric Power Research Institute), can have pertinent information available on their websites: (EPRI) Each state in the United States has its own air quality/permitting (for gas turbines) site. One example is http://www. Design Development and Operational Assessment by Both OEMs and End Users

Aeroengine design precedent has much to offer land-based gas turbine design, whether the engine is “officially” an aeroderivative or not. Development costs of gas turbine design improvements are massive, and OEMs strive to avoid “reinventing the wheel,” as a normal business practice. This is illustrated next by extracts from Case Study 1 on combined cycle gas turbine power generation plants. The reader may note that aeroengine precedent has played a critical role in the development of this OEM’s industrial F, G, and H technology models. The full-load testing mentioned in this case is vital, especially with larger gas turbine models. It is sound business practice for the customer to attend the full-load test of any machinery package that he will end up owning and operating, if at all possible. A full-load test gives one the opportunity to observe the performance of cooling systems such as any steam cooling (closed or open loop) and ensures that the system does not leak, especially on the massive H technology machines.


Case 2 is of interest in that it presents an EPC contractor’s perspective. Depending on the contractor’s work scope, his concerns may be equivalent to an end user’s. The case describes checks and tests that an operator (EPC contractor or otherwise) or end user can conduct to compare how an installed plant fares against the equipment’s measured output in the manufacturer’s facility. Case 3 is an OEM’s work on plant profitability options using PC, AFBC, CC, IGCC, ACFBC, SPFBC, CPFBC technologies (see the case study for a description of these acronyms). It needs to be noted that an OEM may also be its own plant contractor and its own operator or end user, especially in BOOT projects. Some OEM projects are BOOs, where the project is never transferred and the OEM retains part ownership (such as the YTL-Siemens IPP power plants in Malaysia). Further, as per the author’s qualification presented in the introductory material of this book, the cases presented are potentially of interest for both their technical and historical comparison value. A few years after this source material was written, the prices of natural gas escalated steeply, which could change many of the comparisons made here and in similar cases throughout this book. Case 1*

Explosive growth in power plants in the United States and elsewhere is occurring through combined cycle advanced gas turbine technology. Significant fuel expenditure savings are possible through such technology. Much of the recent advances have been possible through the transfer of aeroengine design tools, elevated temperature materials, coatings, and sealing technologies. A balanced approach that melds the aeroengine technologies and longstanding field experience from large industrial frame gas turbines is key to ensuring reliability, availability, maintainability, and durability (RAM-D) design objectives are met. Future costs associated with power generation and distribution with these advanced gas turbine combined cycle power plants will undoubtedly be driven by major decisions of OEMs pertaining to design and validation approach, material selection, reparability, design criteria, and design features for quicker maintainability. Figure 14–1 shows the evolution of Mitsubishi Heavy Industry (MHI) gas turbines during the past two decades. The introduction of F-class gas turbines resulted in an increase in firing temperature of 2000 through the use of newer materials and advanced blade cooling concepts. With firing temperatures around 1300–14,000, the combined cycle efficiency of the F-class combined cycle power plants is 56–57% (LHV). In 1997, MHI introduced the G-class gas turbines at 15,000 firing temperature. G-class gas turbines apply steam cooling to combustor baskets and achieve a combined cycle efficiency of 58% (LHV). The field experience with steam cooling application was further expanded to include other hot gas path components in MHI’s H-class gas turbine. MHI’s H–class gas turbine applies closed circuit steam cooling to combustor baskets, rows 1 and 2 turbine vanes and blades, and turbine rings to achieve thermal efficiency of 60%.

*Source: [14-3] Courtesy of Mitsubishi Power Systems (MPS). Extracts from the MPS collection of academic papers, with specific reference to V. Kallianpur, E. Akita, and Y. Tsukuda, Enhancing Reliability and Reducing O&M Expenditures in Advanced Combined Cycle Gas Turbine Power Plants, IGTI 2001-GT-0499.



It has been demonstrated that the development of these key technologies for large frame gas turbines can be made economical by using the knowledge and experience acquired from aeroengine developments. However, in many cases, there are limitations in extrapolating the aeroengine technologies directly to large frame gas turbines due to size and duty cycle differences. For example, casting of large directionally solidified and single-crystal blades is much more difficult than smaller aeroengine blades. Alloy composition and heat treatment are generally altered for improving castability and production yields of the larger industrial castings. Those chemistry alterations also affect the long-term material behavior aspects. In aeroengines, the hold time exposure at peak transient stress and temperature are significantly shorter, typically around two minutes. By comparison, the LCF hold time exposure at peak stress and temperatures are several hours long in industrial applications, for peaking and base load operation. Therefore, the design approach for achieving high reliability in new highefficiency industrial gas turbines requires retaining the proven designs features and field experience from the frame machines, while transferring aeroengine design technologies and field experience for optimizing stage efficiencies, heat rates, and output. Design Decisions Influencing Reliability

Figure 14–1. Evolution of MHI industrial gas turbines. (Source: Mitsubishi Heavy Industries.)

Combustor technology is shifting toward meeting single-digit NOx emissions. The changes occurring under deregulated generation and dispatch also necessitate that the NOx emission levels are met at a broader load range. Other emissions, such as CO, VOC, and particulates, also have to be minimized. The combustion control to stabilize the flame at a lean fuel-to-air ratio is one of the most important challenges for all gas turbine manufacturers. The thermal efficiency of today’s combined cycle power plants are much higher than conventional steam power plants. For example, a combined cycle power plant with the F-class gas turbine having firing temperatures between 1300 and 1400°C attains thermal efficiency of 55–57%. The combined cycle efficiency has been further improved by raising the firing temperature, as shown in Figure 14–1, and it has even reached 58–60% for the Gand H-class gas turbine. In order to use valuable clean energy efficiently, several key technologies for efficient and environmentally benign combined cycle power generation have been applied: Dry, low NOx combustion technology. Blade cooling technology. Heat resistant materials and casting technology. Aerodynamic design methodology. Numerical flow simulation (computational fluid dynamics). 6. Seal and clearance control technology.

1. 2. 3. 4. 5.

Key features that are important from the standpoint of reliability are use of proven design structural features, maintaining same scaling procedures, use of proven materials, and extensive verification testing. Use of Proven Design Structural Features Figure 14–2 compares rotor cross-sections of the Mitsubishi M501D, M501F, M501G, and M501H gas turbines. There is a striking resemblance between the rotors. Except for the spool-type compressor in the M501D, the compressor and turbine sections in the F, G, and H gas turbines even maintain the exact same bolt count: 12. By retaining the proven design features in the product evolution (see Figure 14–3), the design engineers continue to work within the field experience window relative to temperatures and stresses. MHI rotor designs make use of “positive torque” features for enhancing torque transmission without slippage. In fact, field experience has proven that the use of radial pins in the compressor and curvic couplings in the turbine enhance the overall resistance to interstage slippage, which is particularly important from a startup/ shutdown consideration. Another necessary design feature in advanced design compressors is the provision to replace foreign object damage of compressor blades quickly on site without transporting the rotor to a service overhaul repair facility. Maintaining Same Scaling Procedures The scaling procedure from 60 Hz designs to 50 Hz designs has been steadfastly maintained throughout MHI product lines. For example, the first two rows of blades and vanes of the turbine are common across the 60 Hz (M501 series) and 50 Hz (M701 series) versions. Likewise, the combustors are common between the two frame sizes. The field experience and design calibration with this scaling approach is retained across MHI’s D, F, and G classes of gas turbines. By contrast, others have deviated significantly in scaling method, rotor structure, materials, and coatings. Use of Proven Materials Figure 14–4 compares the materials used in MHI’s F-, G-, and H-class machines. The


Figure 14–2.


Similar rotor cross-sections retained. (Source: Mitsubishi Heavy Industries.)

commonality in materials simplifies transfer of field repair experience and practices. Also, the use of fewer standardized materials makes it possible to concentrate on long-term material properties characterization. By retaining materials and field proven structural design features, MHI’s design focus has been on improving stage efficiencies in the compressor and turbine through state-ofthe-art 3D aerocomputational techniques. Figure 14–5 is a picture of the advanced 3D designed compressor blades in the H machines. The use of such advanced tools has made it possible to achieve a 25:1 pressure ratio, as compared to 20:1 with the G machine. More important, the higher pressure ratio is achieved with two fewer stages than the G. Thus, similar rotor spans are maintained for the G and H machines,

thereby optimizing on design operating experience and reliability aspects. The M501 gas turbine has a 16-can dry premix low NOx combustor to satisfy the worldwide NOx emission regulations. The established concept of the premix combustor is retained, such as the two-stage burner assembly and the bypass valve system. The feature of the combustor is the application of a multiple fuel nozzle system to improve flame stability in lean burning. The combustor has a pilot nozzle in the center and eight surrounding main nozzles supplying the premixed air and fuel. Proper adjustment of fuel flow rates through the pilot and the main nozzles allows the NOx emission to be maintained at a lower level than that of its predecessor in the entire load range. The combustor wall and the




501D5 501F 501G 501H

Cold End Generator Drive 2-Bearing Rotor 4-Stage Turbine Individual Combustors Horizontal Split Casing Figure 14–5. Advanced 3D designed compressor blades. (Source: Mitsubishi Heavy Industries.)

Single Row 1 Vanes Steam (Cooling (

Cooled & Filtered Rotor Air

Figure 14–3. Proven design retained. (Source: Mitsubishi Heavy Industries.)

transition piece are cooled using efficient double-wall cooling structures developed by Mitsubishi, named MTFIN™. The structures efficiently provide more air to the combustion region for the lean, low-NOx burning. The F-class premix combustor is shown in Figure 14–6. Extensive Verification Testing Throughout MHI’s almost 40 years as an industrial gas turbine OEM, new technologies have been made commercially available only after fullscale full-load testing at MHI’s internal facilities. Figure 14–7 is a picture of a full-scale MHI combined cycle power plant at Takasago, called T-Point facility. The facility is operated usually under daily start-stop operation, especially during the summer peak season, and power is transmitted to a local utility. Thus reliability and availability aspects have to be met according to stringent commercial contractual expectations. Thorough inspections following the peak dispatch season enable continuous validation and modifications for enhancing component durability, power plant reliability, and availability. For example, minor design adjustments made during early stages of machine verification and operation resulted in enhancements to cooling circuits, resulting in superior thermal distributions and improved material/coating performance and component durability prior to commercial introduction of G technology. MHI followed a similar approach before commercial introduction of F technology.

Figures 14–8 through 14–10 show the excellent condition of hardware at the fourth inspection on the M501G machine at T-Point following 10185 hrs and 561 starts. The facility is also utilized for validating the H machine. For the previously mentioned reason, the common rotor span between the G and H machines makes it possible to use the T-point facility to conduct design validation tests at the facility. Case 2*

The huge increase in electrical power demand continues worldwide and especially in the United States. Therefore,

Materials used in F, G, & H MGA 1400 MGA 2400 Tomilloy Low Alloy Steel

Turbine Blades Rows 1 to 4 Turbine Vanes Rows 1 to 3 Combustor Transition Piece Rotor

Figure 14–4. Materials commonality retained. (Source: Mitsubishi Heavy Industries.)

Figure 14–6. MHI F-class premix combustor. (Source: Mitsubishi Heavy Industries.) *Reference: [14-4] J. Zachary, “How Close Is the Measured Performance to the True Output and Heat Rate? The Proof Is in the Testing! from the collective papers of J. Zachary, including work presented at PowerGen International 2001.



Figure 14–7. MHI’s T-Point combined cycle power plant. (Source: Mitsubishi Heavy Industries.) Figure 14–9. Service exposed M501 G row 1 vane from T-Point. (Source: Mitsubishi Heavy Industries.)

In the last six years, to keep up with the rapid technological changes, most of the PTCs have been updated and reissued. PTC-46, Power Plant Performance Test Code, (1996), is routinely implemented in combined cycle facilities. PTC-22, Gas Turbine Performance Test Code, will expand its scope to cover the testing and calculations for exhaust temperature and exhaust flow, in addition to power output and heat rate. This new version is because the industry needs to provide

Figure 14–8. Service exposed M501G combustor from T-Point. (Source: Mitsubishi Heavy Industries.)

an increasing number of existing power plants plan thermal performance tests to check their power output range (not necessarily the same as when they were commissioned), before they commit to any further power deliveries. A thermal performance test on a new plant is a test where the end user checks that his newly commissioned plant meets the power output guarantees made by manufacturers and contractors. The proper conductance of the test, data collection, and correction to reference conditions have many contractual, technical, and commercial implications for all parties. The practical aspects of testing, from contract negotiations to field implementation, in which the thermal evaluation of a power plant facility and its major components is carried out, are described as follows. ASME Performance Test Codes

The American Society of Mechanical Engineers (ASME) performance test codes (PTCs) serve as the guiding documents for all aspects of performance testing. The ASME test codes have achieved worldwide acceptance and are applied in Asia, Australia, South America, and Europe.

Figure 14–10. Service exposed M501 G row 1 turbine blades from T-Point. (Source: Mitsubishi Heavy Industries.)



guarantees for exhaust energy and exhaust temperature in combined cycle applications. The methodology will be based on a complete mass and energy balance around the combustion turbine. A new version of PTC-6, Steam Turbine, was issued in 1996. A committee was formed in 2000 to develop a new PTC-6.2 dealing exclusively with steam turbine performance in combined cycles. A new and comprehensive Measurement Uncertainty Code, PTC-19.1, was issued in 1998. A draft for a new PTC-4.4 for heat recovery steam generators (HRSGs) was released for industry review. PTC-4.4 (HRSGs) and PTC-22 (gas turbines) are being revised in close cooperation so that they use the same methodology for calculating combustion turbine exhaust heat (input source for the HRSG). New codes in the PTC-19 series dealing with measurement techniques are close to publication, of particular interest being PTC-19.5, which covers flow measurement.

Combined Cycle Guaranteed Values

The testing of combined cycle power plants, including combustion turbines, HRSG, and steam turbines, requires two measurements: ●

The electrical power output on the high side of the transformers. The fuel heat input—flow and composition—at the facility fence.

Accurate evaluation of the thermal performance in a power plant is challenging. Errors in measurement of power output and heat rate could translate to millions of dollars in liquidated damages (LDs). An example of the commercial risks for missing the guarantees even by very small amounts is presented in Table 14–1. A typical 800 MW power plant with a 6000 Btu/kWh heat rate could pay LDs in excess of $1 million for shortages of 0.07% in performance guarantees. Preparations for test should start at the beginning of a project, when considering conditions and configuration. All of the parameters that might influence the test results need to be properly identified. As part of the contract definitions, all the ambient conditions at the inlet of the combustion turbine and in the vicinity of the heat sink must be stated. One must also define the location of the electrical power metering, auxiliary power measurement, power factor range, fuel quality and heating value, plant configuration during test, makeup water, and blowdown valve positions.

Test Significance

While test codes offer the basic framework, additional practical issues must be resolved to implement code recommendations in real-life situations. Most of the commercial contracts specify that test procedures must be mutually agreed on. Many end users do not realize the true aim of the thermal performance tests and combine other plant acceptance criteria with the thermal evaluation of the plant.

Table 14–1.

Power Heat rate

The thermal performance test is not a reliability or endurance test. Very often, owners and end users request that a lengthy performance test be conducted, far beyond the recommendations of the codes. Requesting a test to be carried out for an excessive number of hours (for example, 8 or 10 hours for a combined cycle) might actually have a negative impact on the results. During these continuous runs, a wide variation in ambient temperature could result in the plant operating at conditions further away from guarantee conditions and thus cause errors. Thermal performance tests are used to verify the correction curves. This controversial issue is common with performance testing. In the following paragraph, the issue of correction curves will be discussed. However, plant performance guarantees are usually made for a single point. Often, the test program requires conducting several tests at different ambient conditions and plant configurations. This does not relate to the performance test but intended to verify if the hardware behaves as correction curves predict. This is a separate task with a different objective than the performance of the equipment. So if the parties involved agree, it should be conducted before the performance test, results should be mutually accepted to by all, and correction curves should be redrawn accordingly. Test repeatability is not an acceptance criterion. A facility thermal performance test is a demonstration of the output and heat rate. Conducting repeated tests and comparing the corrected results might not indicate a poor test. Correction curves might be slightly different at different ambient conditions, or random error values could be higher. Verifying the instrumentation and proofing the conversion methodology are part of the pretest preparations and the mutually agreed-on test procedure, not of the test itself. Conformance with important design criteria of equipment. One prerequisite of the performance test procedure is to operate the power plant at base load. In most cases, there is not a clear definition of what base load means. It should be mentioned that all parties expect the equipment to perform in accordance with manufacturer’s design criteria for “safe continuous” operation. One of the most contested and difficult issues between owners, bank engineers, contractors, and manufacturers is the definition of the combustion turbine control algorithm, which is considered proprietary by the manufacturer. All of the parties need to ensure that the control algorithm used during the thermal performance test will not be further modified, which could invalidate the results. Conductance of the thermal performance test should not be linked to the punch list items. Arguments often arise between the parties because of the component status during the test. For example, a test can be carried out with valves or subsystems operating in manual rather than automatic mode. The performance test scope is to confirm the power output and heat rate guarantees only.

Potential Commercial Liquidated Damages—Typical Case [14-4]



Error (%)



8000,000 kW 6,000 Btu/kWh

500 kW 4 kW

0.0625 0.06667

$1,000/kW $150,000/(Btu/kWh)

$500,000 $600,000



Typical Measurement Uncertainty for a Combined Cycle Plant [14-4]



Systematic Uncertainty

Systematic Uncertainty Contribution

Random Uncertainty

Random Uncertainty Contribution

Power Output Measurement Uncertainty Ambient temperature Facility net output Barometric pressure Ambient RH Circ. water temp. CTG shaft speed CTG gross output STG gross output CTG power factor STG power factor RSS Total uncertainty

0.26051 %/°F 1.00000 %/% 4.23000 %/psia −0.00156 %/%RH 0.01428 %/°F 0.02549 %/rpm 0.01052 %/% 0.00389 %/% 0.01875 %/% 0.00490 %/%

1.33°F 0.258 0.039 psia 2.0040 4.170°F 0.271 rpm 0.318 0.3260 1.030 1.0300

0.34648°F 0.25800 0.16497 psia −0.00313 0.05955°F 0.00691 rpm 0.00335 0.00127 0.01931 0.00504 0.46674

0.20780°F 0.15800 0.02000 psia 0.50000 1.00000°F 0.50000 rpm 0.20000 0.20000 0.00800 0.00800

0.05413 0.15800 0.08460 −0.00078 0.01428 0.01275 0.00210 0.00078 0.00015 0.00004 0.18821

0.5033 Heat Rate Measurement Uncertainty

Gas fuel flow Gas heating value Ambient temperature Facility net output Barometric pressure Ambient RH Circ. water temp. CTG shaft speed CTG gross output STG gross output CTG power factor STG power factor RSS Total uncertainty

1 %/% 1 %/% 0.0056 %/°F 1 %/% 0.38 %/psia 0.0023 %/%RH 0.012 %/°F 0.0024662 %/rpm 0.011 %/% 0.0039 %/% 0.019 %/% 0.0049 %/%

0.801°F 0.150°F 0.562°F 0.258 0.0039 psia 2.0000 4.170°F 0.271 0.318 0.3260 1.030 1.0300

As long as the safety and integrity of the equipment are maintained, the actual status of components or system, which could be fixed later as part of the punch list, should not nullify the test. Measurement Uncertainty and Test Tolerance

The determination of the power output and the heat rate of a power plant is associated with errors in the measuring devices, corrections to guarantees, and inadequate test conductance. A rigorous measurement uncertainty analysis is now required by all PTCs, to assess statistically the potential gap between the test results and the “actual true” power output and heat rate of the plant. The analysis, fully described and commented on in PIC—19.1, basically identifies systematic error (an offset from the actual value obtained by nonstatistical methods) and precision errors (random errors derived by statistical methods) of each primary variable, from the sensor to the data acquisition system. These values are multiplied by a sensitivity coefficient quantifying how each variable influences the result of either power output or heat rate. The square root sum of squares for all parameters is calculated to determine a ± tolerance band. The area, defined by the band applied around the measured test results, creates a domain where there is a 95% confidence level that the “true power output or heat rate” could be found. An example is presented in Table

0.80100 0.15000 0.00315 0.25800 0.00148 0.00460 0.05004 0.00067 0.00350 0.00127 0.01957 0.00505 0.85657

0.05000°F 0.04000 0.20780°F 0.15800 0.02000 0.50000 1.00000 0.50000 0.20000 0.20000 0.00800 0.00800

0.05000 0.04000 0.00116 0.15800 0.00760 0.40115 0.01200 0.00123 0.00220 0.00078 0.00015 0.00004 0.17110


14–2, where the power output uncertainty is 0.5% and the heat rate uncertainty is 0.87%. For the same example of an 800 MW power plant, the uncertainty for power equals ±4 MW valued at $4 million, using the same LD criteria as in Table 14–1. Respectively, for a heat rate value of 6,000 Btu/ kWh, a 0.87% uncertainty equals ±52 Btu/kWh and has a value of $7.8 million. Thus, the commercial value of measurement uncertainty equals close to $12 million or 2.8% of the entire typical project cost. Correction Curves

Power plants are rarely tested at the guaranteed conditions (which usually includes ambient conditions, generator power factor, and other specific plant configuration requirements, such as blowdown). To demonstrate if a test has achieved the guaranteed power output and heat rate, a wellestablished methodology of correction curves is applied. A correction curve for a specific parameter, for example, ambient temperature, is developed using a computer simulation program, where all of the other variables are kept constant at their guaranteed conditions. Only the parameter in question is allowed to vary, and the impact on power output and heat rate is recorded. A curve is drawn, showing the variation of the power output versus ambient temperature, as shown in the example in Figure 14–11. The curve is then converted to a polynomial equation and further used with



Gross Equip’t Output Correction Factor




1.000 y = −2.74904E-05X2 + 1.77604E-03x + 1.03625E+00 0.980


0.940 50.00










Comp. Inlet Temperature - ⬚F

Figure 14–11.

Example of correction curves. [14-4]

other correction curves in a large spreadsheet. The entire process is tedious, time consuming, and expensive. There are many significant problems with this methodology, which could very significantly skew the test results. As can be seen from Table 14–3, the use of correction curves started with the simple process of a single homogeneous fluid expansion, which could be depicted quite accurately. As the concept is expanded to more then one thermodynamic process, the correction curves become two and three dimensional. Table 14–3.

An alternative solution to the problem is to apply a complete computer simulation program for the plant behavior. Thus, all variables can be adjusted simultaneously and all the basic laws for mass, momentum, and energy balance are truly maintained. The correction curve methodology cannot account for secondary effects on the turbomachinery because of the coupled effect of changes in more than one variable. Ambient temperature and relative humidity are the most common examples.

Thermodynamic Processes [14-4]

Component to Be Tested Steam turbine Combustion turbine HRSG Heat sink

Combined cycles Integrated gasification combined cycle (IGCC)

Type of Thermodynamic Process


Adiabatic expansion Adiabatic compression Combustion Adiabatic expansion Heat transfer Vaporization Condensation Various heat removal methods using phase change All of the above All of the above Gasifier Air separation unit

Single homogenous fluid Air Fuel and air Exhaust gases Steam and exhaust gases Steam Water and air


The final thermal performance tests of a combined cycle plant are conducted after all of the components—combustion turbine, HRSG, and steam turbine—are commissioned and fine-tuned, a process that requires a significant number of hours of operation for each of the components. To cover the gap from the “new and clean” performance guaranteed by the manufacturer to the performance measured during the test, equipment degradation curves have been used. The most influential degradation curve is associated with nonrecoverable degradation of the combustion turbine performance. The combustion turbine manufacturer produces these curves based on the results of the performance fleet and in-house evaluation. Great significance is attached to the shape of the curves for obvious impact on plant performance. Particularly for new models where fleet experience is not totally applicable, conservative degradation curves are used. Attempts to develop specific curves based on actual tests are extremely difficult because changes in performance for small numbers of operating hours are the same order of magnitude as the measurement uncertainty. Inlet Cooling Devices

Inlet cooling devices are a safe and profitable means to achieve better performance at low risk and low cost. Evaporative cooling, inlet fogging, inlet air refrigeration using mechanical compression, and absorption systems are popular options. This has created new challenges for testing staff. The performance of the combustion turbine, and the Rankine cycle components, depends not on ambient conditions at the fitter house but on those at the inlet belmouth of the compressor. The methodology to assess the conditions at this particular plane is far more difficult and can create errors for the overall power output and heat rate values. So is the inlet cooling device an integral part of the power plant? With mechanical chillers, should we include the entire refrigeration unit as part of the power plant?

Figure 14–12.


Manufacturers have created a system of interstage cooling for aeroderivatives. How should we deal with performance testing and corrections under these conditions? Of particular concern is the use of inlet foggers with a water injection amount beyond the 100% relative humidity, commercially called wet compression. So some recommend that one exclude all the inlet or interstage cooling devices from the applicable control volume of the power plant. Particularly for combustion turbine tests, verification of the guaranteed exhaust flow and exhaust temperature is almost impossible when the inlet cooling device is running. However, one can conduct tests with the inlet cooling on and then off for comparison purposes. Case 3*

The final evaluation of power generation technologies is based mainly on its electricity generation costs or life cycle cost. Considering today’s fuel prices and price development projections over the plant lifetimes, the economical analysis performed can serve as a framework for project and investment decisions. More stringent environmental regulations raise production cost. Long-term planning in power plant capacities has become uncertain as never before. Changing fuel prices are the third parameter that has to be considered before investing in power plants. According to forecasts of the world energy conference and others, the fossil fuels, like coal, oil, and natural gas will be also in the near future our main energy source for power generation (Figure 14–12). Therefore it is very important to use these nonrenewable energies with great care and burn them only in highly efficient plants. This saves not only our limited reserves but also cuts emissions in order to protect life, environment, and climatic stability. *Source: [14-5] Courtesy of Siemens. Extracts from A. Lezuo and R. Taud, Comparative Evaluation of Power Plants with Regard to Technical, Ecological and Economical Aspects, 2001-GT-0504.

Worldwide electricity generation by fuels. [14-5]



An overview follows of state-of-the art and future power plant technologies, environmental issues, cost, and economic considerations. We employ the following abbreviations: PC = Pulverized coal steam power plant . AFBC = Atmospheric fluidized bed combustion. CC = Combined cycle plant. IGCC = Integrated gasification combined cycle. ACFBC = Atmospheric circulating fluidized combustion bed. SPFBC = Stationary pressurized fluidized combustion bed. CPFBC = Circulating pressurized fluidized combustion bed. Available Technologies

Considering the time frame up to the year 2005, no revolutionary new power plant technology will be commercially available. The improvement will be found mainly in higher efficiencies due to enhancement of components and an increase in the upper process temperatures of the wellknown processes. For all plant designs, the same boundary conditions have been assumed unless otherwise stated, which are in Table 14–4. Coal-Fired Power Plants Due to large reserves and the worldwide availability of coal, both lignite and hard coal, this energy carrier also will play an important role for electricity generation in the future. Although the increase in consumption will be lower than that of natural gas, the relative contribution to the total electricity production will still amount to approximately 33–34%. Therefore, investment in the development of coal technologies also will be of great importance in the future. Pulverized Coal Power Plants Today’s atmospheric pulverized coal power plants (Figure 14–13) are characterized by high efficiencies, high availability, and high reliability. They serve a power range from 20 MW to 1000 MW per block,

Figure 14–13.

Table 14–4.

Assumed Boundary Conditions [14-5]

Ambient temperature Ambient air moisture Ambient air pressure Condenser pressure NOx emission SOx emission Dust emission

°C/°F % bar/psi mbar/psi mg/m3 STP mg/m3 STP mg/m3 STP

15/59 60 1013/14.69 50/0.725 150 100 50

STP = standard temperature pressure

whereas the lower capacities up to 300 MW are usually built as atmospheric fluidized bed combustion systems. For large grids, large-sized double units are preferred for cost reasons. The design points out that net efficiencies for a modern power plant with wet cooling towers and secondary measures for flue gas cleaning can be well above 40% LHV. Due to startup losses and partial load operation, the mean annual net efficiency can be lowered however by up to 3 percentage points. For these investigations, only the design points have been considered. In industrialized countries, newly built large power plants usually have steam conditions of 250 bar and 540°C and are equipped with reheat. In a few cases, power plants with steam conditions of 285 bar and 600°C are under construction. The influence of the steam parameters on the efficiency and investment is shown in Figure 14–14. From this diagram, it can be seen that the investment is increasing more than proportionally compared to the efficiency increase. With the help of desulfurization plants (FGD), DENOX, and dust filters, all the emission limits set up by any regulation authority can be met easily. The limits applied in this

Pulverized-coal-fired steam power plant. [14-5]


Figure 14–14.


Influence of steam condition of pulverized coal power plants on efficiency and investment. [14-5]

study (see Table 14–4) are more stringent than any current limits in the world, but they are expected to be relevant in future power plants. Pressurized Fluidized Bed Power Plant The power plant with stationary pressurized fluidized bed combustion (PFBC) was introduced into the market in the 1990s. Since then, seven plants have been built and a cumulated operating experience of more than 100,000 hours could be gained. While the first plants had a capacity of only 70 MW, in Japan the first plant with an electrical output of 350 MW is in the test phase. The advantage of this type of plant is its possibility to reduce the sulfur and nitrogen emissions only by primary measures, thus saving investment for secondary measures. In addition, this plant can be fed a very wide range of coal types with different compositions. Due to the low operating temperature in the steam generator of approximately 850°C, the formation of thermal NOx can be kept at a minimum.. The reduction of SOx is being managed by adding limestone directly into the fuel, where it is reacting with the sulfur and bonded in the ash. The degree of reduction can be adjusted by the sulfur/limestone ratio. As long as today’s emission standards are applied, the limit values can be maintained, but for lower values, secondary measures, at least for NOx, have to be taken, such as the SCR installed with the 350 MW Karita plant in Japan. This, however, reduces the cost advantage of this concept. By means of expansion of the exhaust of the supercharged steam generator (12–18 bar) in a bottoming gas turbine, the high temperature also can be used for power generation and hence reducing exergetic losses. The gas turbine drives the compressor for the combustion air and in addition an electric generator, which produces about 20% of the total power output. In this way, a net efficiency of approximately 42% LHV can be reached. An improvement of the efficiency by increasing the process temperature is not possible because of the ash melting point. Higher temperatures would make it impossible to reduce the ash content in the flue gas by cyclones, which

are needed to protect the bottoming gas turbine against erosion. Because of the limitation of temperature, this concept cannot take advantage of the highly efficient modern gas turbines with high inlet temperatures. Therefore, the so-called second generation circulating pressurized fluidized bed combustion (Figure 14–15) is being developed. Its higher thermal power density enables very high efficiencies of above 50% LHV. This concept consists of a circulating pressurized fluidized bed combustor (CPFBC) with a pressurized partial gasifier in parallel that generates a syngas. The gasifier converts only 60–80 % of the carbon, and the rest is burned completely in the CPFBC. After cleaning the flue gas from particles in two filter stages, its temperature can be raised to gas turbine inlet temperature by means of the syngas of the gasifier. The exhaust gas of the gas turbine can be utilized in a steam process in the same way as it is done in a conventional combined cycle plant. To maintain today’s emission standards, an adequate sulfur bonding can be reached by admixing additives into the fuel. Because of the high process temperature, an SCR-plant for NOx reduction will be necessary. This concept is still under development, and it has to be demonstrated that the particles in the flue gas can be kept below the permissible values of the gas turbine. Integrated Coal Gasification Combined Cycle The concept of an integrated gasification combined cycle plant incorporates an oxygen or air-blown gasifier operating at high pressure and producing raw gas, which is cleaned of most pollutants and burned in the combustion chamber of the gas turbine (Figure 14–16). The sensible heat of the raw gas and the hot exhaust gas of the gas turbine are used to generate steam, which is expanded in a steam turbine. The mechanical energy of the gas turbine as well as the steam turbine is used to produce electric power. While the power plant systems are well known and commercially available, the different gasification processes, including their auxiliary systems, are still in the beginning of commercial-scale introduction.



Figure 14–15.

Circulating pressurized fluidized bed combustion. [14-5]

The potential of a high net efficiency of more than 50% LHV and very low sulfur and dust emissions—they are removed before passing the combustion process— make it an attractive option for future power generation. Until 1998, five demonstration plants for coal gasification with outputs of between 100 and 300 MW have been put into operation worldwide. Gas-Fired Power Plants Because of the quick gas turbine development, driven by strong competition, during the past 10 years, the conventional gas-fired steam plants are no more of interest. This is not only due to their relatively low efficiency but also due to itheir relatively high investment. The outstanding performance of natural gas-fired combined cycle (CC) plants (Figure 14–17) has led to the situation in which many of the old conventional power plants have been shut down in favor of new CC plants. These CC plants are available in a wide power range from 50 MW up to 800 MW per block. The large units reach a net efficiency level of approximately 56–58% today. Even the small plants rated at about 100 MW are still well above 50%. New plants, which are already under development and in

Figure 14–16.

construction, are supposed to reach the target value of 60% by the year 2002. Besides high efficiencies, combined cycle plants are characterized by low investment, low service cost, and outstanding environmental behavior. The only negative aspect in the row of benefits is the availability of the gas and the gas price, which is very sensitive to market alterations. Efficiencies

The comparison of efficiencies (Figure 14–18) shows that the whole range of modern base-load power plants is able to reach a net efficiency of more than 40%. The outstanding performance of the combined cycle plants is not only due to its technology but also a result of the use of a high-valued clean fuel. The conventional coal-fired steam power plants have only a limited potential in increasing its efficiency by raising the steam parameters or adding a second reheat stage. Only the new technologies like IGCC and CPFBC are able to overcome the limitations that restrict conventional steam turbine cycles. These technologies, such as the natural-gas-fired CC plants, use a combination of gas turbine and steam turbine and hence are able to use the entire temperature gradient from the combustion chamber.

Integrated gasification combined cycle. [14-5]


Figure 14–17.

Single-shaft combined cycle power plant. [14-5]

These technologies are very attractive since they run on almost any type of coal, which is the longest lasting fossil fuel source. Emissions

The consciousness of a benign environment is more and more important to the people all over the world. Power plants are, besides, the traffic the branch with the highest output of gaseous emissions. Several ecological anomalies, like acid rain, the greenhouse effect, and overheating of rivers can be attributed to power plants.

Figure 14–18.


Comparison of efficiencies. [14-5]

In the meantime, government and industry in many countries have been responding with emission regulations and the positive results can be seen already in many areas. Basically all the emissions are reduced by increasing the plant efficiency. That means less fuel is required to generate the same amount of electricity and thus also less pollution is efficient. But this is not enough, and other measures have to be taken to limit the amount of pollutants. Dust filters are now standard equipment in many of the power plants all over the world, admittedly with differing limit values. Certainly, a lot more can be done for a cleaner environment.



Figure 14–19.

Flue gas pollutants. [14-5]

The reduction of SOx and NOx is technically somewhat more complicated and more costly. Therefore, only industrialized countries have been ready so far to invest in these technologies. Flue gas desulfurization plants and DeNOx plants are state of the art and enough experience exists for reliable operation without too much influence on the power plant performance. A reduction down to a concentration of 100 mg of SOx or NOx per m3 of flue gas with secondary measures is easily achievable. Fluidized bed combustion systems are able to reduce SOx by primary measures only down to approximately 150 mg/m3 STP by means of adding dolomite directly into the coal feed where it reacts with the sulfur to form CaSO4 (gypsum), with the result that no further bonding agent is required for the ash product to set when water is added. Due to the low combustion temperature of approximately 850°C in FBC systems, the formation of thermal NOx can be avoided right on the spot. This leads to NOx emissions of only approximately 150 mg/m3 STP, eliminating the need for secondary equipment. Only the CPFBC needs an SCR system, because it makes use of the advanced gas turbines with high inlet temperatures. The desulfurization process in gasification systems is the most effective one, because the sulfur is captured already in the raw gas of the gasifier, where elemental sulfur, a saleable product, can be produced.

Figure 14–20.

Power plant wastes. [14-5]

Figure 14–21. [14-5]

Specific CO2 emission of power plants.

The use of the clean fuel “natural gas” in the combined cycle results neither in SO2 output nor in any output of waste. To make the different power plant technologies comparable regarding its main pollutants and wastes, in Figures 14–19 and 14–20, the various pollutants are related to 1 kWh of electricity output. The emission of the greenhouse gas CO2 from power plants is dependent on the type of fuel and the efficiency (Figure 14–21). The capture of CO2 is technically feasible and there are even solutions for the long-term deposit of the CO2, such as in the oceans or in depleted oil fields, but economical reasons make a realization of these ideas today impossible. Power Plant Investment

Figure 14–22 shows 18 power plant concepts classified according to fuel type. For the pulverized-coal-fired power plants both the influence on capacity size and the additional cost for higher steam parameters are given. All costs include the necessary environmental equipment to reach the standard as specified in Table 14–4. The cost data specified for the emerging technologies have to be understood as target costs for the coming years, when enough design experience exists to cut costs considerably. Their cost accuracy can be assumed to be within 15–20%. The investment for lignite-fired power plants is approximately 20 percentage points above that of hard-coal-fired power plants because of the larger steam generator and the higher expenditure for coal feed and ash removal systems. Because of the low BTU fuel, which would cause very high transportation cost, these plants are usually built as mine-mouth plants. The natural-gas-fired combined cycle plants are attractive not only because of their outstanding high efficiency but also by their very low investment, which is only about 40% of a hard-coal-fired power plant. But one never should forget that it consumes only high-priced, noble fuels, such as natural gas or light fuel oil with limited reserves.


Figure 14–22.

Comparison of investment cost. [14-5]

Economic Evaluation

Besides the plant investment, the fuel price is the most influential portion of electricity generation cost. Furthermore, the fuel price can be subject to relatively large changes over time. Therefore it is the most critical factor for long-term planning.

Figure 14–23.


For this study the fuel prices according to Table 14–5 have been assumed, which represents an estimation of average prices in Europe. Selections of additional important boundary conditions that have been used for the economic evaluation are given

Relative power generation costs in percent. [14-5]



Table 14–5.

Prices as of Year

Hard coal Lignite Natural gas

Assumed Fuel Prices [14-5]

Fuel Price

Table 14–6.

Price Increase



%/a (real)

1.3 1.5 3.1

1.3 1.5 3.2

0.5 0.0 1.0

in Table 14–6. Operation and maintenance costs have been assumed individually for each plant. The resulting power generation cost show clearly the advantage of the natural gas driven combined cycle plants. Only the pulverized-coal-fired plant of high capacity can compete with them. The “second generation” circulating pressurized FBC plant is in the same cost range, but this plant has to prove whether the assumed low investment can be reached after successful market introduction. All these plants come out with lower generation costs than the pulverized-coal-fired reference plant of the 600 MW class and moderate steam conditions (Figure 14–23). Evidently, on

Economic boundary conditions [14-5]

Price basis Start of operation Interest rate Depreciation period Full-load operating hours

Year Year %/a a h/a

2000 2005 8 15 7000

the basis of the low coal price, advanced steam conditions do not justify their higher investment. Also lignite-fired power plants, generally of higher investment costs compared to hard coal power plants, come out with 12% higher generation cost than the reference plant. A price increase of natural gas of only 13% equals the generation costs of the reference coal power plant and the CC plant. IGCC plants as well as pressurized FBC plants with their relatively high efficiency do not appear economical at today’s low coal prices. Power generation in small capacity power plants (100– 200 MW) result in approximately 40–50% higher generation costs.

Manufacturing, Materials, and Metallurgy


“A superior pilot is one who uses his superior judgment to avoid situations that may require the use of his superior skill.” —Old Pilots’ saying


Basic Manufacture 587 Manufacturing Strategy 587 Forging 588 Casting 589 Fabrication 589 Welding 589 Electro-Chemical Machining (E.C.M.) 592 Electro-Discharge Machining (E.D.M.) 594 Composite Materials and Sandwich Casings 595 Inspection 596 Case 1. Upgrading the Core Engine 596 Raising Serviceability Ceilings 603 Spray Forming 604 Casing Fabrication 604 Microstructure of Processed and Heat Treated RS5 604 Creep Resistance Advancements 605 Creep Resistance of Materials for Microturbine Recuperators Ceramic Components 605 Case 2. Ceramic Vanes for a Model 501-K Industrial Turbine Demonstration 606 Case 3. Assessment of Ceramic and Metal Media Filters in Advanced Power Systems 611




Manufacturing methods,* materials and metallurgy (MMM) in gas turbines, like other technical elements of turbine technology, are dictated by the global business climate. The summary that follows describes the main elements of this climate as it affects MMM. The importance of each element at any given time depends on global economics as dictated by currencies (consider the Asian monetary crises of the late 1990s), politics, and wars (see also Chapter 14). Just 20 or so years ago, industrial gas turbine engine could mean a heavy unsophisticated engine compared to its aviation counterpart. Industrial engines are still relatively heavier (with their large flat base and sometimes a “noise protection house” around them). However, their metallurgical sophistication may be quite comparable to aeroderivative and even aviation engines. The increasing sophistication in an OEM’s F, G, and H technology is not that different from that in its aeroderivatives and flight engines. Rolls Royce, for instance, has consistently used its aircraft engine metallurgical technology in its land-based models, which it calls by the same generic stem: Avon, RB211, Trent, and so forth. Siemens Westinghouse is not officially an aircraft engine manufacturer, neither are Mitsubishi Power Systems (MPS) and Alstom (although ABB Stal, which was absorbed under the Alstom umbrella in 2000, had developed the aeroderivative GT35). However, their metallurgy is every bit as sophisticated as that which their rivals, who also make aircraft engines, employ. In today’s age of workers who can travel or change jobs internationally or get different work visas within a week, scarcely anything is sacred in design technology. The wide chord fan blade that proved such an asset to Rolls Royce aeroengine designs showed up on the GE 90 some years after its original design, with different “insides.” The example list is endless and travels in both directions across oceans. To keep costs down, every major manufacturer in the western hemisphere contracts the manufacture of specific components to countries with low labor rates. Korea used to be a favorite, but then Singapore, Malaysia, and Thailand became hotbeds of electronic component manufacture. China and India followed, with contracts acquired for every type of component: mechanical (such as blade and vane airfoils) or electrical (such as switchgear) and electronic (controls, PLCs, PCs, and so forth). The OEMs “follow” the lowest labor rates available and train the local workforce. The contemporary power generation industry also sees the OEMs hard at work selling, installing, and running power plants in these newly industrializing countries (NIC). Typically, they then train the local workforce to operate and eventually take over these plants, which therefore are build, own, operate, transfer (BOOT) projects. The initial “operate” phase then positions the OEM well for a “power by the hour” contract (see Chapter 12, Maintenance, Repair, and Overhaul). All this activity tends to promote the eventual transfer of repair and overhaul (R&O) functions to local repair shops. The OEM’s workforce may stay approximately the same globally: numbers that are hired in Asia and Latin America equate to layoffs in countries with higher labor costs. The large manufacturers such as General Electric have licensees, such as GEC and Nuovo Pignone, that assemble entire engines for them. These licensees, in turn, are large enough that they may establish factories in NICs. Acquisitions, mergers, and joint venture programs also move technology into different OEM firms. Ruston became European Gas Turbine (EGT), which developed new grassroots models, like the Cyclone, Tempest, and Typhoon that *

Working case notes 1975 through 2007, Claire Soares.

differed considerably from the old Ruston’s more traditional, conservative fare. Then EGT became part of ABB, which in 1999 became ABB Alstom, and Alstom Power in 2000. Later, Siemens bought portions of Alstom Power and its engine lines. The combined product range with respect to gas turbines is both broad and varied, the range of manufacturing methods and design development strategy even more so. Also, before this, Siemens and Westinghouse merged. Rolls Royce gained a U.S. partner in Allison. Both Rolls and Siemens can now bid for U.S. DOE grants along with U.S. companies. Reorganizations internally can shift centers of special knowledge, domestically and abroad. To conserve on overhead, Pratt and Whitney closed its West Palm beach military engine facility and sent that workforce to join the commercial aircraft engine group in Connecticut. One example of a joint venture gas turbine is the V2500 engine (with the three Japanese manufacturers that make up the Japanese Aeroengine consortium making the low-pressure compressor, including the wide chord bladed fan, to a Rolls Royce design). Rolls Royce designs and makes the high-pressure compressor and the oil system. Pratt and Whitney designs and makes the hot high-pressure section and MTU (Motoren Turbinen Union) designs and makes the low pressure turbine. Alternate serial numbers are assembled at Rolls Royce, Derby, England, and Pratt and Whitney, Connecticut. Another joint venture example is GE/Snecma’s CFM 56. Perhaps to gain competitive advantage, some OEMs also buy the manufacturers that make some of their accessories. GE bought either entire or partial ownership in several aircraft engine overhaul shops, firms that provide risk insurance for some of its engines, and a manufacturer that makes condition monitoring equipment (Bentley Nevada). Other OEMs have systems or components made under license, then stamp them with their logo before including them in their engine assembly packages. Turbine wash systems are a common “farmed-out” item. Other OEMs farm out increasingly complex manufactured items. An entire components industry has sprung up around firms that make only one of either combustion liners, blades and vanes, fuel nozzles, exhaust cases, gears, or accessory drives. To stay competitive, these firms try and minimize overhead. In the process, they may develop increasingly narrower product ranges that require greater expertise in fewer components. Some accessory manufacturers have been non-OEM for much longer, such as the firms that design and make wash systems. Depending on the year of the order, the actual design of a wash system for instance, on a given large engine fleet, may be quite different as a consequence of being made by two entirely different manufacturers’ contracted suppliers, as may be the case with an inlet air fogging system or inlet air filtration system. There are specialist plating shops, heat treatment shops, casting foundries, forging facilities, machine shops that may perform just one function, such as laser drilling of air cooling passages in blades and vanes—the list is endless. Basically, an OEM tries to keep in house as much work as it can profitably maintain, or as much as might cause it to lose a great deal in warranty claims or specialized transportation, if farmed out. The bottom line in maintaining healthy profit margins in the manufacturing business is spare parts sales. An OEM makes far more money on new spare parts than on overhauled, repaired, or refurbished ones. Very often OEMs will not tell certain customers (who do not know better) that they ought to ask

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about potential repairs. Some of these repairs may be developed by the OEM to keep its more knowledgeable customers happy or developed for “internal use only” by an independent shop (see Chapter 12, Maintenance, Repair, and Overhaul). Sometimes, the OEM develops its own repairs, other times it licenses a trustworthy external facility. Some “renegade” ex-OEM staff members start their own firms. Not taking designs with them does not stop them. They know enough to “reverse engineer” new components without OEM blueprints. Frequently, the customer base of such “guerilla” shops is confined to a client base with machinery well past its warranty period. Generally, these former employees also are shrewd enough to check most of the reverse engineering themselves, thus minimizing their risk profile (see the Chapter 14, “The Business of Gas Turbines”). And, they may have the partial security of feedback from an end-user lobby group (with which they can compare notes) regardless of whether those operators have a “power by the hour” contract with the OEM. However, once they are “power[ed] by the hour,” the need for end users to maintain an engineering staff clever enough to bargain with OEMs and find “good deals” outside of OEM dealings goes away. Power by the hour contracts come at a huge price. How huge may depend on the country of the application. If an OEM feels that a customer, in Pakistan for instance, would be more apt to yell “warranty” in cases where the fault was clearly caused by the operators, the OEM might raise the “power by the hour” or even the cost of basic spare parts to cover these losses. As the business chapter pointed out, however, increasingly, especially in the power generation business, the turbine buyer is the OEM as it may also be the IPP. It is a situation of relative autonomy for the OEM, as it then can write its own spare parts (to be purchased) lists. It also can test prototype components in real-life operating environments with the minimum of negotiation with or concessions to the end user. It can conduct realistic full-load tests on new models, an undertaking that ordinarily is prohibitively expensive. It can be legitimate regular members of end-user lobby groups where, otherwise, it could attend only sessions where “OEMs are invited.” The newer, but no less powerful, IPPs on the scene are the oil companies, which then write the contracts to sell their own fuel to themselves. The section that follows deals with the elements of basic manufacture. The source (Rolls Royce) wrote the original of this section to describe aircraft engine manufacture. However, with today’s technology, the section is appropriate for describing the manufacture of aeroderivative (used in land, offshore, and naval applications) and contemporary industrial engines. Basic Manufacture

During* the design stages of the aircraft gas turbine engine, close liaison is maintained between design, manufacturing, development, and product support to ensure that the final design is a match between the engineering specification and the manufacturing process capability. The functioning of this type of engine, with its high power-to-weight ratio, demands the highest possible performance from each component. Consistent with this requirement, each component must be manufactured at the lowest possible weight and cost and also provide mechanical integrity *Source: Adapted, with permission, from Rolls Royce, The Jet Engine, 1986, Rolls Royce Plc: UK.


through a long service life. Consequently, the methods used during manufacture are diverse and are usually determined by the duties each component has to fulfill. No manufacturing technique or process that in any way offers an advantage is ignored and most available engineering methods and processes are employed in the manufacture of these engines. In some instances, the technique or process may appear by some standards to be elaborate, time consuming and expensive, but is only adopted after confirmation that it does produce maximized component lives comparable with rig test achievements. Engine components are produced from a variety of high tensile steel and high temperature nickel and cobalt alloy forgings. A proportion of components are cast using the investment casting process. While fabrications, which form an increasing content, are produced from materials such as stainless steel, titanium and nickel alloys using modern joining techniques i.e., tungsten inert gas welding, resistance welding, electron beam welding and high-temperature brazing in vacuum furnaces. The methods of machining engine components include grinding, turning, drilling, boring and broaching whenever possible, with the more difficult materials and configurations being machined by electro-discharge, electro-chemical, laser hole drilling and chemical size reduction. Structural components, i.e., cold spoiler, location rings, and by-pass ducts, benefit by considerable weight saving when using composite material. In addition to the many manufacturing methods, chemical and thermal processes are used on part-finished and finished components. These include heat treatment, electroplating, chromate sealing, chemical treatments, anodizing to prevent corrosion, chemical and mechanical cleaning, wet and dry abrasive blasting, polishing, plasma spraying, electrolytic etching, and polishing to reveal metallurgical defects. Also a variety of barreling techniques for removal of burrs and surface improvement. Most processes are concerned with surface changes, some give resistance to corrosion while others can be used to release unwanted stress. The main structure of an aero gas turbine engine is formed by a number of circular casings (see Figure 15–1) that are assembled and secured together by flanged joints and couplings located with dowels and tenons. These engines use curvic and hurth couplings to enable accurate concentricity and mating assemblies that, in turn, assist an airline operator when maintenance is required. Manufacturing Strategy

Manufacturing is changing and will continue to change to meet the increasing demands of aeroengine components for fuel efficiency, cost and weight reductions and being able to process the materials required to meet these demands. With the advent of microprocessors and extending the use of the computer, full automation of components considered for in-house manufacture are implemented in line with supply groups manufacturing strategy, all other components being resourced within the worldwide supplier network. This automation is already applied in the manufacture of cast turbine blades with the seven cell and computer numerical controlled (C.N.C.) grinding centers, laser hard facing and film cooling hole drilling by electro-discharge machining (E.D.M.). Families of turbine and compressor discs are produced in flexible manufacturing cells, employing automated guided vehicles delivering palletized components from computerized storage to C.N.C. machining cells that all use batch of one technique. The smaller blades, with very thin airfoil



Figure 15–1.

Arrangements of a triple-spool turbo-jet engine. (Source: Rolls Royce.)

sections, are produced by integrated broaching and 360° electro-chemical machining (E.C.M.) while inspection and processing are being automated using the computer. Tolerances between design and manufacturing are much closer when the design specification is matched by the manufacturing proven capability. Computer aided design (C.A.D.) and computer aided manufacture (C.A.M.) provides an equivalent link when engine components designed by C.A.D. can be used for the preparation of manufacturing drawings, programs for numerically controlled machines, tool layouts, tool designs, operation sequence, estimating and scheduling. Computer simulation allows potential cell and flow line manufacture to be proven before physical machine purchase and operation, thus preventing equipment not fulfilling their intended purpose. Each casing is manufactured from the lightest material commensurate with the stress and temperatures to which it is subjected in service. For example, magnesium alloy composites and materials of sandwich construction are used for

air intake casings, fan casings, and low pressure compressor casings, since these are the coolest parts of the engine. Alloy steels are used for the turbine and nozzle casings where the temperatures are high and because these casings usually incorporate the engine rear mounting features. For casings subjected to intermediate temperatures i.e., by-pass duct and combustion outer casings, aluminum alloys and titanium alloys are used. Forging

The engine drive shafts, compressor discs, turbine discs, and gear trains are forged to as near optimum shape as is practicable commensurate with non-destructive testing, i.e., ultrasonic, magnetic particle and penetrant inspection. With turbine and compressor blades, the accurately produced thin airfoil sections with varying degrees of camber and twist, in a variety of alloys, entails a high standard of precision forging, reference Figure 15–2. Nevertheless precision forging of these blades is a recognized practice and enables

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Figure 15–2.

Precision forging. (Source: Rolls Royce.)

one to be produced from a shaped die with the minimum of further work. The high operating temperatures at which the turbine discs must operate necessitates the use of nickel base alloys. The compressor discs at the rear end of the compressor are produced from creep-resisting steels, or even nickel base alloys, because of the high temperatures to which they are subjected. The compressor discs at the front end of the compressor are produced from titanium. The higher strength of titanium at the moderate operating temperatures at the front end of the compressor, together with its lower weight provides a considerable advantage over steel. Forging calls for a very close control of the temperature during the various operations. An exceptionally high standard of furnace control equipment, careful maintenance and cleanliness of the forging hammers, presses, and dies, is essential. Annular combustion rings can be cold forged to exacting tolerances and surfaces which alleviates the need for further machining before welding together to produce the combustion casing. H.P. compressor casings of the gas turbine engine are forged as rings or half rings which, when assembled together, form the rigid structure of the engine. They are produced in various materials, i.e., stainless steel, titanium, and nickel alloys. Casting

An increasing percentage of the gas turbine engine is produced from cast components using sand casting, reference Figure 15–3, die casting, and investment casting techniques; the latter becoming the foremost in use because of its capability to produce components with surfaces that require no further machining. It is essential that all castings are defect free by the disciplines of cleanliness during the casting process otherwise they could cause component failure. All casting techniques depend upon care with methods of inspection such as correct chemical composition, test of mechanical properties, radiological and microscopic examination, tensile strength, and creep tests. The complexity of configurations together with accurate tolerances in size and surface finish is totally dependent


upon close liaison with design, manufacturing, metallurgist, chemist, die maker, furnace operator, and final casting. In the pursuit of ever increasing performance, turbine blades are produced from high temperature nickel alloys that are cast by the investment casting or “lost wax” technique. Directionally solidified and single crystal turbine blades are cast using this technique in order to extend their cyclic lives. Figure 15–4 illustrates automatic casting used in the production of equi-axed, directional solidified, and single crystal turbine blades. The lost wax process is unparalleled in its ability to provide the highest standards of surface finish, repeatable accuracy, and surface detail in a cast component. The increasing demands of the engine has manifested itself in the need to limit grain boundaries and provide complex internal passages. The molds used for directional solidified and single crystal castings differ from conventional molds in that they are open at both ends, the base of a mold forms a socketed bayonet fitting into which a chill plate is located during casting. Metal is introduced from the central sprue into the mold cavities via a ceramic filter. These and orientated seed crystals, if required, are assembled with the patterns prior to investment. Extensive automation is possible to ensure the wax patterns are coated with the shell material consistently by using robots. The final casting can also have their rises removed using elastic cut-off wheels driven from robot arms (see Figure 15–5). Fabrication

Major components of the gas turbine engine, i.e., bearing housings, combustion and turbine casings, exhaust units, jet pipes, by-pass mixer units, and low pressure compressor casings can be produced as fabricated assemblies using sheet materials such as stainless steel, titanium, and varying types of nickel alloys. Other fabrication techniques for the manufacture of the low pressure compressor wide chord fan blade comprise rolled titanium side panels assembled in dies, hot twisted in a furnace and finally hot creep formed to achieve the necessary configuration. Chemical milling is used to recess the centre of each panel which sandwiches a honeycomb core, both panels and the honeycomb are finally joined together using automated furnaces where an activated diffusion bonding process takes place (see Figure 15–6). Welding

Welding processes are used extensively in the fabrication of gas turbine engine components, i.e., resistance welding by spot and seam, tungsten inert gas, and electron beam are amongst the most widely used today. Care has to be taken to limit the distortion and shrinkage associated with these techniques. Tungsten Inert Gas (T.I.G.) Welding

The most common form of tungsten inert gas welding, Figure 15–7, in use is the direct current straight polarity, i.e., electrode negative pole. This is widely used and the most economical method of producing high quality welds for the range of high strength/high temperature materials used in gas turbine engines. For this class of work, high purity argon shielding gas is fed to both sides of the weld and the welding torch nozzle is fitted with a gas lens to ensure maximum efficiency for shielding gas coverage.



Figure 15–3.

Method of producing an engine component by sand casting. (Source: Rolls Royce.)

A consumable 4% thoriated tungsten electrode, together with a suitable non-contact method of arc starting is used and the weld current is reduced in a controlled manner at the end of each weld to prevent the formation of finishing cracks. All welds are visually and penetrant inspected and in addition, welds associated with rotating parts, i.e., compressor and/or turbine are radiologically examined to Quality Acceptance Standards. During welding operations and to aid in the control of distortion and shrinkage the use of an expanding fixture is recommended and, whenever possible, mechanized welding employed together with the pulsed arc technique is preferred. A typical T.I.G. welding operation is illustrated in Figure 15–8.

Electron Beam Welding (E.B.W.)

This system, which can use either low or high voltage, uses a high power density beam of electrons to join a wide range of different materials and of varying thickness. The welding machine, reference Figure 15–9, comprises an electron gun, optical viewing system, work chamber and handling equipment, vacuum pumping system, high or low voltage power supply and operating controls. Many major rotating assemblies for gas turbine engines are manufactured as single items in steel, titanium, and nickel alloys and joined together, i.e., intermediate and high pressure compressor drums. This technique allows design flexibility in that distortion and shrinkage are reduced and dissimilar materials, to serve

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Figure 15–4.

Automatic investment casting. (Source: Rolls Royce.)

Figure 15–5.

Robot cut-off. (Source: Rolls Royce.)




Figure 15–7. Typical tungsten inert gas welding details. (Source: Rolls Royce.)

Figure 15–8. Tungsten inert gas welding. (Source: Rolls Royce.)

Figure 15–6. Wide chord fan blade construction. (Source: Rolls Royce.)

quite different functions, can be homogeneously joined together. For example, the H.P. turbine stub shafts requiring a stable bearing steel welded to a material which can expand with the mating turbine disc. Automation has been enhanced

by the application of computer numerical control (C.N.C.) to the work handling and manipulation. Seam tracking to ensure that the joint is accurately followed and close loop under bead control to guarantee the full depth of material thickness is welded. Focus of the beam is controlled by digital voltmeters. See Figure 15–10 for weld examples. Electro-Chemical Machining (E.C.M.)

This type of machining employs both electrical and chemical effects in the removal of metal. Chemical forming, electrochemical drilling, and electrolytic grinding are techniques of

M A N U F A C T U R I N G , M AT E R I A L S , A N D M E TA L L U R G Y

Figure 15–9.

Figure 15–10.

Electron beam welding. (Source: Rolls Royce.)

Examples of T.I.G. and E.B. welds. (Source: Rolls Royce.)




electro-chemical machining employed in the production of gas turbine engine components. The principle of the process is that when a current flows between the electrodes immersed in a solution of salts, chemical reactions occur in which metallic ions are transported from one electrode to another (Figure 15–11). Faraday’s law of electrolysis explains that the amount of chemical reaction produced by a current is proportional to the quantity of electricity passed. In chemical forming (Figure 15–11), the tool electrode (the cathode) and the workpiece (the anode) are connected into a direct current circuit. Electrolytic solution passes, under

pressure, through the tool electrode and metal is removed from the work gap by electrolytic action. A hydraulic ram advances the tool electrodes into the workpiece to form the desired passage. Electrolytic grinding employs a conductive wheel impregnated with abrasive particles. The wheel is rotated close to the surface of the workpiece, in such a way that the actual metal removal is achieved by electro-chemical means. The by-products, which would inhibit the process, are removed by the sharp particles embodied in the wheel. Stem drilling and capillary drilling techniques are used principally in the drilling of small holes, usually cooling holes, such as required when producing turbine blades. Stem Drilling

This process consists of tubes (cathode) produced from titanium and suitably insulated to ensure a reaction at the tip. A 20% solution of nitric acid is fed under pressure onto the blade producing holes generally in the region of 0.026 in. diameter. The process is more speedy in operation than electro-discharge machining and is capable of drilling holes up to a depth 200 times the diameter of the tube in use. Capillary Drilling

Similar in process to stem drilling but using tubes produced from glass incorporating a core of platinum wire (cathode). A 20% nitric acid solution is passed through the tube onto the workpiece and is capable of producing holes as small as 0.009 in. diameter. Depth of the hole is up to 40 times greater than the tube in use and therefore determined by tube diameter. Automation has also been added to the process of electro-chemical machining (E.C.M.) with the introduction of 360° E.C. machining of small compressor blades, reference Figure 15–12. For some blades of shorter length airfoil, this technique is more cost effective than the finished shaped airfoil when using precision forging techniques. Blades produced by E.C.M. employ integrated vertical broaching machines which take pre-cut lengths of bar material, produce the blade root feature, such as a fir-tree, and then by using this as the location, fully E.C.M. from both sides to produce the thin airfoil section in one operation. Electro-Discharge Machining (E.D.M.)

Figure 15–11. Rolls Royce.)

Electro-chemical machining. (Source:

This type of machining removes metal from the workpiece by converting the kinetic energy of electric sparks into heat as the sparks strike the workpiece. An electric spark results when an electric potential between two conducting surfaces reaches the point at which the accumulation of electrons has acquired sufficient energy to bridge the gap between the two surfaces and complete the circuit. At this point, electrons break through the dielectric medium between the conducting surfaces and, moving from negative (the tool electrode) to positive (the workpiece), strike the latter surface with great energy; Figure 15–13 illustrates a typical spark erosion circuit. When the sparks strike the workpiece, the heat is so intense that the metal to be removed is instantaneously vaporized with explosive results. Away from the actual centre of the explosion, the metal is torn into fragments which may themselves be melted by the intense heat. The dielectric medium, usually paraffin oil, pumped into the gap between the tool electrode and the workpiece, has the

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Figure 15–12.

Typical automated manufacture of compressor blades. (Source: Rolls Royce.)

Figure 15–13.

Electro-discharge machining circuit. (Source: Rolls Royce.)

tendency to quench the explosion and to sweep away metallic vapor and molten particles. The amount of work that can be effected in the system is a function of the energy of the individual sparks and the frequency at which they occur. The shape of the tool electrode is a mirror image of the passage to be machined in the workpiece and, to maintain a constant work gap, the electrode is fed into the workpiece as erosion is effected.


Composite Materials and Sandwich Casings

High power to weight ratio and low component costs are very important considerations in the design of any aircraft gas turbine engine, but when the function of such an engine is to support a vertical take-off aircraft during transition, or as an auxiliary power unit, then the power to weight ratio becomes extremely critical. In such engines, the advantage of composite materials allows the designer to produce structures in which directional



Figure 15–14.

Some composite material applications. (Source: Rolls Royce.)

strengths can be varied by directional lay-up of fibers according to the applied loads. Composite materials have and will continue to replace casings which, in previous engines, would have been produced in steels or titanium. By-pass duct assemblies comprising of three casings are currently being produced up to 4ft-7in. in diameter and 2ft-0in. in length using pre-cured composite materials for the casing fabric. Flanges and mounting bosses are added during the manufacturing process, which are then drilled for both location and machined for peripheral feature attachment on C.N.C. machining centers, which at one component load, completely machine all required features. Examples of composite material applications are illustrated in Figure 15–14. Conventional cast and fabricated casings and cowlings are also being replaced by casings of sandwich construction that provide strength allied with lightness and also act as a noise suppression medium. Sandwich construction casings comprise a honeycomb structure of aluminum or stainless steel interposed between layers of dissimilar material. The materials employed depend upon the environment in which they are used.

probes that record sizes and position of features. The C.N.C. inspection machine can inspect families of components at pre-determined allotted intervals without further operator intervention. In the chip machining (i.e., turning, boring, milling etc.) and metal forming processes C.N.C. machine tools enable consistency of manufacture which can be statistically inspected, i.e., one in ten. Component integrity is achieved by use of ultrasonic, radiological, magnetic particle and penetrant inspection techniques, as well as electrolytic and acid etching to ensure all material properties are maintained to both laboratory and quality acceptance standards. To optimize their cost effectiveness, manufacturers build on, extrapolate from and selectively reengineer the cores of their already successful engines. A case history in point follows. It describes how Mitsubishi developed its core experience with TITs of 1150 to 1350 and then to a ceiling of 1500 °C (for 50 and 60 Hz gas turbines in power-generation combined-cycle applications. Case 1. Upgrading the Core Engine*

The next generation G class gas turbine, with turbine inlet gas temperature in 1,500°C range has been developed by


During the process of manufacture, component parts need to be inspected to ensure defect free engines are produced. Using automated machinery and automated inspection, dimensional accuracy is maintained by using multi-directional applied

*Source: [15-1] Courtesy of Mitsubishi Power Systems. Extracts from Y. Tsukuda, E. Akita, H. Arimura, Y. Tomita, M. Kuwabara, and T. Koga, “The Operating Experience of the Next Generation M501 G/M701 G Gas Turbine,” Mitsubishi Heavy Industries Ltd., (MHI) 2001-GT-0546.

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Mitsubishi Heavy Industries, Ltd. (MHI). Many advanced technologies, including a high efficiency compressor, a steam cooled low NOx combustor, a high temperature and high efficiency turbine, etc., are employed to achieve high combined cycle performance. Actually, MHI has been accumulating the operating experiences of M501 G (60 Hz machine) a combined cycle verification plant in MHI Takasago, Japan, achieving high performance and reliability. Also, M701G (50 Hz machine) has been accumulating the operating experience in Higashi Niigata Thermal Power Station of Tohoku Electric Power Co., Inc. in Japan. What follows describes the technical features of M501 G/M701 G, and up-to-date operating status of the combined cycle power plant in MHI Takasago, Japan. MHI developed turbine inlet temperature of 1,150°C class M701D gas turbine and 1,350°C class M501F/M701F gas turbines. Their high efficiency and reliability for combined cycle applications have been proven in field operations. Based on the fact that the combined cycle efficiency is highly dependent on the gas firing temperature, MHI has newly developed the 1,500°C class M501G/M701G, both “G” series gas turbines. Table 15–1 shows the main introductory performance specification of the M501G, in comparison with the M501F. The M501G is a heavy-duty gas turbine designed to serve the 60 Hz power generating utility. The output of the M501G is 254 MW at a turbine inlet temperature of 1°C on natural gas fuel. Development of the “G” series gas turbine was started in early 1990s and the design was based on the following conTable 15–1.

Performance Of G01g Gas Turbine [15-1]

Speed (rpm) G/T Output (MW) G/T Thermal efficiency (%-LHV) Pressure ratio

Figure 15–15.



3600 254 38.7 20

3600 185.4 37.0 16

The M501G rotor. [15-1]


cepts, which give excellent performance and high reliability to the “G” series. Firstly, proven features from the “F” series are kept. Secondly, the most advanced technologies in aerodynamic design, heat transfer design, and new materials for the “G” series are introduced. Thirdly, our conventional design criteria in industrial gas turbines are applied. Fourthly, the turbine inlet temperature is increased to the extent where the NOx and the metal temperature can be maintained at the same level as the “F” series. Finally, verification tests are carried out before production of the M501G gas turbine to secure their high reliability. The trial operation of the M501G was conducted in 1997 in the combined cycle verification plant in MHI Takasago, Japan. It was successful and the M501G commercial operation was started sequentially in June 1997. Since then, four inspections were conducted and even though some operational events were observed, the condition of each component was quite sound. Also, the availability, which defined as the actual power supply hours divided by demanded power supply hours (excluding scheduled shutdown such as periodical inspection, during the operation) was 99.2%, which indicates the high reliability of the M501G. Design Features

The rotor of the M501G is shown in Figure 15–15. The “G” series inherit the proven NMI technology of the “F” series and employs the advanced technology shown in Figure 15–16. Overall Structure The basic structure of the “G” series is the same as our “F” series gas turbines. Several basic design concepts such as the two bearing single shaft structure, cold end generator drive, and axial exhaust are evident. The single shaft rotor is made of compressor and turbine disks that are bolted with spindle bolts. The rotor is supported by two bearings, which are two-element tilting pad bearings. The thrust bearing is a double-acting type using the direct lubrication system on the compressor side.



Figure 15–16.

Advanced technologies applied to the M501G. [15-1]

The air inlet system delivers air to the compressor by a plenum bell mouth and covers the bearings. The compressor is an axial flow design with seventeen stages. A four-stage axial turbine is applied to maintain the optimum aerodynamic loading even at the increased firing temperature and pressure ratio. All gas turbine casings can be horizontally split to facilitate maintenance without rotor removal. Eight radial struts support the front bearing housing and six tangential struts support the rear bearing housing. Airfoil-shaped covers protect the tangential struts from the blade path gas and support the inner and outer diffuser cones. The individual inner turbine casings that are called blade rings are used for the stationary part of each turbine stage and can be easily removed and replaced without rotor removal. The similar structure of blade rings is applied to the compressor rear stages. Another feature of these blade rings is that they have high thermal response being independent of the outer casing and can be aligned concentric to the rotor to minimize the blade tip clearances. Cooling circuits for the turbine section are similar to those of the “F” series. They consist of a rotor cooling circuit and four stationary vane cooling circuits. Rotor cooling air is provided from compressor discharge air extracted from the combustor shell. This air is supplied as the cooling and seal air of the turbine disks and rotating blades after being externally cooled and filtered. Direct compressor discharge air is used to cool the first stage vane while the compressor bleed air from intermediate stages is used as the cooling air for turbine blade ring cavities and second, third, and fourth stage vanes. Advanced Compressor The compressor has highly efficient axial flow design. The “G” series compressor requires a larger flow rate and higher efficiency than the “F” series. The result is that this compressor has a higher Mach number. To meet this requirement, the M501G incorporates multiple circular arc (MCA) airfoils in the forward

four stages of the rotating blades. Also, controlled diffusion airfoils (CDA) are applied for the rest of the stages of the rotating blades, namely from the fourth to the seventeenth stage, and all stages of the stationary vanes. The latest three-dimensional compressor blade design is employed. The aerodynamic performance is verified with both the cascade test and model compressor test. Model compressor test results show that primary parameters of mass flow and efficiency meet the design range as shown in Figure 15–17. Also, aerodynamic performance is proven with MF221 gas turbine, which has a half scale compressor of the M501G. The compressor is also equipped with variable inlet guide vanes, which improve the compressor surge characteristics during start-up and are used in the combined cycle applications to improve part-load performance. Dry Low NOx Steam-Cooled Combustor The combustor design is based on the successful can-annular dry low NOx combustor developed for the “F” series. This combustor currently operates at less than 25 ppm NOx level at 1,400 °C turbine inlet temperature (TIT) defined as the averaged combustor outlet gas temperature. In order to keep the same NOx level as the “F” series at 1,500°C TIT, all the air discharged from the compressor should be supplied for combustion. For this reason, a premixed combustor with closed circuit steam cooling system was applied for the “G” series combustor. To optimize the swirl strength and the configuration of fuel ejection holes, a cold flow test was conducted. Also, atmospheric and high-pressurized combustion tests were conducted using a full-scale combustor and a fuel nozzle as shown in Figure 15–18. The test results showed 25 ppm NOx level and satisfactory wall temperatures without cooling steam leakage. The field verification test of this steam cooled combustor has already been conducted in the M701F gas turbine to verify its durability.

M A N U F A C T U R I N G , M AT E R I A L S , A N D M E TA L L U R G Y


temperature of the vane and the blade is measured with the embedded thermocouples. With the hot cascade tests, the airfoil metal temperature distribution was obtained and the cooling effectiveness was verified. These features and technologies were finally verified through a high temperature demonstration unit (HTDU) by testing the airfoils under certain conditions. The HDTU shown in Figure 15–21 is a special core turbine with 0.6 scale turbine blades and vanes of the M501G for demonstrating the key technologies. Materials The advanced gas turbine requires heat resistant materials as well as advanced cooling technologies. For this purpose, some advanced materials for turbine blades and vanes, and thermal barrier coatings are developed. For the rotating blade material, MGA1400 alloy was developed. MGA1400 is a Nickel-base super alloy and can be used for DS casting as well as for conventional casting. Compared with IN738LC conventionally cast blade, the creep strength of MGA1400DS blade is 50C higher, and that of the conventionally cast MGA1400 is 30C higher as shown in Figure 15–22. Both DS and CC blades are applied in the “G” series gas turbine. For the stationary vane material, MGA2400 alloy was developed. MGA2400 is also a nickel-base super alloy that has excellent resistance against thermal fatigue, oxidation, and hot corrosion as well as high creep strength. It also has good weldability for settlement of accessory parts and repair. Table 15–2 summarized the materials for turbine vanes and blades. Long-Term Operating Experience

Figure 15–17. test. [15-1]

Result of M501G compressor model

High Temperature Turbine It is essential to keep the metal temperature below the allowable limit to secure the same level of reliability at 1,500°C TIT with minimum cooling air flow. To achieve a lot of advanced technologies like full coverage film cooling (FCFC), thermal barrier coating (TBC), new heat resistant material, and directionally solidification (DS) casting technology are introduced. Several heat transfer tests like measurement of film cooling effectiveness around the airfoil, heat transfer characteristics of serpentine cooling passage with turbulence promoters under rotating conditions were conducted. Based on the results obtained from these fundamental tests, the advanced cooled turbine airfoils were designed. Figure 15–19 shows the first stage blade of the turbine. The actual turbine blades and vanes were first verified in the hot cascade test facility shown in Figure 15–20. In the facility, the test was conducted with the maximum average inlet gas temperature up to 1,550 °C in order to check the margin. Gas temperature distribution at the cascade inlet is measured with total temperature probes and the metal

NMI constructed a long-term verification test facility with the M501G as a complete combined cycle power plant in its Takasago Machinery Works. NMI started the trial operation of the M501G in January 1997 to verify the performance and reliability. During the trial operation, more than 1,800 instrumentation probes were installed in the gas turbine. Figure 15–23 shows the special measurement items. The flow path characteristics, metal temperatures, pressures, strains, sound pressure levels, exhaust emissions, etc. were measured over the full range of operating conditions. All important characteristics, including the cooling characteristics and components, reliability were verified. As an example, measured vibratory stresses of the blades and vanes are shown in Figure 15–24. They were measured for the first stage to the fourth stage blades, the first stage to the eighth stage and the seventeenth stage vanes of the compressor and the first stage to the fourth stage blades of the turbine during starting period, rated speed, and up to 110% of the rated speed. These items were measured by a non-contact method using optical fibers for compressor blades and by strain gauges for compressor vanes and turbine blades (with telemeter). The results show that the vibratory stresses are low enough compared with the allowable values. At the end of June 1997, the combined cycle verification plant passed the Ministry of International Trade and Industry (MITI)’s qualification test as an industrial power plant, which consists of one M501G gas turbine, one HRSG and one steam turbine and started commercial operation as the long-term verification test. The plant layout is shown in Figure 15–25. The electricity is sent to the grid of a domestic utility company. As this plant operates on demand of the utility company, it has mainly been operated with



Figure 15–18.

Combustor component tests. [15-1]

The following is the detailed explanation of each operation and inspection. The result shows the high reliability of the M501 G. June-October 1997

The M501G started its first verificational operation for summer peaking duty. In October, summer peaking duty was completed and the first inspection of the M501G started. The hot gas path components like steam cooled combustor, advanced cooled turbine vanes and blades were found to be sound except minor cracks of steam cooled combustor transition piece exhaust mouth comers. December 1997–March 1998

After the first inspection, the M501G was back in service in December 1997. The load demand in winter tends to be lower, but to confirm the soundness in preparation for the next summer peaking duty, the second inspection was conducted in March 1998. The inspection proved the hot gas path components to be sound. June 1998–November 1998

Figure 15–19.

The turbine row 1 blade. [15-1]

Daily Start and Stop (DSS) mode. Accumulated total operating hours/start-and-stop cycles are 10,898 hours/612 cycles at the end of October 2000. It is still accumulating operating experience successfully.

The M501G was back in service. The result of the inspection in November 1998 showed no severe problem and everything was in sound condition. Until the next operation started in July 1999, the operating test of M501H, which has steam cooled first and second stage vanes and blades as well as the steam cooled combustor, was conducted and the results were successful. July 1999–March 2000

The M501G was in service again for summer peaking duty. Accumulated operating hours/start-and-stop cycles were 8,633 hours/514 cycles. The result of the inspection

M A N U F A C T U R I N G , M AT E R I A L S , A N D M E TA L L U R G Y

Figure 15–20.

The hot cascade test ring for turbine cooling performance verification. [15-1]

Figure 15–21.

The HTDU facility. [15-1]

Table 15–2.

Vane Row 1 Row 2 Row 3 Row 4 Blade Row 1 Row 2 Row 3 Row 4

Figure 15–22. Creep rupture strength of the turbine blade material. [15-1]


The M501G Turbine Blade Material [15-1]



MGA2400 MGA2400 MGA2400 MGA2400

EC768 EC768 X-45 X-45

MGA1400 (DS) MGA1400 (DS) MGA1400 MGA1400

IN738LC IN738LC IN738LC U520

TBC is also important for its heat shield effect. The durability and the heat shield effect have been confirmed through many long-term field operational experiences of MF61, MF111, MF221, M7011), M501F, M701F, etc.



Figure 15–23.

Special measurement items. [15-1]

in March 2000 was very good as shown in Figure 15–26 even though partial peeling of TBC at row 1 blade was observed.

Figure 15–24.

Summary of vibratory stress. [15-1]

May–October 2000

After the fourth inspection, the M501G has returned to service and is successfully accumulating operating experience. The result of the inspection in October 2000 was fine by this inspection, accumulated operating hours/start-and-stop cycles are 10,898 hours/612 cycles. The availability defined as the actual power supply hours over the demanded power supply hours reaches 99.2%. Also, the M701G, the “G” series gas turbine of 50 Hz, also started a trial operation in October 1998. The plant started the commercial operation for the domestic utility company in July 1999 and has been successfully accumulating the operating hours and start-and-stop cycles of 9,842 hours/63 times for the No. 1 gas turbine and 9,350 hours/52 times for the No. 2 gas turbine. Since the gas turbine has never stopped except for the scheduled outage, availability defined as the actual power supply hours over the demanded power supply hours is 100%. Because the high reliability of the M501G/M701G is verified through these operations, MHI has already received the order of 17 M501 Gs and 7 M701Gs by the end of October 2000 and further potential orders are expected especially for the M501G. This would be a great help for energy savings and environmental conservation. In summary, the M501G full load test with special measurement, which was conducted during the trial operation in February 1997, showed its high efficiency and high reliability and low environmental impact. At the end of June 1997, the combined cycle plant with the M501G was put into long-term verificational operation after receiving MITI (Ministry of International Trade and Industry)’s certification. By the end of October 2000, the plant has been successfully accumulating the 10,898 operating hours to keep up with the electricity demand from the utility company and start-and-stop cycles reached 612 cycles. The availability of 98.6% is kept. The M501G

M A N U F A C T U R I N G , M AT E R I A L S , A N D M E TA L L U R G Y

Figure 15–25.

Plant layout of M501G combined cycle verification plant of Takasago machinery works. [15-1]

Figure 15–26.

Inspection results in March 2000. [15-1]

experienced five inspections and the condition of each component was quite good. These inspection results showed the high reliability of the M501G. The M501G would make a great contribution to energy savings and good global environmental issues.


Raising Serviceability Ceilings

One summarized example here is a study made of the spray forming of a high(er)-temperature casing (participants were DERA, UK, and Rolls Royce, UK). One of the key parameters of concern with any such work is creep behavior. A summary of this work’s conclusions, to the point reported in a paper, is as follows.* Many current gas turbine casings are manufactured using conventional wrought processing routes. Although

With TIT upper limits being pushed upward, designers of different components within the gas turbine are all forced to seek new materials or manufacture methods or both. The different OEMs employ different technologies and strategies, several of which are discussed in cases in several of this book’s chapters.

*Source: [15-2] Courtesy of Rolls Royce. A. Partridge, M. B. Henderson, D. G. Cole, and P. Andrews, “The Implementation of Spray Forming for High Temperature Casing Applications,” in Proceedings of the ASME Turbo Expo 2001, June 4–7, 2001, New Orleans, 2001-GT-0581.



well established this approach often requires numerous and complex processing steps. This can result in relatively long component lead times and high part costs. In an attempt to reduce lead times and cost, the production of parts using the spray-forming process is under consideration. In modern gas turbine designs structural casings provide a gas tight pressure vessel, structural support for internal and external fixtures, and in the event of a catastrophic failure component containment. These casings are generally nickel, steel, or titanium depending upon the usage temperature and specific application. However, in all cases the casings are manufactured using a wrought processing route. Generally casing structures are fabricated from ring rolled flanges and wrought sheet that are welded together to produce the final component geometry. A typical process route for the production of such a casing would be to take a cast ingot, forge to size, pierce, and then ring roll the pierced component to produce a flange of the required diameter and thickness. The wrought sheet would then be formed to shape and welded to the ring-rolled flanges. This process involves many manufacturing steps, is costly, time consuming, and requires the selected alloy to exhibit good forming and welding characteristics. For alloys that are produced in large quantities the production of casings via the wrought route can be carried out reasonably cost effectively. However, due to the requirement for increased combustion temperatures and higher pressures many of the current materials utilized as combustion and turbine casings are rapidly reaching the extremes of their temperature capability. In the case of the combustion casing support structure, the front of the combustion casing sees wall temperatures approaching 650°C. In this case alloys, such as the nickel-based alloy W718, which is widely used as a combustor support casing, are becoming severely creep limited. Therefore, new higher temperature nickelbased alloys, such as RS5, W939, CM247LC, and MarM002 are under consideration to replace W718, since they offer improved creep capability. Much development effort has been expended in developing and assessing these new alloys for engine applications and a significant proportion of the required work has now been completed. However, as a general rule an alloy that exhibits improved creep resistance (i.e., improved resistance to deformation at elevated temperature) is also more difficult to produce via conventional wrought processing routes, such as forging and rolling. Furthermore, ease of weldability can be an issue with these higher performance alloys, as can the availability and cost of wrought product. Consequently, the introduction of these elevated temperature materials may demand the application of alternative processing techniques. One alternative technique under consideration is spray forming. Spray Forming

The spray forming of components requires the atomization and spraying of molten metal onto a suitably shaped mandrel. Generally the material is melted by induction heating, and then atomized using an inert gas (usually Ar). The atomized metal is sprayed into a deposition chamber held under a reduced pressure and deposited onto a rotating mandrel. Computer control of the spray deposition process means that profiled “near net shaped” casings can be produced. Following deposition the porous pre-form is consolidated by hot isostatic pressing, ring rolled (if necessary) to the final

size, and then machined to the final component geometry. The large reduction in process steps that this approach enables, makes significant cost reductions feasible for many alloys. However, for some of the higher performance alloys that are difficult to wrought process, spray forming may prove to be the only viable production route. In addition to cost spray forming also has the advantage that a fine grain sized and chemically homogeneous product is produced, which again offers benefits over conventional process routes. Casing Fabrication

In this paper the fabrication of a combustion chamber support casing via spray forming was considered. The material selected for study is the high performance nickel-based alloy RS5, which has been identified as a potential replacement alloy for 1N718 for a number of casing applications. The composition of RS5 compared to 1N718 is shown in Table 15–3. The microstructure and mechanical properties of a hot isostatic pressed (HIP) and heat treated pre-form was evaluated. Microstructure of Processed and Heat Treated RS5

The microstructure of the spray-formed RS5 after HIPping, ring-rolling and heat treatment is shown in Figure 15–27. As can be seen from this figure the microstructure is primarily equi-axed, with a grain size ranging from 50-350 microns. The mean grain size was determined as being 100 microns. Electron back-scattered diffraction patterns showed that the microstructure did not contain any evidence of texture, as would be expected from a spray-formed deposit. Mechanical Properties of RS5

A full mechanical property evaluation of the spray-formed RS5 was carried out to assess the suitability of the material for casing applications. Tensile: The tensile strength of spray-cast, HIPped and ring rolled RS5 are comparable to, or better than, typical values for wrought 1N718 over the temperature range evaluated; with the strength of RS5 being retained to at least 60°C higher than 1N718. The elongation of RS5 is comparable to 1N718 in the range 20–600°C but at temperatures greater than 750°C it is significantly lower. Creep: Comparison of the creep behavior of RS5 and 1N718 again indicates that RS5 exhibits a temperature advantage of around 60°C over 1N718 at elevated temperatures.

Table 15–3. Typical Chemical Compositions (wt%) of Alloys IN718 and RS5 [15-2]







C Cr Co Mo W Nb Ti Ta Al

0.05 18.5 0.1 3.0 — 5.0 0.8 — 0.5

0.08 16.0 10.0 4.8 2.0 4.8 2.7 1.5 1.0

B Zr Fe Mn Si S P Ni

0.003 0.006 18.0 0.04 0.07 0.003 0.007 Bal.

0.006 0.005 — 0.05 0.05 0.003 0.005 Bal.

M A N U F A C T U R I N G , M AT E R I A L S , A N D M E TA L L U R G Y


of processing RS5 via the spray-forming route is prohibitive. The major advantage offered by the spray-forming route is the ability to process high strength alloys that are not susceptible to wrought processing. As higher combustion temperatures are realised the need for spray-formed product is likely to increase considerably. Creep Resistance Advancements Creep Resistance of Materials for Microturbine Recuperators

Figure 15–27. Microstructure of spray-formed, HIPped, ring-rolled and heat treated RS5. [15-2]

Fatigue: In terms of the fatigue properties, RS5 was found to be approximately comparable to typical values for wrought. In summary, the deposition and consolidation of sprayformed RS5, results in a chemically homogeneous and equiaxed product, with little evidence of porosity or voiding. Mechanical testing of the spray-formed and processed material has clearly demonstrated that the material is broadly comparable to IN718, but exhibits a significant improvement in its properties at elevated temperature. An analysis of the data indicates that RS5 has a temperature advantage of around 60°C over IN718, in terms of tensile strength and creep resistance. However, tensile, creep and fatigue testing have all shown that the material is highly susceptible to intergranular failure at elevated temperatures. It is clear though that considerable scope exists to modify either the composition or processing routes in an attempt to improve the behavior of the material at elevated temperatures. It is clear that RS5 does offer an increased temperature capability compared to IN718. However, at present the cost

Table 15–4.

Microturbines evolved from automotive and small aerospace turbine applications. They have caught the U.S. Department of Energy’s (DOE’s) attention enough that they are among DOE’s closely pursued optimization projects. They have also caught public attention to the point that it will not be long before the “PT” (personal turbine) is talked about as the “PC” (personal computer) now is. Also see Chapter 16 on microturbines and hybrids. Microturbines run faster than conventional gas turbines and the heat balance of a microturbine system is such that a recuperator is essential for optimum efficiencies. With the recuperator, as with many other components on gas turbine engines, the limiting design parameter is creep, as a development study outlines. That study,* funded by Oak Ridge National Laboratories, concludes: “A group of heat-resistant and oxidation/corrosion resistant austenitic stainless alloys have been processed into 1.3 mm foils and creep-rupture tested at 750 °C and 100 MPa.” See Table 15–4. Ceramic Components

Considered a distant, esoteric prospect only a scant few decades ago, the ceramic turbine is fast approaching reality. Gas turbines that use ceramic coatings and selected components that are ceramic or partially ceramic are already part of mainstream technology. Improvement of this technology continues, sponsored in the United States, in part by the U.S. DOE. The following cases provide details of design, testing

* [15-3] Courtesy of U.S. DOE. P. J. Maziasz and R. W. Swindeman, “Selecting and Developing Advanced Alloys for Creep-Resistance for Microturbine Recuperator Applications,” in Proceedings of the ASME Turbo Expo 2001, June 4–7, 2001, New Orleans, 2001-GT-0541.

Compositions of Heat-Resistant Austenitic Stainless Alloys Processed into Foils (wt.%) [15-3]









347 steel (Allegheny-Ludlum) Modified 803 (Special Metals, developmental) Thermie-alloy (Special Metals) Alloy 120 (Haynes International)

68.7 40

18.3 25

11.2 35

0.3 n.a.

0.64 n.a.

0.03 0.05

0.6 0.001 0.003 n.a. n.a. n.a.

0.2 Co n.a.

2.0 33

24 25

48 32.3

0.5 2.5 max

2.0 0.7

0.1 0.05

0.5 0.6

2.0 0.1

0.8 0.1

Alloy 230 (Haynes International)

3 max 22






Alloy 214 (Haynes International) Alloy 625 (Special Metals)

3.0 3.2

76.5 61.2

— 9.1

— 3.6

— 0.02

— 0.2

— 0.23

4.5 0.16

20 Co 3 Co max, 3 W max, 0.2 N 5 Co max, 14 W, + trace La + minor Y

n.a.—not available

16 22.2






and operational strategies that involve ceramics components and point the way for work in this discipline to continue. Case 2. Ceramic Vanes for a Model 501-K Industrial Turbine Demonstration*

The approach for this project is to design and demonstrate ceramic first-stage vanes in a Rolls Royce Allison Model 501K turbine. These vanes operate at similar (and somewhat higher) temperatures as the second-stage vanes of advanced turbines. Consequently, a successful demonstration of firststage vanes in the current generation Model 501-K turbine could provide a stepping stone to using ceramic vanes in second-stage and downstream rows of future generation advanced turbines. Project Summary

Activities of the DOE/Rolls Royce Allison ceramic vane project include the following: ●

● ●

Design, analyses, and fabrication of ceramic first-stage vanes and their metal mounts for retrofit into Model 501-K turbines Thermal shock proof tests of the ceramic vanes Engine validation test of the ceramic vanes and their metal mounts Phase 1 demonstration of the first-stage ceramic vanes/ mounts in a Model 501-K turbine at a commercial site to assess design integration and materials compatibility Phase 2 demonstration with an optimized vane/mount redesign

These activities have been completed through the Phase 1 demonstration. Operation of an Exxon turbine for a total of 815 hr (793 hr at an Exxon plant and 22 hr proof test) was achieved. The Phase 2 demonstration was originally planned to accommodate any redesign needs of the metal mounts for the ceramic vanes, because past experience has shown the challenges of integrating structural ceramic components with metallic support structures. However, the metallic mounts performed successfully in the 501-KB5 Phase 1 demonstration of first-stage ceramic vanes. Since the Phase 1 demonstration identified a significant issue of ceramic oxidation, the Phase 2 demonstration will address the resolution of the oxidation issue. Ceramic Vane/Mount Design and Analyses

Vanes The AlliedSignal AS 800 silicon nitride ceramic was used for the first-stage ceramic vanes. The ceramic vanes were designed to facilitate manufacturability and relatively low cost. The vane design involves a single airfoil and simple platforms. The mounting arrangement (described in the next section) enables minimal final machining of the vane to reduce costs. The ceramic vane has been designed with a thinner airfoil than for the Model 501 turbine first metal vane. Analyses showed that the thinner vane was necessary for acceptable thermal shock stresses during emergency shutdown of the turbine (the highest stress condition).

*Source: [15-4] Courtesy Rolls Royce. Extracts from R. A. Wenglarz and KI. Kouns, “Ceramic Vanes for a Model 501-K Industrial Turbine Demonstration,” in Proceedings of the ASME Turbo Expo 2000, May 8–11, 2000, Munich, 2000-GT-731.

Thermal and stress analyses indicated a maximum emergency shutdown stress of 207 MPa (30.0 ksi) in the vane mid span trailing edge region. A maximum steady-state stress of 192 MPa (27.9 ksi) was calculated at maximum continuous power for the turbine. The location of the maximum steady-state stress was also in the mid span trailing edge region. The calculated fast fracture probability of survival for the 60-vane engine set exceeds 99.99% for all of the emergency shutdown and maximum continuous power conditions that were analyzed. Stress rupture tests of the AS 800 silicon nitride material used for the ceramic vane with durations up to 10,000 hr have been conducted at Oak Ridge National Laboratory (ORNL) and the University of Dayton at significantly higher temperatures and somewhat lower stresses than calculated for the vane at maximum continuous power conditions. No failures were experienced in 4500 hr by any of the specimens from a properly processed batch of the AS 800 ceramic. Retained strengths of specimens measured after surviving the 4500 hr stress rupture test exceeded 490 MPa (71 ksi), which is substantially higher than the highest calculated emergency shutdown stress of 207 MPa (30.0 ksi) for the Model 501K ceramic vanes. The results of these tests provided a basis for conducting a long term field test of the AS 800 ceramic vanes. Mounts Figure 15–28 illustrates the mounting arrangement for the ceramic vanes. To minimize mount loads and stresses, the vanes are not gripped or otherwise hard mounted but instead are seated in circumferential grooves of the inner and outer mount segments. Ceramic cloth is used at the interfaces between the metal mount segments and the outer surfaces of the vane platforms. This compliant material reduces ceramic contact loads and stresses from the mounts and also insulates the ceramic/metal interface. Insulation allows the mounts to operate at lower temperatures in their alloy working range and reduces the thermal gradient in the ceramic vane, which is the primary source of steady-state stress. Ceramic Vane/Mount Assembly Figure 15–29 shows the first-stage ceramic vane/mount assembly that replaces a similar metal vane assembly used for conventional Model 501-K turbines. The inner vane support and an outer sheet metal band that holds the assembly together are common to both the ceramic and metal vane assemblies. All of the other parts of Figure 15–29 were designed for retrofit of the first-stage ceramic vanes into Model 501-K turbines. The Figure 15–29 front view also shows the saddles that position the transition sections from the six can combustors of the Model 501-K turbines. Consequently, 10 of the 60 first-stage ceramic vanes are located at the exit of each of the transition sections from the six combustor cans. Ceramic Vane Thermal Shock Tests

Trailing edge thickness and other measurements were taken on each of the 87 AS 800 ceramic vanes received from AlliedSignal. The vanes were analyzed using fluorescent penetrant and x-ray analyses. The vanes were then exposed in an atmospheric combustor rig to thermal shock tests. Visual, fluorescent, and x-ray analyses conducted after the thermal shock tests revealed that only one vane had evidence of a possible crack and was questionable for operation in the turbine.

M A N U F A C T U R I N G , M AT E R I A L S , A N D M E TA L L U R G Y

Figure 15–28.

Ceramic vane mounting arrangement. [15-4]

Ceramic Vane/Mount Proof Tests

Turbine proof tests of the ceramic vanes and metal mounts were conducted prior to operation at a commercial site. Objectives of these tests were to verify that (i) the metal mounts do not transmit excessive contact loads to the ceramic vanes, (ii) turbine power and performance are not adversely affected by the vane/mount designs, and (iii) the uncooled ceramic vanes do not result in excessive temperatures in the adjacent metal support structures. Turbine power and performance were considered potential issues because of the challenges of maintaining tight gaps, clearances, and airfoil positioning due to a difference of more than a factor five between the thermal expansion coefficients for the metal mount materials and the ceramic vane materials. The temperature of the metal support adjacent to the ceramic vanes was also a

Figure 15–29.


Ceramic vane/mount assembly. [15-4]

potential issue because the mount parts common to both the metal vane and ceramic vane assemblies do not benefit from the metal vane cooling when operated with ceramic vanes. The approach to accomplish the above objectives consisted of a baseline performance test of the Exxon 501KB5 turbine with metal vanes, performance tests of the same turbine except with the metal first-stage vane assembly replaced with the ceramic first-stage vane assembly, and thermocouple measurements of the temperatures of the metal vane support during ceramic vane runs. The performance of the turbine with the metal and ceramic vane assemblies was compared. The turbine was disassembled and inspected after the final ceramic vane test to determine whether the metal mounts had transmitted excessive loads to the ceramic vanes. The total operation time of the turbine proof test with the ceramic vane/mount assembly was 22 hr. Post-test visual and fluorescent penetrant analyses revealed no fractured or cracked vanes. However, two vanes had platform chips, one of which was suspected to have occurred during disassembly. Evaluations of the other chipped vane and the few vanes that experienced chips during the later demonstration led to the conclusion that the ceramic vane/mount design provided stress relief of inevitable localized contact loads at platform edges associated with both ceramic and metal part tolerances. Oxide scale formation observed on chipped platform surfaces during the later demonstration inspections indicated that the vanes operated many hours after chipping and cracks had not propagated from the chipped surfaces. All six performance calibration point measurements referenced to standard day conditions for the Exxon turbine with the ceramic vane assembly indicated greater power than for the same turbine operated with the metal vane assembly. The average calculated standard day power for the six ceramic vane performance runs exceeded that for the metal vane run by 1.7%. Some of the improved performance for the ceramic vanes probably resulted from a thinner airfoil than the metal vanes without the flow disruption of trailing edge cooling air flow discharge. Also, the ceramic vane



was designed with more advanced aerodynamic analyses approaches than used for the standard metal vane. Thermocouple measurements of the metal vane support temperatures adjacent to the ceramic vanes showed temperatures well below the working limits of the vane support alloy. Following reassembly of the ceramic vane assembly after inspection, the Exxon turbine used in the engine proof tests was sent to the Exxon Mobile Bay facility for the field demonstration. Ceramic Vane/Metal Mount Demonstration

The first-stage ceramic vane Phase 1 field demonstration occurred at an Exxon natural gas processing plant near Mobile, Alabama. Three identical Rolls Royce Allison Model 501-KB5 turbine skids provided power and process steam at this Exxon plant. Figure 15–30 shows one of the turbines in its skid enclosure at Exxon. The turbine with the ceramic first-stage vanes was installed and operated under normal commercial service conditions at maximum continuous power, except for preplanned teardowns and ceramic vane assembly inspections with removal of vanes for analyses. These inspections were originally scheduled at 200, 500, and 1000 hr. The turbine sustained power and performance throughout its operation with ceramic vanes. The turbine at Exxon experienced an emergency shutdown (the highest vane stress condition) at 525 hr and a full power water wash of its compressor with no detectable adverse effects on further operation or the ceramic vanes. The cause of the emergency shutdown was a malfunctioning vibration sensor and was unrelated to the ceramic vane assembly. There was no need to shut the turbine down associated with the ceramic vanes except for the planned inspections. None of the ceramic vanes failed or cracked and the metal mount design was shown to perform successfully. As mentioned earlier, a few vanes experienced chipping at platform edges, which appeared to alleviate local contact loads and enable further operation for many hours without propagation of cracks or failure.

Figure 15–30.

Exxon 501-KB5 turbine at site. [15-4]

Analyses of the vanes removed during the periodic inspections showed unexpected rates of material loss due to oxidation of the silicon nitride ceramic in the turbine operation environment. These rates of materials loss were determined to be excessive for industrial turbine applications, which require part lifetimes of 20,000 hr and longer. Analyses of the vanes showed the need for additional measures (e.g., environmental coatings) to achieve industrial turbine lifetimes. Since the Phase 1 demonstration had achieved its objective of identifying redesign needs, this demonstration phase was discontinued after a total operation time of 815 hr (22 hr proof test and 793 hr demonstration) for the Exxon turbine with ceramic vanes. Analyses of Ceramic Vanes

Visual evidence of ceramic oxidation was apparent during the turbine inspections. As illustrated by Figure 15–31, the color of the vanes had changed from tan/gray (vane on right) to white (vane on left). The ceramic vanes were covered by a white powder. The metal rotor blades and vanes in the two rows downstream of the ceramic vanes also had a dusting of white powder. The white powder was analyzed by Oak Ridge National Laboratory (ORNL) and found to be an oxide of silicon and lanthanum from the intergranular phase of the ceramic. Figures 15–32 and Figure 15–33 illustrate oxidation material losses visible to the unaided eye on vane concave and convex surfaces, respectively. These vanes had experienced 815 hr operation in the turbine. Oxidation versus Position in the Combustor Pattern The trailing edge thickness was measured for each vane removed during inspections and after the demonstration to determine the oxidation loss of material at that location. Figure 15–34 shows trailing edge thickness losses at 815 hr versus radial location on the vanes and circumferential position in the six combustor cans of the turbine. The plot on the top shows thickness losses for vanes located at the same position at the exit of the combustor cans in the saddle region near the outside of the annular transition section from the combustor cans. The plot on the bottom shows thickness losses for

M A N U F A C T U R I N G , M AT E R I A L S , A N D M E TA L L U R G Y

Figure 15–31. Ceramic vanes before and after 815 hr operation in the turbine. [15-4]

Figure 15–32. Ceramic material loss on concave surface. [15-4]

Figure 15–33. Ceramic material loss on convex surface. [15-4]

vanes at the same location at the exit of the combustor cans near the center of the annular transition from the combustors. Both plots show losses at the hub, mid span, and tip trailing edge regions. These plots indicate that the greatest trailing edge losses were measured at the vane mid span, corresponding to the hottest and highest velocity location in the radial direction. The trailing edge losses were also higher at circumferential positions nearer to the center of the combustor outlet transition sections, again corresponding to higher temperatures and velocities. Similar circumferential patterns of trailing edge loss versus circumferential vane location were observed for the six combustors, but the overall level of loss varied by as much as a factor of 2 between combustors. Oxidation versus Time Figure 15–35 shows the measured trailing edge losses at mid span (the trailing edge radial location of greatest loss) versus vane operation time in the


turbine. The data suggest insignificant trailing edge thickness losses for times less than 200 hr. Analyses by ORNL identified an initial oxide scale on the new ceramic vanes resulting from processing. Apparently this scale was much more adherent and impermeable to further oxidant penetration to the underlying substrate than the oxide scale formed in the turbine environment. Figure 15–35 indicates that the two vanes removed after 222 hr of operation had very little measurable trailing edge material losses when compared to the pretest measurements. However, the vanes removed after 522 hr had measured trailing edge material losses up to 0.32 mm (0.0125 in.). Since the test was discontinued after the 815 hr inspection, all 60 vanes removed from the assembly were measured for trailing edge thickness losses. Except for vanes with low oxidation levels because of their locations in untypical flow and temperature regions behind the saddles, the decreases in trailing edge mid span thickness at 815 hr range from 0.13 mm (0.005 in.) to a maximum loss of 0.61 mm (0.024 in.). Percentage decreases in trailing edge thickness range from 12% to 50% of original values. The trailing edge thickness measurements indicated that the rate of oxidation might have been decreasing with time. Oxidation versus Position on Airfoil Surface AlliedSignal took profile measurements of several of the ceramic vanes that had operated 815 hr in the turbine and compared those to profiles measured on the same vanes after fabrication. Figure 15–36 gives the mid span profile comparisons for one of the vanes that had the greatest material loss. Although the gas velocity near the airfoil surface varies from near zero at the nose stagnation point to about 573 m/s (1880 ft/sec) at the trailing edge, the loss does not greatly differ over the airfoil surface. This suggests that gas velocity is a secondary factor in the rates of oxidation and that relatively expensive high velocity rigs (e.g., cascades) might not be needed for ceramic materials oxidation tests. However, such ceramic materials tests do need to replicate the water vapor content and pressures of the turbine flow path environments. Retained Strength of Ceramic Vanes Several of the ceramic vanes removed at various operation intervals from the demonstration turbine were sent to ORNL for retained strength measurements. Small disks (about 6 mm diameter and about 0.6 mm thick) were cut from the vanes and then fractured using a load at their center. Figure 15–37 shows results of the ORNL retained strength measurements versus operation time. The retained strength after 22 hr exposure to the turbine environment (in the engine proof test) increased over the as-processed strengths (zero time exposure). The average retained strength of specimens did not greatly change from initial values for increasing exposure times up to 815 hr, although the scatter in the strength measurements did increase with time. The lowest retained strength measurement in Figure 15–37 of about 500 MPa is approximately 2.4 times greater than the maximum calculated vane stress of 207 MPa at the highest stress vane location and worst (emergency shutdown) condition (see earlier discussion of stress analyses). Consequently, the ORNL data suggest that the vane oxidation is a surface phenomenon that does not substantially affect the strength of the underlying substrate material. Much longer vane lifetimes appear possible if the loss of surface material by oxidation can be inhibited (e.g., through use of environmental coatings). In summary, a first-stage ceramic vane and metal mount design has been developed and demonstrated for 815 hr under commercial industrial turbine conditions.



Figure 15–34.

Trailing edge thickness loss at 815 hr. [15-4]

Figure 15–35.

Mid span trailing edge thickness loss versus time. [15-4]

M A N U F A C T U R I N G , M AT E R I A L S , A N D M E TA L L U R G Y


This design appears to have successfully addressed many of the challenges of integrating stationary structural ceramics with metallics in an industrial turbine. However, the ability to operate a turbine for extended durations afforded by the ceramic vane/mount design has brought to light the issue of excessive long term ceramic oxidation in the industrial turbine flow path environment. Additional measures are needed to improve materials durability so that commercial lifetimes of at least 20,000 hr can be achieved for industrial turbine ceramic parts. Measures to inhibit surface oxidation should advance structural ceramics toward this life goal since the strength of the ceramic structure underlying the oxidizing and recessing surfaces exposed to the flow stream was not observed to be markedly decreasing. Case 3 describes the assessment of ceramic versus metal media filters for gas turbine power systems (conducted by Siemens Westinghouse). Case 3. Assessment of Ceramic and Metal Media Filters in Advanced Power Systems*

Siemens Westinghouse Power Corporation (SWPC) has been involved in the hot gas filter materials technology development since 1988. Emphasis was initially focused on the development and use of oxide- and nonoxidebased monolithic filter materials in bench-scale test programs and field applications (Table 15–5). With thermal fatigue issues being encountered by the oxide-based monoliths, and the oxidation and/or high temperature creep issues resulting in the nonoxide-based filter matrices during pressurized fluidized-bed combustion (PFBC) and/or pressurized circulating fluidized-bed combustion (PCFBC) operation, development of fracture toughened, continuous fiber reinforced ceramic composites (CFCC)

Figure 15–36.

and intermetallic filter elements was undertaken in 1994. Several issues were identified with respect to the long-term durability, response, and performance of the CFCC filter elements during extended service life. These included manufacturing and structural integrity, load bearing capability, and ease of fixturing within the filter system. Numerous advancements continued to be made since initiating development and manufacture of the monolithic and composite ceramic filters in 1988 and 1994, respectively. These included: ●

*Source: [15-5] Courtesy of Siemens. Extracts from M. A. Alvin “Assessment of Ceramic and Metal Media Filters in Advanced Power Systems,” in Proceedings of the ASME Turbo Expo 2001, June 4–7, 2001, New Orleans, 2001-GT-0574.

Figure 15–37.

Mid span profile loss. [15-4]

Development and use of high temperature, creep resistant binders in the clay bonded silicon carbide filter materials. Efforts by alternate domestic and foreign suppliers (i.e., Blasch, Ensto, etc.), to bring to the market potentially viable filter materials and/or filter elements manufactured by alternate processes and production techniques.

Strength versus time for specimens from vanes. [15-4]



Table 15–5.

Porous Ceramic and Metal Filter Technology Development [15-5]

Monolithic Matrices

Fiber Reinforced Composites


Coors P-10OA-1 alumina/mullite Pall clay bonded silicon carbide (442T, 326, 181) Schumacher clay bonded silicon carbide (F40, FT20) GTE cordierite and cordierite-silicon nitride AiResearch reaction bonded and sintered silicon nitride Enstomullite-bonded alumina Blasch mullite-bonded alumina Specific surface cordierite IF&P recrystallized silicon carbide

McDermott oxide-based CFCC Techniweave oxide-based CFCC

U.S. Filter Haynes 214, 556, 188, 230 Inconel 600, Hastelloy X, 3105 (U.S. Filter, Pall, Mott Corp.) Iron aluminide (U.S. Filter, Pall)

3M oxide-based CFCC Americon oxide-based CFCC 3M CVI-SiC

FeCrAIY (U.S. Filter, Technetics, others)

DuPont SiC-SiC Textron Nonoxide-Based CFCC Filament wound Honeywell PRD-66

Vacuum infiltrated chopped fibers IF&P fibrosics™ Foseco aluminosilicate Reticulated foam Ultramet CVI-SiC Selee oxide-based foam

Development of alternate filter concepts (i.e., sheet filter; inverted candle filter; etc.). Development of oxidation resistance coatings for nonoxide matrices. Incorporation of a membrane along the o.d./i.d. surfaces of the filter elements. Enhanced flange strength and surface abrasion resistance.

Table 15–6.

As issues arose with respect to the long-term viability of monolithic and CFCC filter elements, efforts were directed in 1998 to the development of a more robust, metal-based filter element. Note: Table 15–6 provides a summary of the operating hours accumulated for each candle filter type tested in the various programs.

Field and Extended Life Testing [15-5]

Maximum Operating Time, hrs

Equivalent Exposure Time, hrs

Filter Supplier & Matrix


PCFBC—FW Karhula

Schumacher F40 Schumacher FT20 Pall Vitropore 442T Pall 326 CoorsP-100A-1 alumina/ mullite

5,855 1,705 1,705

227(1) 2,201(2) 1,341(1) 2,201(2) 716(1) 2,201(2) 3,311(3) 627(4) 581(5)







5,611 5,030(6)

3M CVI-SIC DuPont PRD-66 3M oxide CFCC McDermott oxide CFCC Techniweave oxide CFCC Blasch mullite-bonded alumina Ensto IF&P REECER Other

2,815 1,705 1,705

(1) 1992–1994 test campaign. (2) 1995–1997 test campaign. (3) 2201 hrs of operation under PCFBC conditions and 1110 hrs of operation under PFBC conditions. (4) 1995–1996 test campaign. (5) 1997 test campaign. (6) New element without field exposure.

Field & Accelerated Testing 11,080; 11,080 9,662; 11,080 8,485; 12,211 13,356

M A N U F A C T U R I N G , M AT E R I A L S , A N D M E TA L L U R G Y Ceramic Filter Elements—Summary Comments

Table 15–7 identifies the manufacturing, as well as thermal, mechanical, and chemical degradation issues that have been identified during the initial and extended stages of life of the oxide and nonoxide-based, monolithic ceramic, fiber reinforced, and filament wound filter materials. Although microstructural changes occur

Table 15–7.

in the porous ceramic filter matrices as a result of exposure to process operating conditions, the residual strength of all materials tends to stabilize after an initial conditioning period. An area that remains to be addressed is whether microstructural or phase changes will continue to occur within the various filter matrices with extended aging of elements during field operation,

Matrix/Component Response to Process Operation—PFBC/PCFBC [15-5]

Initial Life Matrix Operating Time Monoliths Oxides


Plant Commissioning

Fiber reinforced Oxides


Initial oxidation >700 °C

Fiber/SiC bonding and embrittlement Filament wound Oxides

1 Year

Failure resulting from Thermal fatigue process thermal transients Matrix phase changes; component conditioning

Failure resulting from extreme process thermal transients Initial matrix oxidation ≥700 °C


Extended Life > 3 Years

Matrix phase changes; component conditioning

Full matrix crystallization Microcrack formation Plant process control required for material/ component stability and performance Crystallization of binder/ ligaments

Impact of reformulation of binder phase limiting high temperature creep TBD Oxidation ≥ 700 °C)

Oxidation of SiC grains Creep (TBD Limited to < 700–750 °C applications

Potential stability and performance issues related to manufacturing, homogeneity, and reproducibility of elements; lower strength; lower load bearing capabilities; and fixturing need to be addressed Oxidation >700 °C Fiber/SiC bonding and embrittlement; reduced matrix fracture toughness Potential stability and performance issues related to manufacturing, homogeneity, and reproducibility of elements; lower strength; lower load bearing capabilities; and fixturing need to be addressed Oxidation >700 °C Fiber/SiC bonding and embrittlement; reduced matrix fracture toughness

Fiber embrittlement TBD

Potential stability and performance issues related to manufacturing, homogeneity, and reproducibility of elements; lower strength; lower load bearing capabilities; fixturing and membrane stability (devoting, matrix pull-out) need to be addressed

Not recommended for high temperature oxidizing applications




and whether continued phase change will impact the residual strength, thermal and/or mechanical properties, and filtration characteristics of the various filter materials. Continued grain growth and secondary phase formations are projected for some materials during extended field operation, which may have a significant impact on the ultimate viability of these filter elements during commercial operation. Metal Filter Media Development

In 1998, SWPC initiated a program with DOE/NETL to develop and evaluate the use of porous, high temperature, metal media candle filters in PFBC systems. Working with U.S. Filter/Fluid Dynamics, Pall Advanced Separation Systems, Mott Corporation, Fairey Microfiltrex, Technetics, and Ultramet, SWPC produced composite filter elements for exposure to a simulated 1200°F (650°C), 1400°F (760°C), and 1550°F (840°C) PFBC process gas environment containing 200 ppmv S02/ S03. The advanced alloys selected by SWPC for enhanced corrosion resistance in this environment were Haynes 230, 214, 188, and 556, and FeCrAIY. Elements constructed from 310S, Inconel 600, Hastelloy X, and FeAI were included as commercially available materials for comparison of performance in this program. The filtration media of the advanced alloy filter elements principally included metal fibers, powders, wire laminates, and open-cell, metal-based, reticulated foams. Typically the U.S. Filter/Fluid Dynamics, Fairey Microfiltrex, and Technetics sinter bonded fiber-containing metal media is formed into an ∼1 mm thick filtration mat layer which is supported by an underlying, dense, perforated, cylindrical metal support structure. An open mesh outer containment

layer is included either along the outer surface of the porous filter body, encapsulating the filtration mat layer, or is embedded within, as well as sintered bonded to one surface of the porous filtration mat layer. The outer confinement mesh and filtration mat are generally longitudinally welded together, forming a tight fit around the underlying support structure. In contrast, filter elements fabricated from sinter bonded metal media powder or particulates typically are seamless (with the exception of Pall Hastelloy X), are generally thicker walled in comparison to fiber-containing metal filter elements, and do not have an outer confinement layer or underlying metal support structure. The as-manufactured, high temperature, tensile strength of the commercially available and developmental porous advanced metal filter media are shown in Figure 15–38. Post-test exposure strength of the composite elements after 250 and 500 hours of simulated PFBC testing at 1200 °F (650°C) is also shown. In general, the tensile strength of the as-manufactured U.S. Filter/Fluid Dynamics filter elements at 1200°F (650°C) is between 10,000 and 17,000 psi. The strength of the fiber-containing U.S. Filter/Fluid Dynamics filter media generally appeared to increase during the initial 250 hours of exposure to the simulated PFBC operating conditions. After 500 hours of exposure, a minor reduction in the 1200°F (650°C) tensile strength resulted for the advanced U.S. Filter/Fluid Dynamics filter media, as well as Hastelloy X, while a continued strengthening of the commercially available 310S and Inconel 600 filter media resulted. Minor strengthening of the Mott Inconel 600 and Pall FeAI powder-containing media, and Fairey Microfiltrex fibercontaining media resulted during initial operation in the 1200°F (650°C) simulated PFBC environment. In contrast, the 1200 °F (650°C) tensile strength of the powder-contain-


Tensile Strength, psi



0 hrs 242 hrs


500 hrs




Mott IN600

Pall FeAl

Pall Hast X

Pall 310

USF 230

USF 188


USF 556

USF 214

USF Hast X



USF 310



Figure 15–38. Tensile strength of the porous metal filter media at 1200 °F (650 °C) as a function of exposure time to simulated PFBC process operating conditions. [15-5]

M A N U F A C T U R I N G , M AT E R I A L S , A N D M E TA L L U R G Y

ing Pall 310 and Hastelloy X porous filter media decreased as a function of operating time. Due to the variation in the use of coarse vs. fine outer containment mesh, trends in the Technetics residual tensile strength were not readily appar-


ent for the porous FeCrAIY filter media. Currently testing is on-going at SWPC STC to demonstrate the potential viability of the various porous filter media during 1400°F (760°C) simulated PFBC operation.

Microturbines, Fuel Cells, and Hybrid Systems*


“Faith makes all things possible. Love makes all things easy. Hope makes all things work.” —Unknown


Microturbines 618 Fuel Cells 618 Power Generation Tubular SOFC Technology 618 Hybrids 619 Applications and Case Studies 621 621 Case 1. Microturbine in a CHP Application 622 Case 2. A Fuel Cell Application Wide Application Fuel Cell Turbomachinery 624 Case 3. Tubular Solid Oxide Fuel Cell/Gas Turbine Hybrid Cycle 626 Power Systems Case 4. A Turbogenerator for a Fuel Cell/Gas Turbine Hybrid 629 Power Plant

*Source: [16-1] Unless otherwise specified, Claire M. Soares, Microturbines and Fuel Cells (Boston: Elsevier).



A microturbine,* as the name suggest, is a small gas turbine. Research on microturbines predicts that affordable commercially available models eventually will shrink to thumbnail-size and become PTs, or personal turbines, much the way large room-sized computers became PCs. For the time being “affordable, commercially available” microturbines are about the size of a household refrigerator and run on a variety of waste (like wood waste, biomass, or methane rising off landfill) and low BTU gases. Microturbines require a recuperator to develop anywhere close to an efficiency (about 40%) that makes them commercially viable. Commercial microturbines deliver from 50 kW to 500 kW most commonly and can power small schools, remote process plants, and small industry. A tie in to the local grid, if grid access is available, for backup power can be provided. Hybrid is the name given to a gas turbine in conjunction with a fuel cell. Fuel cells are given some space in this chapter because of their ability for application in concert with gas turbines. In contemporary work, the gas turbine in a hybrid system is most commonly a microturbine. The hybrid then results from the partnership of a heat engine and a nonheat engine (two different cycles). Because the term combined cycle is reserved for the combination of two different heat cycles (gas and steam turbine cycles), the gas turbine-fuel cell is called a hybrid. The recent work on hybrid systems has been intense. Most of the U.S. work on hybrid systems has been funded by the U.S. Department of Energy (DOE). The DOE gives grants to U.S. manufacturers, so when Siemens became Siemens Westinghouse and Rolls Royce merged with Allison, the Europeans could then get U.S. DOE grants, too. Due to the lack of emissions and the potential for future power distribution for large consumers as well as single households, DOE’s sponsorship is well founded. Minus the greenhouse gas emissions of conventional fossil fueled plants and the hybrid’s potential to eventually make dinosaurs of power lines and massive transmission systems, the hybrid’s future may be bright indeed. It may be a few years before its price is brought down from current levels of $900/kW to $1500/kW uninstalled. In fact some initial commercial systems may cost in excess of $3000/kW. A few tested systems today boast lower figures than that value; however, the reader needs to check all data that may affect system-related costs in “local” conditions to arrive at an accurate “cost per kW of this system.” When target price objectives are reached however, it is anticipated that hybrids will become competitive and then drop in price below conventional power generation unit costs. Microturbines

Microturbines** produce between 25 kW and 500 kW of power. Microturbines were derived from turbocharger technologies found in large trucks or the turbines in aircraft auxiliary power units (APUs). Most microturbines are single-stage, radial flow devices with high rotating speeds of 90,000 to 120,000 revolutions per minute. However, a few manufacturers have developed alternative systems with multiple stages and/or lower rotation speeds. Microturbines are currently at partly commercial status. Capstone, for example, has delivered over 2400 microturbines to customers as of 2003. However, many of the microturbine installations are still undergoing field tests or are part of large-scale demonstrations. *[16-1] **Source: [16.2] Courtesy of the U.S. DOE.

Table 16–1.

Microturbine Overview

Commercially available Size range Fuel Efficiency Environmental Other features Commercial status

Yes (limited) 25–500 kW Natural gas, hydrogen, propane, diesel 20–30% (Recuperated) Low (< 9–50 ppm) NOx Cogen (50–80 °C water) Small volume production, commercial prototypes now.

Microturbine generators can be divided in two general classes: ●

Recuperated microturbines, which recover the heat from the exhaust gas to boost the temperature of combustion and increase the efficiency, and Unrecuperated (or simple cycle) microturbines, which have lower efficiencies, but also lower capital costs.

While some early product introductions have featured unrecuperated designs, the bulk of developers’ efforts are focused on recuperated systems. The recuperator recovers heat from the exhaust gas in order to boost the temperature of the air stream supplied to the combustor. Further exhaust heat recovery can be used in a cogeneration configuration. Figure 16–1 illustrates a recuperated microturbine system. Fuel Cells

We now look at the basics of fuel cell technology, specifically solid oxide fuel cell (SOFC) technology. Many† gas turbine OEMs now have divisions developing microturbines, fuel cells (SOFC or otherwise), and hybrids. We will look at a specific OEM’s SOFC as follows: Siemens Power Generation is developing tubular SOFC technology with the support of the U.S. Department of Energy’s advanced fuel cell research program and the German Ministry of Economics and Labor (BMWA). Power Generation Tubular SOFC Technology

Siemens Power Generation’s Stationary Fuel Cells (SFC) division, as of 2006, is in the pre-commercial phase of its business plan and expects to have its first commercial product available in 2008. The Siemens Power Generation solid oxide fuel cell is made up of an electrolyte and two electrode layers in a unique tubular design. This design eliminates the need for seals required by other types of fuel cells, and also allows for thermal expansion. In a tubular SOFC design, air flows through the interior of the cell, and fuel flows on the outside of the cell. At elevated temperatures, the oxygen in the air ionizes and the resulting ions flow through the electrolyte and combine with the fuel on the cell’s exterior. This is an electrochemical reaction, so electrons are released. With proper connections, they can flow through an external circuit as electricity. The design of the stack is simple. It is cooled using process air, and during normal operation consumes no external water. It also has integrated thermally and hydraulically within its structure a natural gas reformer that produces the

† Source: [16-3] Courtesy Siemens Power Generation. Adapted with permission.


Air In


Turbine Exhaust

Air Filter

Compressor Power Shaft Generator


Power Conditioning


Recuperator System Exhaust (Heat Recovery)

Fuel Injection

Gas Compressor Gas Source

Figure 16–1.

A recuperated microturbine system. [16-2]

hydrogen and carbon monoxide utilized by the cell. Also, except during start up, no external heat source is needed. Siemens Power Generation’s first pre-commercial product will be the SFC-200 (Figure 16–2). This is a 125 kW SOFC cogeneration system, operating on natural gas at atmospheric pressure, with electrical efficiency of 44–47% at full load. An overall system energy efficiency of >80% is expected, assuming steam/hot water or other cogeneration. Hybrids

If a SOFC is pressurized, an increased voltage results, thus leading to improved performance. For example, operation at 3 atmospheres increases the power output by ∼10%. However, this improved performance alone may not justify the expense of pressurization, but what may is the ability to integrate the SOFC with a gas turbine, which needs a hot pressurized gas flow to operate. Since the SOFC stack operates at 1000°C it produces a high temperature exhaust gas. If operated at an elevated pressure, the exhaust becomes a hot pressurized gas flow that can be used to drive a turbine. If a SOFC is pressurized and integrated with a gas turbine, the pressurized air needed by the SOFC can be provided by the gas turbine’s compressor, the SOFC can act as the system combustor, and the exhaust from the SOFC can drive the compressor and a separate generator. This yields a dry (no steam) hybrid-cycle power system that promotes unprecedented electrical generation efficiency (Figure 16–3). During normal operation of the pressurized SOFC hybrid, air enters the compressor and is compressed to ∼3 atmospheres.

This compressed air passes through the recuperator where it is preheated and then enters the SOFC. Pressurized fuel from the fuel pump also enters the SOFC and the electrochemical reactions take place along the cells (Figure 16–4). The hot pressurized exhaust leaves the SOFC and goes directly to the expander section of the gas turbine, which drives both the compressor and the generator. The gases from the expander pass into the recuperator and then are exhausted. At ∼200°C the exhaust is hot enough to make hot water. Electric power is thus generated by the SOFC (dc) and the generator (ac) using the same fuel/air flow. Analysis indicates that with such SOFC/GT hybrids an electrical efficiency of 55% can be achieved at power plant capacities as low as 250 kW, and ∼60% as low as 1 MW using small gas turbines. At the 2 to 3 MW capacity level with larger, more sophisticated gas turbines, analysis indicates that electrical efficiencies of up to 70% are possible. Future of SOFC/Gas Turbine Hybrids

Numerous alternative SOFC/GT hybrid configurations under a Cooperative Agreement with the U.S. Department of Energy, National Energy Technology Laboratory have been studied. These studies have included hybrids with pressurized and atmospheric pressure fuel cell modules, turbines heated only by SOFC exhaust or also with supplemental duct heating and multiple, staged (cascaded) fuel cell/turbine reheat cycles. These studies have shown that while many different cycles offer considerable promise efficiency is maximized in a pressurized SOFC hybrid without supplemental firing, where the SOFC acts as the combustor for the gas turbine.


CHAPTER SIXTEEN Instrumentation & control system, electrical distribution

Power conditioning system

Heat export system

Auxiliary air system Process air system Steam & purge systems Fuel supply & desulfurization system Figure 16–2.

The SFC-200 will be the building block for systems up to 500 kW. [16-3]

For large scale applications (∼20 MWe) staged reheat cycles have indicated that electrical generating efficiencies could reach as high as ∼70%. These studies led to demonstrations of pressurized SOFC/GT hybrids in pursuit of these high electrical efficiencies. Through testing of a 220 kW and a 300 kW pressurized hybrid we

have verified the feasibility of the pressurized SOFC/GT hybrid concept. With these demonstrations Siemens have also demonstrated that the close coupled pressurized hybrids are quite costly, but because of their feasibility and potential further development is warranted.

Air Filter Turbine DC AC


SOFC generator

Power conditioning system

G Hot-gas turbine

Exhaust Recuperator/ fuel heater Desulfurizer

Figure 16–3.

SOFC/gas turbine hybrid cycle diagram. [16-3]

Natural gas



dc/ac inverter UPS

Fuel supply system

Gas turbine

Electrical cabinets

SOFC generator

Figure 16–4.

SOFC/Gas Turbine Hybrid System. [16-3]

Studies of hybrid cycles indicated that atmospheric cycles, while offering somewhat lower efficiency than pressurized cycles, would be less complex to develop and quicker to implement. Because they would require less integration of the SOFC and gas turbine, they have the potential to also be less expensive and could accommodate a wider variety of gas turbines. Further study of other SOFC/gas turbine hybrid cycles is planned to assess their potential. Further efforts are also needed on the part of government and industry to ensure the availability of appropriately sized small gas turbines. For pressurized hybrids especially, suitable mass flow, pressure ratio and other characteristics are necessary. Applications and Case Studies*

Grassroots design development is expensive and this field of small gas turbine systems providing distributed power lends itself to several OEM joint ventures and component supplier arrangements. Capstone turbine, for instance, uses a recuperator developed by Solar Turbines under the U.S. DOE funding umbrella. Ingersoll Rand (IR) formed an alliance with a division of Siemens to supply power to projects like the one described as follows: In September 2002, Ingersoll-Rand Company Limited (NYSE: IR) and Siemens Building Technologies, Inc. formed an alliance. Siemens thus integrated the Ingersoll-Rand 70-kilowatt and 250-kilowatt PowerWorks microturbine products to create a new offering—Microturbine Energy Systems. Recently adapted for end-user applications, Ingersoll-Rand’s microturbine technology functions as an on-site, micropower generation plant that can complement or supplement the user’s other sources of power. These systems utilize natural gas or other fossil fuels to produce small-scale electricity in the ranges of 70 kilowatts for a single unit, to 3 megawatts of capacity with multiple units. Exhaust heat from the microturbine can also be used to produce hot water or steam in a highly efficient combined heat and power (CHP) plant. * [16-1]

Case 1. Microturbine in a CHP Application**

A CHP application example (Oregon) follows. In 2004, Siemens contracted to design, build, operate, and maintain a Combined Heat and Power Plant (CHP) to serve Oregon Health and Science University’s (OHSU) new River Campus in Portland, Oregon. The CHP will provide OHSU with a clean, flexible, reliable and efficient source of heat and electric power. It will feature five natural gas-fired microturbines, which will produce all of the heat required by the facility, as well as 34% of its electric power. The CHP will serve Building One, a 400,000 square-foot facility that will house medical offices, outpatient surgery, research laboratories, a wellness center, an imaging center, conference center, retail outlets, and parking. It is the first building being built in the university’s expansion along the Willamette River in the new South Waterfront District. According to the U.S. Department of Energy, a CHP design will reduce the amount of fuel consumed by almost 40% when compared to a traditional fossil fuel-fired utility power plant and customer-owned boilers. In addition, OHSU estimates that CHP will reduce its CO2 emissions by roughly 9 million pounds per year. A chilled water production plant will serve the cooling needs of the building. Both the CHP and chilled-water plants will be integrated and controlled as a coordinated central utility plant. OHSU and its design and construction team are utilizing the U.S. Green Building Council’s LEED (Leadership in Energy and Environmental Design) rating system to gauge the sustainability of the project. OHSU’s goal is to achieve a gold LEED rating. Innovative features of the new OHSU facility, such as using rainwater to flush public fixtures and a internal bioremediator to treat waste, might just earn it LEED’s highest platinum rating. Siemens is helping OHSU to secure financial incentives for the CHP. State tax credits from the Oregon Department of **Source: [16-4] Siemens Power Generation.



Energy, combined with financial incentives from an Energy Trust of Oregon pilot project, contribute to making the project an effective choice for OHSU. Case 2. A Fuel Cell Application*

The target this DOE-sponsored partnership’s effort (Rolls Royce Allison and stack manufacturer) was aimed at producing between 3 and 30 MW units at under $1500/kW uninstalled. Interim progress is discussed. Work in this field continues. Rolls Royce is working with a molten carbonate fuel cell manufacturer to accelerate commercialization of a pressurized power generation package. The intent of the participants is to introduce stack and reformer improvements coupled with a new system integration approach to achieve a product with commercially competitive qualities. Cost-effectiveness and durability must be brought to fuel cell systems which already achieve high efficiency and low emissions. A key element of the program will be endurance testing in base load mode for extended periods. Stack performance will be tracked in order to assess the maximum useful working life of this high investment component. Load following generally requires careful management in fuel cell systems, typically because the stack/reformer system should be kept in a near-steady state environment. This will be demonstrated. Existing systems have usually been designed somewhat similarly to a chemical process plant, using off-the-shelf components. This approach leads to a highly predictable but *Source: [16-5] Courtesy of Rolls Royce. Extracts from S. A. Ali and R. Moritz, “A Prototype for the First Commercial Pressurized Fuel Cell System,” in Proceedings of the ASME Turbo Expo 2000, May 8–11, 2000, Munich, 2000-GT-551.

Recycle blower to present cooling as a small temp difference

excessively complex and costly system. System simplification and cost reduction efforts have been initiated, with a goal of a 3:1 reduction in the cost of the balance-of-plant. Preliminary results of this work are not available due to a delay in the start of the program. The cost reduction goal is to bring the plant uninstalled cost to less than $ 1500/kW. The projected costs of early commercial systems as currently estimated are almost twice this goal. Project Description

The baseline system to be tested in the evaluation program for performance and durability consists of three distinct modules: the power module, the mechanical module, and the electrical module. This is the configuration selected for most exploratory fuel cell plants. The primary purpose of this first system is to demonstrate stack life, performance, and operational characteristics of the new stack and reformer. The prototype system test bed configuration represents a more flexible but more expensive system than that required for a commercial product. A simplified schematic of the pressurized molten carbonate fuel cell (MCFC) test system is presented in Figure 16–5. The power module contains the fuel cell stack assembly, reformer, manifolds, and the anode (fuel side) recirculation ejector. The mechanical module includes all other major air and fuel gas management equipment including the turbo-machinery, gas desulfurization system, cathode recycle blower, valves, and interconnect piping. The third module, the electrical module, provides power conditioning, electronics, and system controls. High Temperature Fuel Cell Plants

The three fuel cell systems, studied by Rolls Royce Allison under the DOE High Efficiency Fossil Power Plants (HEFPP) conceptualization program, have the following major components in common:

Fresh cold air Cycle pressure

Diluted cooling air

Reformer is heated to run at higher temp than stack to function at pressure Natural gas + steam

1100 F Heat for reformation 1280 F

Gas + CO2

Catalytic oxidation of residual fuel

Exhaust ~

Bonus power

~ Figure 16–5.

Simplified pressurized MCFC. [16-5]

Turbogenerator is shown spread apart


Fuel cell stack Turbogenerator Power conditioning Electronic controls Fuel desulfurization

In pressurized systems, the fuel cells acts in place of a combustor for the turbogenerator. In the unpressurized system, the fuel cell is placed in the turbogenerator exhaust stream but also supplies heat and residual fuel to a heat exchanger acting as an indirect combustor. Additional major components for individual systems are: ● ● ●

1100°F heat exchanger (pressurized SOFC) 1600°F heat exchanger (1 atmosphere MCFC) 1500°F exchanger/reformer (pressurized MCFC)

Though each system has distinctive merits and challenges, a common problem is that each module is of high cost. The power module uses raw materials that are expensive and heavy, whether they are ceramic or nickel based. At present, each kilowatt requires 10–20 lbs. of active fuel cell and 10–20 lbs. of associated structure, or more than 15 tons of stack per megawatt. This ratio is considerably higher than for a simple cycle gas. The fuel cell active surfaces can provide a range of current density in which the delivered voltage (efficiency) drops as current rises but there is little scope for increasing the current per unit area at the high efficiency. It follows that the required route is to increase the active surface area in a given stack volume, a requirement very similar to that of producing compact high effectiveness heat exchangers. Figure 16–6 gives an indication of the comparative compactness of available fuel cells and heat exchangers. Stack pressurization is required in order to provide enough fuel and oxidizer gas to these compact active surfaces with low parasitic pumping loss. This is the primary reason for the belief that pressurized systems are the long term valid solution. Though more heat is released per unit volume of stack, it is carried away by proportionally more

gas, thus avoiding excessive temperature. Pressurization also offers important secondary gains, both increasing the power that may be drawn at a given level of stack efficiency and making it easier to convert cycle heat into electricity in associated turbomachinery (accounting for 10–20% of total system power), without using more fuel. A preliminary comparison of performance characteristics and rough order of magnitude cost of solid oxide and molten carbonate systems was conducted. The results indicate that near term (before 2010), the two offer a similar level of performance and technical challenges. The somewhat simpler system advantage of the solid oxide is offset by its often higher operating temperature. The lower cost of the balance-of-plant system for the SOFC tends to be offset by higher stack cost. The MCFC system’s pressurized reformer has to be supplied with an excess of steam in order to suppress carbon formation. This phenomenon poses a significant complication, and requires the continuous addition of treated water to the cycle. The higher operating temperature capability and the flexibility provided by a planar solid oxide stack arrangement indicates that the solid oxide system will dominate in the longer term. Over long term, the SOFC stack offers the following potential advantages: ● ●

the more durable chemistry compatibility of internal reforming with potentially high pressures at the higher temperature eliminating the need for excess steam.

An opportunity has been made available to partner with M-C Power in the pressurized MCFC programs. This opportunity represents the earliest possibility to launch a fuel cell hybrid product. Pressurized MCFC and SOFC systems will enable moving towards longer term aspirations of launching higher power density products. The intent is to introduce into operation the first in-service pressurized MCFC system. The plan is

Metal foam 20 ppi

Auto radiator area/2

1 cm Tube-in-Shell






Active area / Active volume, Figure 16–6.


Fuel cell vs. heat exchangers comparison. [16-5]





to participate in designing and developing the prototype systems, currently funded by the DOE MCFC Product Design and Improvement (PDI) program.

forward “chemical plant” style, with pipe work and valves linking and controlling the major processes. The mechanical module assembly, manufactured as prototypes with soft tools and jigs, requires a large number of pipes and valves. The components of the mechanical module alone cost more than the intended early production cost of the whole plant. This high system cost problem is being attacked to resolve it by a different approach. The plan is to modify the overall system operational control, and greatly simplify system integration. The following integration changes have been proposed:

Pressurized MCFC System Design

M-C Power gained considerable insight into the design and functioning of pressurized MCFC systems. This valuable experience was gained by running the plant installed at the Miramar Naval Air Station (test units ranging in size from 75 kW to 250 kW). This system is not a full hybrid. Although turbomachinery is used to turbocharge the system to about 3 atmospheres, no attempt is made to generate bonus electrical power with it. A plant design for the PDI program was developed by the M-C Power partnership based on the operating experience gained at the Miramar station. The PDI program incorporates a number of improvements:

● ●

● ● ● ● ●

power increased to 450 kW (improved stack mechanical and thermal design, and materials modifications) temperature stable reformer/catalytic combustor pressurization increased turbogenerator used for about 10% power bonus once-through steam generator (unattended) reduced footprint

The proposed PDI system analysis made it apparent that the cost of the system was very high as designed. The first reaction is of course, that the stack and reformer are determined to be expensive because they are complex parts produced on a “once-off handmade” basis. This was expected. There is a coherent plan to decrease their cost by an order of magnitude. The electrical module cost was based on offshelf power conditioning and power electronics components. The cost of this module represented a minor portion of the overall system cost. This is partly because good electronic control systems are very competitively priced and inverters are continuing to decrease in cost. What came as a surprise, however, was that the collection of pipes and valves in the mechanical module, specified to service the system, is the major cost challenge. Unlike the stack and reformer, the mechanical module is an assembly of standard, volume produced, components which are not likely to reduce cost. The PDI plant is configured in a fairly straight-


Figure 16–7.

The resulting system package which is closely integrated is sketched in Figure 16–7. Revised system cost estimates indicate that these changes decrease the total initial production plant cost (uninstalled) by 30% and the long term plant cost by 45%. Wide Application Fuel Cell Turbomachinery*

The DOE is urging the development of high efficiency hybrid fuel cell/gas turbine systems generating electric *


Comb’r / Heat Exchr

Fuel cell 1/2-stack


Simplified MCFC system. [16-5]

put all critical pipe connections inside the pressure vessel that houses the stack and reformer. air delivered from the intake compressor is discharged into the pressure vessel. the turbine is driven by the exhaust gases as they emanate and then pass to the external exhaust heat recovery unit. all other flow manipulation is accomplished inside the pressure vessel, and can therefore be handled in lightweight ducts (with small pressure differences across the ducts). small leaks are acceptable and this opens the way to using slip joints if necessary. eliminate motorized air/gas valves. Select and use the turbomachinery and its electrical loading to master flow control, probably aided by a waste gate system. provide an integrated turbomachinery package. Replace the present large low speed industrial hot recycle blower and its variable frequency drive and drive motor by a small high speed fan. The fan is driven by a free power turbine, using the same hot gas stream as the turbogenerator turbine.

Fuelcell 1/2-stack




power in the range of 20 to 30 MW. The long range plan is to enable these systems to serve the 21st Century power generation needs in the U.S. and globally. Fuel cell manufacturers, working on the High Efficiency Fossil Power Plant (HEFPP) program, examined a variety of fuel cell cycle arrangements reaching the level of efficiency specified. From this work, it is possible to draw a number of conclusions: 1. The attainment of 70% efficiency is challenging yet attainable, requiring improvement in stack efficiency, fuel utilization, and supporting system efficiency. 2. Turbomachinery is mostly configured as though for a recuperated cycle (compressor discharge flow supplied to stack and returned to turbine), with generator. 3. The required pressure ratio may be less than that available in high pressure ratio gas turbines. 4. Cycles may require intercooled compressors. 5. Supporting machinery flow size is relatively low, usually less than 50 lbs/sec of air being required for a 20 MW hybrid system. 6. Each stack module power output is much less than 20 MW, so plant may divide the total flow between multiple small turbines, perhaps 5 lbs./sec each, depending on modular concept selected. Suitable gas turbines are not available at this size. 7. Approximately 40,000 hours of base load operation poses a major challenge to small turbomachinery. To achieve this life, special bearings may be needed. 8. Turbine entry conditions are mostly limited by stack capability below level demanding blade cooling. What emerges from these preliminary system definitions above is the need for a turbogenerator with a minimum specification quite close to that of a “fuel cell flexible” (FCF) turbine. These turbines will be designed to a pressure ratio 4 to 8, turbine temperature 1700°F, recuperated and fitted with a generator. The flow size of emerging microturbines

High speed direct drive alternator

is limited to about 2 lbs./sec, but larger versions may follow. Using FCF turbines offers a big cost benefit because they are to be mass produced. Currently available microturbines fall short of the pressure ratio and mass flows indicated for maximum efficiency pressurized fuel cell systems. An optimum pressure ratio of 7 appears to be suitable for both SOFC and MCFC systems. This is a coincidental outcome, because the cycles are different due to diverse characteristics of active components of the molten carbonate and solid oxide fuel cells. Therefore, there is the possibility that a dedicated style of gas turbine should be developed, which could serve several types of fuel cell systems. Its specification is likely to be: Pressure ratio Turbine entry temp Flow size Stall margin Combustor Compressor Intercooler Ducting Turbine Bearings Adaptability

7 1700°F max 5–20 lbs./s Generous Start only One-stage radial None As if recuperated Two-stage axial Non-contact Scalable

This unit has the potential to serve as a high efficiency small turbogenerator if recuperated. By combining fuel cell and stand-alone turbogenerator market opportunities, it may be possible to provide a generous return on the initial investment, and minimize the fuel cell system cost. A schematic indicating the configuration of this gas turbine is presented in Figure 16–8. The design proposed in this figure represents an approach of a fuel cell flexible or fuel cell neutral turbomachinery.

2-stage axial turbine Magnetic bearings Radial Thrust 2-way

Radial compressor Heat block Figure 16–8.


Fuel cell flexible turbogenerator integration for low cost. [16-2]



The design approach represented for hybrid fuel cell systems is usually analogous to gasification systems and pressurized fluidized bed combustion systems. These approaches have tended to lead to expensive system configurations. At the bench-top level of fuel cell experiments, it was naturally convenient to use readily available components to build the pressurized systems. For pressurization, the most convenient source of mildly compressed air is a radial compressor driven by a synchronous electric motor. This type of pressurization requires no direct control of the overall system because the user can add motorized valves to select pressures and flows as required. Incorporating a fuel cell flexible gas turbine which is specifically designed to serve the needs of pressurized fuel cell systems would enable achieving these key benefits: ●

a fuel cell flexible gas turbine would help simplify operational control by minimizing high temperature ducting and a vast number of valves a fuel cell flexible gas turbine would also enhance operational stability of a fuel cell hybrid by controlling the generator loading, therefore spool speed in a single shaft machine it would also help improve the system load following capability the turbine would help minimize the fuel cell stack pressure and temperature fluctuations, by maintaining mass flow uniformity, resulting in uniform pressure and temperature distributions within the stack the operational stability of the fuel cell stack (facilitated by the FCF gas turbine) is necessary to achieve hybrid system life in the range of 40,000 hours under steady state base load operating conditions a gas turbine designed specifically to be compatible with fuel cell operating requirements would facilitate overall design simplification with system design simplification, both in the mechanical module and the power module, it would be easier to meet the system cost reduction goal specified earlier a FCF gas turbine would serve the needs of the various high temperature pressurized hybrid systems. Meeting this goal is important in order to reduce the cost of turbomachinery, since these are likely to be produced initially in comparatively small quantities a FCF turbine would impact favorably the cost of the mechanical module another important potential benefit of having a gas turbine designed specifically for fuel cells is the ability to ensure power quality of the system due to the fact that the entire system would have a tendency to operate with great stability. An operationally stable fuel cell hybrid system would allow the meeting high power quality requirements on a sustained basis a pressurized fuel cell hybrid system utilizing a performance optimized compatible gas turbine would derive other benefits such as the system’s ability to simplify the grid interconnect the system would be able to access grid interconnect directly to an AC power line. The Institute of Electronics and Electrical Engineers (IEEE) is developing an interconnect standards under the 519 code. It would be possible to couple the system to the grid through a properly designed gas turbine and a correspondingly compatible

electrical module. Such an approach would eliminate use of a DC load bank and a more complicated grid interconnect. the system incorporating several of the cost reduction techniques, would also have the capability to serve in the combined heat and power (CHP) mode it is necessary for these distributed resources systems to offer not only the electrical output, but also heat and cogeneration capability

The ultimate objective of the cost reduction and design simplification program is to reduce stack cost by at least 40%, and overall system cost by approximately 45%. These numbers represent the type of cost reduction from current levels required to achieve system costs of 70%. A relatively simple, low cost, turbogenerator will be the best option for fuel cell plant of up to approximately 10 MW hybrid capacity, supporting efficiencies >65%. The same gas turbine can serve as the core of a larger capacity turbogenerator for up to a 30 MW fuel cell plant. The turbogenerator to be designed on this project will be matched initially to serve the needs of a 1–3 MW hybrid plant. The unit will combine the following features:

The initial mass flow and pressure ratio requirements are based on the latest concepts of the fuel cell manufacturers for their hybrid systems. Some fuel cells start with larger flow requirements, both the solid oxide and molten carbonate fuel cells need 1 kg/sec/MW generated. Stack unit power is a consistent factor. Four major hybrid configurations are presented in Table 16–5. The data given are representative and will be reviewed with the fuel cell manufacturers to confirm their latest standards. The last cycle shown in Table 16–5 represents a more complex higher efficiency solid oxide system that requires a minimum of one module-pair (stacks operating in two different pressure zones). The solid oxide ambient pressure hybrid was not included in this assessment, because the system becomes economically unattractive in MW class range. Such a system would require a very high temperature recuperator. To date, fuel cell manufacturers have expressed limited interest in a SOFC ambient pressure hybrid system. The table contains the total airflow required for the various types of fuel cells, which is roughly the same for each system. Even more significant is that the higher flow requirements are also compatible with higher operating pressure ratio. This tabulation supports the notion that a properly designed single turbogenerator would satisfy all the high temperature fuel cell systems. The last cycle configuration points out that turbine reheat may be needed for this hybrid system. Using this preliminary data, a turbogenerator is being configured to provide 2.8 Kg/s airflow, work at a pressure ratio of 9 and accept 1000°C at turbine entry. Such a turbogenerator would serve all systems. It would be operated at part speed to lower its pressure ratio for the solid oxide systems. If used as a stand-alone module, the initial unit would develop 6 700

600 and




Baseline solid oxide hybrid system. Pressurized stack. Heat recovery by recuperation. Molten carbonate hybrid system. Pressurized stack. Heat recovery by recirculation. Molten carbonate hybrid system. Ambient pressure stack. Heat recovery by recuperation plus indirect residual fuel combustion Alternate solid oxide hybrid system with series modules. Pressurized stack. Recuperated

Improvements in Fuel Cell Hybrids

Joint studies with fuel cell manufacturers showed that an approach for fuel cell hybrid system design by merely assembling off-the-shelf components in a simplistic “chemical plant” manner, fails to achieve a marketable product resulting in a complex and expensive system. This experience suggests that, when a higher efficiency power plant is designed, requiring several of the available fuel cell stack modules, it will be preferable to use several of the same integrated modules rather than a farm of fuel cell stack vessels connected to a single turbogenerator and balance of plant. Five of the basic 2 MW modules can be packaged into such installations, to provide plant capability of up to 10 MW size. Fuel cell manufacturers are working to increase power density. It is anticipated that individual truckable modules will grow in power output (just as any other powerplant does). This improvement would cause the turbogenerator to grow also. The baseline turbogenerator will be operating at part speed for SOFC plant initially (to avoid exceeding the best cycle pressure ratio). The likely second generation SOFC plant temperature flexibility and acceptable pressure ratio should also rise. The turbogenerator can expand its capabil-

Table 16–6.

ity simply through speeding the unit up to design speed. This feature will probably accommodate 30–50% power increase. It is anticipated that the dynamics of the turbogenerator rotor with only two radial bearings will not be amenable to the addition of a “zero stage.” So further growth of this configuration will probably be achieved by geometrical scaling. The relative merits of designing to accommodate a zero-stage (possibly adding a third radial bearing) versus accepting the change through scaling, will be evaluated. Performance Comparison with Available Turbogenerators

There are several aeroderivative turbomachinery spools of approximately the same mass flow and pressure ratio as proposed. However, these fall short of the requirement specified earlier. The undesirable features of these aeroderivatives that need to be modified are: (1) contact bearings and rotating assemblies with many separate elements, (2) gear driven generators, (3) gas paths to be directly compatible with connection to the fuel cell system in place of the usual combustor, (4) expensive aviation hardware which offsets cost reductions that may accrue from volume production, (5) an older style design, using a combination of axial stages

Performance of the Proposed Turbogenerator and Derivatives [16-7]

Configuration Turbogenerator design pt Operation with PSOFC Operation with MCFC Stand alone at 1000 TIT As above + recuperator As above + reheat Recup. + cooled turbine

Airflow, Kg/s

Press. Ratio

Turbine Inlet, °C




Recup. Inlet, °C

Stack Temp., °C

Power, MW

Thermal Efficiency










































and a radial impeller to achieve the same duty served by an impeller alone. The proposed generator extends the range of high speed direct drive alternator products, from the 30–100 kW range (now being introduced in microturbines), to >0.5 MW. This is a significant technology enhancement step and is expected to be an important development in a continuing evolution to higher direct drive generation, which is paced economically by progressive decreases in power conditioning system prices. The improvements for fuel cell hybrids provided by the proposed system (see Table 16–7) are: ●

● ●

Much improved durability and reliability for the turbogenerator High pressure ratio (relative to micro-turbines) improves fuel cell hybrid efficiency Lower first cost, particularly as the turbogenerator production volume increases Easier integration into the fuel cell hybrid plant gas path Better environmental quality, both by eliminating oil usage and by maximizing plant efficiency Direct drive gives better cycle control during load following


The merits of a nominal 1 MW class stand-alone generator of direct drive design include local power quality improvement. Very low emissions (un-cooled turbine will be run at emissions-favorable temperature), low weight, good efficiency by recuperation or CHP (suitable exhaust temperature), and low noise and vibration, will make this unit a good candidate to displace many diesel generator sets. This would result in a large production volume. As fuel cell stack technology improves, and the power generated in a transportable modular unit increases, a need will develop for a turbogenerator having a higher unit flow capacity and power than the machine proposed. With this in mind, the turbogenerator design will be laid out, as far as is possible, for literal geometrical scalability, to facilitate low cost derivation. One product of the program will be the understanding of the extent to which this is feasible. Preliminary configuration studies are being conducted under contract DE-FC26-00NT40914 for the U.S. DOE. These incorporate cell manufacturer and DOE inputs to selection of the best duty cycle, and determine a mechanical design with acceptable dynamic and durability characteristics. Particular attention will be given to non-contact bearing selection and direct drive alternator design.

Market for the Turbogenerator


Based on experience in working with prospective fuel cell manufacturers, we have seen that the microturbines being developed for one sector of the distributed generation market are an enabling technology for very small fuel cell hybrid systems. But these are not big enough to serve a commercially attractive plant. The availability of the correct size turbogenerator with promises of good durability has been of great importance to early fuel cell hybrid designs. Some fuel cell hybrids have actually been designed to fit the available microturbines. With flexibility to serve a variety of the planned fuel cell hybrids, it is believed that an assured U.S. fuel cell hybrid market exists, arising with the success of fuel cells. There is promise that these small turbogenerators will support plant in sizes from 0.8 MW up to 12 MW through 2010 and beyond.

There is a need to provide a new high quality, low cost, long life turbogenerator to be compatible with hybrid fuel cell systems.

Table 16–7.

A Comparison of Performance of the Proposed Turbogenerator with Existing Units [16-7]

Manufacturer/ Model Proposed Baseline simple cycle unit Unit + recuperator Simple cycle existing ASE8-1000* Volvo VT600* P&W ST6L-795* Recuperated existing Capstone microturbine(1) GM404 Patriot (ISO day) *

Airflow, Kg/s

Press. Ratio

Turbine Inlet, °C







3.58 3.58 3.22

10.6 8.9 7.4

935 977 1000∼

0.27∼ 1.82

3.25∼ 4.3

880∼ 1020

Data taken from Gas Turbine World 1998–1999 Performance specs Used a metal regenerator rather than a recuperator From Capstone website ~Approximate **


1. There is a good possibility that a single machine can have wide applicability to the various U.S. manufactured fuel cell system modules anticipated. 2. Though individual module power may only be 1–3 MW, larger plant installations will probably use multiples of the base module, up to 10 MW. 3. The proposed turbogenerator will support some system power growth, but design evaluation is required to determine whether scaling is required to support growth beyond 50% power increase in fuel cells.

Recup. Inlet, °C


600∼ 700**

Stack Temp., °C

Power, MW

Thermal Efficiency







496 538 589

0.548 0.670 0.678

0.221 0.235 0.247

271(1) 313

0.028(1) 0.240

0.259(1) 0.315

Training and Education


“I was gratified to be able to answer promptly. I said I don't know.” —Mark Twain


Industry Training 638 Case 1. OEM Project Application Engineer Training 638 Training Programs within Academia 642 Case 2. Industry Supported Multimedia Aeroengine Design Case 644 Case 3. Theoretical Calculations Compared with Actual Cogeneration Plant Case 4. Undergraduate Engine Design Program 645 Case 5. Gas Turbine University Laboratory Study 653 Aircraft Gas Turbine Engine Experiment 654




With† the gas turbine developing at the rate that it does, education and teaching methods struggle to keep pace. This chapter provides specific examples and case studies of training and education in both the industrial and academic worlds. All cases are detailed with regard to program structure and content. However, in the hands of creative in-house trainers in industry or professors, they could suggest potential for creating one’s own tailor-made program. Industry Training

All OEMs offer some kind of training to their customers. These presentations can vary from “sales-type” commercial overviews to those that are considerably more comprehensive. The latter are generally given to customers who bought the OEM’s equipment, and the training is included in the price, in other words, “free.” In addition to theoretical courses, the OEMs offer practical training at the customer’s plant or in their own plants, with a very “hands-on” approach. This type of training is generally given to key mechanics, operators, and service crew. Independent firms, which frequently are owned and staffed by ex-OEM senior people, offer similar training. They point out that they offer a more objective perspective than an OEM might. The job titles given to engineers in field operations or field operations consulting are varied: Field service representative, field service engineer, applications engineer, field engineer, or simply OEM’s rep are common. Project application engineers is the term used by the OEM authors of Case 1. In some cases, that engineer is one that the OEM dispatches to solve field problems that an end user may have. In others, the engineer may be one who follows an individual project within the OEM’s walls, through all phases, including but not limited to initial customer specification, manufacture, testing, commissioning, and even optimization (also called streamlining or debottlenecking). These individuals are well equipped to then also serve the OEM as field troubleshooters. Depending on the corporate culture (OEM or otherwise) involved, a successful field service or project applications engineer may be moved to “technical sales” or marketing. In certain corporations, the senior officers have been promoted from these “nuts and bolts” beginnings. The following extracts were written by senior staff within an OEM’s organization. This OEM makes small- and medium-sized gas turbines, as well as associated packages for mechanical drive and power generation service. However, the template they provide is a sound one for all gas turbine OEMs and, in fact, all OEMs. Case 1.* OEM Project Application Engineer Training

Project application engineers (PAE) are a critical link between the customer and the OEM. His or her knowledge of both internal capabilities and the customer’s business make the PAE an important contributor in developing new projects. Despite the fact that this position can be an important and satisfying career path for engineers, its existence is widely unknown among engineering graduates. Therefore, a description of the tasks, duties, and challenges for project application engineers is provided. † [17-1] Working case notes, Claire Soares, 1975 through present. * Source: [17-2] Courtesy of Rainier Kurz. Extracts from R. Kurz and H. Andrade, The Training and Education of Application Engineers, 2005-GT-68097. (NB: Both authors work for Solar Turbines.)

We cover the training and education of application engineers for packaged industrial gas turbines. However, most of the concepts are applicable to application engineers for most engineered products. Packaged industrial gas turbines, especially in the oil and gas industry, consist of pre-engineered and customengineered components. The gas turbine and power turbine themselves are usually standardized products. The package components may, depending on the manufacturers philosophy and the project requirements, be either mostly pre-engineered with some customized components or mostly custom designed. The driven equipment may be standardized (such as a generator), or as for most compressors and pumps, either customized using pre-engineered components or entirely custom designed. The Job Description

The application engineer is the interface between in-house technical, commercial, and legal disciplines, on the one hand, and the sales force and ultimately the customer, on the other hand. The exact boundaries vary from company to company and also depend on the extent of project related special engineering (Figure 17–1). In-house technical disciplines include engineers specialized in equipment design, manufacturing and testing of the equipment, or the design of ancillaries and balance of plant items. They also include legal and commercial specialists. However, this should not be construed as the PAE being just a transmission vehicle. Rather, his knowledge of both internal capabilities and knowledge and the customer’s business make him an important contributor in developing new projects. Again, depending on company strategy, the distribution of tasks between the sales engineer and the project application engineer can vary. Ideally, they work in close cooperation as a team. Figure 17–2 shows the typical steps in the project cycle. The PAE supports primarily the selling process with his technical expertise and product knowledge. In this role, the PAE helps define the scope of the project, as well as the type and the features of the product offered. An important milestone in a project is the handover process from the business development organization (which sells and defines the product) to the business management organization (which is responsible to manage all necessary steps to execute the project). The project application engineer tends to stay involved during this time to make sure that the project is fully defined. Custom-engineered products, such as centrifugal gas compressors, require more involvement by the engineering organization, while standardized or pre-engineered products may be handled entirely by applications engineers, equipped with product knowledge and application guidelines. Typical projects include land-based power generation with simple cycle or combined cycle gas turbines, gas compression stations for pipelines, power generation, gas compression, and pump applications in offshore applications (Figures 17–3 through 17–5). In many cases, the scope includes not only the turbomachinery but also the ancillary equipment; balance of plant items may be included and, often, complex testing requirements as well as legal and commercial aspects have to be covered. To meet this rather broad requirement, the application engineer has to be able to communicate both with internal organizations as well as the sales force and with the



-Engineering -Gas Turbine -Compressor -Package -Balance of Plant -Manufacturing -Test

-Purchasing -Legal -Commercial -Engineering -Operations -Project management

-Legal -Commercial

Figure 17–1. The Project application engineer (PAE) as the interface between the manufacturer’s internal organization, the sales organization, and the customer’s organization. [17-2]

customer. This, in turn, requires that he or she understands the tasks, options, capabilities, and preferences of the internal organization. This is more than just “product knowledge” but rather the capability to think as if a member of a variety

Figure 17–2.

Project cycle (top) and steps (bottom). [17-2]

of internal organizations. This is the reason why a large number of application engineers have worked in one or more of the (usually technical- or commercial-oriented) internal organizations.



Figure 17–3.

Gas turbine application on an offshore platform. [17-2]

Figure 17–4.

Multiple gas-turbine-driven gas compressors in a pipeline compressor station. [17-2]

Another important task lies in the understanding of the customer’s business. Since turbomachinery products are bought by the industry in order to achieve commercial success, a good application engineer has also to understand the customer’s business (which is why sometimes application engineers are former employees of gas turbine users). In a sense, the task of acting as an interface between internal organizations and customers exists in a similar fashion for the project manager, who is responsible for the project execution in the order fulfillment process. Where to Find the Right People?

Obviously, the wide spectrum of knowledge and experience just described is not achievable without training and

education. There is—to our knowledge—no program in any U.S or European university dedicated to the professional development of application engineers. Nor would such a course be feasible without a close interaction between academia and industry. Even general descriptions of careers in the gas turbine industry sometimes omit the existence of application engineers. On the other hand, successful application engineers often come from the ranks of the technical or commercial (such as business management) disciplines within the companies whose products they are supposed to support. Another successful route tends to be people who worked operating or specifying the equipment in question. The “right people” are therefore not only defined by a predetermined education but rather by




Development of a scheme to measure applicant’s problem-solving skills.

Training Program

The complete self-paced training program must consist of individual modules with specific objectives targeting business applications. Still, for the training program to work, managers are recommended to promote initiative and assertiveness from all participants. The components of the training program follow and are described next: 1. 2. 3. 4. 5.

Figure 17–5. Power generation on an FPSO (floating production, storage, and offloading) vessel. [17-2]

a certain mindset, including good communication skills, the capability to learn the basics in new fields fast, the capability to work in a team and with limited supervision, the capability to work multiple tasks and prioritize, and a wide educational and professional background. Because most of the business in the gas turbine industry is international, it is of significant advantage for any application engineering organization to retain employees with a variety of language capabilities and cultural backgrounds. In this context, differences in the educational and business structure in different countries have to be understood. Development

The ideal application engineer in an ideal application engineering organization is a person with working knowledge in all facets of topics required to represent the product and in-depth knowledge in one or more of these topics. The ideal department has engineers such that at least one expert is available for any topic required. In many instances, the screening process comes as a result of months of internal networking searches for future candidates. Together with the networking efforts, managers can seek aid from the human resource personnel to develop a solid interview process. Areas of consideration for the development of a good interview process should be discussed and agreed upon. Points of reference follow: 1. Review of previous performance appraisal and interview supervisors and peers to determine the candidate’s track record. 2. Request for a writing sample. 3. Panel interview to target technical background and gauge interpersonal skills.

Self-paced modules. Hands-on training. Formal training. Project work. Progress review.

Self-Paced Modules If not already available, management must develop a list of applicable themes related to the industry and accountabilities related to the position. As an example, Figure 17–6 provides commercial and technical themes applicable to the turbomachinery industry. Each of these modules should be structured with a selfstudy outline covering related topics. An illustration detailing a typical module is provided in Figure 17–7. As noted in Figure 17–7, the module provides a list of the reference material to be reviewed and highlights the main points under study. In addition, the module topics can incorporate estimated times for completion. Introductory Modules (1–3 and 8) These first modules should familiarize newcomers with the organization and must be written to allow a smooth transition. Typical items covered in these sections should encompass a checklist to work logistics (credit card, phone card, cubicle location, etc), PC hardware and software, passwords (networks, programs, etc.), and provide direction to coordinate software application training. Technical Modules (4–7 and 9–11)/Commercial/ Legal Modules (12–14) As a minimum, the technical aspects should encompass areas related to product packaging, turbine and compressor theory, fuel suitability analysis, etc. This portion should be matched with specific areas of the business (i.e., customer services, balance of plant equipment, engineering, etc.). Other examples of technical areas to consider are listed next: ● ● ● ●

Fuel suitability analysis. Turbine and compressor performance guarantees. Packaging and controls theory. API and industry specification review and explanations. Auxiliary equipment.

In turn, the commercial modules must provide a full understanding of company’s policies from a legal and contractual perspective. Examples of commercial/legal topics to consider are denoted here: ●

Review of company’s policy of terms and conditions of sale exchange policy. Trade terms (incoterms).



Figure 17–6.

● ● ● ●

Training module list. [17-2]

Commercial tools (i.e., bank guarantees, bonds, letters of credit, etc.). Responsibility matrix. Credit rating policy. Department internal policies. Pricing policies.

At the end of the self-paced training, an application engineer must be able to develop an understanding for technical considerations from a commercial/legal perspective. In turn, the training process will allow for good decision making while managing risk. Hands-on Training A newly hired application engineer should spend several days in the workshop and test cells. The idea is to provide new application engineers with a better understanding of the product and present a global picture of the business. Typical areas for review during this portion of the training program are 1. Testing capabilities (i.e., ASME PTC 10, ASME PTC 22, American Petroleum Institute test requirements, etc.). 2. Manufacturing capabilities (product lines, shop lineup, lead- time factors, etc.). 3. Understanding of demand management functions. 4. Review of bill of materials, package maintenance, controls, etc. Formal Training Application engineering management must balance the preceding training with the company’s formal training program. For example, some of the areas useful to application engineers can be tied to human resources courses related to interpersonal skills:

● ● ● ● ● ●

Time management/organization skills. Negotiation skills. Communication skills. Technical writing course. Business management. Managing professional growth.

Project Work Depending on training progress, management must bring application engineers in direct contact with customer inquiry work from day 1. Application engineers can be exposed to these areas in a step fashion to start building their accountabilities. For example, a trainee can help a senior application engineer with budgetary proposals, help solve technical queries, and obtain exposure as an observer during technical clarification meetings. These tasks help trainees develop the required confidence to cope with the assigned work responsibilities. Progress Review Finally, a monthly status report must be completed to monitor the progress of trainees and obtain feedback on the effectiveness of the training program. The monthly status report should include a signed copy of the sections that have been completed during the given month. Training Programs within Academia

When† it comes to undergraduate engineering courses, standards vary all over the global map. However, the ease of †



Figure 17–7.


Typical training module. [17-2]

communications and especially the Internet is slowly closing gaps between curricula in different countries. At one point in the 1960s, universities (all universities) offered little more than a few ideal and theoretical cycle diagrams with equally theoretical heat balance calculations. If the university was fortunate enough to have well-funded labs, the practical equipment may have included a steam turbine, a diesel turbine, perhaps some car engines for the students to strip and reassemble. The first university/OEM joint educational accredited course venture in the United States may have been the University of Cincinnati/General Electric collaboration back in the 1920s. Their example was not one other U.S. universities were swift to follow but follow they eventually did. The early 1970s saw the start of a landmark program in the United Kingdom. In 1971, Dr. D.B. Spalding, then professor of Heat and Mass Transfer at Imperial College, London, England, conceived COBALT (computer based learning and teaching). He wanted experimental rigs constructed or modified to demonstrate the efficacy of prediction flow formulas. Experimental readings on the rigs were used in nontheoretical calculations and compared with the computer program results that iterated flow parameter values, starting with boundary layer conditions. The

program would thereby introduce masters’ level program material to second-year undergraduates. Some of those predictive flow formulas are still used in performance analysis (PA) systems, such as are described (in Chapter 10 on Performance Optimization) and designed 20 years later, so that earlier work is still current. That summer in 1971, I was one of two students hired to realize Spalding’s plan, and after the other became unavailable, the only one. The initial work scope I had been tasked with was finished in the summer of 1972. OEM/university joint ventures are still not quite as common as they could be. When they are in place, however, they benefit students greatly. University students may be able to complete some experiments that the OEM cannot perform more inexpensively in its own facility. This can and ought to be organized throughout the undergraduate degree program and, if possible, still earlier. With most gas turbines, simulators, flight or otherwise, are used to train plant operators, naval seamen, and pilots or “refresh” their own skills periodically. Schools and universities often cannot afford the investment that good simulators or real gas turbines (even small ones) require. They depend on donations and other help from industry (see the examples and cases that follow).



Today, students are lured into fields seen as more lucrative, such as law or business. Some engineers may soon realize that, if they want to make more money, they need to go back to school for an MBA. Of the few who stay loyal to the basic profession, still fewer may be attracted to the subdisciplines within the engineering field that need new blood. On the other hand, if somehow an engineering student gets a detailed enough look at the reality of operating turbomachinery when a student, his interest is often anchored for life. Employers find the “catch-up” time that fresh graduates take to come up to speed is then, reduced to a substantial extent. Engineering student recruiting numbers stand at low to dwindling. Robert Herbold (former COO, Microsoft) compiled the data in Table 17–1. All four Asian countries have four to eight times the per capita number of students going into engineering and China and Japan have four times and twice, respectively, the annual number of B.S. degrees in absolute terms compared to the United States. Consider also the numbers for students receiving Ph.D.s in physical science or engineering, shown in Table 17–2. Data sources indicate that the United States in 2005 graduated only 10%, in U.S.-resident engineer numbers that China did and 20% the number that India graduated. Many of those engineers will work for U.S. and European corporation branch offices without ever leaving their home country. Also, the total U.S. graduate engineer population is effectively halved because half of them are foreign and cannot get a work permit since the start of the U.S.Afghanistan war in September 2001. Given the current U.S. policy of exporting technical jobs to countries with cheap labor, the figures are not likely to change much in the near future. Many U.S. students argue that there is no future in engineering. The cultures in these countries that rival the United States for the globally available engineering jobs are more apt to place an engineer in a top management position than a lawyer or an accountant. For many years, Europe was similar in this regard. The “MBA-rules” perspective has taken over with some European companies, but it is still not as widespread as in the United States. To demonstrate the effectiveness as well as the “nuts and bolts” of specific academic programs, I have included some examples and case studies of academia’s efforts to bring the outside world and gas turbines into their classrooms. They provide excellent templates for ambitious professors and the potential for endless variations. The first example involves an industry (BMW-Rolls Royce and MTU Munich)-academia (Berlin University of Technology) joint venture in Germany. Table 17–1.*

United States China South Korea Taiwan Japan

Engineering Degrees

B.S./B.A. Degrees (000s)

B.S. Engineering (000s)

B.S. Engineering (%)

1253.0 567.9 209.7 117.4 542.3

59.5 219.6 56.5 26.6 104.5

5% 39% 27% 23% 19%

* Source:

Table 17–2.

Doctoral Degrees

U.S. citizens getting Ph.D.s Asian Citizens



4,700 5,600

4,400 24,900

Growth (6.4%) 345%

Note: Parentheses indicate negative growth.

Case 2.* Industry Supported Multimedia Aeroengine Design Case

The Jet Propulsion Laboratory at the Berlin University of Technology introduced an aeroengine design project, Project Jet Propulsion. The seminar, in which the German aeroengine industry is actively involved, is directed at students who have successfully finished their basic engineering training course. The objective of the course is to provide experience in all stages of the complete design process of an engine component in a genuine industrial working environment. The component is selected to ensure that a wide range of design requirements, including customer requirements, aero-thermodynamic and mechanical design, pricing and certification, must be considered. An experiment supporting the design completes the course. The course lasts for one year. Minutes are kept and action lists checked. The students are encouraged to work on their own. Industry participates with telephone conferences, giving their comments on the work of the group and answering questions, a video conference sometimes, and in-house OEM progress reviews at intermediate and final design stage. The incentive to start this program was prompted by the realization that Basic engineering education tends to produce engineers who know a little about many different subjects, while postgraduate and Ph.D. education tends to produce engineers who know a lot about a few subjects. Industry [used to] promotes this trend developing generalists who in the long run know nothing about everything and specialists who know everything about nothing…. Classical teaching has not changed significantly over the past 50 years. Most of the reforms introduced in this period of time have been concerned with the opening of the universities to a larger number of young people rather than with a quality improvement. The universities have little flexibility to adapt to a changing environment. The Germans are trying to remedy matters. The objective of the Jet Propulsion Project is to lead the students through the interdisciplinary process required to define and develop a gas turbine component or system. Several theory courses provide the background basics, including

*[17-3] Extracts from J. Hourmouziadis, N. Schroeder, K. Beigi, J. Schmidt, S. Servaty, and W. Gärtner, A Multimedia Aeroengine Design Course with Industry Support, 2000-GT-585.

T R A I N I N G A N D E D U C AT I O N ● ●

● ● ● ● ● ●

Thermodynamic cycle design. Component characteristics (intake, compressor, combustor, turbine, nozzle). Engine performance and partial-load operation. Engine systems (air, oil, control system). Measurement techniques (laboratory, engine). Experimental facilities. Certification requirements and procedures. Safety and reliability aspects. A course in turbomachinery aerodynamics presents

● ●

● ● ● ●

Short review of fundamental gas dynamics. 1D axisymmetric hub-to-tip and 2D blade-to-blade design (quasi-3D design system). Overview of CFD techniques and applications. Boundary layer theory and application to profile design. Secondary flows. Transsonic and supersonic cascade flow. A course on mechanical design and cooling teaches

● ● ● ● ● ● ● ●

Engine architecture alternatives. Hot and cold annulus diagram. Bearings and oil system design. Air system components (restrictors, seals) requirements. Design principles and analysis. Heat transfer and thermal control of engine parts. Thermal transients and clearance effects. Cooling methods and design principles.

The Jet Propulsion Project is an integrating course. One of the objectives is getting used to preparing a complete solution to a technical problem and presenting the results in a team. The participants have to communicate data, technical, and time scale information and learn how to behave in a team to achieve a common goal within schedule constraints. The objective of the first phase, which lasts about one third to one half the course, are as follows: ●

Provide the necessary background information, like requirements, performance data, design constraints, etc. Preliminary study of alternative solutions, evaluation, and selection of realistic configurations. One may be selected after a review. Preparation of a plan and schedule for the second phase. The second design phase includes

● ● ● ● ●

Mechanical design. Failure analysis. Material selection, stressing, and lifing. Development and certification program. Costing of engineering work and costing of product.

The last meeting is a final design review at a supporting company. The course is finished with a final report and an evaluation of the course by the students. Two problems treated by the Jet Propulsion Project were the design of an HP-Compressor bleed system for a twospool turbofan (1997/98) and the design of an LP shaft failure protection system for a turbofan engine (1998/99). The results from this project included student-designed items that were “industry ready.” One is described next. Two electronic systems for an emergency fuel shutoff were investigated. The first uses two shaft speed gauges, one on the fan end of the shaft and the other on the LP turbine


end. The signal difference is used for actuation. The second system uses the LP turbine speed gauge and responds to the acceleration rate of the rotor. To determine if the signal is sufficiently fast, transient performance of the engine was analyzed. It was found that acceleration rates after shaft failure is several orders of magnitude greater than in normal operation. Both systems require a speed gauge in the “hot” part of the engine. System accuracy ensures that no undesirable fuel shutoffs occur. The system using the rotor acceleration rate appeared preferable, because it uses only one speed measurement and is therefore more reliable. To reduce response time, the students came up with digital electronics for a faster evaluation of the signal than in current systems. This proved to be of major importance for the response time. To support this evaluation, experiments were performed in the laboratory with three speed gauges and the signals were analyzed in the time domain to define the requirements on the electronic treatment. The investigations ended with a final assessment of the sequence of events after engine failure and the resulting turbine overspeed. This required an analysis of the dynamics of the system and the engine during and after fuel shutoff, when the HP rotor feeds energy back into the core mass flow. Three out of four systems satisfied the FAA requirements, so no extra overspeed capability has to be designed into the LP turbine disc design. Since all the systems investigated were new, tests were needed as part of the compliance with the FAA certification requirements. The students produced an engine development plan lasting two years, which used eight engines. Case 3.† Theoretical Calculations Compared with Actual Cogeneration Plant

In another project, the Royal Institute of Technology in Sweden ran a program, assisted by ABB Stal. The students chose an optimum design configuration for a cogeneration application and then were able to visit the actual plant and compare their own work with ABB Stal’s choices. Table 17–3 indicates how close they came. The following two cases* are courtesy of K.W. van Treuren, Baylor University. As with most gas turbine academics, he is keen to spread the word on gas turbines and he has presented his work at different venues, including IGTI conferences. The first case involves using commercial software and spreadsheets for gas turbine design that accommodates a flight mission profile. The second is work on a land-based gas turbine that the university was given to work on, in its laboratory. The starting point for the first case was the U.S. Air Force Academy (USAFA). The USAFA program was adapted for use at Baylor University in Texas. Case 4.* Undergraduate Engine Design Program

A unique, three-part undergraduate gas turbine engine design project was developed to acquaint students, †

[17-4] Courtesy of Alstom Power. Reference S. Svensdotter, P. Almqvist, and T.H. Fransson, Introduction of Project Based Learning for Designing and Heat and Power Plant into the Last Year Curriculum, 2000-GT-583. *Source: [17-5] The work of K. W. van Treuren, including extracts from K. W. van Treuren and B. A. Haven, Undergraduate Gas Turbine Engine Design Using Spreadsheets and Commercial Software, IGTI 2000-GT- 587.



Table 17–3.

Comparison between the Model Plant and the Result of the Students, Major Components [17-4]

Item Gas turbine Steam turbine Pressure levels Waste heat boilers Supplementary firing Bypass Transformer


Student Result

2 × 23.7 MWel (ABB GT 10B) 1 × 27 MWel (ABB V40AHH) 2 levels 2 10–100% Yes 2 × 40 MVA for 110 kV

2 × 25 MW (ABB GT 10) 1 × 24 MW (ABB VAX HP 16) 70 bars, 7 bars 2 Up to 100% Possibility to add For 3 transformers for feeding the electric grid

working in teams of two or three, with the process of engine cycle selection. The design application is a low-flying, close air support (CAS) aircraft using a separate exhaust turbofan engine. Both spreadsheets and commercial software are used. The commercial software is included with the course textbook, Elements of Gas Turbine Propulsion, by Dr. Jack D. Mattingly. Using commercial software, reinforced by classroom lectures, allows the students to focus on the design decisions. The first part of the project is mission analysis, which introduces the student teams to the design problem. A spreadsheet template is given to each student team that includes aircraft and mission profile specifications. The students must complete the spreadsheet and develop the relationships for lift, drag, thrust required, and fuel burn to calculate a useable fuel remaining at the end to the mission. The spreadsheet allows the students to obtain an average specific fuel consumption that results in 1500 lbm of fuel remaining at the end of the mission. This target value is used in the second part of the design process, on-design parametric cycle analysis (PCA), as a basis for engine cycle selection. Parametric cycle analysis is accomplished using the program PARA.EXE. PARA.EXE generates a carpet plot of possible engine design choices by varying the compressor pressure ratio, bypass ratio, and fan pressure ratio. From these carpet plots the students must identify three possible engine cycles that meet the target value for specific fuel consumption found during the mission analysis. Trade-offs between thrust and fuel consumption are discussed, and the students are required to justify their choices for the engine cycle. The last part of the project is the off-design engine performance analysis (EPA) using the program PERF.EXE. The chosen engines must fly the mission and meet the required performance and mission constraints. Based on the overall mission performance, the students narrow the field of three possible engine cycles to one. Each student team then does a sensitivity study to determine if there is an additional benefit for slight changes in the design choices. The result of this sensitivity study is the students’ final engine cycle. With this cycle, an additive drag calculation is made using the program DADD.EXE to account for losses (off-design) and these losses are then factored back into the performance spreadsheet to check the engine’s capabilities for completing the mission. The iterative nature of the design process is emphasized throughout, but only one pass through the process is accomplished. Units are given in English Engineering, as that is what is required for the project.

Both SI and English Engineering units are taught in the course. Nomenclature

CD CL Dadd F F/m·

= = = = = k =

m· = m·f = S = T = TO = TSFC =

drag coefficient. lift coefficient. additive drag, lbf. uninstalled thrust, lbf. specific thrust, lbf/(lbm/sec). drag due to lift factor for given wing planform. mass flow rate of air, lbm/sec. mass flow rate of fuel, lbm/sec. uninstalled specific fuel consumption, (lbm/hr)/lbf, (m·f/F). installed thrust, lbf, (F–Dadd). takeoff. installed specific fuel consumption, (lbm/hr)/lbf, (m·f/T).


πf πc α ϕ

= = = =

fan pressure ratio. compressor pressure ratio. bypass ratio. installation loss coefficient (Dadd/F).

The need for design in an engineering curriculum is further emphasized in the recent engineering criteria (EC) 2000 developed by the Accreditation Board of Engineering and Technology (ABET). The design described next is not a capstone design experience but is meant to emphasize the conceptual design portion of the process. For the engineer, this is often thought of as creative problem solving. The problem can be defined in great detail or may be something very ill-defined. Whatever the detail, the engineer must develop an acceptable solution that satisfies the requirements. This process of arriving at an acceptable solution uses the cyclical nature of the design process as seen in Figure 17–8. Here, engineers use all their mental faculties to be creative with ideas, analyze the ideas, and then decide on their relative merit, as is shown in Figure 17–9. This often leads to more ideas to be evaluated and further decisions that must be made. Eventually, the engineer repeats this cycle many times until an acceptable solution is determined, as shown in Figure 17–10.


Figure 17–10. Figure 17–8.

Design spiral (Brandt 1997). [17-5]

The design wheel (Raymer 1992). [17-5]

The project described in this section acquaints the students, working in teams of two or three, with the process of engine cycle selection and reinforces the design decisions necessary for the conceptual design of a gas turbine engine. Cycle analysis, according to Oates (1988), is the process to obtain estimates of the performance parameters (primarily thrust and specific fuel consumption) in terms of design limitations (such as maximum allowable turbine temperature), flight conditions (the ambient pressure and temperature and the Mach number), and design choices (such as compressor pressure ratio, fan pressure ratio, and bypass ratio). With these goals in mind, the initial development of the project was accomplished at the U.S. Air Force Academy by Lt. Col. Brenda Haven and has been subsequently adapted for use at Baylor University in an elective course on propulsion systems for mechanical engineers. The degree program at Baylor University is a more traditional undergraduate B.S. in Engineering with a mechanical or electrical emphasis. Baylor does not have a graduate engineering program, but approximately 13% of the students take additional study at other institutions and receive advanced degrees. Approximately 10 students take this course in the fall of their senior year. Mechanical engineering students often have a keen interest in aerospace topics. This project reinforces that interest and presents the complexities of designing a gas turbine engine. Prerequisites for this course are fluid mechanics and an advanced course in thermodynamics. Heat transfer is taken concurrently. Propulsion systems are presented as an application of these fields.

The project has great value in light of ABET EC 2000. Teamwork is strongly emphasized as the students work in teams of two or three. Student teams are thought of as industry competitors. They are allowed to work with their partner and the professor but not allowed to talk with other students about the details of their project or use material from previous semesters. At the end of the course the student teams present their design and discuss its performance. After each team presents its results, the class decides on the “winner” of the competition. A final, written report is also required, thus exposing the students to both written and oral presentation. Higher-order thinking skills are developed, as the students must conduct multiple paper studies of various engines and make engineering trade-offs. While there are many solutions, the desire is to optimize the results for the “best” solution possible. In the process of selecting the engine, the students are using design tools such as spreadsheets and performance analysis programs. The design project is accomplished in three parts. Basic physical concepts and analysis techniques required by the design process are emphasized throughout the course and provide the basis for these parts. The first part is a mission analysis, which introduces the student teams to the design problem. The request for proposal (RFP) calls for an aircraft to fly the close air support mission. The students are given the requirements for the mission and need to determine lift, drag, thrust required, and fuel burn at each mission point. The next part is the parametric cycle analysis, where the


Associative Creative Creative Mind (Right Brain)

Deductive Analytic Judicial Mind (Left Brain)

Figure 17–9.


+ No rules + Uncritical +Irrational +Illogical +Divergent +Alternatives




Mental activity in the design cycle (Brandt 1997). [17-5]

+Rigid rules +Critical thinking +Rational +Logical +Convergent +One answer



students are required to select the design choices for the engine cycle after comparing potential engine performance at the chosen engine on-design point. The last part of the design process is the engine performance analysis, where the chosen engine is “flown” off-design to see if it satisfies the mission requirements. After the engine is shown to meet these design requirements, an additive drag calculation is accomplished and the engine run again to determine if the engine still satisfies the design requirements. This last check of performance emphasizes the iterative nature of the design process. Mission Analysis

The first part of the project, mission analysis, introduces the student teams to the design problem. The students are placed in the scenario of being young propulsion design engineers working for a contractor. Their task is determining a suitable engine cycle for the USAF’s next generation two-engine, thrust vectoring, close air support aircraft. This part of the design process is the conceptual design phase, where engineers, logisticians, and technical support team that includes aircraft and mission profile specifications (see Table 17–4 for completed spreadsheet). The students must complete the spreadsheet and develop the relationships for lift, drag, thrust required, and fuel burn to calculate a useable fuel remaining at the end of the mission. The design constraint for this mission is the aircraft must land with 1500–1510 lbm of useable fuel remaining after engines are shut down. The students are led through an algorithm for this analysis (see Figure 17–11). Not all necessary information is available at this time, and the students must use an average specific fuel consumption that results in required fuel remaining at the end of the mission. Class time is used to review the RFP to ensure the students know what is required. The mission presented is a simple mission as given in Figure 17–12. The mission profile consists of the following mission legs: 0–1 Warmup/Taxi, 1–2 Takeoff, 2–3 Climb, 3–4 High Cruise, 4–5 Descent, 5–6 Combat, 6–7 Low Cruise, and 7–8 Landing/ Taxi. Guidelines for fuel usage are given in the RFP. Standard percentages for fuel used are given for all legs except the High Cruise, Combat, and Low Cruise legs. These are the legs where the team must determine the amount of thrust required for the aircraft. The aircraft is expected to combine some of the best features of the A-10 and AH-64 platforms, including survivability, lethality, efficiency, and maneuverability, while being cheaper, lighter, and more versatile in extreme weather. Thrust vectoring only occurs at the combat condition and the vector angle is 45°. The aircraft loiters for 100 minutes at the combat conditions and then expends its ordinance. The aircraft specifications are given in Table 17–4. These values are programmed into the spreadsheet template that each student team is given. Students then develop the drag model and ultimately calculate the uninstalled thrust. A separate exhaust turbofan has been selected as compressor pressure ratio, fan pressure ratio, and the bypass ratio. The designers are required to calculate the uninstalled thrust, F, and the uninstalled specific fuel consumption, S. To relate these quantities to their installed counterparts, T and TSFC, the teams use a first “guess” for the installation loss coefficient, ϕ or PHI, as given in Table 17–4. Fuel-used calculations for cruise legs are made with a user input value of S. The spreadsheet is developed in such a way as to allow an update of the engine performance S values at the off-design condition, when this analysis is accomplished later in the design process. A sample spreadsheet with example val-

ues is given to the students so they can validate their spreadsheet formulas for accuracy. However, the numbers given do not represent a viable engine solution. To satisfy the first phase of the conceptual design process, Design Project I, the team must deliver a written report containing: 1. A working spreadsheet. 2. Information on current technology medium/highbypass turbofan engines (i.e., provide typical values for specific thrust, specific fuel consumption, engine diameter, πc, πf, α) for attack aircraft. 3. A discussion of the purpose of doing a mission analysis. 4. The complete mission description. 5. Full and complete discussions of the equations used in the spreadsheet and their corresponding assumptions. 6. The average S needed for the mission and what drives the selection of average S. 7. The effect of installation losses on engine thrust required and specific fuel consumption. 8. A selection and discussion of the engine “design point.” Several skills are used in this part of the exercise. The students use spreadsheets for calculation. While a template is supplied into which equations for lift, drag, and uninstalled T and TSFC are coded, the students still must develop and validate their equations in the spreadsheet. The spreadsheet equations also make use of basic principles learned in fluid mechanics and aerodynamics, reinforcing the concepts of lift, drag, thrust, and fuel consumption. Next, the students must research current technology engines of this size. They are shown the importance of historical data from which to make projections for future technology capabilities. Parametric Cycle Analysis

The second part of the design project is to accomplish the on-design parametric cycle analysis. Mattingly et al. (1987) state three reasons for PCA: First, off-design analysis cannot begin until the design point and the size of the engine have been chosen by some means. On-design analysis is much less tedious and time consuming than off-design, often providing mathematical optima that can be directly exploited. Third, and most important, identifying the combinations of design choices that provide the best performance at each mission flight condition reveals trends that illuminate the way to the best solution. Computer labs introduce the students to each of the commercial programs used: PARA.EXE and PERF.EXE. In the lab, the students are given a self-paced tutorial worksheet to familiarize themselves with the operation of the program. This has worked remarkably well as PARA.EXE is a Windows-based program and is menu driven. The program calculates the on-design cycle performance that was previously discussed in class. In the Design Project I handout, the students are given a discussion of how to generate data and how to present data using a carpet plot. A second page explains how to import the data into a spreadsheet and then create the plot. PARA.EXE calculates engine performance and generates the data. The carpet plot displays possible engine design choices that result from varying the

Table 17–4.

DESIGN PROJECT - Part 1: Mission Analysis [17-5]

Aircraft Specifications

Mission Specs: Number of Engines:


Ordinance (Ibf):


0-1 Warmup/Taxi

Dry A/C Weight (Ibf):


1-2 Take Off

Altitude ft

Density Ibm / ft3

Temp R

Mach no.

Velocity (ft / s)

Time (minutes)




























Usable Fuel (Ibm):


2-3 Climb

Parasite CD:


3-4 High Cruise


4-5 Descend


Wing Area (ft )


5-6 Combat










6-7 Low Cruise















k: 2

TO distance (ft):





7-8 Landing/Taxi





Mission Particulars:


Fuel Used (Ibf )



T Required (Ibf ) per engine

TSFC (Ibm / hr)/Ibf

F Required (Ibf )per engine

Average S: (Ibm / hr)/Ibf































High Cruise






























Low Cruise





















A/C Weight @ New A/C Weight start of leg (Ibf ) (Ibf )





Select Average S

Warmup/Taxi Fuel Used

High Cruise

New Aircraft Weight

Aircraft Velocity

Descent Fuel Used





Fuel/Ordnance Used

New Aircraft Weight

New Aircraft Weight

Takeoff Fuel Used

New Aircraft Weight


Climb Fuel Used

Low Cruise

New Aircraft Weight


Final Aircraft Weight

Fuel Remaining within limits Yes

No End

Notes: 1.

means execute the dashed-boxed routine and return.


means you must iterate on a solution for the combat phase.

Figure 17–11.

Algorithm for mission analysis. [17-5]

Figure 17–12.

Mission profile. [17-5]

compressor pressure ratio, bypass ratio, and fan pressure ratio (see Figure 17–13). This is a parametric study of the three design variables available to the turbofan designer; πf, π.c, and α, and observation of the trends in specific thrust, F/ m, and specific fuel consumption, S, as the design variables are changed. The program PARA.EXE, developed by Dr. Jack Mattingly, is used to input the on-design conditions and output the F/m. and S for variations in the design choices. The results allow the design teams to narrow the field of possible engine designs. The students are given a range of values for the design choices that must be explored, as reported in Table 17–5. . A carpet plot shows how F/m and S vary for a given πf, and variable πc and α. Plots are generated for the range of πf. For each πf value, the design team must determine

combinations of πc and α that might satisfy the maximum average S requirement determined from the previous Design Project I exercise. Drawing a horizontal line on the carpet plots corresponding to the maximum allowable average S does this. Based on these plots, the teams have now identified many different engines that have the same value of S at the design point (albeit different values of πc, πf, and α), with this value equaling the average S calculated from Design Project I. Each possible engine design might meet the mission requirements, although it is still too early in the design process to tell for sure, as the analysis is incomplete without an off-design calculation. The students must choose the final engine cycle after carefully considering the trade-offs required. The students must also justify their answer by looking at factors such




Carpet Plot for πf = 1.2; F/m vs. S


πc = 10


πc = 15

1.1 α=7

S (1/hr)


α=8 α=9


α=1 α=4 α=5 α=6



πc = 20 πc = 25 πc = 30 πc = 40


0.7 0.6 0.5 0.4 0








F/m (lbf / lbm /s) Figure 17–13.

Table 17–5.

Typical carpet plot. [17-5]

PCA Range of Design Choices [17-5]

Design Choice



πc α πf

10–40 1–9 1.4–2.3

10 1 0.3

as pressure rise per stage, number of stages, cost, weight, size, etc. After generating the carpet plots, the students must identify three possible engines that will satisfy the mission constraint of 1500–1510 lbf fuel remaining at the end of the mission. Trade-offs between thrust and fuel consumption are discussed, and the students are required to justify their choices for the engine cycle based on their knowledge of technology, performance, cost, etc. Class time is devoted to going over the Design Project II handout and parametric cycle analysis. During this part of the design process, the teams begin to explore the vast number of possible turbofan designs that might encouraged to use the combat loiter flight condition (M = 0.4, altitude = 200 ft) as the on-design point. Since the aircraft will spend about 70% of the mission time at this condition, this is a logical candidate. The requirements for Design Project II are as follows: 1. Justification for doing a PCA. What does it reveal, in general? 2. The significance of picking an on-design point. Why is an on-design point needed? 3. Inclusion of Design I mission analysis and how it relates to PCA. . 4. Physical explanations of the trends in S and F/m when each of the three design variables are changed.

5. Selection of three engine designs (unique combination of πc, πf, and α) that meet the maximum average S requirement. Also required is a discussion of the justification with regard to size, potential cost, unique technology requirements, etc. Design Project I is intended to be an introduction to Design Project II as well as part of the final report (Design Project III). Previous spreadsheet errors should be corrected by now. Students are encouraged to begin collecting a list of figures, nomenclature page, references or documentation, etc. as they go. They also should include a closing statement/ paragraph regarding how this PCA effort will provide the foundation for the next step in the design process, engine performance analysis. Engine Performance Analysis

The last part of the project is the off-design engine performance analysis accomplished on the three engines chosen in Design Project II. The chosen engines must “fly” the mission and meet the required performance and the mission constraints. The EPA is conducted using commercial software PERF.EXE. The on-design file from PARA.EXE is input into PERF.EXE and Figure 17–14 shows the algorithm for each cruise condition. For the chosen engines, the off-design values of the uninstalled specific fuel consumption, S, at the two cruise legs and the combat leg will be input into the mission analysis spreadsheet written in Design Project I. A final selection of the best engine and a justification of this choice is required. By comparing the different fuelremaining values generated for each engine, along with relative knowledge of engine technology, cost, reliability, weight, materials, and size, the student teams refine the engine design for the aircraft and decide on a final engine configuration described by a unique set of πc, πf, and α values. The output of the spreadsheet program, as previously discussed, will be a final fuel-remaining value for the


CHAPTER SEVENTEEN Input engine cycle data into PERF Run an off-design calculation for each cruise leg and the combat leg at the required thrust

Save data as a reference file

Input S values for each cruise leg and the combat leg into the Mission Analysis spreadsheet

Run a single point calculation at the takeoff condition Note the fuel remaining Size the engine

Figure 17–14.

Algorithm for EPA. [17-5]

engine/airframe combination. Using this selected engine, the students do a sensitivity study to determine if there is an additional benefit for slight changes in the design choices. Five additional engines are run to determine if the selected design choices are optimum (see Figure 17–15). From the fuel remaining vs. bypass ratio plot and relative knowledge of cost, technology, etc., the design team chooses one engine (a combination of πc, πf, and α) to satisfy the RFP. This engine must lie on one of the two πc lines from the sensitivity analysis, it must meet the fuel remaining limit (no more, no less than 1500 lbf), and it will most likely require linear interpolation to determine the appropriate. The design team must then take this new engine, size it, and run the mission spreadsheet with the new S values to ensure the final design will satisfy the requirements. As a final step, a calculation is made to determine the actual additive drag of the chosen engine at the takeoff, high cruise, combat, and low cruise mission legs. To do

Fuel Remaining vs. Bypass Ratio Separate Exhaust Turbofan πf = 2.0

Fuel Remaining (lbf)




6 1500

2 5

πc = 10 1450



πc = 20

1400 0

Figure 17–15.


4 6 Bypass Ratio

Sensitivity study. [17-5]



this, the program DADD.EXE is used. This program uses the PERF.EXE results at the different mission legs. The students also perform one hand calculation at the takeoff condition for verification purposes. The program DADD.EXE will ask for on-design and off-design values of the Mach number, altitude, and mass flow. Once the additive drag is calculated, the new values for ϕ are input into the mission spreadsheet and the fuel remaining is recalculated. Students discuss how good the original assumptions were for additive drag and what the impact on the final design is. The next step, iteration, is discussed but not required for this project. The iterative nature of the design process is emphasized throughout the course but only one pass through the process is accomplished. The students must deliver a final design report incorporating Design Projects I and II with the following new information added: 1. A general discussion which answers the “What is it?” and “How is it done?” of EPA. 2. A summary table listing the results of the EPA for the chosen engine. Include values of πc, πf, α, S (at each cruise/combat condition), and the amount of fuel remaining at the completion of the mission. 3. A plot of fuel remaining vs. bypass ratio, along with a complete explanation of the observable trends in fuel remaining as functions of πc and α. 4. A table for the additive drag. Comment on how close the estimated values are to the calculated values. How do the calculated values affect the fuel remaining? If the fuel remaining decreases due to the higher additive drag, what might the designer do? 5. Strong justification for why the chosen engine should be produced. 6. Computer/spreadsheet output that provides the supporting information for all plots, tables, figures, calculations, and numerical results. Again, a variety of skills are used to arrive at the finished product. Written skills are present with the final


design report. Students had the benefit of feedback on their writing skills for Design Projects I and II. An oral presentation is given at the close of the project, giving important performance parameters and a justification for why their engine is the best. After all students have presented their engines, the class determines which engine should be declared the “winner” of the competition. The students used a variety of tools, including spreadsheets and commercial software, to aid in their design analysis. They made difficult choices concerning the trade-offs associated with design of gas turbine engines. A sense of accomplishment is evident in their confidence when they complete the course. References for Case 1

Oates, Gordon C., 1988. Aerothermodynamics of Gas Turbine and Rocket Propulsion. Washington, DC: American Institute of Aeronautics and Astronautics, Inc. Mattingly, Jack D., 1996. Elements of Gas Turbine Propulsion. New York: McGraw-Hill, Inc. Mattingly, J.D., Heiser, W.H., and Daley, D.H., 1987. Aircraft Engine Design. New York: American Institute of Aeronautics and Astronautics, Inc. Brandt, S.A., Stiles, R.J., Bertin, J.J., and Whitford, R., 1997. Introduction to Aeronautics: A Design Perspective. Reston, VA: American Institute of Aeronautics and Astronautics, Inc. Raymer, D.P., 1992. Aircraft Design: A Conceptual Approach. Washington, DC: American Institute of Aeronautics and Astronautics, Inc. Case 5.* Gas Turbine University Laboratory Study

An important part of teaching a gas turbine course is exposing students to the practical applications of the gas turbine. This laboratory proposes an opportunity for students to view an operating gas turbine engine in an aircraft propulsion application and to model the engine performance. A Pratt and Whitney PT6A-20 turboprop was run at a local airfield and engine parameters typical of cockpit instrumentation were taken. The students, in teams of two, then modeled the system using the software PARA and PERF in an attempt to match the manufacturer’s specifications. This laboratory required students to research the parameters necessary to model this engine that were not part of the data set provided by the manufacturer. The research and modeling encompassed areas such as technology level, efficiencies, fuel consumption, and performance. The end result was a two-page report containing the students’ calculations comparing the actual performance of the engine with the manufacturer’s specifications. Supporting graphs and figures were included as appendices. The same type laboratory could be adapted for cogeneration gas turbines. Over 121 colleges and universities have cogeneration facilities on campus and that presents a unique opportunity for the students to observe the operation of a land-based gas turbine used for power generation. A 5 MW TB5000 manufactured by Ruston (Alstom) Gas Engines is available on the Baylor University campus and is highlighted as an example. Potential problems encountered with using the Baylor University gas turbine *Source: [17-6] The work of K. W. van Treuren, including extracts from K. W. van Treuren, “An Application Oriented Gas Turbine Laboratory Experience, 2004-GT-5376.


are discussed, which include lack of appropriate engine instrumentation. Much emphasis is being placed by ABET EC2000 (www. on topics such as the students having an ability to design and conduct experiments, as well as analyze and interpret data; however, with budget constraints, purchasing commercial equipment for many types of practical laboratories is prohibitive due to cost. Floor space at many universities is also at a premium. If a school has the equipment for student laboratories, leaving the equipment set up year round is often not an option. At Baylor University’s mechanical engineering laboratory, space available for use by undergraduates is very limited. The single fluids/thermal laboratory must serve as classroom, laboratory, and storeroom for any experimental apparatus. Much of the equipment is used for demonstration purposes only once or twice each year. Due to cost and space limitations, the addition of desirable labs involving large-scale hardware is restricted. The possibility exists for virtual laboratories or computer exercises to fill some of this void. However, students need exposure to actual “hands-on” experiments with hardware to solidify much of what is learned in the classroom. There is no substitute for practical experience. In thermodynamics, the basics of the first and second law are discussed and an introduction to the Brayton cycle is accomplished. The students learn about the individual components, such as the compressor, combustor, and turbine and link these components in a cycle toward the end of the course. A senior elective course at Baylor University looks at the gas turbine engine as a propulsion system. The course has students design an engine cycle for an aircraft application. This includes choosing the appropriate cycle compressor pressure ratio, fan pressure ratio, and bypass ratio. After selecting these design choices, the student looks at the engine cycle’s off-design performance. As part of the course, two lessons each on rotating machinery, combustors, and inlets/nozzles are included. One lesson shows the history of the component with current technology and future trends. Without hardware, appropriate pictures of components are included for the students to see. The additional lesson develops the design methodology and shows design considerations for the components. Included in these lessons are short discussions on operational issues such as stall, surge, flame instability, and emissions. After studying these topics it would be a natural extension of the class to look at the performance of an actual gas turbine engine. Nomenclature

Cpo C Cprop Ctot ESHP f m·o rpm shp T0

= = = = = = = = = =

Specific heat Work output coefficient Propeller work output coefficient Total work output coefficient Equivalent shaft horsepower Fuel air ratio Mass flow rate of air Revolutions per minute Shaft horsepower Atmospheric temperature



Aircraft Gas Turbine Engine Experiment

Several options exist to give the students an experimental laboratory experience with gas turbines when such a facility does not currently exist on campus. The simplest option, and perhaps the most costly, would be the purchase of a commercial gas turbine test system. Prices range from $30,000 to well over $100,000. Looking at the capabilities, these machines are very versatile and offer the greatest opportunities for students to learn about gas turbines in a laboratory setting. Most engine test systems commercially offered have the capability to perform basic cycle analysis in addition to detailed experiments on component performance. The test systems also have the capability of being integrated with computers for control of the experiment/engine and for data acquisition. However, the cost is prohibitive for most universities. At best, these high-dollar items must be budgeted several years in advance and integrating their use into the curriculum during the appropriate courses to the maximum extent possible is absolutely necessary to justify their cost. Another option would be to design and build a gas turbine test system similar to the commercial systems. Suitable engines exist, such as those currently being used in R/C model aircraft applications. While the design process itself is beneficial, the cost is still high (about $5,000 to $10,000) and the time involved with the development cycle can be long. As part of the gas turbine propulsion elective course, the class visited the Baylor University Department of Aviation Science test facility at a local airport and was able to take data from an operating turboprop engine. Not every university has a Department of Aviation Science with such a facility. Other

Table 17–6.

options to run a turboprop engine might be available from a local community college or aviation maintenance school. Another avenue for exposure to gas turbine engine operation is a cogeneration plant, such as the one located on the Baylor University campus. This work explores the use of the Baylor University Department of Aviation Science test facility and suggests the use of the Baylor University cogeneration plant to augment Brayton cycle instruction in the classroom. In preparation for the visit to the airfield, two lessons on turboprops are given as a precursor to the turboprop laboratory. At this point in the course the students have studied cycle analysis, component performance, and engine cycle off-design performance. Students understand performance parameters and what figures of merit are used to characterize gas turbine operation. They understand efficiency, specific fuel consumption, and specific thrust. The turboprop lessons introduce them to turboprop operation, including work coefficient. The first lecture develops the equations of performance to include the core and power turbine work coefficient. Since the course is a propulsion system design course, propeller efficiency is also discussed. The second lecture looks specifically at the engine to be tested. The engine is a Pratt and Whitney PT6A-20 turboprop with the specifications given in Table 17–6. A crosssection diagram of the engine gas path is discussed as well as prominent features of the engine (see Figure 17–16). The students are to run the engine, collect typical cockpit data, and then model the performance of the engine for comparison to the manufacturer’s data. The laboratory requirement includes a two-page report with supporting graphs and figures as appendices.

Manufacturer’s Data in Cockpit Instrumentation Units [17-6]

Takeoff Max Cont. Max Climb Max Cruise

Figure 17–16.



Prop RPM

Jet Thrust (lbs)

Fuel Consumption (lb/ESHP/hr)

Fuel Consumption (lb/hr)

579 579 566 550

550 550 538 495

2200 2200 2200 2200

72 72 70 68

0.649 0.649 0.653 0.067

376 376 370 369

PT6A-20 Cross-section diagram. [17-6]


Baylor University is fortunate to have this particular engine available through its Department of Aviation Sciences. The department is focused on the development and qualification of alternative fuels. As part of their program, they have a PT6A20 mounted on a truck bed (Figure 17–17). The engine runs regular aviation fuel in addition to fuels such as ethanol and bio-fuels. The airfield is approximately 10 minutes from campus and is easily accessed by the students. Extra time must be allocated for this laboratory above the normal class time. The students were given one class period (approximately 1 hour and 20 minutes) for compensation but the overall laboratory takes approximately 2 hours including transit time. Upon arrival, the students were given a tour of the engine and facilities. Components, such as the inlet, starter-generator, compressor, etc., were identified by the students. The students also examined the propeller connected to the power turbine as shown in Figure 17–18. Eventually the engine technician explained the starting procedure for the engine prior to initiating the sequence. The control panel was equipped with the standard engine instruments found in any cockpit (see Figure 17–19). Table 17–7 displays the experimental data. The engine was run at five power settings and is allowed to stabilize prior to taking data. These data formed the basis for the comparison with the manufacturer data and the theoretical engine simulation. Colocated at the same airfield with Baylor University’s Department of Aviation Science is the Texas State Technical College (TSTC), which also possesses a PT6A-20 engine on

Figure 17–17. [17-6] Table 17–7.

Turb inlet (°R) Torque (ft-lbf) N1 RPM (%) Fuel Flow (lb/hr) Power (ft-lb/s) Power (hp)

Baylor University PT6A-20 gas turbine.


Figure 17–18.

Students examining the engine. [17-6]

Figure 17–19.

Control panel. [17-6]

a test stand. Figure 17–20 shows this test stand. It is used for students to become familiar with running an engine and test engines after their disassembly and reassembly. The engine test stand contains all cockpit controls as shown in Figure 17–21. The same cockpit data can be taken with this engine as compared to the Baylor engine. An added bonus with visiting the TSTC campus is the cutaway engines (Figures 17–22 and 17–23) and the spare parts available for viewing (Figure 17–24).

Typical PT6A-20 Cockpit Engine Data (Fall 2002) [17-6]

1410 100 51 132.5

1437 290 70 125.0

1482 500 80 220.0

1590 850 90 295.0

1626 950 93 325.0

11750 18

4676 89

92153 160

176243 241

20353 327



Figure 17–20. Turboprop at Texas State Technical College. [17-6]

Figure 17–23.

Allison 250 cutaway engine. [17-6]

Figure 17–24.

Miscellaneous engine parts. [17-6]

Figure 17–21. Control panel for Texas State Technical College. [17-6]

Figure 17–22.

Early turbojet engine. [17-6]

When this on-design engine was run off-design at sea level, several problems were encountered. First, it was not clear where the quoted mass flow rate from the manufacturer was taken. If one assumes the mass flow rate and compressor pressure ratio stated by the manufacturer were given as the sea-level values, then the on-design mass flow and compressor pressure ratio had to be adjusted. When this was accomplished, the original engine would not run at sea level and input values were changed to determine a combination that would work. After much iteration, the mass flow and compressor pressure ratio were correct for sea level, but the power distributions between the core and the propeller had been changed significantly. More research must be done to find the proper engine data to provide a more accurate model. Calculations were made with engine data, as shown in Table 17–7, but the engine was not able to be run at maximum power on the ground.


As stated previously, some problems were encountered finding parameters, such as efficiencies, and the calculated output did not always closely match the manufacturer’s data or the experimental results. The exercise was valuable, as the students learned to do a sensitivity analysis for the various input parameters to decide which parameter might be in error and by how much. Cogeneration Gas Turbines

Another alternative to the aviation gas turbine is the cogeneration plants. Baylor University is one of over 121 colleges and universities across the United States that has such facilities on campus. Baylor’s cogeneration plant is located in the center of the campus and generates


approximately 4.1 MW of electrical power 24 hours a day for seven days a week. See Figures 17–25 and 17–26 for pictures of the facility. The gas turbine is a 5 MW TB5000 manufactured by Ruston (Alstom) Gas Engines installed in 1989. It uses exhaust gases to heat water and also includes a mister for the inlet to increase performance during the hot Texas summers. The thermodynamics and freshman orientation classes have been visiting the facility as a field trip. The purpose of these trips is to expose the students to power generation as an illustration of the cycles discussed in class. Of all the colleges and universities listed with cogeneration facilities, only one has made academic use of the facility. The University of Florida had a laboratory/control room

Figure 17–25.

Cogeneration power facility. [17-6]

Figure 17–26.

Close up of the gas turbine and generator housing. [17-6]



Figure 17–27.

Close up of the control computer screen. [17-6]

simulator with “read-only” computer output. At this time the website is no longer functional, indicating the university has suspended this program. At Baylor University, not enough parameters are being monitored by the facility to enable calculations of performance. The energy complex at Baylor University is only concerned with electrical power output and not with efficiency. More work could be done to look at the possibility of instrumenting the engine to take engine health parameters. Discussions are in progress to explore possibilities. Any data would be taken from existing monitoring screens as shown in Figure 17–27.

In summary, this work investigated several alternatives to purchasing commercial gas turbine demonstrators. Using an aviation gas turbine on a dedicated test stand is the option discussed in the paper, however, facilities at either a local community college, aviation maintenance school, or at a fixed-base operator at the local airfield could provide a suitable alternative. As an alternative to the turboprop laboratory, cogeneration facilities exist at numerous colleges and universities. These facilities are underutilized and could be developed for academic purposes.

Future Trends in the Gas Turbine Industry


“I am enough of an artist to draw freely on my imagination. Imagination is more important that knowledge. Knowledge is limited. Imagination encircles.” —Albert Einstein


Changing Tides: Financial, Political, Legislative, and Technological 661 Politics 661 Global Deregulation in Power Generation 661 Environmental Factors 666 Environmental Legislation 666 Fuel System Variables and Versatility 666 OEM Growth and Diversification 667 OEM Acquisitions, Joint Ventures, and Licensees 667 OEM Business Strategy Including Production Backlogs and Vendor Alliances 668 Technology Transfer 668 Optimization of Existing Features and Support Technology 670 Transmission and Distribution Improvements 670 End-User Associations and Lobbies 670 End-User Associations 670 Lobbies 671 E-Trading 671 New and Unconventional Fuel Resources 671 Distributed Power: How Large Does a Power Plant Need to Be? 671 The Age of the Personal Turbine 671 The Power Mix 671 672 Case 1. Does California Need Liquefied Natural Gas? California’s Energy Efficiency Potential 673 California’s Renewable Energy Potential 673 Is California’s Renewable Energy Market Viable? 673 Additional Supplies of Natural Gas in North America 677



The future† of the gas turbine business is steered by several factors. Business factors are a far greater influence on technology than the average engineer feels comfortable acknowledging. The reader is advised to read this chapter in conjunction with Chapter 14 on business. A quick look at the world in 2007 indicates that oil and gas will continue to fuel the engine of global growth. There are enough renewable energies in the world that it could free itself of fossil fuel dependence in several decades, any time it chose to initiate that progress. However, using renewables requires the development of several budding technologies, and large oil interests not hiding the successful ones they already bought out. The technological tone for the developing world is set by the United States for the most part, and the United States policy is set by lobbyists, who are frequently powerful enough they can threaten senators and congressional representatives with nonelection “the next time.” Technology aside, China, India, and Indonesia (collectively more than half the world’s population) have large reserves of coal and access to cheap residual oil that the Middle East is happy to sell. Based on the needs of their swelling population and economic growth, it is likely these giants, all their Asian neighbors, and the countries of South and Central America will do little that changes their overall requiredfuels mix. Fossil fuels will continue to reign supreme for probably the next 30 to 40 years, with renewables making a small but growing dent in the fuels pie. Certain proactive countries, like Brazil, justifiably concerned about their rain forest and its people, have developed an alternative to “big oil:” ethanol made from homegrown sugar cane. They are now energy independent. Note that the sugar cane ethanol produces about 8:1 times the energy required to produce it. With U.S. corn ethanol production, the ratio is 1:1. Whatever happens, the gas turbine is going to be around for a very long time and will continue to improve efficiency, either on its own or in concert with cogeneration adaptations. It will continue as large conventional utility models or distributed energy size microturbines. It will burn an increasing number of fuels and will get better at burning pulverized coal. The gas turbine’s technological progress depends on money just as much as it does human intellect. Without money no turbines are bought, no installations completed. Without actual sales and project investment, there is no working experience to affirm designs, point the way to improvements, or provide a “real-conditions test run” for validating a new feature. However, in turn, money does not “happen” without the right politics, international or domestic infrastructure, or trust among international original equipment manufacturers (OEMs). So an appreciable part of this chapter is devoted to explaining the business and financial climate in which gas turbines attempt to progress and prosper while maintaining legislated environmental requirements. Business acumen can add credibility to the text of “request(s) for funding.” The gas turbine’s future is also dictated by the size and growth of the different industrial sectors that use gas turbines. Today, in order, those are power generation, energy production (including oil and gas), aviation (commercial, military, and commuter), marine (ferries, frigates, and other naval ships; cruise liners), and small (domestic, cars) use.

The order in which relevant factors affect the business and their relative importance depend on the demographic circumstances and how they work in concert. The following factors affect the future of gas turbines in the short (up to 5 years), interim (the next 15 years), and long term (over 15 years): 1. Changing tides (financial, political, legislative or technological) in the world, including ●

2. Environment related factors, including environmental legislation and national and international caucuses (such as Kyoto, Montreal, and Rio) and the priorities they promote. 3. OEM growth and diversification, particularly ●

[18-1] Working course notes, Claire Soares, 1975 through present; Proceedings ASME IGTI panel sessions 1985 to 2003, “ECMS as they relate to life expectancy of GT components,” Chair: Claire Soares.

OEM acquisitions, joint ventures, licensees, and resulting technological transfer. OEM business affairs, including production backlogs and vendor alliances. OEM technological research and development as well as support by and for government programs. Significant (OEM or government agency funded) technological breakthroughs that will revolutionize the state of the industry. Performance optimization trends in system or component design.

4. The effect of powerful gas turbine or end-user lobby groups. For instance, ●

The change in priorities caused by wars. In the United States, in mid-2006, the companies that service the military continue to “staff up” from pre-2001 levels. Gas turbine orders for 2003 for peacetime industries, like power generation, hit an all time low, and the figures for 2004 were lower. These industries continue in layoff to status quo mode (and, yes, sometimes layoffs do bring the stock value up for a while). Global deregulation within the power generation business, the changing mix of IPPs (independent power producers), SPPs (small power producers), and MPPs (merchant power producers). The escalation of technology for distributed power and small power plants that will run a small farm, factory, and even a household. Global business trends including international trading blocs, resource conservation, and financial crises. The progress of large rival (to fossil fuel) power technologies (including nuclear) and growing rivals (like wind and tidal power). Natural disasters in major financial center areas, like potentially a mega tsunami on the United States east coast; a crippling earthquake in Tokyo or on the U.S. west coast. Just a major earthquake in Tokyo would cause Japan to recall a couple of trillion dollars in international loans. This would be a disaster to the U.S. economy. So would anything that might cause China to recall the multibillion dollar loans it has afforded the United States, particularly during the second Iraq War .

What’s the use of pointing out that sugar cane ethanol (Brazil’s variety) is better for the environment than corn ethanol (which the United States plans to make), if the corn lobby is stronger than the sugar lobby?


What’s the use of developing heat pumps that use solar energy trapped in the ground (free) if you lack the muscle to force legislative subsidies that would make that product an affordable option? Why would you develop alternative energy technologies that could curtail much of the dependence on fossil fuels if you have no lobby to promote them? Actually, there is a good answer to that one. You develop it and then wait for an oil company to offer you millions to buy it, so it can stay “off the shelves.”

5. E-trading of energy (fuel), power (kW), emissions credits, and gas turbine spares. 6. New and unconventional fuel resources. 7. Distributed power: How large does a power plant need to be? The short- and medium-term future of gas turbines will be largely dictated by the success of the OEMs in terms of their technology. Their business strengths will be dictated by all these factors and can change their finances over decades or in the blink of an eye. Their technological success is as always in “the eye of the beholder” (the end user). What follows are details on how the preceding seven major factors have altered and may continue to alter the gas turbine world, as well as a case study. Case 1, this chapter’s only case, is written by the Community Environmental Council (CEC), an organization in California that aims to point out that California could be fossil fuel free by around 2030. California is more proactive than the rest of the United States with respect to the environment, and if any state could pull this off, it is likely to be California. At such time as California succeeds, this could create a model for some states, but much depends on the state’s individual culture. The oil and gas lobby is very strong in the United States; and oil and gas, as well as the “fuel share” in the gas turbine sector, may not alter appreciably in our lifetimes. As the CEC report also points out, the construction order has already been given elsewhere in the United States for LNG (liquid natural gas) terminals (which the report objects to having in California) and Canada-U.S. gas pipeline projects already have their green light.

Changing Tides: Financial, Political, Legislative, and Technological Politics

At the 2002 annual IGTI meeting, a 40-year, retired power generation veteran of one of the world’s largest OEMs said of his previous employer’s gas turbine order status, “250 for this year, 150 so far for next year and 50 for 2004 so far.” The lead time for gas turbines is frequently upward of two years, so the beating the market takes from political unrest on a global scale was much in evidence. That the major OEMs will survive the fray and be ready to meet the surge in orders, which reinstates itself after power generation development lags growth in GDP, is a given. Many small systems suppliers who survive from monthly order to monthly order may not be that fortunate. The small businesses that will thrive in all circumstances are those that the OEM needs for day-to-day business, such as repair shops that complete piecework the OEM does not want to spend liquid capital on support “in house.” Niche suppliers of specialized instrumentation, such as optical pyrometers,


that are required for design development and operational investigation probably always will have enough business to maintain their overhead. War will see some resurgence of orders for projects like rebuilding Iraq. This may not always mean new gas turbine orders, though, due to the lead times involved. A service industries acquaintance mentioned several gas turbines ordered for Iraq that were “existing, old.” Several of these packages are all over the world, collecting dust because the customer “cancelled the order.” The already industrialized countries would not likely buy older models if they can afford to wait for the latest ones. However, a nation anxious to pull out of Iraq while keen to be seen doing everything it can to rebuild that county’s damaged infrastructure is likely to buy “what still works.” In many cases, these old gas turbine packages were never installed, so they are operationally “new.” Aviation as Affected by Politics

Commercial flying has seen a turndown due the events in global politics. The result has been felt all through the chain: airline to aircraft manufacturer to aircraft engine OEM to the OEM’s employees (layoffs and early retirement packages). The military engine market saw more activity as recent politics revived some hitherto neglected military aviation programs. Not that this would help the progress of gas turbine technology as a whole, however. In the last 20 years, the level of technology with commercial aircraft engines crept ahead of their military engine counterparts. In short, at the turn of the century, war and political unrest essentially do little or nothing to promote gas turbine technology (as different from the second World War, which did much to pave market entry for the gas turbine). Marine Sector

Gas turbines in commercial marine applications is a relatively new field and activity here has stayed steady. Gas turbines in military marine applications (like the U.S. Navy’s LM2500 fleet) continues to stay an active business. Installations on cruise ships and ferries increase. Land-Based Applications

Any niche-technology system that saves money is given a gracious hearing as oil soared above $70 a barrel in 2006. The rest of commercial industry scrutinizes expenditures and overhead, cutting back on attendance at trade shows, perks, and even the corporate commuter jet fleet. Meanwhile the government-sponsored programs for fuel cells, hybrid systems, the oil-free large gas turbine engine program and microturbine CHP systems continue steadily. Government sponsorship continues, even if private industry contributions diminish in the United States (U.S. DOE). Global Deregulation in Power Generation

The largest economic sector in the world today is power generation. Oil companies now realize that they are prudent to get into the business as independent power producers and become their own best customer for their oil, gas, as well as nonconventional energy and fuel production. Smaller process and petrochemical plants decide to join in the fray, particularly if their incentives include ●

● ● ●

A potential fuel source that ordinarily would be a waste by-product in their process. Tax incentives to become power producers. A major utility grid that will buy the power it makes. Some combination of those factors.



Large gas turbine manufacturers such as Alstom stabilize their portfolios by buying major shares in mega-sized power companies. Alstom’s share in the Midlothian power plant is a case in point. Government regulations everywhere are changing in terms of deregulation of the power business, environmental regulations, fair competition laws, and trading bloc requirements. Smaller “guerilla” business units, termed merchant power producers, rent or buy stationary or portable turbine packages to supply power for what may be a limited period of time. They generally are short on permanent assets and technical expertise, but they nip persistently at the heels of large IPPs and national utilities, generally for quick profits before they vanish altogether or go to a different location. IPP candidates have no shortage of countries that would be willing to receive their investment dollars. The catch then is to estimate gains both monetary and otherwise and the work involved beyond that of designing, building, and operating a power plant. What follows could never be exhaustive from a perspective of global IPP activity, but it does illustrate the main features of the IPP market, with particular reference to the continent of long-term maximum potential power demand growth—Asia.

Build, operate, and transfer (BOT). The developer builds and operates the plant for a contractual number of years. Then, the plant is sold to another authority, often a government department or agency after that time. Repower (replace steam with gas or combined-cycle turbines)/refurbish, operate, and transfer (ROT). In these contracts, the developer may operate the plant for as long as it takes to recover its investment plus a designated profit margin. Another firm or government agency retains ownership of the plant. International purchase. Especially when caught in the crisis of unexpected growth, countries resort to the emergency strategy of buying power from a neighbor. Malaysia, in its early 1990s shortage crunch, bought power from Singapore. Malaysia sells some power to Thailand. Whom the power contract is with may have something to do with desired national fuel resource conservation policy. For instance, both Thailand and Singapore would like to buy a great deal more gas than Malaysia currently sells them. Why do some gas-rich countries “hoard” their gas reserves? Possibly because they are aware that any artificially low prices for natural gas will give way to larger profit margins in some years (enough to outdistance the diminishing value of unit currencies).

Who and Where Are the IPPs?

The answer to this question is becoming infinitely more complex than it was only 10 years ago. The acronym IPP used to refer to firms that existed for the sole purpose for investing in and building power plants then selling the power to a national governing body. It still does, except the IPP ranks are swelling to include “small” power producers (SPPs). Small producers include large industrial entities, such as refineries and manufacturing plants, that buy their own power production machinery (generally to avoid expensive brownouts or outages) and make their own power. In some countries, they sell their excess power back to the national grid. The limits of this sale generally are set by the size of the distribution lines available. This small power producer generally gets less of a tariff for its power than it pays for national grid supplied power. As such power producers increase, they lessen demand growth and therefore the required size of new large power plants. IPP ranks are further being swelled by IPP joint venture companies, which can have as a major or controlling interest partner one of the turbine manufacturers, such as Alstom, Siemens, or GE. Interesting variations on a theme of joint ventures can be arranged contractually with OEMs. Consider the case of Malaysia. ABB (prior to being part of Alstom) made a turnkey delivery and transfer (BOT: build, operate, and transfer) arrangement on the Kuala Langat plant with the Genting Corporation and the Lumut plant with Segari Ventures. GE (General Electric) had a turnkey arrangement with the power plant owned by the Port Dickson group. The 51%–49% joint venture that Siemens Westinghouse has with the YTL corporation has Siemens the controlling partner. In the latter project, the number of Siemens and other expatriate staff will slowly dwindle to zero six years after commissioning. The national goodwill created by firms that assist newly industrialized countries (NICs) with attaining financial independence is immense and hard to measure. Options for IPPs ●

Build, operate, and own (BOO). The developer builds, operates, and owns the plant for its entire life. This owner generally secures a PPA (power purchase agreement) and a fuel purchase agreement before commencing construction.

Asian Currency Crises

Currency problems in the late 1990s sent SE Asian currencies tumbling. In 2005, the Malaysian ringitt, one of the more stable SE Asian currencies, still was down about 28% from its pre-1998 value, and Indonesian currency was even worse. However, the bottom line is that IPP investments generally yield 18–20 % long term. Financing, Politics, and Changes in Asia

The number of IPP opportunities in Asia is immense— bigger than anywhere else in the world. Even once the current economic hassle sorts itself out, the catch is getting financing, and that depends on where the project is and what incentives or drawbacks go with the location. Any global IPP scene summation must include China, the highest power demand growth area in the world, with India and Indonesia as close seconds. China has potential investors wary for many reasons, which go beyond any current economic crisis. The Chinese frequently offer 16% ROI (return on investment). It took much gut wrenching to get it up from 13%. Other countries offer between 18 and 20%. Attractive, if their currency is stable. Older problems in China include a non-globally traded currency, although moves have begun to slowly change that. The currency also carries some devaluation uncertainties. Tariff pricing issues are a further stumbling block. Major drawbacks with development in India have been the lack of infrastructure and government corrupt practices. Consider though that “corrupt” is often in the eyes of the beholder. “Baksheesh” is a way of doing business in many countries and frequently Anglo-Saxon cultures (other than those restricted by the U.S. Corrupt Practices Act) just pay the “expediting fees” and do business. All the main turbomachinery players—Alstom Power, GE, and Siemens Westinghouse—are in India, each with a longterm agenda in the power generation industry. GE arrived late, behind its traditional rivals, but its agenda is ambitious. As are Alstom’s (separately ABB and GEC Alstom when they first entered India) and Siemens Westinghouse’s (Siemens when they first entered India). GE picked a variety


of local firms with relevant expertise to joint venture with for market entry. Siemens came in through Siemens India, and ABB came in alone. India does not smile on 100% foreign ownership or joint ventures in non-high priority industries. Political waves have meant a great deal of stalled legislation and project approvals, even in critical industries such as power. As of 1995, however, the way was cleared for the first few “fast track” power projects. Support industries, such as telecommunications, have been opened to privatization, which helps add overall economic momentum. Latin (South and Central) America

Global unrest due to situations and conjecture in Israel, Iraq, North Korea, and Afghanistan notwithstanding, some Latin American countries always experience their share of internal unrest. The responsible factors include politics, military coups, vandalism by guerrillas, drug cartels, poverty, and in Columbia for instance, “a culture of nonpayment among our clients.” Also someone like Venezuela’s Hugo Chavez, can affect the United States adversely by tightening his country’s oil exports. Other factors include slow progress of the privatization process and waste of power in an ineffective transmission system (as high as 29% at one power company in Columbia). The Latin American countries are struggling to rebuild their infrastructure despite all handicaps. Large OEMs have the deep pockets to wait out the period it takes to get recoup their investment. Africa

The situation is similar to that in Latin America, exacerbated by worse poverty and disease. Nonetheless, development of industry and power generation continues, particularly in countries such as Nigeria that have oil resources. Gas turbine-related development, however, is unlikely to reach the per capita levels currently prevalent in India and China in any foreseeable timeframe. The Universal Financing Process

The capital available for and invested in a project ultimately gives gas turbine systems and technology the proving ground they require. With the world’s drastically changing economy bringing turmoil and political disarray, some of this finance is in short supply. The basic methods of raising it essentially are the same and deserve short mention. This subsection will make constant mention of China and India. This is logical, as the countries collectively hold about half the world’s people. Neither country is exactly devoid of unrest. However, both populations demonstrate an intellect and capacity for the study of technology. That bodes well for investing companies to find the trainable labor that gas turbine-related projects require. As an indicator, China took 10 years in the field of aviation technology to cover what had taken the Western world 60 years to develop. Granting loans (by private banks or multilateral agencies, such as the World Bank) in most contemporary instances depends on the project supporting “sustainable development,” which in turn requires sound environmental practices. Approved projects have been cancelled in midstream on this basis alone. The concerns of project developers follow those of their lenders and the same factors affect everyone’s profitability.


Political Incentives, Infrastructure, and SPPs

Political infrastructure does not always see fit to give incentives to SPP formation. Singapore Power used to be quite adamant about not buying excess power made by SPPs, such as oil and petrochemical firms. For instance, until the late 1990s, Singapore Power had been able to supply all its consumers profitably. It now allows IPP agreements and is likely to relent further in terms of purchases from SPPs. As a consequence of the initial policy, firms such as Petrochemical Corporation of Singapore (PCS) were careful to generate power that was just below their own requirement of about 25 MW, after they had installed their in-house Alstom GT 10, so there was no question of them supplying any to the national grid. Other SE Asian countries had future SPP development stalled for a while as IPPs have long-tenured power purchase agreements in place. The government is obliged to buy the power they produce. For the most part, these IPPs have been running at base load since being commissioned around the late 1990s. Tenaga Nasional Berhad (TNB), Malaysia’s national power company, therefore has not seen much incentive for encouraging its own plants to retrofit cogeneration facilities, let alone encourage SPPs. Thailand, on the other hand, will take everything it can get. It had created an incentive structure for receiving power from SPPs by the mid 1990s. This is excellent planning, particularly in its recent predicament with devalued currency and a sudden dearth of willing international IPP investors. The Electrical Generating Authority of Thailand (EGAT) is the authority that buys SPPs’ excess power. Thailand provides good incentives for SPPs, as is illustrated by the Esso refinery in Sriracha, Thailand. It has two ABB GT35s for its power needs and sells the excess to the national grid. Unfortunately, this is limited by the transmission lines available for the purpose, only 15 kV rated, as in the case in some areas of Thailand. Thailand’s first trash burning plant contract (20 MW) was let to Kvaerner in the 1990s. Thailand is likely to see far more of these plants; many of them will probably be IPP facilities or SPPs who need steam produced from the trash fuel for their other processes. Thailand also is progressing on biomass burning in around 20 MW increments, using yet another fuel (rice husks, bark, and other plant material) of which it is not short. Other SE Asian countries, such as Vietnam, have used biomass on a small family-sized scale for centuries before their oil and gas resources, as well as the potential for power generation revenues, brought the major OEMs to their countries. Merchant Power Producers

The latest trend in the fast moving business of independent power producers is that of merchant power producers. An MPP is an IPP that has no long-term contract for sales of most of the power it produces; in other words, no measurable financial security at the time of making the decision to build the plant. MPPs’ business and negotiating skills therefore have to be superior, as does their credibility, or they will make little or no profit. New MPPs can compete with established IPPs whose contracts are running out, on level turf. MPPs mark a trend that is barely five years old. It was fostered by the fact that deregulation creates intense global competition in this industry. Deregulation in turn mutually fosters decentralization, which causes rural industry and power demand to grow. A good example is Brazil, which



managed to get inflation below 10%, down from 2500% annually. The net effective spending power of its people rose accordingly, creating a middle class with appliance and gadget hunger to match. This also contributes to small rural industries, which now have enough stable capital to invest in industries such as small mining rural plants. These plants need power in quantities that make a great deal of sense for small- to medium-sized power plants owned by IPPs or MPPs. The plants owned by national companies generally are much larger and more centrally located. Power purchased from them often is an inefficient proposition, because of tariff structures, transmission losses, or both. MPP contracts are being signed on an almost daily basis now. MPPs build small- to medium-sized facilities that require less of an outlay than some of the massive IPP plants built (which had a guaranteed power purchaser or purchasers). IPP strategy, in face of competition from MPPs, is for raised efficiency, optimized operation, automation that reduces required personnel, and anything else that cuts cost per fired hour. Some of the optimization stems from anticipating tougher environmental legislation. In England, an IPP facility at Dagenham (an English-Canadian joint venture) purchased an expensive engine condition monitoring system that will help it not get overcharged for emissions with CO2 tax legislation. The Oil Company Model Thus Far

Some 30 years or so ago, the only consideration for an oil company to produce its own power was the size of its power requirement or the remoteness of its facility. Commissioned about 20 years ago, the first 170,000 barrels-a-day Syncrude oil sands plant in northern Alberta needed to run machinery in a $3.5 billion (in 1976 dollars) plant, as well as support the massive startup load of its mining draglines. It required its own power plant, as did Esso’s Norman Wells oil production operations in Canada’s remote north. Efficiency was less of a power production machinery selection criteria than availability. No one talked about combined cycles or cogeneration much. Also, if the government tariff for power it bought back from the operator was not advantageous, that was not considered a major issue. Power companies felt enough in control of turning healthy profits to discourage potential SPPs. This is changing drastically but at varying rates throughout the world. The burden of emissions regulations and, in progressive countries such as Sweden, high taxes on weight of emissions, has made burgeoning industries of retrofit and environmental engineering. Faced with increased difficulties in turning a profit, many formerly smug national power companies are allowing “independents” (power producers that make only power) as well as SPPs (that may be refineries, process plants, and mills) to enter the fray. Some nonremote oil company facilities produce what power it takes to help them get their products delivered. Take Elf, UK, for instance, which produces all the power it requires at its Flotta terminal and sells any excess back to the national grid. Offshore platforms always have made their own power. Occasionally, as with the BP Forties field in the North Sea, if platforms are close enough together, the oil company may lay down underground cables for platforms to share power produced by one of them. However,

underground cables are expensive to lay. Also, changes in production flow could occur, as is the case with Forties and Brent after their fields were found to be larger than thought. Power to platforms could get interrupted if the “main” platform were to shut down its generation turbines for any reason. Today, there is a proactive movement by oil companies to get involved with the power generation business internationally. It does provide an end market for the fuels they provide. If and when this is done by an operating plant for its own power consumption (with excess being sold to the national grid), such as Syncrude, it also provides consolidation of specific resources, such as specialist staff services and repair facilities. A number of contemporary projects involve oil companies in joint venture plans, with governments and other power companies, for actual ownership in power plants. BP Gas, not always the most assertive of the oil companies in terms of power generation, nevertheless, admits that it currently is considering several power project joint ventures, including ones in Vietnam and Columbia. Shell International acquired 50% of InterGen, a joint venture between Bechtel Enterprises Ltd. and Shell Generating Ltd. One of InterGen’s ventures, the 770 MW station at Rocksavage, England, was opened on July 31, 1998. Only recently did Shell officially recognize the need to use major increases in power generation capability to make its 1996-initiated “fuels to power” strategy effective. Another proactive example of oil companies providing a market for their fuel with power plant investments was thus set. Exxon Mobil’s publicly stated strategy on power generation, particularly in lucrative SE Asian markets, is assertive and focused. The former Exxon’s statement read: Pursue attractive power generation investment opportunities worldwide to grow earnings while capitalizing on synergies with other Exxon businesses. Maximize the long-term value of current power interests in Hong Kong.

Exxon had noted the global trend toward deregulation and therefore the emergence of power investment opportunities in many countries. The first area of major interest selected was Hong Kong. Exxon Energy Limited (EEL) holds 60% ownership of three power stations in Hong Kong. China Light and Power (CLP) operates the stations and owns the remaining 40%. CLP also owns all transmission and distribution facilities in Kowloon and the New Territories. EEL also owns 51% the company which has off-take rights to half the capacity of a pumped storage station in Guangdong Province, China. Exxon Mobil’s generating facilities in China are listed in Table 18–1. The Gas Turbine’s Main Rivals

Nuclear Power Nuclear power’s pitfalls can (as many recent crises in that industry segment demonstrate) include (but are not confined to) ●

● ●

Inadequate or complacent management in some firms (the now defunct Ontario Hydro is a case in point). Waste fuel management technology. Politics revolving around waste fuel management (like the unpopularity of Yucca Mountain with locals in the United States).


Exxon Mobil Generating Facilities in China

Capacity Castle Peak A (Hong Kong) Castle Peak B Black Point Penny’s Bay Guangdong


Ownership (%)


Coal/fuel oil


2708 2500 300 600

Coal/ fuel oil/gas Gas Diesel Pumped storage

60 60 60 51

*Reference: Black Paint Station management.

The management of these issues can make the difference between whether a nuclear power plant provides economic power or not. The best illustrations of this fact are acquired by looking at some of the recent events in the nuclear industry in some of the countries attempting to sell their nuclear technology to newly industrialized countries in SE Asia: Canada, Finland, Japan, the United Kingdom, and the United States. The Ontario Hydro debacle or the far worse messes of Three-Mile Island and Chernobyl will not stop the growth of nuclear power, as sector estimates for different countries’ growth indicates. It is worth pointing out, however, that, of all forms of power generation, nuclear power by fission is one that leaves the public at considerable potential risk. Unlike the case with fossil plants, nuclear plants may not provide a gradual warning of future problems. Nuclear reactors that use the fusion process avoid the waste problem that fission reactors have. Some current estimates to get fusion reactors into commercial operation state 2030 as an approximate realistic target date. Fossil fuel poor countries will continue to advocate nuclear fission power. Japan is still the world’s second largest economy, with power needs to match. It imports all but 0.4% of its oil, 5.6% of its coal, and 4% of its gas; hence, its emphasis on nuclear power. It needs to import the fuel but otherwise can consider nuclear power a semi-domestic industry. It consumes about 140 GW of power and 30% of that is nuclear provided. By 2010, nuclear’s sector share will climb to 42%. Public Opinion The global domestic sector currently is about 20% of overall global activity. One might be tempted to think that isolated individual consumers, such as households or small farms that install mini-hydro or windmill facilities, might not affect the large power producer’s territory. This is totally untrue, as illustrated by the two nuclear plants in Sweden that were cancelled when 200,000 households installed individual geothermal heat pumps. Not everyone has the Swedes’ characteristic environmental verve, however. Some Lessons and Results One lesson learned from the severe ice storms suffered by Canada and the United States early in 1998 is that smaller IPP installations might prove less of an Achilles heel to overall power demand than a few large national power plants. Problem-riddled national nuclear industries in Canada, the United States, and Japan are testament to overly optimistic life prognoses of nuclear fission reactors. They have and will continue to be decommissioned. This can result in several smaller IPPs taking up the slack. Coal-Fired Thermal Units (Steam Turbines) The world has about 70 years worth of natural gas supply left at last


count and over 300 years worth of the commonest fossil fuel today, coal. So, much as legislation may point out that natural gas causes only half the greenhouse gases and global warming that coal does, all countries want to use their coal. Besides, countries that have an abundance of natural gas, such as Malaysia, are thinking in terms of its export more than its domestic consumption. At a power generation conference in 1996, Malaysia’s Prime Minister, Dr. Mahathir Mohammed, stated that he would like to see less “dependence on gas turbines.” Translated, that is likely to have meant, “we can burn cheap coal, imported or otherwise and sell our natural gas at a profit to Japan, Thailand, and so forth … also if we put off selling it, the prices are sure to go up.” Currently, China is flooding the market with its cheap, abundant coal. It has become hard for coal rich countries in Eastern Europe for instance, to export theirs. Frequently, in countries like the United States, fuel-burning facilities, such as power plants, “share” or exchange their pollution allocations to meet a legislated area average. After-the-fact retrofits to help environmental emissions cost 300% what they cost to put them in at initial installation stage, so they are not popular with plant owners. The Economics of Coal Coal, particularly in developing areas, is the fuel of choice. Apart from the size of known global reserves, there are other economic reasons. To look at these in more detail, it is worth considering SE Asia, where more than half the world’s population lives. Coal is their most common fuel. Gas is cleaner but expensive if you do not own it. Poor in natural resources, Japan currently maintains most of its stringent environmental standards by burning expensive LNG and continuing to develop nuclear power. The Philippines, despite the Camago Malampaya gas field discovery, nevertheless has a long-term energy policy that places coal uppermost in its priorities. The offshore field has gas reserves enough to keep 3000 MW (1 MW = 1000 kilowatts) of electrical generation capacity running for 15–25 years. Nonetheless, the 25 GW (1 GW = 1000 MW) of anticipated power generation new installation before 2010 breaks down into 60% of coal-fueled power, 10 % hydro power, and the rest gas. Coal takes the lead because it is still the cheapest and most abundant fuel that the country can use. Back in 1995, Indonesia started a national policy to reduce its dependence on oil. Instead, it exports its oil and will base power growth mainly on coal and hydro resources. Currently Indonesia’s 10 GW are fuelled thus: 25% gas, 20% hydro, 20% diesel, 35% coal, and 5% others, including geothermal. It is intended that, by 2020, 50% or higher will be coal and 40% oil and gas. Indonesia, in the early 1990s, was gifted with Finnish technology and joint venture capital aimed at developing its vast natural peat resources as a fuel. Therefore, Indonesia has yet another economic reason to curtail the burning of natural gas and oil, its cleaner fuels, and concentrate more on coal (and peat on a smaller scale). New trifuel (coal/oil/gas) burner technology (for boiler and steam plant designs) can limit NOx (or oxides of nitrogen that combine with water to make acid rain) levels to below 20 ppm (parts per million, by volume). This standard is good enough for the most stringent environmental NOx standards in the world.



Despite an increase in China’s natural gas and liquid fueled facilities, it is expected that 75% of that power will be, as it now is, coal fired. China is the world’s largest market for coal-fired stations, and power is its largest industry sector. China releases over 7 million tons of SO2 (sulfur dioxide, which combined with water also adds to the acid rain problem) to the atmosphere annually. Coal burning, of course, is the main culprit. As a consequence of fast changing environmental standards, the wealthier nations of SE Asia are retrofitting scrubbers (to clean up coal emissions) as fast as they can. Countries with a higher standard of living, like Taiwan and Korea, have more stringent standards. Those standards are progressively tightened every five to seven years to produce still cleaner emissions. Gas Turbines, Coal Gasification, and Coal Gas Coal gasification technology (to use coal gas instead of natural gas in gas turbines) is on the upswing. Gas turbines then will grow in popularity. This is because, despite the world’s tendency to promote steam units due to its desire to use coal, once coal gasification is widely commercialized, the gas turbine population will increase and help make coal-burning steam plants redundant. Users also want to take advantage of the higher efficiencies offered by the gas turbine. A higher efficiency of 20% means one uses 20% less fuel. Coal gas now also can be produced by underground coal gasification. Basically, the process is simple. Two boreholes from the surface are drilled. One supplies oxygen and water, the other removes the gas produced. The former is generally drilled vertically, the other follows the curvature of the coal seam. The process can “work” coal seams up to 1 km deep. What the process essentially does is avoid all the cost and dangers of underground mining and results in a gaseous coal product suitable for power generation, with the ash and several other unwanted constituents in the ground. The prevalent tendency is to think “steam” and “steam turbine” or “thermal unit” at the mention of the words coal fuel. Since coal fields in the middle to late twenty-first century may look more like oil fields than current mining establishments, the vision is probably outdated. Commercially, Siberia and Uzbekistan are the only countries that have used this process. However, recently, a European Union (EU) project in Spain demonstrated the feasibility of this process. The EU, like the rest of the world, is looking for a hedge against natural gas prices soaring when escalating requirements and security of supply raise gas prices. The process can mine deep coal seams that would be uneconomic to mine using conventional methods. Some of these coal seams, interestingly enough, have been found when companies were drilling for oil and gas. Now this in-situ conversion of coal into gas gives the gas turbine world a potentially plentiful source of fuel. The acronym UCG (underground coal gasification) has been coined. The Spanish project’s coal gas had a heating value of 11 MJ/cubic meter. Optimization could yield 16 MJ/ cubic meter. “Renewables” These include turbines driven by wind and tidal power. Their profile is growing globally. Other regenerables include wave energy and biomass energy. Wave energy is in its infancy. Biomass, including peat, are not yet widespread on a large scale.

Environmental Factors Environmental Legislation The Effects of International Caucuses Such as Kyoto, Rio, and Montreal

The effects of international caucuses such as Kyoto include additionally stringent environmental legislation. The massive acid rain damage noted in the 1970s and 1980s made NOx and SOx emissions the first major emissions priority. Carbon dioxide emissions were very much part of Kyoto, but only in early 2006 did the mainstream U.S. media (Time magazine) began the cry of “be worried … be very worried” with respect to global warming. For further details on carbon dioxide removal and sequestering, see Chapter 11, Environmental Technology. Fuel System Variables and Versatility

Regardless of the emissions reduction method, the variables involved include type and grade of fuel and external atmospheric conditions. As coal is gas’s greatest fuel rival, progress with coal fuel and steam turbines directly affect the gas turbine business. Fuel quality affects how “good” the coal is. Consider for instance the following grades of boiler coal used in China: Source/Grade/LHV (lower heating value) in MJ/kg/ash % by weight. Jiangxi/Anthracite/24/ 19 Datong/HV (high volatile) bituminous/28/13 Kailuan/HV bituminous/13/41 Hebi/LV (low volatile) bituminous/28/16 Shulan/brown/12/30 Although all these coals contain roughly between 1% and 2% of sulfur, the furnace, boiler, and associated environmental equipment for each obviously differ greatly, as does the thermal efficiency (amount of fuel required per unit of power). Original equipment manufacturers use a combination of techniques for NOx reduction, each with their own trade name. Alstom’s, for instance, include a technique they call tangential firing (TF), which uses dedicated fuel and air compartments; TF with overfire air (OA), which subdivides the combustion air to reduce the excess oxygen provided and thus retard NOx formation; and low NOx concentric firing system (LNCFS). The latter is an extension of TF with OA as it delays the secondary air from mixing with the fuel. Several OEMs now make trifuel burners, which are important with the fuel versatility required especially in newly industrializing countries. Mitusi Babcock’s trifuel burner, specifications for which claim below 10 ppm NOx formation minimum, have been retrofitted in Castle Peak, Hong Kong, a station owned by China Light and Power. Supercritical Steam

Higher temperature steam gives a power facility more heat to extract than lower temperature steam. Supercritical steam plants have been able to attain efficiencies of about 42%, based on LHV of the coal fuel used versus about 31% with some conventional steam and single-cycle gas turbine stations in existence. Condensing turbines extract the most possible heat from the steam. Reheat, single cycle or otherwise, is used to help attain supercritical steam conditions.


For instance, Shidongkou, China’s first supercritical steam plant has 2600 MW units and uses single-cycle reheat steam and condensing steam turbines to attain 42% thermal efficiency. This is a steam-turbine-only plant, but it illustrates that coal derived steam would work as well with a combined-cycle steam turbine. Put another way, for the same coal input, if the heating surfaces required in a subcritical boiler total 24,100 square meters, the figure for a supercritical boiler would be 15,810 square meters. (Also, if the boilers were the same 12 meters in diameter, the subcritical one would be about 10% taller.) These figures directly affect efficiency and thus fuel consumption and emissions in both combined-cycle and steam-turbine-only applications. The cost of power production not counting environmental equipment is typically 5% lower for a supercritical steam plant versus an only-steam-turbine plant. With environmental equipment factored in, this percentage rises, depending on the environmental equipment required. Efficient Steam Turbine Condensing

Because a condenser can seriously affect the back pressure on a turbine, its efficiency can considerably alter a plant’s overall efficiency (and therefore its fuel consumption). For instance, for a condenser backpressure of 45 mbar where, in a specific plant 3MW electrical output power is “gained,” the corresponding “gain” for 80 mbar is 1 MW and for 115 mbar, 3 MW are lost. Note also that it is important to the environment that cooling water be “returned to nature” as cool as possible, so condensers also have a direct effect on the environment. Removal of Emissions after They Have Been Produced

After the fuel (coal, oil, distillate, or gas) has been burned, there are SOx, fly ash, and particulates, NOx, as well as dioxins and heavy metals, to be removed. Separate systems can handle each of these or combination solutions can be sought by a power company, depending on the plant configuration. CO2 is vastly more expensive to remove from solution (after it has been produced) than to limit its production in the first place. The latter is done by raising cycle efficiencies to reduce the fuel burned. OEM Growth and Diversification OEM Acquisitions, Joint Ventures, and Licensees Which “Parent” Philosophy Governs Which Model?

“Parent” companies also are changing rapidly. As we saw in the introductory to the chapter, due to acquisitions, mergers, joint ventures, and engineers who work for more than one OEM, it gets hard to recognize certain gas turbine models from their insides. Certain key developments are well known; and it is easy to identify where, when, and by whom they might have been originally designed. For instance, the SEV (sequential environmental) burner was an ABB (Asea Brown Boveri) design, designed when the company was ABB, not Brown Boveri (as it once was), and not ABB Alstom, later Alstom, as it later became. The wide chord fan blade was a Rolls Royce original. Steam cooling in closed-cycle loops to support H technology, which was a success both in design and full load test, was probably a Mitsubishi first. This may be debated by some, but note that “first” refers to no leakage on a full load test. The Cyclone, Tempest, Tornado, and Typhoon were grassroots designs engineered by European


Gas Turbine (before ABB bought it) when it was EGT, not in its formerly Ruston days. Now these models are owned by Siemens. Sooner or later, every OEM has a variation on a theme or a better alternative for which it may not have done the grassroots development. Grassroots model development is expensive. The very fact that the Cyclone was developed in the first place indicates that the manufacturers foresaw potential market share in a power bracket that would also equate to a Solar Mars. At this power range, the compressors partnered with mechanical drive gas turbines tend to require adherence to API (American Petroleum Institute) specification. It could have been anticipated that this would put the OEM on equal footing with manufacturers like Solar, who currently has the lion’s portion of the installed mechanical drive market share in sectors such as SE Asia’s oil and gas production market. It similarly dominates in the installed-machinery oil and gas production market in the United States and Canada. Solar’s historical advantage was based partly on market entry timing and partly on the fact that their smaller compressors did not always need API specification adherence to win contracts. Licensee Growth and Development

When a licensee does well, the company that licenses it to build gas turbines also gains strength. General Electric is a major conglomerate with a large stable of licensees for different gas turbine product lines. They include Nuovo Pignone, GEC, Stewart and Stevenson, and Kvaerner. Consider the growth of Kvaerner. Kvaerner, originally founded in 1853, made steel products. This was extended to include high-head Francis and Pelton type turbines: current unit sizes exceed 400 MW. The 1956 agreement signed with General Electric licensed Kvaerner to build marine steam turbines and later industrial and aero-derivative gas turbines. Kvaerner’s client base is largest in Scandinavia but they now market aggressively in SE Asia, as an individual company and also in joint venture agreements. Kvaerner bought John Brown, another licensee of GE, in April 1996. John Brown was already seasoned in Asia and its plants included one of the earliest combined-cycle plants in the world, built in Hong Kong and commissioned in 1972. John Brown has been renamed Kvaerner Energy Limited. Its consortium with Kvaerner is called Kvaerner Energy Thermal Power. Asian projects include a combined-cycle plant in China. The 330 MW station in Zhenai, Zhejiang province, China, is heavy oil fueled and then requires technology similar to that employed by the plant in Shunde, Guangdong province, that runs two ABB (now Alstom) 13D-3s in combined-cycle mode. In the case of the 13Ds, the design already incorporates the low turbine inlet temperatures (TITs) required to make the turbine run successfully on residual or bunker oil. In Kvaerner’s case, the GE-9E combustors are adapted for burning residual. The fuel is washed and chemically treated. It is also heated, with steam from the steam turbine, to lower its viscosity so that it flows well enough for fuel injection. As with all residual fuel applications, expensive high-quality distillate is required on startup and shutdown to avoid the fuel nozzles clogging. Deposits build up on turbine blades and have to be washed off regularly or the effect gas path area will eventually clog. The frequency of the washes depends on the turbine design and fuel quality. In this plant’s case, washing is about once weekly. The plant cost over $100 million to build. When necessary, it can be operated in simple-cycle mode. The plant is run



16 to 18 hours a day for at least 300 days a year, adding up to 5000 to 6000 hours a year. In 1995, Kvaerner opened an office in Kuala Lumpur, Malaysia. Its first contract was for one LM2500 gas turbine driver for an Ebara compressor, which will be used in Shell’s Central Luconia project in Sarawak. A Kvaerner-built foil cat that serves the route between Hong Kong and Macau runs on Kvaerner supplied gas turbines. Kvaerner services some of the Indonesian navy’s LM2500s in its overhaul and repair facility in Agotnes, Norway. OEM Business Strategy Including Production Backlogs and Vendor Alliances

The state of all manufacturers’ backlogged orders is proof that the power business in booming with unprecedented vigor. Although manufacturers are strict about not making predictions regarding future order numbers, indications are that the backlog condition will escalate in the next few years. Many customers, new and old, have stopped looking at individual design features that can directly affect their costs per fired hour, even if they know how to assess them. They just take whichever machine they can get delivered the quickest. If that machine has problems due to ironing out new design updates, the customers need to compensate for this by writing “guarantee points” into the contract (the manufacturer promises a certain availability for the first year, collects bonus points for meeting targets, demerit points for not doing so, and raises the availability figure with increasing experience with any one model). Even large customers who have their own engineering staff are opting for “power by the hour” contracts with the OEM and leaving all parts replacement decisions to the OEM. This may prove to be expensive, as OEMs make the bulk of their profits with aftersale spares and service. Yet, increasingly U.S. customers expect their OEMs to also do their service, rather than staff up to do their own or even their own assessment of the effectiveness of overhauls. The power producer mix is shifting to include OEMS, oil companies that are also becoming IPPs, SPPs, and hungry MPPs anxious for a quick return. The demand for gas turbines in all sizes and system formats (simple or combined cycles) keeps climbing. The strategy of major OEMs has also been to acquire all the turbine systems accessories and support companies they can. GE is a good illustration of this. By staying abreast of these developments, customers can turn their OEM’s diversification and growth in their favor. Another noteworthy trend among the OEMs is the development of power options that use renewable resources for fuel. It is a considerable goodwill factor in their annual statements bottomline, something that is increasingly acknowledged within the United States. This sometimes can be rewarded with public awards for performance and service. To what extent gas turbine OEMs allow their renewables portfolio to flourish depends on which of their lines (and profitability) will decline if they do. Their overall publicity campaign (e.g. “ecoimagination” ads) support their decisions regarding profitability mix, government contracts sought, and gains in political alliances. OEMs have continued to buy companies, stakes in new technology development, and e-trading businesses, all of which will affect the turbine market, in the United States and globally.

OEM Development Programs with the U.S. Government (DOE)

This has been well illustrated in this book with several case studies of the work done by the OEMs under U.S. DOE (Department of Energy) sponsorship. Oil and Gas Production Portfolios Help OEMs

Examples of this include: GE Energy Rentals bought Jenbacher, an Austrian natural gas power generation reciprocating engines. GE Power Systems purchased Nuovo Pignone (which makes compressors, gas and steam turbines, pumps, and an assortment of process and power accessories), Gemini (which makes reciprocating compressors for natural gas applications), and Thermodyn (which makes small compressors and steam turbines for oil and gas as well as power generation). The larger OEMs’ philosophy seems now to be to maintain a presence with both the fuel supplier and the customer base for their own machines. OEMs Communications Infrastructure Grows Portfolio

A case in point is this: GE bought Young Generators in April 2000, a company that is a leading provider of power generation rental equipment and services for the motion picture, broadcast, and events businesses. This increases GE’s reach with respect to temporary distributed power solutions. “Outage Optimizer” is another Internet service provided by GE. It helps turbine owners plan outages for their machines, evaluate service bids, and purchase them online. Technology Transfer Service Company Acquisitions

Most OEMs have secured technology transfer agreements with highly sophisticated companies that developed specialized repairs: coatings, blade tip robotic welding, powder metallurgy, online wash systems, and so forth. Despite items such as online trading in used or reconditioned parts, sometimes an OEM may make these available to a specific customer only if that client knows enough to ask for the option. (Not all these developments end up as general service bulletins.) To a smaller company, this “current options” information can save a great deal of money. It is always worth a customer’s while to investigate the OEM’s current state of technology share agreements to pursue every last advantage possible in the fight to drive down costs. Where Is the Renewables Market Going?

Staying current with environmental legislation helps direct where OEMs must eventually head. OEMs are aware that the century of renewable energy fuels is anywhere from three to five decades ahead, and they are getting ready. While not in a hurry to abandon their conventional technologies, all of them want to be able to sell their client base fuel cells and tidal turbines when those markets turn profitable. An informed customer will use this to tailor contemporary demand curves within his control to best advantage when in negotiations with the OEM. Accuracy in Reading the Target Market

The end customer must consider an interesting twist to the market equation. It is a consideration tied irrevocably to the changing manufacturing partners, as this affects the largest questions on the purchaser’s mind: How much will good service cost me? Who will provide it? What are their service and engineering philosophies—old, new, negotiated compromise?


Consider that what was ABB Stal’s (now Siemens by acquisition) grass-roots designed GTX-100, 43 MW has not yet made a dent in LM6000 territory. Reasons may include GE’s financial services competence with structuring deals or perhaps a preference for an aeroderivative’s modular design over an industrial one. Will the GTX eventually take a sizable market share because of its ability to withstand dirtier fuels and a wider range of heating values? Using Technology to Advantage

Fuel Technologies The gas turbine continues to burn a widening range of fuels including but not limited to ● ● ● ● ● ●

Residual fuel. Biomass. Waste fluids from petrochemical processes. Waste liquor from paper production. “Syngas.” Pulverized coal.

Designers continue to improve the gas turbine’s technology with respect to burner residence time, flame temperature, cooling, reading hot section temperatures, and so on. Repowering Repowering is a major activity in Europe and the United States. The incentives are adherence to Kyoto objectives, but the higher efficiencies available with gas turbine options can make IPPs far more competitive. Although emissions taxes are not yet reality in Asia, they are in Europe; and the trends will eventually spread. They should, particularly if we look at the economic gains in an example such as the Peterhead station in Scotland. The two boiler, two GE 115 MW Frame 9E station had been designed to operate on heavy fuel oil, LNG, sour gas, and natural gas. In 1998, the decision was made to increase plant capacity with three Siemens Westinghouse V94.3 combined cycle units. The V94.3 is a scaled-up version of the V84.3, which can run at both 60 and 50 cycles. The economics of the situation are heavily influenced by fuel sources now made available by the U.K.’s gas supplies. It is important to note, however, that station efficiency will jump from 38% to between 50 and 55%. NOx emissions will be reduced by 85%. Another major reason for the repowering trend is that what was thought to be 60 years worth of natural gas left in global supply terms was “updated” to 70 years plus recently. Evidence from ongoing exploration indicates that this figure will climb. Despite China’s anxiety to use its coal and the Middle East’s desire to use its residual oil, the trend toward gas turbines burning cleaner fuels will continue as lending agencies increasingly tie up their loans with environmental standards as conditions. As gas turbines get better at burning atomized coal, residual fuel, and other erosive or corrosive fuels, use of the gas turbine will increase. As will use of these fuels—at least until emissions taxes are felt as heavily as they are in countries like Sweden. NOx and SOx taxes will become the norm fairly early in the new millennium, as they are a source of tax revenue from power companies. Deregulation will tend to favor establishing these taxes worldwide. A CO2 tax will soon follow in their wake and, with it, the operational economics that may make more-expensive natural gas start to approach competitiveness with residual fuel and coal. Operational economics consider overall costs per running hour, which includes factors such as TBO (time between overhauls, which extends with cleaner fuels) and longevity of components. The gas turbine then is in the ascendant, the remaining question is, Whose turbine?


The primary reason that gas turbine packages are bought is good financial purchase packages (GE, for instance, excels in the financial arena), not technology. However, good service features (which technology dictates), fuel price, flexibility in terms of choices, and parts longevity are high on that list, too. Desalination A complacent world is getting alarmingly short of fresh drinkable water at a pace that accelerates in proportion to global industrial activity. I ought to say, some countries instead of world, although it may as well be the world. The larger powers have more of all basic resources, including water, and wake up calls, such as part of California’s ground level sinking as it drains its usable water, go relatively unsung in terms of widespread public alarm. On the other hand, gains in fossil fuel reserves, whether by exploration or some new technology, get greater press. We always take for granted what we have in abundance. So it is with the Middle East and her fuel reserves. Always water hungry, however, a new technology that may as yet be underestimated in terms of global reach, now gives the fossil fuel rich moguls a reason to care about efficiency. No doubt, this technology will spread. The Middle East has fuel resources in abundance—natural gas, clean oil, and residual oil—and technology available that will help it burn each of its options with what it terms “acceptable” (not optimum values in most Western countries) efficiency. This technology also helps it achieve its major operational objective, which is to extend time between overhauls and therefore parts life (as defined by life cycle analysis, LCA) over the previous generation of power-producing machinery it operated. Saving fuel for its own sake is not as critical to this market as it is to areas that do not have natural gas and oil in abundance. However, a new reason that the Middle East has for caring about efficiency has emerged in the last decade: desalination. The Middle East is very short of fresh water. How Desalination Works There are many different techniques for desalination. Among the main ones are the multistage flash (MSF) process and reverse osmosis. Qatar’s technology showpieces include the Ras Abu Fontas B power and desalination plant, which cost $1 billion to build. Dubai, in the United Arab Emirates (UAE), has a 60-million-gallon per day desalination plant at Jebel Ali. The plant’s eight MSF units are part of a cogeneration power facility, and the fresh water would have been at least as much incentive in the Middle East as the increased total thermal efficiency. The desalination equipment in both cases was supplied by Weir Westgarth (WW). WW designed the MSF process. The principle of the system is simple: Water and steam in a closed system can be made to boil at temperatures lower than at standard temperature and pressure by reduction of the system pressure. MSF plants contain a series of closed chambers—as many as 20, each held at a lower pressure than the preceding one. Heated saltwater is passed through the overall system. In each chamber, some of the saltwater vaporizes into steam. Moisture droplet separators remove saltwater droplets. The steam condenses to fresh water when faced with cold tubes and is collected for storage. The last chamber’s brine is quite cool, and it is used as the coolant fluid. Then it starts to pick up the latent heat of condensation and increases in temperature. Only a small amount of additional heat investment is required to prepare this stream for entry into the first flash chamber. One source of this steam, of course, is low-pressure steam from a power station. The key to the reverse osmosis (RO) process is a suitable semipermeable membrane. Improvements in membrane



technology now mean that the process can apply to industrialscale plants. Common contemporary membrane selections are made of a cellulose-based polymer or a polyamide layer applied to a microporous polymer film. This membrane is bonded to a porous polyester sheet for structural stiffness. This composite is rolled into a spiral. Spun hollow fine fibers are the finished product. The semipermeable layer is on the outside of the fibers. The total thickness of the composite is about 24 microns. The outside diameter of the tube is about 95 microns, making for a large surface area for rejecting salt. The fibers are made into bundles that are sealed with epoxy in a fiberglass pressure container. The Global Drive for Desalination The main forces behind the optimized commercialization of desalination technology are ironies in the light of conditions in the Middle East. Concern regarding seawater contamination of fresh water aquifers in more freshwater-rich countries was one. (Seawater takes the place of fresh water as the aquifer pressure drops with water extraction.) The need to give nuclear energy a better image (by using its waste heat to produce fresh water) was another. With respect to the first concern, desalination alleviates use of underground fresh water aquifers, which then reduces the risk of seawater seeping in to make up the balance of fresh water pumped out of the ground. Japan is gas and oil poor. A major user of nuclear power, it has been instrumental in promoting the use of desalination processes in conjunction with its nuclear facilities. The water is produced only in enough quantities to be used by the plants themselves. However, the Nuclear Power Technology Development section of the International Atomic Energy Agency (IAEA) has been seeking to promote large-scale desalination in conjunction with nuclear power production since 1989. The IAEA no doubt hopes that a fresh water supply would overcome the general public’s reluctance to be situated close to a nuclear station: Water rises in cost if it has to be transported further. Interestingly, despite the IAEA agreeing that MSF is promising, it does not contemplate using it for any of its large-scale attempts at fresh water production because of its inflexibility at partial load operation. MSF’s tendency to corrosion and scaling versus other desalination techniques does not help either. Metallurgical Selections The amount of seawater handled for a given membrane selection and seawater temperature varies directly as the applied pressure. Gulf seawater typically contains 19,000 ppm of salt. Typical temperature gradients are 20–30°C. Metallic corrosion at 30° is four times what it would be at 20° (double the rate of corrosion for each 5°C rise in temperature). This then requires corrosion-resistant alloy selections for the pumps. To design for a 25-year pump life for a Danish nuclear plant, Alfa Laval used copper nickel alloys in the evaporator and titanium for the heat transfer tubing. Of course, desalinated water requires fewer chemical additives for water treatment. This is an advantage in terms of overall system cost. Optimization of Existing Features and Support Technology Transmission and Distribution Improvements

Some of the easier items to address in the drive for greater efficiency involve retrofitting modern transmission and distribution equipment, including

● ● ●

● ●

Modern voltage regulators. Replacing old conductors. Reactive power compensation equipment, such as static var compensators. Dynamic power compensation equipment. Infrastructure review.

This requires administrative involvement mainly on a national level and less of the international technical involvement that revamping of the power plant machinery often needs. Action items here, among others, are ●

● ●

Improvement of training procedures to reduce outages and inefficiencies not due to equipment. Review of the incentive system for SPPs. Incentives added for SPPs, as these can take up the bulk of a demand curve’s peaking load in a mature economy. Review of the transmission system available to take an SPP’s contribution to the national grid. Countries like Thailand offer SPPs incentive but their contribution is limited by transmission line size. Consideration of the location and performance of substations, although this is best done at design time. For instance, the IPP plant at Kuala Langat, Malaysia, is situated close to one of the national power company’s substations as well as next door to the mill that receives some of its steam.

End-User Associations and Lobbies End-User Associations

End-user associations exist for practically every model in the gas turbine world. For instance, the Alstom-11N population have their own meeting, the GE-7E people meet every year, and every military helicopter engine has its own CIP (component improvement program) meeting. One needs to find one’s own crowd and stay abreast of their global community’s problems. The paradigm “You get what you negotiate” is true with overhaul contracts as much as anything else. When the contracts cross international boundaries, this may be even more accurate. Increasingly, customers need to investigate contract term options with the worldwide client base of their particular original equipment manufacturer. Overhaul contracts are negotiated on a variety of bases. The end user must pick what best befits its application. Power by the hour is one of the most common bases for contracts. Others specify hot section overhaul only, with everything else on an as-needed basis. The term used by some for this kind of contract is hot gas path inspection protection plan. A monthly charge applies per machine. Some power producers turn over overhaul and repair entirely to the OEM or an OEM company. The end user’s aim ought to be to get the best cost per fired hour. The end users with sufficient experience with repair and overhaul, achieve this with a combination of OEM-bought parts and maintenance, independent repair vendor-bought parts and maintenance, some maintenance from in-house end-user staff, and constant experience comparisons with other end users in the business via end-user associations. Two of the most valuable items on which end users can compare notes is independent contractors and spare parts price/power by the hour price variations.


End-user associations force OEMs to accommodate machinery owner priorities and preferences by sheer weight of numbers. Another powerful and growing asset in the quest to reduce overhaul costs is the independent overhaul contractor workforce. Frequently, the main executives at independent overhaul contractors are ex-OEM employees who may have designed or pioneered the technology they now are “going independent on.” Such contractors have an edge over others with “reverse engineering,” the term used to describe working out the steps in the manufacture of a component just by having one physically to work with, without benefit of the OEM’s drawings or designs. Some such contractors will also confidently tackle “re-engineering,” which is actually engineering the manufacture of a component again. Metallurgy, heat treatment, coatings, and so forth may differ from the original in a re-engineered component. Typically, a component is re-engineered to save money, improve its operation or life, or all of these. It requires extreme engineering competence and confidence to do this. It also requires considerable technical competence on the part of the end user to assess such a contractor’s ability to match its claims. When it can, however, the end user stands to save a great deal of money. Therefore, as lost revenue is always a source of ire to the OEM, a further bargaining asset for the end user is available. Such independent overhaul contractors have made considerable strides in the United States and western Europe. This is starkly contrasted against their minimal potential in countries that are, or recently were, communist. An entrepreneur in this sector once mentioned his frustration when visiting Vietnam, when he invited end users to a free seminar on his firm’s range of services. Some of the end users, used in their domestic industrial culture to being totally dependent on the OEM, expected to be paid for listening to the seminar. In newly industrialized countries (NICs), such contractors have been viewed with interest for some time. Growing “trial usage” of their services is underway. These firms are anxious to break into territory traditionally occupied exclusively by the major OEMs. See the Chapter 12, Maintenance, Repair, and Overhaul, for further details. Varying Spare Parts and Service Prices

Spare parts, whether paid for singly or as part of a powerby-the-hour contract, are a major component of overhaul costs. End users sometime stumble upon major differences in prices internationally. A U.S. IPP representative investigating joint venture potential for a company in Pakistan once found that spare parts prices may vary by as much as 300%. To the consumer-power culture in the United States, this seems a large differential. However, the OEM may have built in allowance for “expediting payments” in the chain of customs command in the country in question, which are totally acceptable in the local culture. Also, if the end user is not yet seasoned in the use of the models in question, its expectations of what the warranty may normally exclude (such as component failures resulting from faulty operation) might not be the same as everywhere else. Some OEMs understandably mark up prices for that user to accommodate this difference. Lobbies

The U.S. world is structured based on the work of various lobbyists. Brazil is now fuel independent with its production


of sugar cane ethanol. The U.S. corn lobby is working hard to promote, well, corn, of course. Corn ethanol does not have nearly the environmental advantages of sugar ethanol, but the sugar beet guys in the United States do not have the political power of the corn crowd. In the short term in the United States, natural gas will continue to be used wherever possible and coal will be used where there is a great deal of it (like in West Virginia). Soothsayers claim that the U.S. people will “rise in revolt” when gasoline at the pumps costs between $4 and $5 a gallon (it already has been more than $8 in Europe for a while). Nothing of the kind is likely to happen. The fossil fuel lobbies will continue to promote fossil fuel usage, and the cost increases will be borne by the individual consumers. In the United States, consumers will pay all power bills and car fuel bills and still drive SUVs whenever they can. E-Trading

OEMs now e-trade repair parts, spares, and services. Energy and power companies, which sometimes are their own best customers for the oil and gas they produce, e-trade their products. Secondhand merchants, some of them quite respectable in terms of intent (they check that they are not selling junk or bogus parts or engines) also e-trade. New and Unconventional Fuel Resources

Several of these were discussed earlier in the chapter. Some consideration must be given to the huge deposits of methane hydrates globally. There are about 300 years worth (at current U.S. consumption rates) of natural gas in the hydrates deposits in the Gulf of Mexico. No one has yet figured out how to commercialize the process of bringing the hydrates (solid under a huge wall of water) safely to the surface without destabilizing the seabed around them. Several research branches of government, including the U.S. DOE, the U.S. Geological Survey, and Japan’s powers that be, continue work on the problem. Distributed Power: How Large Does a Power Plant Need to Be? The Age of the Personal Turbine

The age of the personal turbine (PT) will probably arrive in a few decades. LG, a Korean company, and the German Fraunhofer Institute for Solar Energy Systems (ISE) just launched a product that is a fuel cell system integrated into a laptop computer. A mini fuel cell, hydrogen fuel tanks, and electronics have replaced the computer battery. This may be one a series of steps to the day when we carry our personal turbine/computer (PT/ PC) to our car, plug it in, drive to and from work, come home, plug it in, and have our own personal heating system incorporated in this PT, the size of a CD player. Massive transmission line systems may become redundant dinosaurs in many locations. For more information, see Chapter 16, Microturbines, Fuel cells, and Hybrids. The Power Mix

Many countries, including the U.S.’s DOE legislated 10% of the energy mix come from renewables, within varying allocated periods. President Bush’s opinion of CO2 emissions control notwithstanding, the United States is heading in this



direction, if not at the head of the pack. He gained one ally in Australia, inexplicably, given Australia’s previous reputation for caring about their environment. Australia’s prime minister opted to “toe the Bush [U.S.] line” claiming “thousands of Australian jobs will be lost” if his country meets the Kyoto protocol. As it turns out, Australia is closer to the Kyoto targets it negotiated than most countries. The implication to its people of meeting Kyoto is the cost of abating 20 million tons of CO2. This works out to an insignificant $1.95 (2002 prices) rise in their annual power bill: an all-time storm in a kangaroo’s teacup. Case 1. Does California Need Liquefied Natural Gas?*

Our analysis shows that renewables and energy efficiency could produce 133% to 381% of the projected additional gas demand in California by 2016. This report looks critically at natural gas supply and consumption projections and concludes that California’s energy efficiency and renewable energy mandates could readily meet expected additional natural gas demand and, therefore, eliminate the need for LNG import terminals along our coast. Figure 18–1 and Table 18–2 outline how. The conclusion that flat or declining California production requires building LNG import terminals in California fails to take into account several key points, including these. First, the California terminals would far exceed the 355 million cf/d of LNG needed in the next decade—with each terminal capable of funneling 800 million to 1 billion cf/d. The infrastructure created could lock California and other states served by the terminals into natural gas generated electricity for decades to come and give a false sense of comfort, making it difficult to pursue other, more preferable, options such as renewables and energy efficiency. Second, the California Energy Commission’s projections do not include all of the state’s plans, from the California Public *Source: [18-2] Courtesy of the Community Environmental Council, adapted extracts from T. Hunt, A. Chan, J. Phillips, and S. Wright, Does California Need Liquefied Natured Gas? The Potential for Energy Efficiency and Renewable Energy to Replace Future Natural Gas Demand (Santa Barbara, CA: Community Environmental Council, 2006).

Utilities Commission (CPUC) and other state departments, to reduce energy demand through funded demand response and energy efficiency programs (which have reduced statewide power equivalent to twenty 500 MW power plants since 1975) as well as plans for generating more energy from renewable sources. The Energy Commission’s projections do include the CPUC’s energy efficiency programs through 2008, but do not include additional targets through 2013 or later. Similarly, the projections do include the 20% Renewable Portfolio Standard (RPS) by 2010, but not the 33% RPS by 2020 that has been called for by the Governor, the state’s 2005 Energy Action Plan, and SB 107. Nor do the projections include Governor Schwarzenegger’s mandate that all state-owned buildings reduce energy demand by 20% by 2015, or his strong encouragement that non-state owned buildings meet the same goal. Third, the state has made it clear that energy efficiency, demand response, and renewable energy generation are preferred over additional fossil fuel generation, via the state’s Energy Action Plan II (2005), a document jointly produced by the Energy Commission, the CPUC, and the Independent System Operator (an independent agency that manages California’s electricity grid) states. The loading order identifies energy efficiency and demand response as the State’s preferred means of meeting growing energy needs. After cost-effective efficiency and demand response, we rely on renewable sources of power and distributed generation, such as combined heat and power applications. To the extent efficiency, demand response, renewable resources, and distributed generation are unable to satisfy increasing energy and capacity needs, we support clean and efficient fossil-fired generation. Demonstrating the seriousness of this loading order, the CPUC recently approved $2 billion for energy efficiency and demand response programs for the state’s largest three utilities, expected to save $5 billion for consumers and eliminate the need to build three large power plants. Fourth, some California cities will likely increase energy efficiency targets and markets for renewables even further through implementation of the Community Choice Aggregation law (AB 117). This permits cities to aggregate the electric loads of residents, businesses, and municipal facilities, allowing cities to negotiate better rates on behalf of their constituents and/or to purchase renewable electricity

Potential for renewables and efficiency, low Potential for renewables and efficiency, high 2016 new gas demand Large LNG terminal capacity 0

Figure 18–1.



60 80 100 Thousands of GWh



Energy efficiency and renewable energy potential vs. natural gas demand. [18-2]



Some voluntary goals include

Table 18–2. Energy Efficiency and Renewable Energy Total Potential by 2016. [18-2]

Energy Efficiency Potential (GWh) Renewable Energy Potential (GWh) Total (GWh) Percent of projected demand by 2016 Percent of a large LNG import terminal



17,497 32,781 50,278 133% 84%

68,305 75,843 144,148 381% 240%

Note: See the body of this paper for the derivations of each of these numbers.

in higher amounts than would otherwise be the case. Aggregation may also create business opportunities for renewable energy, energy efficiency and conservation by providing new markets for these services. Over 20 local governments examining Community Choice Aggregation in California have adopted an RPS target of 40% by 2017 as a pre-condition for obtaining a low-cost1 feasibility study,2 making it likely that aggregation will lead to a higher level of renewables than without.3 These areas—energy efficiency and conservation goals, the Renewable Portfolio Standard, and community choice aggregation—will greatly reduce the demand for traditional forms of electricity generation, particularly natural gas-fired generation, as well as demand for natural gas for heating and cooking. Since renewable energy and energy efficiency are the officially preferred options, the need for LNG in California should be fully examined because of its potentially detrimental impact on meeting the state’s renewable energy and energy efficiency goals and because it is a less desirable fuel source from an environmental and energy security perspective. In short, the Public Utilities Commission set the state policy gears in motion for construction of LNG import terminals in California after a relatively cursory examination of whether LNG is actually needed in the state, now or at any point in the future. The decision was issued without an examination of the effect of LNG terminals in our state on meeting the preferred energy options: renewables and energy efficiency.


In 2004, the CPUC called on the state’s four largest privately owned utilities to reduce their annual electricity demand by 23,183 GWh by 20134—equivalent to 38% of a large LNG import terminal. For natural gas, the CPUC set an annual reduction goal of 444 million therms by 2013—equivalent to 22% of a large LNG import terminal. With these goals, the CPUC expects energy efficiency to meet 55–59% of the utilities’ additional electricity generation needs between 2004 and 2013. A year later, the CPUC approved $2 billion in funding to ensure that some of the goals outlined in its 2004 decision are met. The plans are expected to reduce electricity demand by 7,371 GWh per year from 2006 to 2008 and reduce natural gas use by 122 megatherms per year from 2006 to 2008—equivalent to 3,575 GWh— for a total of 10,946 GWh per year. These programs will reduce the need for 18% of a large LNG import terminal. Meanwhile, the California Energy Commission and the CPUC outlined a similar goal in their joint Energy Action Plan II, calling for saving 23,000 GWh of electricity per year by 2013 primarily by implementing the state’s most recent energy efficiency standards, such as new Title 24 requirements for new buildings. This amount is not in addition to that called for in the CPUC decision, however. Also addressing building efficiency, California’s Green Building Initiative calls for reducing electricity use by 20% in state-owned buildings by 2015. This amounts to 3870 GWh per year and is equivalent to 6.5% of a large LNG import terminal. In addition, there is substantial potential for energy savings through re-powering California’s aging natural gas-fired power plants. If only 17 of the 25 natural gas plants over 500 MW were re-powered with modern, more efficient gas turbines, 174 billion cubic feet per year would be saved, equivalent to 50,808 GWh and 85% of a large LNG import terminal. Tables 18–3 through 18–5 depict the various calculations discussed in this section.

California’s Renewable Energy Potential California’s Energy Efficiency Potential

From 1975 to 2001, California’s energy efficiency efforts eliminated the need to build more than 10,000 megawatts (MW) of generation capacity, equivalent to 10 large nuclear plants, or 20 large natural gas plants. This is equivalent to 15% of current electricity demand. More recently, during the 2001 energy crisis, Californians successfully reduced their energy consumption significantly, proving their ability to immediately and effectively employ energy efficiency measures.


The bulk of the costs are paid through a grant from the Energy Commission from its Public Goods Charge funds. 2 The studies were financed through a partnership with the Local Government Commission under a grant from the Public Utilities Commission for this purpose. 3 At this point in time, it is impossible to quantify the likely renewable generation capacity, or additional energy efficiency improvements, to be achieved through Community Choice Aggregation, so we mention this development as a qualitative consideration only.

Table 18–6 depicts the energy production under the mandated, or likely to be mandated, renewable energy goals in California. Is California’s Renewable Energy Market Viable?

The following sections discuss estimates of California’s renewable energy potential, from the Energy Commission and other reliable sources. Table 18–7 summarizes the potential from the various renewable resources in California. Wind

In 2004, California generated 4258 GWh of electricity using wind power, 1.5% of the gross system power and equivalent to about 7 of a large LNG import terminal.

4 California Public Utilities Commission. Decision 04-09-060. Sept. 2004, p.10. Available at



Table 18–3.

Current California Energy Efficiency Mandates [18-2]

Efficiency Mandate CPUC mandate to reduce electricity and natural gas demand by 10,946 GWh per year by 2008a Green Building Initiative mandate to reduce electricity use in state-owned buildings by 1935 GWh by 2015b Total percentages

New Natural Gas Demand by 2016

Equivalent Large LNG Terminals

(Already included)







CPUC, D.05-04-093 (Aug. 17, 2005), Attachment 4. The Governor’s Green Building Initiative requires state-owned facilities reduce their energy consumption 20% by 2015. We assume, for this paper, that half of that reduction will occur in non-investor-owned utility territory, such that there is no “double dipping” in accounting for the savings from IOU programs, under the PUC, and the Governor’s independent mandates. Accordingly, 3870 GWh per year represents a 20% reduction in state-owned facilities by 2015, and 1935 GWh represents half that amount. b

Table 18–4.

California’s Non-Mandated Energy Efficiency Goals [18-2]

Efficiency Target

New Natural Gas Demand by 2016

CPUC goal to reduce natural gas consumption by 444 million therms by 2013a CPUC goal to reduce electricity demand by 26,508 GWh by 2013c Total Total GWh

Equivalent Large LNG Terminals




26 %

66% 24,997



CPUC, Decision 04-09-060, p. 10 (Sept., 2004). This figure does not include the three year natural gas savings goals, from 2006-8, already included in the CEC’s natural gas demand assessment. c CPUC, Decision 04-09-060, p. 10 (Sept. 2004). d This figure does not include the three year electricity and natural gas savings goals, from 2006–2008, already included in the CEC’s natural gas demand assessment. b

Table 18–5.

Other Energy Efficiency Potential [18-2]

Efficiency Target Re-power California’s aging non-peaking natural gas plantsa Total GWh per year a

New Natural Gas Demand by 2016

Equivalent Large LNG Terminals




Synapse Energy Economics, Comments of Synapse Energy Economics on the California Natural Gas Utilities’ Phase 1 Proposals. Synapse estimates, using Energy Commission data, that re-powering the 17 oldest plants would eliminate 174 billion cf/y, equivalent to 50,808 GWh per year.


California’s Current and Prospective Renewable Energy Mandates. [18-2]


Generation (GWh)

2016 New Gas Demand

20% by 2010


30% by 2016 33% by 2020

32,781b 47,323c

(Already included) 87% 125%

a b c


Equivalent Large LNG Terminals 49% 55% 79%

20% of projected 2010 electricity demand. This figure does not include the 20% by 2010 amount, so represents new generation above the 20% RPS goal. This figure represents the total new generation by 2020, not already accounted for in the 2010 RPS goal.

Table 18–7.

California’s Renewable Energy Potential [18-2]

Resource Wind Solar PV Solar thermal Concentrating solar Geothermal Biomass/landfill gas Small hydroelectric Ocean power Totals

Estimated Generation by 2017a (GWh)

2016 New Gas Demand

19,760b 4,139c NAd 18,615e 22,654f 35,000g 2,947h 4,728i 107,843

52% 11% NA 49% 60% 93% 8% 12% 285%

Equivalent Large LNG Import Terminals 33% 7% NA 31% 38% 58% 5% 8% 180%

a We project new generation through 2017, instead of 2016, which is the time frame for the Energy Commission’s natural gas assessment, because state agencies have done a considerable amount of work looking at potential by 2017, which was the original date for achieving the 20% RPS. Due to the large leeway our numbers provide in meeting future natural gas demands from renewable energy, this one year discrepancy should not be that important. b California Energy Commission, Renewable Resources Development Report, 2003 (RRDR), p. 98 (estimating 6644 MW of new wind projects throughout California by 2017). The CPUC report, Achieving a 33% Renewable Energy Target (Nov. 2005), finds a larger potential of 6960 MW in California (it also includes consideration of nearby out-of-state resources as a separate figure), plus a separate figure for potential from repowering wind turbines at Altamont Pass (p. 39). We use the lower estimate for present purposes because the CPUC report does not state that this full potential could be developed by 2016, the time frame for our analysis. c Based on the California Solar Initiative’s stated goal, with rebates likely to be approved by the California Public Utilities Commission in January 2006, of 3000 MW of new solar, in addition to the approximately 150 MW already installed in California. This production figure assumes a 15% capacity factor. The CPUC report Achieving a 33% Renewable Energy Target finds a 5000 MW capacity for solar PV (p. 41). We find the lower figure more realistic at this time, but are optimistic that 5000 MW or more will be installed, given the rapid pace of innovation in this technology. d The California Energy Commission does not currently provide an estimate of solar thermal potential in California, either in its 2005 draft solar power assessment or its 2003 renewable resources development report. We hope this oversight will be corrected soon, as solar thermal technologies have vast potential for displacing natural gas and electricity demand, as evidenced by the fact that the largest source of renewable energy in the world (other than large hydroelectric, which is not considered renewable in California) is solar thermal, due largely to the numerous installations in China. e The California Energy Commission estimates 1 million MW of concentrating solar potential in its 2005 draft staff paper on California solar resources, but we don’t believe, for obvious reasons, that anywhere near this amount of CSP will be built by 2017 or even 2027. We have assumed that 10 systems like the 850 MW CSP facility recently approved for SCE by the PUC could be built by 2017, leading to a total of 8,500 MW of CSP by 2017, and 18,615 GWh per year by 2017, at a 25% capacity factor. The CPUC report Achieving a 33% Renewable Energy Target finds a similar potential, at 10,200 MW (p. 41). f California Energy Commission, California Geothermal Resources, CEC-500-2005-070, April 2005, p. 7. The GWh total assumes, as the CEC does, a 90% capacity factor for 2862 MW. The CPUC report Achieving a 33% Renewable Energy Target (Nov. 2005) finds a similar figure of 2565 MW of potential in California (p. 40). g California Energy Commission, Biomass Resources in California: Preliminary 2005 Assessment (April 2005), p. v. The figure cited is the low estimate in that report. The CPUC report Achieving a 33% Renewable Energy Target finds a much lower potential, at 1,775 MW, equivalent to 13,994 GWh (p. 40). The report explained this discrepancy: “Biomass power in general has favorable economics. But the development potential of biomass is contingent on securing long term fuel supplies, with each project requiring a narrow range of fuel specification. Biomass projects tend to be of modest scale and linked geographically to local fuel sources. For these reasons, biomass was only projected to supply 10% of the renewable energy needs” (p. 42). We use the higher estimate due to our expectation that reliable baseload capacity will be developed where it is economically feasible, making biomass generation very attractive where feedstock is available, and due to the more detailed (and more convincing) analysis in the CEC’s Biomass Resources report. h California Energy Commission, draft report, “California Small Hydropower and Ocean Energy Resources” (May 2005), p. 4. i Ibid., p. 16. We ignore the secondary sites identified in this report and assume that only 25% of the primary site potential identified by the Energy Commission will be developed by 2017.



Expanding wind power capacity from the 2,096 MW of capacity in 2004 to about 8,540 MW in 2017, as is expected by the Energy Commission, would produce 19,760 GWh per year, equivalent to 33% of a large LNG import terminal. The technical potential for wind power is of course much larger—the Energy Commission recently estimated 127,000 MW of potential in the state. Solar

Solar energy is another renewable resource that is easily accessible in many parts of California with significant expansion potential. The technical potential for photovoltaic and concentrating solar power systems in California exceeds 17 million MW. The state currently has about 60,000 MW of generation capacity. The Governor’s goal of 3000 MW of new solar PV installed by 2016 is attainable, in light of the CPUC’s recent approval of a new system of rebates over an 11-year period. Solar photovoltaic technology is still the most expensive of the renewable technologies and is dependent on incentives for its success. In addition, 16 counties throughout the state receive an annual average of solar radiation of 6 kWh per day per square meter—enough to meet the requirement for concentrating solar power (CSP) systems. CSP is generally utility-scale solar, so may lead to much larger capacity additions than solar PV. This insolation data leads to a technical CSP potential in California of over 1 million MW of capacity, capable of producing about 2.7 million GWh. Again, the state’s total generation capacity today is about 60,000 MW, so this potential is about 15 times the total generation in California today. As CSP technology improves, many other areas of the state will be suitable for CSP, not just the 16 counties described in the CEC study. Moreover, with existing technologies such as those used in Kramer Junction, California, a natural gas generator can be integrated into the CSP plant, making it appropriate for any insolation level since natural gas backup can operate any time there is insufficient insolation for CSP generation alone. The Kramer Junction trough-system plants have achieved on-peak capacity as high as 80% with solar alone, but over 100% of capacity by using the gas assist generator to sell additional amounts of peak power. By 2016, the construction of 10 CSP plants similar to that being built near Barstow for Southern California Edison, or 850 MW at full capacity, is likely. We believe it is realistic to expect 8500 MW of CSP plants to be built in California by 2016, or shortly thereafter—a tiny fraction of the technical potential—utilizing either dish systems or trough systems. (Our estimate is based on recent advances in Stirling engine technology and a resurgence of interest in trough systems.) This estimate of 8,500 MW of CSP would produce about 18,615 GWh per year, at a 25% capacity factor, or about one third of a large LNG import terminal. A poll of CSP manufacturers taken by the Western Governors Association found that the industry could supply the southwestern U.S. with up to 13 GW of CSP by 2015. Given the fact that California has approximately the same power demand as the entire western states combined (excluding Texas), it is not unreasonable to project 8500 MW being built in the state. This conclusion is reinforced when we consider the strong renewable energy and climate change policies already enacted in California. If thermal energy storage systems currently being examined by the industry, such as molten salt systems, are

included with trough or dish systems, capacity factors could be as high as 60%, much higher than the current 25%. This conclusion is based on the 60% capacity factor achieved with Solar Two’s (a now defunct solar power tower array) thermal energy storage system in California during the 1990s. Geothermal

Though wind and solar resources have perhaps the largest potential in California, geothermal, biomass, and small hydroelectric facilities currently contribute more to California’s total renewable energy resource base. Geothermal power contributed 13,571 GWh, or about 4.9% of the gross system power in 2004. The Western Governors’ Association’s Clean and Diversified Energy Advisory Committee found, in a recent draft report, 2,400 MW of new geothermal capacity in California— capable of producing as much as 15,768 GWh per year. The Energy Commission reported a slightly larger potential of 2,862 MW, or 22,564 GWh per year, in its 2005 geothermal resources report. Biomass and Waste to Energy

Biomass energy is generated from organic wastes such as woody agricultural wastes and forest thinnings. Biomass power plants provided 5997 GWh of electricity in California in 2004–about 2.2% of the gross system power. In its 2005 updated biomass assessment, the Energy Commission found an additional technical potential of 4700 MW of biomass power by 2017, using current technologies. The report also estimates a 7,100 MW potential in a best case scenario and states that as much as 60,000 GWh per year could be generated from biomass by 2017—but acknowledges this is an optimistic projection. Taking the more realistic potential of 4,700 MW, or 35,000 GWh, per year by 2017 is a reasonable estimate of production. Small Hydroelectric

Small hydroelectric plants (30 MW capacity or less) are considered renewable due to the relatively small amount of water required for their operation and consequent minimal environmental impacts when compared to large hydroelectric projects. In 2004, about 1.7% of the electricity generated in California was produced by small hydroelectric plants. Small hydroelectric power potential is estimated at 2280 GWh from new facilities,5 plus 667 GWh from water pipelines among municipal water utilities and irrigation districts. Ocean Power

The ocean is also a viable resource for energy production, especially in California. Wave power along the coast—from surface wave energy conversion alone—has a technical potential of 18,912 GWh, at primary sites only. We are, for the purposes of this report, not considering the secondary sites that the Energy Commission’s consultant also considered, which amount to 75% of the potential of the primary sites in terms of GWh of production. We also assume that only 25% of the primary site potential will be developed by 2017, resulting in 4728 GWh of ocean power, equivalent to 8% of a large LNG import terminal. We also do not consider the potential of current power devices, which may be appropriate in some locations along our coast.

5 California Energy Commission, California Small Hydropower and Ocean Wave Energy Resources, CEC-500-2005-074, April 2005, p. 4.

FUTURE TRENDS IN THE GAS TURBINE INDUSTRY Table 18–8. Summary of Energy Efficiency and Renewable Energy Mandates [18-2]

Low Estimate Energy efficiency mandates (GWh) Renewable energy mandates (GWh) Total (GWh) Percent of a large LNG import terminal

Table 18–9. Energy Efficiency and Renewable Energy Total Potential [18-2]

High Estimate



29,533 42,414

64,781a 77,662




This figure represents 32,781 GWh of new generation by 2016 plus 32,000 GWh already included in the Energy Commissions’ natural assessment, representing new renewable generation by 2010.

Energy efficiency potential (GWh) Renewable energy potential (GWh) Total (GWh) Percent of projected demand by 2016 Percent of a large LNG import terminal

Additional Supplies of Natural Gas in North America

It is certainly possible that the state will not meet its renewable energy mandates by 2010, let alone the likely new mandate of 3% by 2020. It is even possible that the CPUC’s ambitious and funded energy efficiency programs with the investor-owned utilities will not produce expected savings. We believe this possibility is unlikely, but we have to consider it. However, even if the state slips in meeting its own mandates, California need not be overly concerned about natural gas supplies, as significant additional supplies will come online in North America in the next decade from a number of sources: ●


Domestic U.S. natural gas production is expected to increase over the next decade, while Canadian imports are projected to decrease. However, the decrease from Canada is projected to be more than offset by increases in U.S. production.6 Pipeline bottlenecks for natural gas deliveries to California have, according to the Energy Commission, been resolved such that the historical price differentials between California and the rest of the U.S. have disappeared. Three LNG import terminals have been approved by the Mexican government for Baja California and will provide over 2.4 billion cubic feet per day of natural gas to Mexico and the U.S. This figure may soon be increased by 1.5 bcf/d because Sempra, the company currently building the first of these terminals, has, as mentioned, requested an expansion of its 1 bcf/d facility to 2.5 bcf/d, half of which is slated for the U.S. The Energy Commission expects the first of these Mexican plants to be online by 2008 and also expects a portion of this gas to service the San Diego region. Thirteen additional LNG import terminals (or expansions of existing terminals) have been approved in the U.S., outside of California, and 25 other projects have been proposed for other sites within the U.S.





17,497 32,781 50,278 133% 84%

68,305 75,843 144,148 381% 240%

A consortium of oil companies has proposed a natural gas pipeline from Alaska and Canada to the contiguous U.S. This project will provide 1.5 to 2.0 trillion cubic feet of natural gas per year and should be completed by 2016. If completed, this pipeline would forestall the apparent peak in North American natural gas production by a number of years because it would provide access to otherwise stranded natural gas resources. An additional pipeline, from the MacKenzie region of Canada’s Yukon, is expected to be online by 2013. If this pipeline comes online, it will forestall by a number of years the expected declines in Canadian production.

Although it is impossible to predict where exactly these additional natural gas supplies will be used in the contiguous U.S., they could provide additional downward pressure on North American natural gas prices and ease any supply constraints to California. We are not here endorsing any LNG import terminals in other states or outside of the U.S. However, we do acknowledge that additional supplies from sources outside of California have either already received permitting approval and are being constructed, or will likely receive approval and be constructed at some point before 2016. State and federal planners need to consider that these additional supplies are coming online over the next decade when making any decision about LNG import terminals not yet approved for construction, in a similar calculus to that provided above for renewable energy and energy efficiency. It is evident that significant new natural gas supplies will soon be available in the U.S. and that additional downward pressure on natural gas prices will be exerted, even if California builds no LNG import terminals. Additionally, previous natural gas pipeline constraints into California from other western states have been resolved, making it much easier to transport additional natural gas supplies from elsewhere in the U.S. to California. Tables 18–8 and 18–9 summarize the energy efficiency and renewable energy potential in California. It should be clear at this point that energy efficiency and renewable energy could readily replace the need for any LNG import terminals in California.

Basic Design Theory


“Never mistake motion for action.” —Ernest Hemingway

Contents Operational Envelope 680 The Environmental Envelope 680 Installation Pressure Losses 687 The Flight Envelope 689 Properties and Charts for Dry Air, Combustion Products, and Other Working Fluids 692 Description of Fundamental Gas Properties 692 Description of Key Thermodynamic Parameters 693 Composition of Dry Air and Combustion Products 693 The Use of CP and Gamma, or Specific Enthalpy and Entropy, in Calculations 694 Database for Fundamental and Thermodynamic Gas Properties 694 Formulae 699 “Design Point” Engine Design, Definitions, and Terminology 701 Design Point Performance Parameters, Definitions 702 Linearly Scaling Components and Engines 704 Design Point Exchange Rates 704 Open Shaft Power Cycles 704 Combined Heat and Power 706 Closed Cycles 706 Aircraft Engine Shaft Power Cycles 706 The Engine Concept Design Process 706 Margins Required When Specifying Target Performance Levels 707 Case 1. Prediction Effects of Mass-Transfer Cooling on the Blade-Row Efficiency of Turbine Airfoils 708 One-Dimensional Methods 710 The TOTLOS Method 712 Case 2. Advanced Technology Engine Supportability: Preliminary Designer’s Challenge 714 Historical Trends/Recent GEAE Experience 715 Advanced Materials 715 Engine Preliminary Design 716 Specific Examples 716



At some point, a gas turbine operations or repair and overhaul engineer has to consider the design of the gas turbine package in his or her care. This may be for ● ● ● ●

Specification of a new package or system. An engineering a retrofit package. Arguing a warranty case. Troubleshooting or failure analysis.

Regardless of the reason for a look at the gas turbine system design, it is useful to know the terminology and basic theory behind the OEM’s design. What follows is a summary of an OEM’s basic theory and terminology in the design areas of ● ●

Operational envelope. Properties and charts for dry air, combustion products, and other working fluids. “Design point” definitions and terminology.

After these sections, there are two case studies and a Mach number/altitude chart developed by an aircraft engine designer. The very basic thermodynamic laws and cycle diagrams used by operational engineers with little or no design (retrofit or otherwise) or specification responsibility are in the chapter on gas turbine cycles. Operational Envelope*

The performance—thrust or power, fuel consumption, temperatures, shaft speeds etc.—of a gas turbine engine is crucially dependent upon its inlet and exit conditions. The most important items are pressure and temperature, which are determined by the combination of ambient values and any changes due to flight speed, or pressure loss imposed by the installation. The full range of inlet conditions that a given gas turbine engine application could encounter is encompassed in the operational envelope. This comprises: ●

● ●

An environmental envelope, defining ambient pressure, temperature, and humidity Installation pressure losses A flight envelope for aircraft engines

The Environmental Envelope

The environmental envelope for an engine defines the range of ambient pressure (or pressure altitude), ambient temperature, and humidity throughout which it must operate satisfactorily. These atmospheric conditions local to the engine have a considerable effect upon its performance. International Standards

The International Standard Atmosphere (ISA) defines standard day ambient temperature and pressure up to an

altitude of 30,500 m (100,066 ft). The term ISA conditions alone would imply zero relative humidity. US Military Standard 210 (MIL 210) is the most commonly used standard for defining likely extremes of ambient temperature versus altitude. This is primarily an aerospace standard, and is also widely used for land based applications though with the hot and cold day temperature ranges extended. Table 19–1 shows the ambient pressure and temperature relationships of MIL 210 and ISA. For land based engines, performance data is frequently quoted at the single point ISO conditions, as stipulated by the International Organization for Standardization (ISO). These are: ● ● ● ●

101.325 kPa (14.696 psia), sea level, ambient pressure 15°C ambient temperature 60% relative humidity Zero installation pressure losses

Ambient Pressure and Pressure Altitude

Pressure altitude, or geo-potential altitude, at a point in the atmosphere is defined by the level of ambient pressure, as per the International Standard Atmosphere. Pressure altitude is therefore not set by the elevation of the point in question above sea level. For example, due to prevailing weather conditions a ship at sea may encounter a low ambient pressure of, say, 97.8 kPa, and hence its pressure altitude would be 300 m. Table 19–1 includes the ISA definition of pressure altitude versus ambient pressure, and Figure 19–1 shows the relationship graphically. It will be observed that pressure falls exponentially from its sea level value of 101.325 kPa (14.696 psia) to 1.08 kPa (0.16 psia) at 30,500 m (100,066 ft). The highest value of ambient pressure for which an engine would be designed is 108 kPa (15.7 psia). This would be due to local conditions and is commensurate with a pressure altitude of −600 m (−1968 ft). Ambient Temperature

Table 19–1 also presents the ISA standard day ambient temperature, together with MIL 210 cold and hot day temperature, versus pressure altitude. Figure 19–2 shows these three lines of ambient temperature plotted versus pressure altitude. Standard day temperature falls at the rate of approximately 6°C per 1000 m (2°C for 1000 ft) until a pressure altitude of 11,000 m (36,089 ft), after which it stays constant until 25,000 m (82,000 ft). This altitude of 11,000 m is referred to as the tropopause; the region below this is the troposphere, and that above it the stratosphere. Above 25,000 m standard day temperature rises again. The minimum MIL 210 cold day temperature of 185.9 K (−87.3°C) occurs between 15,545 m (51,000 ft) and 18,595 m (61,000 ft). The maximum MIL 210 hot day temperature is 312.6 K (39.5 °C) at sea level. Relative Density and the Speed of Sound

*Source: Courtesy Rolls Royce, Gas Turbine Performance, Walsh and Fletcher, Blackwell Science. Adapted with permission. The reader ought to note that this section., while covering the basics required for this book, is abbreviated considerably from the original work. Gas turbine “pure design” engineers ought therefore to consider getting the source book for design calculations.

Relative density is the atmospheric density divided by that for an ISA standard day at sea level. Table 19–1 includes relative density, the square root of relative density, and the speed of sound for cold, hot and standard days. Figures 19–3 through 19–5 present this data graphically. These parameters are important

Table 19–1.

Ambient Conditions versus Pressure Altitude (Source: Rolls Royce.)

MIL STD 210A Cold Atmosphere Pressure Pressure Altitude (kPa) (m)

Temp (K)

Standard Atmosphere

MIL STD 210A Hot Atmosphere

Relative Density

√Relative Density

Speed of Sound (kt)

Temp (K)

Relative Density

√Relative Density

Speed of Sound (kt)

Temp (K)

Relative Density

√Relative Density

1.298 1.226 1.158 1.095 1.042 1.004 0.973 0.944 0.915 0.887 0.860 0.833 0.807 0.783 0.761 0.741 0.722 0.703 0.685 0.667 0.649 0.632 0.615 0.599 0.582 0.567 0.551 0.536 0.521 0.507 0.493 0.479 0.466 0.453

1.139 1.107 1.076 1.046 1.021 1.002 0.987 0.972 0.957 0.942 0.927 0.913 0.898 0.885 0.872 0.861 0.850 0.839 0.828 0.817 0.806 0.795 0.784 0.774 0.763 0.753 0.742 0.732 0.722 0.712 0.702 0.692 0.682 0.673

581.0 589.0 596.9 604.7 610.7 612.8 612.8 612.8 612.8 612.8 612.8 612.8 612.8 612.4 611.1 609.3 607.4 605.5 603.6 601.7 599.7 597.8 595.8 593.8 591.8 589.7 587.7 585.5 583.5 581.3 579.2 577.0 574.9 572.7

288.2 286.6 284.9 283.3 281.7 280.0 278.4 276.8 275.2 273.5 271.9 270.3 268.6 267.0 265.4 263.8 262.1 260.6 258.9 257.3 255.7 254.1 252.4 250.8 249.2 247.5 245.9 244.3 242.7 241.0 239.4 237.8 236.2 234.5

1.000 0.976 0.953 0.930 0.907 0.885 0.864 0.842 0.822 0.801 0.781 0.761 0.742 0.723 0.705 0.686 0.669 0.651 0.634 0.617 0.601 0.585 0.569 0.554 0.538 0.524 0.509 0.495 0.481 0.468 0.454 0.441 0.429 0.416

1.000 0.988 0.976 0.964 0.953 0.941 0.929 0.918 0.906 0.895 0.884 0.873 0.861 0.850 0.839 0.829 0.818 0.807 0.796 0.786 0.775 0.765 0.754 0.744 0.734 0.724 0.714 0.704 0.694 0.684 0.674 0.664 0.655 0.645

661.7 659.8 658.0 656.1 654.2 652.3 650.4 648.5 646.6 644.7 642.8 640.9 639.0 637.1 635.1 633.2 631.2 629.3 627.3 625.3 623.4 621.4 619.4 617.4 615.4 613.4 611.4 609.3 607.4 605.3 603.2 601.2 599.2 597.1

312.6 310.9 309.1 307.4 305.6 303.8 302.1 300.3 298.5 296.7 294.8 293.0 291.2 289.5 287.8 286.1 284.4 282.6 280.8 279.1 277.3 275.5 273.7 271.9 270.2 268.5 266.8 265.1 263.4 261.7 259.9 258.2 256.5 254.7

0.922 0.900 0.878 0.857 0.836 0.816 0.796 0.777 0.757 0.739 0.720 0.702 0.685 0.667 0.650 0.633 0.616 0.600 0.585 0.569 0.554 0.539 0.525 0.511 0.497 0.483 0.469 0.456 0.443 0.431 0.419 0.407 0.395 0.383

0.960 0.949 0.937 0.926 0.914 0.903 0.892 0.881 0.870 0.859 0.849 0.838 0.827 0.817 0.806 0.796 0.785 0.775 0.765 0.754 0.744 0.734 0.724 0.715 0.705 0.695 0.685 0.675 0.666 0.656 0.647 0.638 0.628 0.619

Speed of Sound (kt)

(a) SI units: 0–15,000 m 101.325 98.362 95.460 92.631 89.873 87.180 84.558 81.994 79.496 77.060 74.683 72.367 70.106 67.905 65.761 63.673 61.640 59.657 57.731 55.852 54.022 52.242 50.507 48.820 47.178 45.584 44.033 42.525 41.063 39.638 38.254 36.909 35.601 34.330

222.1 228.2 234.4 240.6 245.3 247.1 247.1 247.1 247.1 247.1 247.1 247.1 247.1 246.8 245.7 244.2 242.7 241.2 239.7 238.2 236.6 235.1 233.5 231.9 230.4 228.8 227.2 225.6 224.0 222.3 220.7 219.0 217.4 215.8

689.0 687.1 685.2 683.3 681.3 679.3 677.3 675.4 673.3 671.3 669.2 667.2 665.2 663.2 661.3 659.3 657.3 655.3 653.2 651.2 649.1 647.0 644.9 642.8 640.8 638.8 636.8 634.7 632.7 630.6 628.5 626.5 624.3 622.2




0 250 500 750 1,000 1,250 1,500 1,750 2,000 2,250 2,500 2,750 3,000 3,250 3,500 3,750 4,000 4,250 4,500 4,750 5,000 5,250 5,500 5,750 6,000 6,250 6,500 6,750 7,000 7,250 7,500 7,750 8,000 8,250


Ambient Conditions versus Pressure Altitude (Source: Rolls Royce.)—Cont'd.

MIL STD 210A Cold Atmosphere

Standard Atmosphere

MIL STD 210A Hot Atmosphere

Pressure Pressure (kPa) Altitude (m)

Temp (K)

Relative Density

√Relative Density

Speed of Sound (kt)

Temp (K)

Relative Density

√Relative Density

Speed of Sound (kt)

Temp (K)

Relative Density

√Relative Density

8,500 8,750 9,000 9,250 9,500 9,750 10,000 10,250 10,500 10,750 11,000 11,250 11,500 11,750 12,000 12,250 12,500 12,750 13,000 13,250 13,500 13,750 14,000 14,250 14,500 14,750 15,000

214.1 212.3 210.6 209.1 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 207.0 205.1 202.7 200.3 197.9 195.4 193.0 190.7 188.7

0.440 0.427 0.415 0.403 0.390 0.375 0.361 0.348 0.335 0.322 0.309 0.297 0.286 0.275 0.264 0.254 0.244 0.235 0.227 0.220 0.214 0.208 0.203 0.197 0.192 0.187 0.182

0.663 0.654 0.644 0.635 0.624 0.613 0.601 0.590 0.578 0.567 0.556 0.545 0.535 0.524 0.514 0.504 0.494 0.485 0.476 0.469 0.463 0.456 0.450 0.444 0.438 0.432 0.426

570.4 568.1 565.9 563.8 562.3 562.3 562.3 562.3 562.3 562.3 562.3 562.3 562.3 562.3 562.3 562.3 562.3 562.3 560.9 558.3 555.1 551.8 548.4 545.0 541.6 538.4 535.6

232.9 231.3 229.7 228.0 226.4 224.8 223.2 221.5 219.9 218.3 216.7 216.7 216.7 216.7 216.7 216.7 216.7 216.7 216.7 216.7 216.7 216.7 216.7 216.7 216.7 216.7 216.7

0.404 0.392 0.381 0.369 0.358 0.347 0.337 0.327 0.317 0.307 0.297 0.286 0.275 0.264 0.254 0.244 0.234 0.225 0.217 0.208 0.200 0.193 0.185 0.178 0.171 0.164 0.158

0.636 0.626 0.617 0.608 0.599 0.589 0.580 0.571 0.563 0.554 0.545 0.534 0.524 0.514 0.504 0.494 0.484 0.475 0.466 0.456 0.447 0.439 0.430 0.422 0.414 0.406 0.398

595.0 592.9 590.9 588.7 586.6 584.6 582.4 580.3 578.2 576.0 573.9 573.9 573.9 573.9 573.9 573.9 573.9 573.9 573.9 573.9 573.9 573.9 573.9 573.9 573.9 573.9 573.9

252.9 251.2 249.5 247.9 246.2 244.6 242.9 241.2 239.7 238.2 236.7 235.2 233.6 232.1 231.0 230.6 230.8 231.0 231.1 231.3 231.5 231.8 232.0 232.2 232.4 232.6 232.8

0.372 0.361 0.350 0.340 0.329 0.319 0.310 0.300 0.290 0.281 0.272 0.263 0.255 0.246 0.238 0.229 0.220 0.211 0.203 0.195 0.187 0.180 0.173 0.166 0.160 0.153 0.147

0.610 0.601 0.592 0.583 0.574 0.565 0.556 0.548 0.539 0.530 0.521 0.513 0.505 0.496 0.488 0.479 0.469 0.460 0.451 0.442 0.433 0.424 0.416 0.408 0.399 0.391 0.384

33.096 31.899 30.740 29.616 28.523 27.463 26.435 25.441 24.475 23.540 22.628 21.758 20.914 20.106 19.331 18.583 17.862 17.176 16.512 15.872 15.257 14.669 14.105 13.558 13.034 12.530 12.045

Speed of Sound (kt) 620.0 617.9 615.8 613.8 611.8 609.7 607.6 605.6 603.6 601.7 599.8 597.9 595.9 593.9 592.5 592.0 592.3 592.5 592.8 593.0 593.2 593.5 593.8 594.1 594.3 594.6 594.9


Table 19–1.

(b) SI units: 15,250–30,500 m 15,250 15,500 15,750 16,000 16,250 16,500 16,750 17,000 17,250 17,500 17,750 18,000 18,250 18,500 18,750 19,000 19,250 19,500 19,750 20,000 20,250 20,500 20,750 21,000

11.579 11.131 10.702 10.287 9.889 9.509 9.142 8.789 8.446 8.118 7.806 7.502 7.213 6.936 6.668 6.410 6.162 5.924 5.695 5.475 5.263 5.060 4.864 4.676

187.1 186.1 185.9 185.9 185.9 185.9 185.9 185.9 185.9 185.9 185.9 185.9 185.9 185.9 186.8 188.1 189.5 190.9 192.2 193.5 194.7 195.9 197.0 198.1

0.176 0.170 0.164 0.157 0.151 0.145 0.140 0.134 0.129 0.124 0.119 0.115 0.110 0.106 0.102 0.097 0.092 0.088 0.084 0.080 0.077 0.073 0.070 0.067

0.420 0.412 0.405 0.397 0.389 0.381 0.374 0.367 0.359 0.352 0.346 0.339 0.332 0.326 0.319 0.311 0.304 0.297 0.290 0.284 0.277 0.271 0.265 0.259

533.2 531.9 531.6 531.6 531.6 531.6 531.6 531.6 531.6 531.6 531.6 531.6 531.6 531.6 532.8 534.8 536.7 538.7 540.5 542.3 544.0 545.6 547.2 548.8

0.152 0.146 0.140 0.135 0.130 0.125 0.120 0.115 0.111 0.107 0.102 0.098 0.095 0.091 0.088 0.084 0.081 0.078 0.075 0.072 0.069 0.066 0.064 0.061

0.390 0.382 0.375 0.367 0.360 0.353 0.346 0.340 0.333 0.326 0.320 0.314 0.308 0.302 0.296 0.290 0.284 0.279 0.273 0.268 0.263 0.258 0.253 0.248

573.9 573.9 573.9 573.9 573.9 573.9 573.9 573.9 573.9 573.9 573.9 573.9 573.9 573.9 573.9 573.9 573.9 573.9 573.9 573.9 573.9 573.9 573.9 573.9

233.1 233.2 233.3 233.4 233.5 233.6 233.7 233.7 233.8 233.9 234.0 234.1 234.2 234.2 234.3 234.4 234.5 234.6 234.7 234.8 234.9 235.1 235.4 235.6

0.141 0.136 0.130 0.125 0.120 0.116 0.111 0.107 0.103 0.099 0.095 0.091 0.088 0.084 0.081 0.078 0.075 0.072 0.069 0.066 0.064 0.061 0.059 0.056

0.376 0.368 0.361 0.354 0.347 0.340 0.334 0.327 0.321 0.314 0.308 0.302 0.296 0.290 0.284 0.279 0.273 0.268 0.263 0.258 0.252 0.247 0.242 0.238

595.2 595.4 595.5 595.6 595.7 595.9 596.0 596.0 596.1 596.2 596.4 596.5 596.6 596.7 596.8 596.9 597.1 597.2 597.3 597.4 597.5 597.8 598.1 598.5


Notes: The source for this chart provides data for up to 100,200 m pressure altitude. To convert kt to m/s multiply by 0.5144. To convert kt to km/h multiply by 1.8520. To convert K to °C subtract 273.15. To convert K to °R multiply by 1.8. To convert K to °F multiply by 1.8 and subtract 459.67. Density at ISA sea level static = 1.2250 kg/m3. Standard practice is to interpolate linearly between altitudes listed.

216.7 216.7 216.7 216.7 216.7 216.7 216.7 216.7 216.7 216.7 216.7 216.7 216.7 216.7 216.7 216.7 216.7 216.7 216.7 216.7 216.7 216.7 216.7 216.7




Figure 19–1.

Ambient pressure versus pressure altitude. (Source: Rolls Royce.)

Figure 19–2.

Ambient temperature versus pressure altitude. (Source: Rolls Royce.)

in understanding the interrelationships between the different definitions of flight speed. Density falls with pressure altitude such that at 30,500 m (100,066 ft) it is only 1.3% of its sISA sea level value.

The maximum speed of sound of 689.0 kt (1276 km/h, 792.8 mph) occurs on a hot day at sea level. The minimum value is 531.6 kt (984.3 km/h, 611.6 mph), occurring between 15,545 m (51,000 ft) and 18,595 m (61,000 ft).


Figure 19–3.

Relative density versus pressure altitude. (Source: Rolls Royce.)

Figure 19–4.

Square root of relative density versus pressure altitude. (Source: Rolls Royce.)

Specific and Relative Humidity

Atmospheric specific humidity is variously defined either as: 1. the ratio of water vapor to dry air by mass 2. the ratio of water vapor to moist air by mass


The former definition is used exclusively herein; for most practical purposes the difference is small anyway. Relative humidity is specific humidity divided by the saturated value for the prevailing ambient pressure and temperature.



Figure 19–5.

Speed of sound versus pressure altitude. (Source: Rolls Royce.)

Humidity has the least powerful effect upon engine performance of the three ambient parameters. Its effect is not negligible, however, in that it changes the inlet air’s molecular weight, and hence basic properties of specific heat and gas constant. In addition, condensation may occasionally have gross effects on temperature. Wherever possible humidity effects should be considered, particularly for hot days with high levels of relative humidity. For most gas turbine performance purposes, specific humidity is negligible below 0°C, and also above 40°C. The latter is because the highest temperatures only occur in desert conditions, where water is scarce. MIL 210 gives 35°C as the highest ambient temperature at which to consider 100% relative humidity. Figure 19–6 presents specific humidity for 100% relative humidity versus pressure altitude for cold, standard, and hot days. For MIL 210 cold days specific humidity is almost zero for all altitudes. The maximum specific humidity will never exceed 4.8%, which would occur on a MIL 210 hot day at sea level. In the troposphere (i.e. below 11,000 m) specific humidity for 100% relative humidity falls with pressure altitude, due to the falling ambient temperature. Above that, in the stratosphere, water vapor content is negligible, almost all having condensed out at the colder temperatures below. Figure 19–7 and 19-8 facilitate conversion of specific and relative humidities. Figure 19–7 presents specific humidity versus ambient temperature and relative humidity at sea level. For other altitudes Figure 19–8 presents factors to be applied to the specific humidity obtained from Figure 19–7. For a given relative humidity specific humidity is higher at altitude because whereas water vapor pressure is dependent only on temperature, air pressure is significantly lower.

Industrial Gas Turbines

The environmental envelope for industrial gas turbines, both for power generation and mechanical drive applications, is normally taken from Table 19–1 up to a pressure altitude of around 4500 m (or 15,000 ft). Hot and cold day ambient temperatures beyond those of MIL 210 are often used, ±50°C being typical at sea level. For specific fixed locations, altitude is known, and S curves are available defining the annual distribution of ambient temperature: these allow lifing assessments and rating selection. (The name derives from the characteristic shape of the curve, which plots the percentage of time for which a particular temperature level would be exceeded.) The range of specific humidities for an industrial gas turbine would be commensurate with 0–100% relative humidity over most of the ambient temperature range, with some alleviation at the hot and cold extremes. Automotive Gas Turbines

Most comments are as per industrial engines, except that narrowing down the range of ambient conditions for a specific application based on a fixed location is not appropriate. Marine Gas Turbines

The range of pressure altitudes at sea is governed by weather conditions only, as the element of elevation that significantly affects all other gas turbine types is absent. The practice of the US Navy, the most prolific user of marine gas turbines, is to take the likely range of ambient pressure as 87–108 kPa (12.6–15.7 psia). This corresponds to a pressure altitude variation of −600–1800 m (−1968–5905 ft).


Figure 19–6.


Specific humidity versus pressure altitude for 100% relative humidity. (Source: Rolls Royce.)

At sea, free stream air temperature (i.e. that not affected by solar heating of the ship’s decks) matches sea surface temperature, day or night. Owing to the vast thermal inertia of the sea there is a significant reduction in the range of ambient temperature that marine gas turbines encounter when on the open sea relative to land based or aircraft gas turbines. However ships must also be able to operate close to land, including polar ice fields and the Persian Gulf. Consequently for operability (if not lifing) purposes, a wide range of ambient temperature would normally be considered for a marine engine. The most commonly used ambient temperature range is that of the U.S. Navy, which is −40–50°C. U.S. Navy ratings are proven at 38°C, giving some margin on engine life. The relative humidity range encountered by a marine gas turbine would be unlikely to include zero, due to the proximity of water. In practice values above 80% are typical. The upper limit would be commensurate with 100% relative humidity over most of the ambient temperature range, again with some alleviation at the hot and cold extremes. Aircraft Engines

The environmental envelope for aircraft engines is normally taken from Table 19–1 up to the altitude ceiling for the aircraft. The specific humidity range is that corresponding to zero to 100% relative humidity as per Figure 19–6.

plane for thrust engines. When installation pressure losses, together with other installation effects, are included the resultant level of performance is termed installed. For industrial, automotive, and marine engines installation pressure losses are normally imposed by plant intake and exhaust ducting. For aircraft engines there is usually a flight intake upstream of the engine inlet flange which is an integral part of the airframe as opposed to the engine; however for high bypass ratio turbofans there is not normally an installation exhaust duct. An additional item for aircraft engines is intake ram recovery factor. This is the fraction of the free stream dynamic pressure recovered by the installation or flight intake as total pressure at the engine intake front face. Pressure losses due to installation ducting should never be approximated as a change of pressure altitude reflecting the lower inlet pressure at the engine intake flange. While intake losses do indeed lower inlet pressure, exhaust losses raise engine exhaust plane pressure. Artificially changing ambient pressure clearly cannot simulate both effects at once. For industrial, automotive, and marine engines installation pressure losses are most commonly expressed as mm H2O, where 100 mm H2O is approximately 1% total pressure loss at sea level (0.981 kPa, 0.142 psi). For aircraft applications installation losses are more usually expressed as a percentage loss in total pressure (%∆P/P).

Installation Pressure Losses

Engine performance levels quoted at ISO conditions do not include installation ducting pressure losses. This level of performance is termed uninstalled and would normally be between inlet and exit planes consistent with the engine manufacturer’s supply. Examples might include from the flange at entry to the first compressor casing to the engine exhaust duct exit flange, or to the propelling nozzle exit

Industrial Engines

Overall installation inlet pressure loss due to physical ducting, filters and silencers is typically 100 mm H2O at high power. Installation exhaust loss is typically 100–300 mm H2O (0.981 kPa, 0.142 psi to 2.942 kPa, 0.427 psi); the higher values occur where there is a steam plant downstream of the gas turbine.



Figure 19–7. Royce.)

Specific humidity versus relative humidity and ambient temperature at sea level. (Source: Rolls


Figure 19–8.


Ratio of specific humidity at altitude to that at sea level. (Source: Rolls Royce.)

Automotive Engines

In this instance both installation inlet and exhaust loss are typically 100 mm H2O (0.981 kPa, 0.142 psi).

employed the same free stream conditions are experienced as for the propulsion unit. The intake ram recovery is often lower, however, due both to placement at the rear of the fuselage and drag constraints on the intake design.

Marine Engines

Installation intake and exhaust loss values at rated power may be up to 300 mm H2O (2.942 kPa, 0.427 psi) and 500 mm H2O (4.904 kPa, 0.711 psi) respectively, dependent upon ship design. Standard values used by the U.S. Navy are 100 mm H2O (0.981 kPa, 0.142 psi) and 150 mm H2O (1.471 kPa, 0.213 psi). Aircraft Engines

For a pod mounted turbofan cruising at 0.8 Mach number, the total pressure loss from free stream to the flight intake/ engine intake interface due to incomplete ram recovery and the installation intake may be as low as 0.5% ∆P/P, whereas for a ramjet operating at Mach 3 the loss may be nearer 15%. For a helicopter engine buried behind filters the installation intake total pressure loss may be up to 2%, and there may also be an installation exhaust pressure loss due to exhaust signature suppression devices. The Flight Envelope Typical Flight Envelopes for Major Aircraft Types

Aircraft engines must operate at a range of forward speeds in addition to the environmental envelope. The range of flight Mach numbers for a given altitude is defined by the flight envelope. Figure 19–9 presents typical flight envelopes for the seven major types of aircraft. For each flight envelope the minimum and maximum free stream temperatures and pressures which the engine would experience are shown, together with basic reasons for the shape of the envelope. Where auxiliary power units are

Free Stream Total Pressure and Temperature

The free stream total pressure (P0) is a function of both pressure altitude and flight Mach number. Free stream total temperature (T0) is a function also of ambient temperature and flight Mach number. Both inlet pressure and temperature are fundamental to engine performance. They are often used to refer engine parameters to ISA sea level static conditions, via quasi dimensionless parameter groups. To do this the following ratios are defined: DELTA (δ) = P0/101.325 kPa THETA (θ) = T0/288.15 K Definitions of Flight Speed

Traditionally aircraft speed has been measured using a pitot-static head located on a long tube projecting forward from the wing or fuselage nose. The difference between total and static pressure is used to evaluate velocity, which is shown on a visual display unit or gauge in the cockpit. The device is normally calibrated at sea level, which has given rise to a number of definitions of flight speed: ●

Indicated air speed (VIAS) is the speed indicated in the cockpit based upon the above calibration. Calibrated air speed (VCAS) is approximately equal to VIAS with the only difference being a small adjustment


Figure 19–9. Flight envelopes for the major aircraft types. (a) Conventional civil transport turboprop. (b) Subsonic civil transport turbofan. (c) Supersonic civil transport. (d) Helicopter. (Source: Rolls Royce.)


Figure 19–9. cont'd (e) Subsonic airbreathing missile, drone, or RPV. (f) Supersonic airbreathing missile. (g) Advanced military fighter. Notes: APUs have lower intake RAM recovery than propulsion engines. Pressures shown are free stream, i.e. 100% RAM recovery. To convert temperatures in K to R multiply by 1.8. To convert temperatures in K to C subtract 273.15. To convert temperatures in K to F multiply by 1.8 and subtract 459.67. To convert pressures in kPa to psia multiply by 0.145038 To convert speeds in kt to km/h m/s miles/h ft/s multiply by 1.8520, 0.5144, 1.1508, 1.6878 Maximum temperatures shown are for MIL STD 210 Hot day. Minimum temperatures shown are for MIL STD 210 Cold day. Minimum Reynolds’ Number ratios shown are for MIL STD 210 Hot day. Unducted fans would have similar flight envelope to commercial turbofans. “RPV”= Remotely Piloted Vehicle. All numbers shown are indicative, for guidance only. (Source: Rolls Royce.)




to allow for aircraft disturbance of the static pressure field around the pitot-static probe. Equivalent air speed (VEAS) results from correcting VCAS for the lower ambient pressure at altitude versus that embedded in the probe calibration conducted at sea level, i.e. for a given Mach number the dynamic head is smaller at altitude. When at sea level VEAS is equal to VCAS. True air speed (VTAS) is the actual speed of the aircraft relative to the air. It is evaluated by multiplying VEAS by the square root of relative density as presented in Figure 19–4. This correction is due to the fact that the density of air at sea level is embedded in the probe calibration that provides VIAS. Both density and velocity make up dynamic pressure. Mach number (M) is the ratio of true air speed to the local speed of sound. Ground speed is VTAS adjusted for wind speed.

VEAS and VCAS are functions of pressure altitude and Mach number only. The difference between VEAS and VCAS is termed the scale altitude effect (SAE), and is independent of ambient temperature. Conversely, VTAS is a function of ambient temperature and Mach number, which is independent of pressure altitude. To a pilot both Mach number and ground air speed are important. The former dictates critical aircraft aerodynamic conditions such as shock or stall, whereas the latter is vital for navigation. For gas turbine engineers Mach number is of paramount importance in determining inlet total conditions from ambient static. Often, however, when analyzing engine performance data from flight tests only VCAS or VEAS are available. Properties and Charts for Dry Air, Combustion Products, and Other Working Fluids*

The properties of the working fluid in a gas turbine engine have a powerful impact upon its performance. It is essential that these gas properties are accounted rigorously in calculations, or that any inaccuracy due to simplifying assumptions is quantified and understood. This chapter describes at an engineering level the fundamental gas properties of concern, and their various interrelationships. It also provides a comprehensive database for use in calculations for: ● ● ● ●

Dry air Combustion products for kerosene or diesel fuel Combustion products for natural gas fuel Helium, the working fluid often employed in closed cycles

Description of Fundamental Gas Properties Equation of State for a Perfect Gas

A perfect gas adheres to Formula F19.1. All gases employed as the working fluid in gas turbine engines, except for water vapor, may be considered as perfect gases without compromising calculation accuracy. When the mass fraction of water vapor is less than 10%, which is usually the case

*Source: Courtesy Rolls Royce. Gas Turbine Performance, Walsh and Fletcher, Blackwell Science. Adapted with permission.

when it results from the combination of ambient humidity and products of combustion, then for performance calculations the gas mixture may still be considered perfect. When water vapor content exceeds 10% the assumption of a perfect gas is no longer valid and for rigorous calculations steam tables must be employed in parallel, for that fraction of the mixture. A physical description of a perfect gas is that its enthalpy is only a function of temperature and not pressure, as there are no intermolecular forces to absorb or release energy when density changes. Molecular Weight and the Mole

The molecular weight for a pure gas is defined in the Periodic Table. For mixtures of gases, such as air, the molecular weight may be found by averaging the constituents on a molar (volumetric) basis. This is because a mole contains a fixed number of molecules, as described A mole is the quantity of a substance such that the mass is equal to the molecular weight in grams. For any perfect gas 1 mole occupies a volume of 22.4 liters at 0°C, 101.325 kPa. A mole contains the Avogadro’s number of molecules, 6.023 × 1023. Specific Heat at Constant Pressure (CP) and at Constant Volume (CV)

These are the amounts of energy required to raise the temperature of 1 kilogram of the gas by 1°C, at constant pressure and volume respectively. For gas turbine engines, with a steady flow of gas (as opposed to piston engines where it is intermittent) only the specific heat at constant pressure, CP, is used directly. This is referred to hereafter simply as specific heat. For the gases of interest specific heat is a function of only gas composition and static temperature. For performance calculations total temperature can normally be used up to Mach numbers of 0.4 with negligible loss in accuracy, since dynamic temperature remains a low proportion of the total. Gas Constant (R)

The gas constant appears extensively in formulae relating pressure and temperature changes, and is numerically equal to the difference between CP and CV. The gas constant for an individual gas is the universal gas constant divided by the molecular weight, and has units of J/kg K. The universal gas constant has a value of 8314.3 J/mol K. Ratio of Specific Heats, Gamma (γ ) (Formulae F19.6–F19.8)

This is the ratio of the specific heat at constant pressure to that at constant volume. Again it is a function of gas composition and static temperature, but total temperature may be used when the Mach number is less than 0.4. Gamma appears extensively in the “perfect gas” formulae relating pressure and temperature changes and component efficiencies. Dynamic Viscosity (VIS) and Reynolds Number (RE) (Formulae F19.9)

Dynamic viscosity is used to calculate the Reynolds number, which reflects the ratio of momentum to viscous forces present in a fluid. The Reynolds number is used in many performance calculations, such as for disc windage, and has a second-order effect on component efficiencies. Dynamic viscosity is a measure of the viscous forces and is a function of gas composition and static temperature. As viscosity


has only a second-order effect on an engine cycle, total temperature may be used up to a Mach number of 0.6. The effect of fuel air ratio (gas composition) is negligible for practical purposes. The units of viscosity of N s/m2 are derived from N/(m/s)/m; force per unit gradient of velocity. Gas velocity varies in a direction perpendicular to the flow in the boundary layers on all gas washed surfaces. Description of Key Thermodynamic Parameters

The key thermodynamic parameters most widely used in gas turbine performance calculations are described below. Their interrelationships are dependent upon the values of the fundamental gas properties described above.


Total and static pressure diverge much more rapidly versus Mach number than do total and static temperature. Calculation of pressure ratio from temperature ratio is far more sensitive to errors in the assumption of the mean gamma than the reverse calculation. Specific Enthalpy (H) (Formulae F19.14, F19.15)

This is the energy per kilogram of gas relative to a stipulated zero datum. Changes in enthalpy, rather than absolute values, are important for gas turbine performance. Total or static enthalpy may be calculated, depending on which of the respective temperatures is used. Total enthalpy, like total temperature, is most common in performance calculations.

Total or Stagnation Temperature (T) (Formula F19.10)

Total temperature is the temperature resulting from bringing a gas stream to rest with no work or heat transfer. Note that here “at rest” means relative to the engine, which may have a flight velocity relative to the Earth. The difference between the total and static temperatures at a given point is called the dynamic temperature. The ratio of total to static temperature is a function of only gamma and Mach number, as per Formula F19.10. In general for gas turbine performance calculations total temperature is used through the engine, evaluated at engine entry from the ambient static temperature and any ram effect. At locations between engine components total temperature is a valid measure of energy changes. In addition, this aids comparison between predictions and test data, as it is only practical to measure total temperature. For most component design purposes, however, static conditions are also relevant, as for example the Mach number is often high (1.0 and greater) at entry to a compressor stator or turbine rotor blade. Total temperature is constant for flow along ducts where there is no work or heat transfer, such as intake and exhaust systems. Total and static temperature diverge much less rapidly versus Mach number than do total and static pressure, as described below. Total or Stagnation Pressure (P) (Formulae F19.11, F19.12, and F19.13)

Total pressure is that which would result from bringing a gas stream to rest without any work or heat transfer, and without any change in entropy. Total pressure is therefore an idealized property. The difference between total and static pressure at a point is called either the dynamic pressure, dynamic head, or velocity head (Formulae F19.12 and F19.13). The term head relates back to hydraulic engineering. The ratio of total to static pressure, as for temperature, is a function of only gamma and Mach number. Most performance calculations are conducted using total pressure, that at engine inlet again resulting from ambient static plus intake ram recovery. Total pressure is not constant for flow through ducts, being reduced by wall friction and changes in flow direction, which produce turbulent losses. Both these effects act on the dynamic head; the pressure loss in a duct of given geometry and inlet swirl angle is almost always a fixed number of inlet dynamic heads. For this reason for performance calculations both the total and static pressure must often be evaluated at entry to ducts. Again for component design purposes both the total and static values are of interest.

Specific Entropy (S)

Traditionally the property entropy has been shrouded in mystery, primarily due to being less tangible than the other properties discussed in this section. Entropy relates to other thermodynamic properties relevant to gas turbine performance, and thereby helps overcome these difficulties. During compression or expansion the increase in entropy is a measure of the thermal energy lost to friction, which becomes unavailable as useful work. Composition of Dry Air and Combustion Products Dry Air

Dry air comprises the elements in Table 19–2. There are also trace amounts of helium, methane, krypton, hydrogen, nitrous oxide, and xenon. These are negligible for gas turbine performance purposes. Combustion Products

When a hydrocarbon fuel is burned in air, combustion products change the composition significantly. Atmospheric oxygen is consumed to oxidize the hydrogen and carbon, creating water and carbon dioxide respectively. The degree of change in air composition depends both on fuel air ratio and fuel chemistry. The fuel air ratio such that all the oxygen is consumed is termed stoichiometric. Distilled liquid fuels such as kerosene or diesel each have relatively fixed chemistry. Properties of their combustion products can be evaluated versus fuel air ratio and temperature using unique formulae, with the fuel chemistry inbuilt. In contrast, the chemistry of natural gas varies considerably. All natural gases have a high proportion of light hydrocarbons, often with other gases such as nitrogen, carbon dioxide, or hydrogen. Because

Table 19–2. Royce.)

Composition of Dry Air (Source: Rolls

Nitrogen (N2) Oxygen (O2) Argon (Ar) Carbon dioxide Neon

By Mole or Volume (%)

By Mass (%)

78.08 20.95 0.93 0.03 0.002

75.52 23.14 1.28 0.05 0.001



the composition of natural gas combustion products varies, along with the fuel chemistry, unique formulae for their gas properties do not exist, hence the calculation is more complex.

Table 19–3. Molecular Weight and Gas Constants (Source: Rolls Royce.)

The Use of CP and Gamma, or Specific Enthalpy and Entropy, in Calculations

Dry air Oxygen Water Carbon dioxide Nitrogen Argon Hydrogen Neon Helium

Either CP and gamma, or specific enthalpy and entropy, are used extensively in performance calculations. The manner of their use is described below in order of increasing accuracy and calculation complexity. This list covers all gas turbine components except for the combustor. Constant, Standard Values for CP and Gamma

This normally uses the following approximations: ●

Cold end gas properties: CP = 1004.7J/kg K, gamma = 1.4 Hot end gas properties: CP = 1156.9J/kg K, gamma = 1.33 Component performance: Formulae use values of CP and gamma as above

This is the least accurate method, giving errors of up to 5% in leading performance parameters. It should only be used in illustrative calculations for teaching purposes, or for crude “ballpark” estimates.

Specific Enthalpy and Entropy—Dry Air, and Diesel or Kerosene

For fully rigorous calculations changes in enthalpy and entropy across components must be accurately evaluated. This improves accuracy to be within 0.25% for leading parameters at all pressure ratios. Here polynomials of specific enthalpy and entropy are utilized, obtained by integration of the standard polynomials for specific heat. In these methods, a formula for specific heat is therefore still required. The use of specific enthalpy and entropy for performance calculations is now almost mandatory for computer “library” routines in large companies. Specific Enthalpy and Entropy—Natural Gas

For the combustion products of natural gas it is logical to use specific enthalpy and entropy only if CP is evaluated accurately. Database for Fundamental and Thermodynamic Gas Properties Molecular Weight and Gas Constant

Data for gases of interest are listed in Table 19–3.

Gas Constant (J/kg K)

28.964 31.999 18.015 44.010 28.013 39.948 2.016 20.183 4.003

287.05 259.83 461.51 188.92 296.80 208.13 4124.16 411.95 2077.02

Note: The universal gas constant is 8314.3 J/mol K.

Figure 19–10 shows the gas constant resulting from the combustion of leading fuel types in air plotted versus fuel air ratio. It is not possible to provide all encompassing data for natural gas due to the wide variety of blends that occur. For indicative purposes combustion of a sample natural gas has been used. The following are apparent: ●

Values for CP and Gamma Based on Mean Temperature

For formulae using CP and gamma it is most accurate to base these values on the mean temperature within each component, i.e. the arithmetic mean of the inlet and exit values. It is less accurate to evaluate CP and gamma at inlet and exit, and then take a mean value for each. For dry air and combustion products of kerosene or diesel the formulae given for CP as a function of temperature and fuel air ratio give accuracies of within 1.5% for leading performance parameters. The largest errors occur at the highest pressure ratios.

Molecular Weight

For kerosene, molecular weight and gas constant are not changed noticeably from the values for dry air up to stoichiometric fuel to air ratio. For diesel molecular weight and hence gas constant change minimally, in a linear fashion versus fuel to air ratio. For performance calculations there is negligible loss in accuracy by ignoring these small changes and using data for kerosene. For the sample natural gas molecular weight and gas constant vary linearly with fuel air ratio from the values for dry air to 27.975 and 297.15 J/kg K respectively at a fuel to air ratio of 0.05. A significant loss of accuracy will occur if this change is not accounted.

The effect of gas fuel is more powerful than that of liquid fuels, primarily due to the constituent hydrocarbons being lighter (i.e. containing less carbon and more hydrogen); this results in a higher proportion of water vapor after combustion, which has a significantly lower molecular weight than the other constituents. Specific Heat and Gamma

Figures 19–11 and 19–12 present specific heat and gamma respectively for dry air and combustion products versus static temperature and fuel air ratio for kerosene or diesel fuels. Figure 19–13 shows the ratio of specific heat following the combustion of the sample natural gas to that for kerosene, versus fuel to air ratio. This plot is sensibly independent of temperature. As stated earlier, specific heat is noticeably higher following the combustion of natural gas due to the higher resultant water content, which significantly impacts engine performance. Figure 19–14 shows specific heat respectively versus temperature for the individual gases present in air and combustion products. The higher value for water vapor is immediately apparent. For inert gases such as helium, argon, and neon, specific heat and gamma do not change with temperature.



Figure 19–10. Gas constant, R, for combustion products of kerosene, diesel, and natural gas versus fuel air ratio. (Source: Rolls Royce.)

Temperature Entropy Diagram for Dry Air

Most heat engine cycles are taught at university level via schematic illustration on a temperature–entropy (T–S) diagram. This approach becomes laborious to extend to “real” engine effects such as internal bleeds and cooling flows, but remains a useful indication of the overall thermodynamics of a known engine cycle. Figure 19–15 presents an actual temperature–entropy diagram for dry air, complete with numbers, showing lines of constant pressure. Such a diagram is rare in the open literature. The following are important: ●

Raising temperature at constant pressure (e.g. by adding heat in a combustor) raises entropy. Reducing temperature at constant pressure (e.g. by removing heat in an intercooler) lowers entropy. Compression from a lower to a higher constant pressure line (i.e. by adding work) produces minimum change in temperature (i.e. requires minimum energy input) if entropy does not increase. Isentropic compression is an idealized process. In reality entropy does increase during compression, hence extra energy must be provided, beyond the ideal work required for the pressure change. This extra energy is converted to heat. Expansion from a higher to a lower constant pressure line produces maximum change in temperature (i.e. produces maximum work) if entropy does not increase. Isentropic expansion is also an idealized process. In reality entropy does increase during expansion, hence less work output is obtained than the ideal work pro-

duced pressure change. This “lost” energy is retained as heat. Entropy may be defined as thermal energy not available for doing work. In real compressors and turbines some energy goes into raising entropy, as some pressure is lost to real effects such as friction. The ideal work would be required or produced if entropy did not change, i.e. the process were isentropic. Isentropic efficiency is defined as the appropriate ratio of actual and ideal work, and is always less than 100%. (The term adiabatic efficiency is also commonly used, but is strictly incorrect. It only excludes heat transfer but not friction, and an isentropic process would have neither.) Gas turbine cycles utilize the above processes, and rely on one other vital, fundamental thermodynamic effect: Work input, approximately proportional to temperature rise, for a given compression ratio from low temperature is significantly lower than the work output from the same expansion ratio from higher temperature. This is because on the T–S diagram lines of constant pressure diverge with increasing temperature and entropy. This can be seen by considering a sample compression, heating, and expansion between two lines of constant pressure, using Figure 19–15. At an entropy value of 1.5 kJ/kg K the temperature rise required to go from 100 to 5100 kPa is 500 K. If fuel is now burned at this pressure level such that entropy increases to 2.75 kJ/kg K, and temperature to 1850 K, an expansion back to 100 kPa will achieve a temperature drop of around 1000 K. This clearly illustrates the rationale behind the Brayton cycle.



Figure 19–11. Rolls Royce.)

Specific heat, CP, for kerosene combustion products versus temperature and fuel air ratio. (Source:


Figure 19–12. Royce.)

Gamma for kerosene combustion products versus temperature and fuel air ratio. (Source: Rolls




Figure 19–13. Specific heat, CP, for typical natural gas combustion products relative to kerosene versus fuel air ratio. (Source: Rolls Royce.)

Figure 19–14. Rolls Royce.)

Specific heat, CP, for the constituents of air and combustion products versus temperature. (Source:

BASIC DESIGN THEORY Schematic T–S Diagrams for Major Engine Cycles

Figures 19–16 through 19–21 show the key cycles of interest to gas turbine engineers. Figure 19–16 shows the Carnot cycle. This is the most efficient cycle theoretically possible between two temperature levels. Gas turbine engines necessarily do not use the Carnot cycle, as unlike steam cycles they cannot add or reject heat at constant temperature. Figure 19–17 shows the Brayton cycle. This is the basic cycle utilized by all gas turbine engines where heat is input at constant pressure. The effect of component inefficiency is shown by the non-vertical compression and expansion lines, a further difference from the ideal Carnot cycle. The form of the Brayton cycle is modified for heat exchangers and bypass flows. Figure 19–18 presents the cycle for a turbofan. The bypass stream only undergoes partial compression, and no heating before expansion back to ambient pressure. Figure 19–19 shows a heat exchanged cycle. Waste heat from exhaust gases is used to heat air from compressor delivery prior to combustion, thereby reducing the required fuel flow. Figure 19–20 presents an intercooled cycle, where heat is extracted downstream of an initial compressor. This reduces the work required to drive a second compressor, and thereby increases power output. Figure 19–21 shows a Rankine cycle with superheat. This is used in combined cycle applications, with the gas turbine exhaust gases providing heat to raise steam. Where heat is added at constant temperature during evaporation a close approximation to the Carnot cycle is achieved, the main deviation being the non-ideal component efficiencies. Formulae

F19.1. Equation of state for perfect gas


F19.7. Gamma = fn(gas constant (J/kg K), CP (J/kg K) ) γ = CP/(CP – R) F19.8. The gamma exponent (γ − 1)/γ = fn(gas constant (J/kg K), CP (J/kg K) ) (γ – 1)/γ = R/CP F19.9. Dynamic viscosity of dry air (N s/m2) = fn(shear stress (N/m2), velocity gradient (m/s m), static temperature (K) ) VIS = Fshear/(dV/dy) 1. Fshear is the shear stress in the fluid. 2. V is the velocity in the direction of the shear stress. 3. dV/dy is the velocity gradient perpendicular to the shear stress. F19.10. Total temperature (K) = fn(static temp (K), gas velocity (m/s), CP (J/kg K) ) T = TS + V^2/(2 × CP) F19.11. Total pressure (kPa) = fn(total to static temperature ratio, gamma) P = PS × (T/TS^)( γ /( γ − 1) ) Note: This is the definition of total pressure. F19.12. Dynamic head (kPa) = fn(total pressure (kPa), static pressure (kPa) )

RHO = PS/(R × TS) VH = P – PS F19.2. Specific heat at constant pressure (J/kg K) = fn(specific enthalpy (J/kg), static temperature (K) )

F19.13. Dynamic head (kPa) = fn(density (kg/m3), velocity (m/s), Mach number)

CP = dH/dTS F19.3. Specific heat at constant volume (J/kg K) = fn(specific internal energy (J/kg), static temperature (K) ) CV = dU/dTS F19.4. Gas constant (J/kg K) = fn(universal gas constant (J/kg K), molecular weight)

VH = 0.5 × RHO × V^2( (1 + 0.5 × (γ − 1) × M^2 ) − 1) × 2/( γ × M^2 ) For incompressible flow, such as that of liquids, it is sufficient to only use the first term—this is the well known Bernoulli equation. F19.14. Specific enthalpy (kJ/kg) = fn(temperature (K), CP (kJ/kg K) )

R = Runiversal/MW where the universal gas constant Runiversal = 8314.3 J/mol K. F19.5. Gas constant (J/kg K) = fn(CP (J/kg K), CV (J/kg K) ) R = CP – CV

H = H0 + ∫ CP dT H0 is an arbitrarily defined datum. The datum is unimportant in gas turbine performance as it is changes in enthalpy that are of interest. F19.15. Change in enthalpy (kJ/kg) = fn(temperature (K), CP (kJ/kg K) )

F19.6. Gamma = fn(CP (J/kg K), CV (J/kg K) ) γ = CP/CV

DH = CP × (T2 − T1)



Figure 19–15.

Temperature–entropy (T–S) diagram for dry air. (Source: Rolls Royce.)


Figures 19–16. Royce.)

Ideal Carnot cycle. (Source: Rolls


Figures 19–19. Cycle with heat recovery for shaft power applications. (Source: Rolls Royce.)

Figures 19–20. Intercooled cycle for shaft power applications. (Source: Rolls Royce.) Figures 19–17. Brayton cycle for turboshaft, turboprop, turbojet, or ramjet. (Source: Rolls Royce.)

Figures 19–21. Rankine cycle with superheat; typical steam cycle used with a gas turbine for combined cycle power generation. (Source: Rolls Royce.)

Figures 19–18. Royce.)

Cycle for turbofan. (Source: Rolls

“Design Point” Engine Design, Definitions, and Terminology* The Engine Design Point and Design Point Performance

For initial definition work, the operating condition where an engine will spend most time has been traditionally chosen *Source: Courtesy Rolls Royce, Gas Turbine Performance, Walsh and Fletcher, Blackwell Science. Adapted with permission.

as the engine design point. For an industrial unit this would normally be ISO base load, or for an aeroengine cruise at altitude on an ISA day. Alternatively some important high power condition may be chosen. Either way, at the design point the engine configuration, component design, and cycle parameters are optimized. The method used is the design point performance calculation. Each time input parameters are changed and this calculation procedure is repeated, the resulting change to the engine design requires a different engine geometry, at the fixed operating condition.



For the concept design phase described here the component design points are usually at the same operating condition as the engine design point. In a detailed design phase however, this may not be true. For example in the detailed design phase an aeroengine fan may be designed at the top of climb, the highest referred speed and flow, whereas the engine design point would be cruise. The term design point refers to the engine design point in the concept design phase, which is taken to be coincident with the component design points.

monly used. This difference reflects the higher importance of fuel weight in aero applications, and the lower likely variation of fuel calorific values. ●

Design Point Performance Parameters, Definitions Engine Performance Parameters

A number of key parameters that define overall engine performance are utilized to assess the suitability of a given engine design to the application, or compare several possible engine designs. These engine performance parameters are described below. ●

Output power or nett thrust (PW, FN). The required output power or nett thrust is almost always the fundamental goal for the engine design. It is evaluated via the overall cycle calculation. The term effective or equivalent power is used for turboprops and turboshafts, where any residual thrust in the exhaust is converted to a power value and added to the shaft output power. Exhaust gas power. For a turboshaft engine core this is the output power that would be produced by a power turbine of 100% efficiency. It is of interest when engine cores are tested or supplied without their free power turbine, which may remain with the installation or be supplied by another collaborating company. Specific power or thrust (SPW, SFN). This is the amount of output power or thrust per unit of mass flow entering the engine. It provides a good first-order indication of the engine weight, frontal area, and volume. It is particularly important to maximize specific power or thrust in applications where engine weight or volume are crucial, or for aircraft that fly at high Mach numbers where the drag per unit frontal area is high. For turboprops and turboshafts and effective specific power may be evaluated, based on the effective power value. Specific fuel consumption (SFC). This is the mass of fuel burned per unit time per unit of output power or thrust. It is important to minimize SFC for applications where the weight and/or cost of the fuel is significant versus the penalties of doing so. When quoting SFC values it is imperative to state the calorific value of the fuel, and whether it is the higher or lower heating value, to ensure valid “back to back” comparisons. Again, for turboprops and turboshafts an effective SFC may be evaluated. Thermal efficiency for shaft power engines (ETATH). This is the engine power output divided by the rate of fuel energy input, usually expressed as a percentage. It is effectively the reciprocal of SFC, but is independent of fuel calorific value. However when quoting thermal efficiencies it is still important to state whether the values are based upon the higher or lower fuel heating value. For combined cycle applications the terms gross and nett thermal efficiency are used. Gross thermal efficiency does not deduct the power required to drive the steam plant auxiliaries, whereas nett values do.

Thermal efficiency is usually quoted for industrial gas turbines, and SFC for aircraft turboshafts and turboprops. For marine and automotive gas turbines both terms are com-

Heat rate for shaft power cycles (HRATE). Heat rate is a parameter used only in the power generation industry, and is the rate of fuel energy input divided by the useful power output. Hence it is comparable to SFC but is independent of fuel calorific value. Again it is important to state whether higher or lower calorific value has been assumed in calculating fuel energy input, and for combined cycle applications whether the values are gross or net. Exhaust temperature (T6). For engines used in combined cycle for industrial power generation, high exhaust temperature is vital in maximizing overall efficiency. For combined heat and power the optimum value depends on the relative demand of heat versus power. In both cases there is a limit to the allowable exhaust temperature due to mechanical integrity considerations in the steam plant.

For military aircraft applications low exhaust gas temperature is important to reduce the infrared signature presented to heat seeking missiles. ●

Exhaust mass flow (W6). For engines used in combined cycle or combined heat and power applications the exhaust mass flow is important in indicating the heat available in the gas turbine exhaust, and hence the overall plant thermal efficiency.

For aircraft thrust engines there are a number of secondary performance parameters. These do not in themselves describe overall engine performance, but do help the engine designer understand the variation of the primary performance parameters across a number of designs. These parameters are as follows: ●

Thermal efficiency. Thermal efficiency for aircraft thrust engines is defined as the rate of addition of kinetic energy to the air divided by the rate of fuel energy supplied, usually expressed as a percentage. The energy in the jet is proportional to the difference in the squares of jet and flight velocities. Generally thermal efficiency increases as pressure ratio and SOT increase together, as this results in a higher jet velocity for a given energy input. Propulsive efficiency (ETAPROP). Propulsive efficiency for aircraft thrust engines is defined as the useful propulsive power produced by the engine divided by the rate of kinetic energy addition to the air, again usually expressed as a percentage. The nett thrust is proportional to the difference in the jet and flight velocities. Since power is force times velocity, propulsive power is proportional to the flight speed times the difference in the jet and flight velocities.

Propulsive efficiency is improved by low jet velocities, due to lower energy wastage as jet kinetic energy. This requires high pressure ratio and low SOT. However low jet velocities produce lower thrust output, hence to achieve high propulsive efficiency, as well as a required thrust, high engine mass flow must be coupled with low jet velocities. This leads to engines of low specific thrust, which are large and heavy. Turbofan engines are based upon this principal. Thrust SFC is directly proportional to flight speed, and inversely proportional to both thermal and propulsive efficiencies. The dependency on the efficiencies is intuitively


obvious. The choice of pressure ratio and SOT for minimum SFC is a compromise between maximizing propulsive and thermal efficiency. The dependency of thrust SFC on flight speed arises because fuel flow relates to power with the thermal and propulsive efficiencies fixed, and propulsive power is directly proportional to flight speed for a given thrust. Cycle Design Parameters

The fundamental thermodynamics of gas turbine cycles in relation to temperature entropy diagrams show that the changes in pressure and temperature that the working fluid experiences strongly affect the engine performance parameters. The degree of change of pressure and temperature are reflected via the following cycle design parameters.

Changes in component performance parameters have a secondary effect on the optimum values of engine cycle design parameters. Mechanical Design Parameters

For a given performance design point to be practical the mechanical design parameters must be kept within the limits of the materials, manufacturing, and production technology available. These are mechanical design restraints in relation to gas turbine engines. ●

Overall Pressure Ratio

This is total pressure at compressor delivery divided by that at the engine inlet.

Stator Outlet Temperature (SOT)

This is the temperature of the gas able to do work at entry to the first turbine rotor. Other terms are also used to reflect maximum temperatures in a cycle: ●

Rotor inlet temperature (RIT): this term is sometimes used in North America, and means the same as SOT Combustor outlet temperature (COT): this is the temperature at the first turbine nozzle guide vane leading edge Turbine entry temperature (TET): this can have either of the above meanings

The standard definition for SOT, used herein, is: The fully mixed out temperature resulting from combustion delivery gas mixing with all cooling air that enters upstream of the first turbine rotor, and is able to do work due to having momentum comparable to the nozzle guide vane flow. Hence, in this definition, nozzle guide vane or platform cooling air entering upstream of the throat, or trailing edge cooling air ejected with the same momentum and direction as the main flow, would be included. However front disc face cooling air flow would not be considered in evaluating SOT since it will not do work in the turbine rotor. For most gas turbine engine types it is desirable to raise SOT to as high a level as possible within mechanical design constraints. In addition for turbofan engines two further cycle design parameters occur due to the parallel gas paths. Fan Pressure Ratio

This is the ratio of fan delivery total pressure to that at fan inlet, and is usually lower for the core stream than the bypass due to lower blade speed. Bypass Ratio

This is the ratio of mass flow rate for the cold stream to that for the hot stream. Component Performance Parameters

A plethora of parameters define component performance in terms of efficiency, flow capacity, pressure loss, etc. As the level of component performance parameters improves, at fixed values of cycle design parameters, then the design point engine performance parameters also improve.


Creep as a function of material type, metal temperatures, stress level, or AN2 Oxidation as a function of material and coating type, and metal temperatures Cyclic life (low cycle fatigue) as a function of material type and metal temperatures Disc and blade tensile stress as a function of rim speed or AN2 Casing rupture as a function of compressor delivery pressure Choke or stall flutter as a function of fan or compressor referred speed Vibration (high cycle fatigue) of rotating components as a function of rotational speed and excitation parameters such as upstream blade numbers and pressure levels Shaft critical speeds

Life Parameters

The two major life parameters are: 1. 2.

Time between overhauls (TBO) Cyclic life (also called low cycle fatigue life): this is the number of times the engine is started, accelerated to full power, and eventually shut down, between overhauls.

The TBO is governed mainly by creep and oxidation life, while cyclic life is dictated by thermal stress levels. Typical life requirements for the major gas turbine applications are as shown in Table 19–4. Fuel Type

Kerosene is the standard aviation fuel while marine engines burn diesel and most industrial applications use natural gas. The highly distilled forms of diesel used make little difference to performance compared with kerosene, but natural gas gives performance improvements because of the higher resulting specific heat of the combustion products. Design Point Diagrams

A design point diagram is created by plotting engine performance parameters versus the cycle parameters. To produce the diagram the design point calculations are repeated varying each cycle parameter in turn through the range of interest; every point is a different engine geometry. These diagrams are useful in the engine design process for selecting the optimum cycle parameters, or for comparing the performance of different gas turbine types. Initially design point diagrams are prepared using constant component performance parameter levels for all combinations of cycle parameters. Later in the engine design process different individual component performance levels are used for each combination of cycle parameters, based on aerothermal component design work.



Table 19–4.

Typical Life Requirements (Source: Rolls Royce.)

Application Power generation—base load Power generation—standby/peak lopping Gas and oil pumping Automotive—family saloon Automotive—truck Marine—military Marine—fast ferry Aeroengine—civil Aeroengine—military fighter*

TBO (hours)


25,000–50,000 25,000 25,000–100,000 5,000 10,000 5,000–20,000 5,000–10,000 15,000 25–3,000

3,000 10,000 5,000–10,000 10,000 5,000–10,000 2,000–3,000 3,000 3,000 25–3,000


There is a large difference between past achievements and future targets, as the emphasis has moved from performance to cost of ownership.

Referred Parameters

The design point charts may be applied to any altitude, if the referred form of specific power or thrust, SFC, etc. are used. In this way the datum values for the charts are adjusted. A change in flight Mach number does change engine matching however, unless all nozzles are choked, and also changes ram drag. The charts are not directly adaptable to other flight Mach numbers.

Linearly Scaling Components and Engines

During the concept design process the scaling of existing components, or occasionally a complete engine, will be considered wherever possible. If viable this will significantly reduce program cost and development risk. Design Point Exchange Rates

Design point exchange rates show the impact of a small change, typically 1%, in leading component performance levels on engine design point performance parameters. All other component efficiencies and cycle parameters are held constant as the parameter in question is varied. In practice this would require many other components to be redesigned, to change flow sizes. Tables of design point exchange rates are extremely useful in the engine design process in highlighting the most sensitive component design areas, and should always be produced. Synthesis exchange rates are quite different, and are utilized for off design analysis whereas the component in question is modified no other components are redesigned. All components move or rematch to a different nondimensional operating point. In consequence component performance parameter levels change, as well as cycle parameters.

Thermal efficiency and specific power generally increase with SOT. Though less convenient, combustor temperature rise is a better gauge of the cycle’s ability to deliver power. When this is low, excess power is low and the losses due to component inefficiencies dominate, reducing both thermal efficiency and specific power. The optimum pressure ratio for thermal efficiency increases with SOT, being 12:1 at 1100 K and rising to over 40:1 at 1800 K. The fact that there is an optimum is because as well as high combustion temperature rise, high thermal efficiency also requires low exhaust temperature to minimize energy wastage. Maximum thermal efficiency occurs at the minimum value of the ratio of combustor temperature rise to exhaust temperature, reflecting the ratio of heat input to heat wastage. Achieving this mainly requires low exhaust temperature, hence the optimum pressure ratios are relatively high. At too high a pressure ratio the low combustor temperature rise offsets the low exhaust temperature, which reduces thermal efficiency. The optimum pressure ratio for specific power also increases with SOT but is only around half that for thermal efficiency, being only 7:1 at 1100 K rising to 20:1 at 1800 K. Maximum specific power occurs at the maximum difference between the combustor temperature rise and the exhaust temperature, which reflects work output. Achieving this is less dominated by exhaust temperature, and more by the need to reduce compressor work. For mechanical integrity the combustor entry temperature must be limited to between 850 and 950 K, depending on the technology level. If the engine is to be used in combined cycle or combined heat and power then, exhaust temperature must be limited to between 800 and 900 K, depending on the technology level of the heat recovery system.

Open Shaft Power Cycles

With one exception all gas turbine engine configurations are open cycle. Air that enters the front of the engine is not recirculated, but is exhausted back into the atmosphere. Simple Cycle

This is the basic shaft power cycle. First air is compressed, and then it is heated by burning fuel in the combustor. Next expansion through one or more turbines produces power in excess of that required to drive the compressors, which is available as output. Whether the engine is single spool or free power turbine is only reflected in a design point diagram by any small change in assessed overall turbine efficiency.

Recuperated Cycle

This is as per the simple cycle except that a heat exchanger transfers some of the heat in the exhaust to the compressor delivery air. If the gas and air streams do not mix the heat exchanger is known as a recuperator; if they do mix, as with the automotive ceramic rotating matrix variety, it is known as a regenerator. ●

Thermal efficiency and specific power generally increase with SOT. At optimum pressure ratios the thermal efficiency is around 10% better than that for the simple cycle, due


to the heat recovery reducing the fuel requirement. This difference reduces as SOT increases as the corresponding simple cycle becomes more efficient. The optimum pressure ratio for thermal efficiency is comparatively low since the difference between the exhaust and compressor delivery temperature is high, hence more heat may be recovered. This is the dominant effect of pressure ratio. The optimum pressure ratio for specific power is 7.5:1 at 1100 K and 23:1 at 1800 K, and is independent of effectiveness. It is very similar to that for simple cycle, being only slightly reduced by the additional pressure losses in the recuperator. Effectiveness is one of the few component design parameters that has a strong effect upon the optimum pressure ratio for thermal efficiency. As it is increased, the optimum pressure ratio decreases, since increased heat recovery more than offsets a poor simple cycle efficiency. Combustor inlet temperature rises with falling pressure ratio for a given SOT. This is because of the reduced power requirement to drive the compressor, which reduces the temperature drop in the turbines. For mechanical integrity the recuperator and combustor entry temperatures must be limited to between 850 and 950 K, depending on the technology level.

ratio, such that the compressors would have equal pressure ratios. This corresponds to rejecting more heat than for the case of optimum thermal efficiency, and clearly requires more fuel energy input. Intercooled and Recuperated Cycle

This is the combination of intercooling and recuperation. The thermal efficiency loss due to intercooling is offset by increased exhaust heat recovery due to the lower recuperator air side entry temperature. ●

Intercooled Cycle

In this configuration the temperature of the air is reduced part way through the compression process using a heat exchanger and an external medium such as water. This increases power output via reduced compressor work, which is directly proportional to compressor inlet temperature. Generally thermal efficiency reduces as more fuel is required to reach a given SOT. ●

Thermal efficiency and specific power generally increase with SOT. Thermal efficiency is marginally worse than for the simple cycle below the optimum simple cycle pressure ratio and significantly better above it. This is driven by the relative magnitudes of the extra power output and the extra fuel flow required to raise the lower compressor delivery temperature to the given SOT. The optimum pressure ratio for thermal efficiency is 18:1 at 1100 K and over 40:1 at 1800 K. This is higher than for simple cycle, as the intercooler gives most benefit with a comparatively high pressure ratio. As the intercooler position is moved, thermal efficiency peaks with it 30% through the compression ratio, such that the first compressor pressure ratio would be the overall value raised to an exponent of 0.30. (The design point diagrams are drawn for the intercooler placed 50% through the compression such that the compressors have equal pressure ratios.) Specific power is approximately 20–40% higher than for simple cycle due to the reduction in the power to drive the compressor stages after the intercooler. This drive power is directly proportional to compressor inlet temperature for a given pressure ratio. The optimum pressure ratio for specific power is 12:1 at 1100 K and over 40:1 at 1800 K. Again this is higher than for simple cycle, and for the same reason. As the intercooler position is moved, specific power peaks with the intercooler 50% through the compression


Thermal efficiency and specific power generally increase with SOT. Thermal efficiency is around 20% higher than for simple cycle for a given SOT at the respective optimum pressure ratios, as in concert both the intercooler and recuperator reduce fuel consumption. The optimum pressure ratio for thermal efficiency is 7:1 at 1100 K and 20:1 at 1800 K. However, the cycle curves are flatter versus pressure ratio than for the other configurations above. Again, increasing recuperator effectiveness significantly reduces the optimum pressure ratio for thermal efficiency. Specific power is around 10% lower than for an intercooled only cycle due to the recuperator pressure losses, but still significantly higher than for simple cycle. The optimum pressure ratio for specific power is 13:1 at 1100 K and over 30:1 at 1800 K. Again, the cycle curves are flatter versus pressure ratio than for the other configurations above. For mechanical integrity the recuperator and combustor entry temperatures must be limited to between 850 and 950 K, depending on the technology level. As the intercooler position is moved, thermal efficiency peaks with it 40% through the pressure rise, and specific power peaks with it at 50%.

Combined Cycle

This is where a steam (Rankine) cycle also generates power, using exhaust heat from a simple cycle gas turbine. In addition, supplementary firing may be employed whereby a separate boiler supplements the gas turbine heat output when necessary. The curves are for a triple pressure reheated steam plant. ●

Thermal efficiency and specific power generally increase with SOT. Thermal efficiency exceeds that of all other configurations by around 20–30%. The optimum pressure ratio for thermal efficiency is 4:1 at 1100 K and around 21:1 at 1800 K. These values are lower than for simple cycle, as here increasing pressure ratio at a given SOT reduces the exhaust heat available for the steam cycle, reducing its efficiency. At the highest SOT levels the thermal efficiency curves are flatter versus pressure ratio than for all other configurations above; the steam cycle trends offset those of the gas turbine, benefiting from the higher exhaust temperature when gas turbine efficiency falls. As a rule of thumb, the pressure ratio that gives the best combined cycle thermal efficiency, while retaining an acceptable gas turbine exit temperature, is the optimum value for simple cycle specific power. The optimum pressure ratio for specific power is less than 4:1 at 1100 K and 7:1 at 1800 K. These values are



even lower than those for simple cycle due to the effect of high gas turbine exit temperature on steam plant power. The exhaust temperature limits of 800–900 K discussed for simple cycle engines must be considered here. ●

Combined Heat and Power

This configuration differs from those above in that the engine exhaust heat is also utilized in the application, either directly in an industrial process or to raise steam for space heating. A varying amount of exhaust heat may be utilized or wasted, hence heat to power ratio is an important parameter in cycle comparisons. Again, supplementary firing may be employed. ● ●

Thermal efficiency increases with SOT. Thermal efficiency increases almost linearly with heat to power ratio, as would be expected. Increasing pressure ratio increases thermal efficiency, though with diminishing returns above a value of 12:1. This reflects the corresponding simple cycle trends. Relatively high exhaust temperature, as given by a high specific power gas turbine, is often beneficial as high grade heat is more useful for a variety of processes. The exhaust temperature limits of 800–900 K discussed for simple cycle engines must be considered here, however.

is 17:1 at 1100 K SOT, and over 30:1 at 1700 K. The small increase in optimum pressure ratio is due to the increased cycle temperature ratio at the cooler inlet conditions at altitude, despite the change in matching produced by the flight Mach number. At both conditions the optimum pressure ratio for specific power is around 7:1 at 1100 K SOT and 19:1 at 1700 K.

Aircraft Engine Thrust Cycles Turbojets

Here a simple cycle configuration produces thrust via high exhaust gas velocities. Turbofans

Here air from the first compressor of what is otherwise a turbojet engine bypasses the remaining compressor and turbine stages. This air produces thrust directly, additional to that from the hot exhaust gases. Ramjets

Here fuel is burned in air compressed solely by the intake ram effect; there is no turbomachinery. Engine performance parameters are therefore a function only of SOT and flight Mach number.

Closed Cycles

The Engine Concept Design Process

Here the working fluid is recirculated through the cycle. Heat exchangers are employed in place of the intake/ exhaust and combustion processes, passing heat to and from external media. Maximum temperatures are limited by heat exchanger mechanical integrity, and unlike for open cycles, compressor entry pressure may be controlled to vary power level. Applications involve energy sources unsuited to direct combustion within a gas turbine engine, such as nuclear reactors or alternative fuels. The working fluid is normally helium, due to its high specific heat.

This section presents a simplified overview of the complex concept design process. To lead an engine concept design effectively requires a full understanding of gas turbine performance and all the associated design processes and their interrelationship. Equally, others involved in the process must have some knowledge of performance if they are to contribute to it beyond their own subject areas.

● ●

Thermal efficiency and “power ratio” generally increase with SOT. The “power ratio” as presented is specific power multiplied by the ratio of the density of helium at the inlet temperature and pressure to that of air at ISO conditions. This reflects the impact on the required engine size. The optimum pressure ratio for thermal efficiency is around 4:1. Reducing inlet temperature raises thermal efficiency and power ratio, via increased non-dimensional SOT, i.e. SOT/T1. Raising inlet pressure increases power ratio, via increased fluid density. The optimum pressure ratio for power ratio is around 6:1. Practical SOT levels are low, due to heat exchanger integrity limits.

Statement of Requirements

A statement of requirements or specification for a new engine may be presented by a customer organization, or may be specified within the cycle designer’s company to meet a perceived market need. Realism is required in terms of technical challenge as well as potential development and unit production costs. The document must not just reflect what “Marketing” or “the Customer” desires but also what “Engineering” can achieve. It should be written jointly. With respect to performance the statement of requirements must contain a minimum of: ●

Aircraft Engine Shaft Power Cycles

Here a simple cycle configuration produces shaft power, along with a residual exhaust thrust. SFC is plotted rather than thermal efficiency.

● ●

● ●

SFC and specific power generally improve with SOT. At ISA SLS the optimum pressure ratio for SFC is 12:1 at 1100 K SOT and over 30:1 at 1700 K. At the typical turboprop cruise flight condition of 6000 m 0.5 M it

● ●

Performance targets both at design point and other key operating conditions. The relationship to average or minimum engine and in service deterioration must also be specified, as well as future growth potential Full definition of operating conditions for the above, and also the entire operational envelope, including ambient temperature, pressure or pressure altitude, humidity, flight Mach number, and installation losses The starting envelope, as well as starting and above idle transient response times Fuel type and emissions requirements Engine diameter, length, and weight Time between overhauls and cyclic life Design and development program duration and cost, as well as unit production cost Any derivative engines that should be considered



“First Cut” Design Points

Off Design Performance

Generic design point diagrams will show what engine configurations, together with the levels of cycle parameters, are likely to meet the statement of requirements. Next, initial component performance targets are set. For the narrow range of cycle parameters of interest, refined design point diagrams are then produced. Usually component efficiency variation with engine cycle parameters is unknown at this stage. As far as possible the cycle designer takes account of mechanical design limits such as temperature levels, and considers the use of existing or scaled components. From these design point diagrams a first cut design point for each engine configuration under consideration is formally issued to component designers. An example of multiple configurations is that both simple cycle and recuperated engines may be competitive for a shaft power application. For clarity all design points should have an identifying version number, as many more updates will follow in what is a highly iterative design process.

Once a good candidate design point is emerging from the above iterations the cycle designer must then freeze the engine geometry and issue off design performance. This should cover other key operating points as well as all corners of the operational envelope. Often at this juncture the component designers will not have created off design maps for the “frozen” component designs so maps from existing components of similar design must be used, with factors and deltas applied to align them to the design point. The performance engineer must decide how the engine will be controlled for key ratings before running the off design cases. It is good practice at this stage for the performance engineer to highlight the operational cases where the maximum and minimum value of all key parameters occur, and any margins that need to be applied for say operating temperatures for a minimum engine.

“First Cut” Aero-Thermal Component Design

The component specialists now reassess the component performance inputs assumed in the design points, and perform initial component sizing. Their analysis uses component design computer codes and empirical data. Mechanical design parameters are monitored and where there is doubt regarding limits mechanical technologists must be consulted. Proper choice of rotational speed is crucial. It is key to achieving the target compressor and turbine efficiency levels as well as number of stages and diameter, and the compressor and turbine designers must agree upon it. The practicality or otherwise of using the number of spools that the cycle designer had in mind when setting the initial design points will soon be apparent, and weight and cost implications will become clear. Component performance levels are now bid back to the performance engineer for each design point. Design Point Calculations and Aero-Thermal Component Design Iterations

By repeating the design point calculations using the new bid component performance levels the concept design team can decide which engine configuration is the most suitable. If a bid is changed even for only one component, it will change the design point requirements for all others. The process is repeated a number of times for the chosen configuration so that a number of cycle parameter combinations, each with specific component performance levels, can be compared. Engine Layout

It is important to commence engine layout drawings as early as possible to highlight potential difficulties. For example, for a turbofan there would normally be a rigid engine diameter constraint. The core diameter required by the compressor and turbine designs, combined with the bypass duct annulus area to keep Mach number to a level where pressure loss is acceptable, may exceed this limit. In this instance the cycle designer may have to reduce bypass ratio, or the component designers increase rotational speed.

Performance, Aero-Thermal, and Mechanical Design Investigation

The off design performance data must be examined in detail by all parties. The cycle designer must check whether the engine design meets other performance requirements besides that at the design point. The aero-thermal and mechanical component designers must ensure that the components are satisfactory throughout the operational envelope with respect to component performance levels, stress, and vibration. Basic Starting and above Idle Transient Performance Assessment

Engine operability is assessed by ensuring that surge and weak extinction margins are commensurate with the required accel, decel, and start times. A judgement is made with respect to the need for variable stator vanes or blow off valves (BOVs); these also impact compressor design, unless the BOVs are at compressor delivery, and may be inherited anyway if an existing compressor design is utilized. Unless there are unusual or severe requirements, modeling of transient performance or starting would not normally be conducted in the concept design phase. However when such requirements are present or if a novel engine configuration is employed, then transient performance modeling is essential as transient considerations can significantly impact the fundamental engine design in terms of cycle, number of spools, etc. Iterations

A number of iterations through the whole process concludes the concept design phase. The resulting engine design is then compared with the statement of requirements and a judgment made as to whether to proceed into a detailed design and development program. Margins Required When Specifying Target Performance Levels

It is important that no ambiguities are present when performance targets for an engine design are specified, and that certain less obvious issues are not forgotten; some of the latter are outlined below.



Minimum Engine

Owing to manufacture and build tolerances there will be significant engine to engine variation in production. Usually the engine designers deal with average engine data, that is the average performance of all production engines. However if the customer has been guaranteed a given performance level then even the minimum engine must achieve this standard. Hence a design margin must be built into the average engine performance targets. The shortfall in power or thrust and SFC of a minimum engine in a production run will be 1–3% versus the average engine if run at constant temperature, depending on build quality and engine complexity. If the customer has been guaranteed levels of power or thrust then this minimum engine will run up to 20 K hotter than an average engine to achieve power or thrust. This must be allowed for in the mechanical design. Design and Development Program Shortfall

At the outset of a program the risk of component performance levels falling short of the values used in any preliminary design point analysis must be assessed. Ideally some engine performance risk analysis should be employed to quantify the potential shortfall versus confidence level. Suitable margins should then be applied to the performance target levels. However, at the outset of a program this level of risk analysis may not be commensurate with time or resource constraints and the available component performance data base. In this instance judgement must be used. The level of the margins should reflect the confidence of component performance levels employed in any preliminary analysis. Each case must be considered individually, however typical margins are presented in Table 19–5 for three confidence levels that the components will meet their design targets. When in competitive tender for an engine application the luxury of SFC margins may not be allowed due to commercial constraints. However for shaft power engines building in power margin is often practical by sizing the engine larger. In this instance, should the component performance levels employed in the preliminary analysis be achieved then almost invariably the customer will accept the extra power. In aircraft applications it may be more difficult to provide margin for thrust due to tight restrictions on weight and frontal area.

and the General Electric CF6 range. Margin is required on levels of temperature and speed, and there must be a practical route to increasing engine mass flow. Engine Deterioration

At the concept design stage it is unusual to specify performance requirements after deterioration over a number of hours in service. However if this is the case then a margin must be allowed for from the outset. The amount required depends on whether in service the engine is governed to fixed levels of temperature, speed or thrust/power. Depending on engine complexity typical margins at 10,000 hours, expressed at constant SOT, are: +3 to +6% SFC; −5 to −15% power. Performance degradation is usually exponential with time, and after 10,000 hours there is minimal further deterioration. Practices vary regarding the accounting or not of running in effects caused by initial seal cutting as part of deterioration. The aim of running in is to improve performance levels by ensuring a gentle first contact on key seals, which removes less material than would a first in-service rub. One further effect is compressor fouling where accretion of airborne particles on aerofoil surfaces reduces flow and efficiency, raising engine temperature levels. This applies mainly to ground based engines and is recoverable via compressor washing, for which appropriate fluid injection nozzles must be provided. The temperature increase depends entirely on site location, filter effectiveness, and washing frequency. Installation Losses

Usually performance targets are stipulated as uninstalled, with the engine performance quoted from the engine intake flange to the engine exhaust or propelling nozzle flange. If the performance targets are installed then the magnitude of all installation effects must be stated, as follows: ● ● ●

● ●

Plant or airframe intake pressure loss Plant exhaust or airframe jet pipe pressure loss Customer auxiliary power offtake (gas turbine accessory power requirements should be accounted even for uninstalled performance) Customer bleed offtake Whether shaft power output and thermal efficiency are at turbine, gearbox or alternator output Whether the thrust and SFC include any pod drag utilize

Growth Potential

Almost any engine must be capable of adaptation to higher power or thrust levels. In aircraft applications the airframe usually requires it, intentionally or otherwise. In addition, addressing a wider market with development costs spread over a family of engines is attractive economically. Examples for turbofans include the Rolls Royce RB211/Trent family (thrust growth of 180 to 400+ kN in 25 years), the Rolls Royce civil and military Spey family,

Two case histories and one Mach number-altitude chart follow. Although the cases involve aircraft engine design, the principles are applicable to all gas turbines. The cases were written in 1972 and 1988, respectively, but they still draw interest today. Because the 1972 case is now hard to access, it is reprinted almost entirely.

Table 19–5. Typical Performance Margins, by Confidence Level (Source: Rolls Royce.)

Two analytical models for calculating the effect of injected coolant on cascade efficiency are presented. Both

Power or thrust SFC




+2.5% −2%

+5% −4%

+7.5% −6%

Case 1. Prediction Effects of Mass-Transfer Cooling on the Blade-Row Efficiency of Turbine Airfoils*

*Source: [19-1] Courtesy of J. E. Hartsel from J. E. Hartsel. “Prediction Effects of Mass-Transfer Cooling on the Blade-Row Efficiency of Turbine Airfoil.” AIAA 72–11, 1972.


methods assume that the performance losses that accompany coolant injection are due wholly to the mixing of coolant and mainstream gases and may be superimposed on the basic boundary layer loss. One model employs the “influence coefficient” method, assuming that the differential form of the one-dimensional equation for compressible flow with injection may be applied to finite injection rates. This method, although approximate, does agree well with more exact calculations using one-dimensional constant static pressure mixing. The approximation also reveals the significant mixing loss parameters in a relatively simple form, showing that coolant injection effects are primarily dependent on mainstream Mach number, coolant fraction, coolant injection angle, and the ratios of coolantto-mainstream total temperature and velocity. The second analytical model, primarily suited for numerical computation, employs the concept of one-dimensional mixing layers to calculate losses due to surface injection (film- or transpiration-cooling) but employs a two-dimensional solution for the flow downstream of the trailing edge in order to include the effects of airfoil boundary layers and trailing-edge coolant bleed. The numerical method has been applied to several stator cooling configurations and good agreement with available data is obtained.


The increasing use of mass-transfer cooling in turbines has allowed significant increases in turbine inlet temperatures and overall engine performance. The problem of predicting the aerodynamic effects of injecting coolant air has grown in importance as mass-transfer cooling has increased in both extent of application and amount of cooling air employed. The rising costs of experimental testing have encouraged the development of analytical methods to predict the effects on blade-row performance of film-, transpiration-cooling, and the introduction of spent cooling air by methods such as airfoil trailing-edge bleed. The present case examines the purely aerodynamic loss, often called the “mixing loss,” due to coolant injection within a turbine airfoil blade row and its subsequent mixing with the mainstream flow. The general methods developed, however, may be applied to any portion of the turbine where coolant is injected. Consider the turbine airfoil blade row of Figure 19–22, which represents a rotor or stator employing mass-transfer cooling. The thermodynamic efficiency for the cascade shown is defined as


cP M P s

= = = =

s* t te T V W α γ δ*

= = = = = = = = =

δ** = θ = θ* = δTE = η = ξ = ρ = φc =

Specific heat at constant pressure Mach number Pressure Height of trailing-edge coolant jet when expanded to pressure P1 s/(t cosα1) Blade-row pitch Trailing-edge thickness Temperature Velocity Mass flowrate Cascade flow exit angle Ratio of specific heats Total boundary layer displacement thickness at the trailing edge based on average freestream (Station 1) conditions δ*/(t cosα1) Total momentum thickness at the trailing edge based on average mainstream (Station 1) conditions θ/(t cosα1) te/(t cosα1) Cascade thermodynamic efficiency Ratio of coolant-to-mainstream mass flowrates Density Angle of coolant injection measured from local mainstream direction


0 = Inlet 1 = Average mainstream condition at the trailing-edge plane 2 = Fully-mixed equilibrium downstream state c = Coolant f = Local condition downstream of injection g = Local mainstream condition t = Total or stagnation condition

Figure 19–22. [19-1]

General cooled cascade nomenclature.




actual exit kinetic energy ideal exit kinetic energy

⎛ Tt c ⎞ ⎜1 + ε T ⎟ ⎝ to ⎠

= 1+ ε





⎛P ⎞ −⎜ 2⎟ ⎝ Pt 0 ⎠

⎡ ⎢ ⎛ P2 ⎞ ⎢1 − ⎜⎝ P ⎟⎠ t2 ⎢⎣ γ −1 γ

γ −1 γ

⎤ ⎥ ⎥ ⎥⎦

Tt ⎛ P ⎞ −ε c⎜ 2⎟ Tt ⎝ Pt c ⎠ o

γ −1 γ

γ −1 2⎞ ⎛ ∆Pt ⎜ 1 + 2 M f ⎟ = Pt g ⎜ 1 + γ − 1 M 2 ⎟ ⎜ g⎟ ⎠ ⎝ 2


where Equation 19.1 is written for like, perfect gases and assumes that the ideal available kinetic energy of the exit flow is equal to the sum of the ideal kinetic energies of the coolant and inlet flows when expanded isentropically (without mixing) to the exit static pressure. For the particular case where Ptc = Pto, the efficiency expression reduces to the classical cascade efficiency,


⎛P ⎞ 1− ⎜ 2 ⎟ ⎝ Pt 2 ⎠ ⎛P ⎞ 1− ⎜ 2 ⎟ ⎝ Pt 0 ⎠

γ −1 γ


⎡ cp ( γ − 1)(1 + ε)(Tt g + εTt c )

M2 = ⎢ f


(Vg + εVc cos φ)2


( γ − 1) ⎤ ⎥ 2 ⎥⎦

−1 (19.4)

is obtained.

Figure 19–23. [19-1]

The one-dimensional mixing model.

γ −1 γ

A Linear Approximation γ −1 γ


In engine applications Ptc is an external variable, usually dictated by the cycle coolant air availability, thus the airfoil cascade efficiency is determined by the average exit total pressure Pt2 for a fixed coolant supply pressure. The prediction of cooled blade-row efficiency is thus equivalent to predicting the total pressure change ∆Pt = Pt2 – Pt0 caused by viscous effects, trailing-edge blockage, and coolant-primary flow mixing. The methods of this case are based on the assumption that these losses are additive and may be determined independently. This implies that the injected coolant mixes with the mainstream flow rather than remaining entrained in the boundary layer. Although the true situation is undoubtedly something between the two extremes of complete entrainment and complete mixing, there does exist experimental evidence to substantiate the present simple model. One-Dimensional Methods

The simplest model for coolant-mainstream mixing is the one-dimensional slot shown in Figure 19–23. This may be viewed as an appropriate idealization of a single row of film-cooling holes or, if the imagination is willing, an “average” of a complex cooling geometry. Two solutions are readily obtained for the one-dimensional case. Constant Static Pressure Mixing

If the upper boundary of the flow shown in Figure 19–23 is assumed to be flexible, then coolant and mainstream flows may be mixed under the assumption of a constant static pressure. Applying the equations of continuity, streamwise momentum, energy, and assuming thermally and calorically perfect gases for both mainstream and coolant, the result

The one-dimensional mixing of Figure 19–23 may also be approximated by adopting the “influence coefficient” method of Shapiro in the following manner. For the compressible flow of a perfect gas having constant external and frictional forces, the differential variation of total pressure may be expressed as ⎛ ∂P ⎞ ⎛ ∂P ⎞ ⎛ ∂P ⎞ dPt = ⎜ t ⎟ dA + ⎜ t ⎟ dTt + ⎜ t ⎟ dW ⎝ ∂A ⎠ ⎝ ∂W⎠ ⎝ ∂ Tt ⎠

with partial derivatives of ∂ Pt =0 ∂A ∂ Pt γM 2 Pt =− 2Tt ∂ Tt ∂ Pt γM 2 Pt ⎛ Vc ⎞ dW cos φc ⎟ =− ⎜1 − ⎠ W ∂W W ⎝ V

as obtained from the derivation by Shapiro. Rearranging gives ⎞ dW ⎛ dPt − γ 2 dTt V = − γM 2 ⎜1 − cos φc ⎟ M 2 Pt Tt Vg ⎠ W ⎝ c



which assumes that the injected fluid enters the mainstream at the local static pressure. Exact solution of Equation 19.5 requires integration of the functions, but, assuming that relatively small variations of Tt and W occur, the differentials may be considered ∆’s. The term “linear approximation” is thus derived from the fact that the equation is thus linear in the independent variables dTt/Tt and dW/W. The term dTt/Tt may be simplified by assuming equal mainstream and coolant specific heats and writing the energy equation for a perfect gas in differential form as

Tt g Wg + Tt c dWg = (Wg + dWg )(Tt g + dTt g ) which, when expanded and second-order terms are dropped, becomes

dTt g Tt g


⎞ dWg ⎛ Tt c − 1⎟ ⎜ Wg ⎝ Tt g ⎠


ods. A constant coolant area for each temperature ratio has been chosen so that coolant and mainstream total pressures are equal at a coolant mass fraction ξ = .03. Coolant velocity for high coolant pressures was limited to the sonic value for these calculations. Aside from showing the close agreement of the linear approximation with constant static pressure mixing, the effects of total temperature ratio and coolant injection angle are quite apparent. The close agreement of the two calculation methods is not surprising since they are, of course, identical in the limit of zero coolant addition. Figure 19–26 presents the linear approximation in terms of a dimensionless loss parameter in order to show the effects of temperature ratio and coolant injection angle for the ideal case in which coolant and mainstream gases are identical in composition, have equal total pressures, but differ in total temperature. Figure 19–26 is merely a graphic portrayal of the bracketed term in Equation 19.6. The result shows that not only do losses decrease with decreasing angle of injection, but it also reveals that as injection angle decreases, the effect of coolant-to-mainstream temperature ratio becomes less pronounced for higher temperature ratios and more evident for lower ratios. As coolant

Since dW/W = ξ, Equation 19.5 may then be written in the more convenient form ⎤ Tt ∆Pt − γ 2 ⎡ V = M g ξ ⎢1 + c − 2 c cos φc ⎥ 2 Pt g Vg ⎥⎦ ⎢⎣ Tt g


A further simplification results when Ptc = Ptg, in which case Vc = Vg

Tt c Tt g

since γc = γg = γ has been assumed. The linear approximation method is valuable, not merely because it allows rapid hand-calculation, but also since it reveals the primary mixing-loss parameters in their simplest form. This is seen by comparing Equations 19.3 and 19.4 with Equation 19.6. The latter relationship shows that gas properties affect the mixing result only weakly through the specific heat ratio, while mainstream Mach number and coolant fraction are far more significant, as are the coolant-mainstream temperature ratio, velocity ratio, and the coolant injection angle. As would be expected from a one-dimensional analysis, the losses predicted for injection normal to the mainstream flow (φc = 90°) are independent of coolant velocity since the streamwise component of coolant momentum is zero for all coolant velocities. Figures 19–24 and 19–25 present a comparison of calculated losses using both of the one-dimensional meth-

Figure 19–24. One-dimensional mixing results for coolant injection normal to the mainstream flow direction. [19-1]

Figure 19–25. One-dimensional mixing results for coolant injection inclined 30° from the mainstream flow direction. [19-1]



Figure 19–26. One-dimensional mixing loss for ideal coolant and mainstream gases (γc = γg and Ptc = Ptg ). [19-1]

total temperature approaches extremely low values, the intuition that injection angle becomes less important is confirmed. For total temperature ratios in the general vicinity of ½, however, the effect of coolant injection angle is quite significant. It is also interesting to note that the one-dimensional methods discussed above are in close agreement with one-dimensional constant area mixing methods, which are far more difficult to apply, particularly for transonic Mach numbers. The TOTLOS Method

The one-dimensional methods discussed above are based on the concept of coolant injection at a single location into a uniform mainstream. A more practical problem is that posed by complex cooling geometries in which injection occurs at a variety of locations having differing mainstream and coolant conditions. It is possible to apply the one-dimensional techniques by assuming coolant and mainstream parameters which are “typical” of the lumped cooling system, but the method of selecting the average parameters for such a simplification is not fore-known. The following method, called the TOTLOS method, allows the calculation of the total blade-row ∆Pt due to viscous boundary layers, trailing-edge blockage, and coolant injection. The method, as with the onedimensional ones just discussed, is based on the assumption that losses due to coolant-mainstream mixing may be superimposed on those due to boundary layers and other causes unrelated to cooling per se, such as airfoil base pressure drag and endwall losses. Total pressure loss due to film or transpiration-cooling of the airfoil surface is found by applying the one-dimensional constant static pressure mixing method within a “mixing layer” over each surface, allowing coolant and mainstream flow to be mixed at successive “nodes” along the surface. These nodes may correspond to either rows of injection holes or arbitrary subdivisions of a porous region. The local static pressure of each node is equal to that on the

Figure 19–27. Schematic of the TOTLOS mixing-layer model for calculating losses due to surface coolant injection. [19-1]

airfoil surface at that particular station. As shown in Figure 19–27, the unaffected mainstream flow is then mixed with the contents of both surface mixing layers (again using the one-dimensional constant static pressure mixing method) at a static pressure equal to the average mainstream value in the trailing edge plane (P1). No theoretical basis for selecting the thickness of the mixing layers has been formulated to date, but numerical computations using the TOTLOS method show repeatedly that the final result is not significantly dependent on this parameter. As more experience is gained using the method as a comparison with experimental data, a dependence of mixing-layer size on other parameters may be discerned. Good candidates for such parameters would be cooling geometry, airfoil pressure distribution, mainstream turbulence, etc. For the present calculations, each mixing layer height at Station 0 has been arbitrarily set at 5% of blade-row pitch, and variation of this initial height from 3% to 30% of inlet pitch shows little effect on the final calculated loss. The inclusion of viscous losses, trailing-edge blockage effects, and the effect of coolant injection from the trailing edge is accomplished using the two-dimensional model shown in Figure 19–28. The method used is based directly on that of Stewart, with some modification to include a coolant jet in the airfoil base. The desired result of the two-dimensional calculation between Stations 1 and 2 is the fully-mixed, uniform downstream state, particularly the total pressure and flow direction. The equations of continuity,




2γ ⎞ ⎤ ⎡ ⎛ γ ⎞ ⎤ ⎡ 2⎛ ⎛ γ ⎞ ⎟ ⎢ A ⎜ γ − 1 ⎟ ⎥ ⎢ C ⎜1 − γ − 1 ⎟ ⎥ γ −1⎠ ⎝ ⎠⎥ ⎝ ⎝ ⎠ ⎥− ⎢ 2 ρ =− + ⎢ 2 2 Q2 ⎥ ⎢Q ⎥ ⎢Q − 2c P Tt ⎢⎣ C 2 − 2c P Tt 2 ⎥⎦ ⎢⎣ C 2 − 2c P Tt 2 ⎥⎦ 2 C2 A⎜

from which the complete flow condition at Station 2 may then be found using standard relationships. Two required inputs for the inclusion of boundary layer losses in the final result are the displacement and momentum thicknesses at the trailing edge. The program of McDonel has been adopted for this purpose, but any comparable method could be used. The TOTLOS calculation scheme can become quite laborious if more than a few coolant-injection locations are specified, thus the method has been programmed for numerical computations, allowing the inclusion of real gas properties. Cooling geometries having up to 70 injection locations have been analyzed using the programmed version. The TOTLOS calculation method has been applied to a series of cooled stator designs tested by The Lewis Research Center of NASA. Figures 19–29 through 19–31 present the variation of stator thermodynamic efficiency, both measured and predicted, for the three vane cooling configurations tested. These designs included film-cooling through holes drilled normal to the surface, transpirationcooling employing porous wire-mesh surface segments, and trailing-edge injection through rectangular slots. The film- and transpiration-cooled designs incorporated coolant injection over the entire vane surface and all data were obtained in an annular stator at a coolant-to-mainstream total temperature ratio of 1. Since the TOTLOS method is two-dimensional, a “pitch-line” analysis at a nominal cascade pressure ratio of 1.5 was used to calculate the predicted stator efficiencies shown here. The calculations

Figure 19–28. Schematic of the TOTLOS trailing-edge mixing control volume. [19-1]

tangential momentum, and axial momentum for the control volume shown are written as C = = Q = = A = =

cosα2(ρV)2 cosα1(ρV)1(1 – δTE – δ**) + (s/t)(ρV)c cosα2 sinα2(ρV2)2 cosα1 sin α1[(ρV2)1(1 – δTE – δ** – θ*) + s*(ρV)c cos2α2(ρV2)2 + P2 cos2α1 [(1 – δTE – δ** – θ*)(ρV2)1 + s*(ρV2)c] + P1

By introducing the energy and state equations, the system may be solved. The solution for the case of a perfect gas is a direct one, obtaining the downstream density as

Figure 19–29. Comparison of measured and predicted stator efficiency for film-cooled vanes (ϕc = 90°, discrete coolant holes). [19-1]



Figure 19–30. Comparison of measured and predicted stator efficiency for transpiration-cooled vanes (ϕc = 90°, wire-mesh surface). [19-1]

pressure distribution and the known coolant fraction were employed in an iterative solution to find the coolant supply pressure and the distribution of inflow or outflow over the vane surface. Once this surface flow distribution was found, the mainstream flow into the vane was neglected and only surface outflow was used in the loss calculation. A second case, calculated for each vane design and shown as a dashed line in each figure, was the “design” case in which the coolant supply pressure was held constant at the design value, approximately equal to the inlet total pressure. The predicted efficiencies agree well with the data for coolant pressures equal to or above the design value, the region in which coolant flow distribution could be most accurately predicted. The large differences between efficiencies calculated for the “tested conditions” case and the “design” case at large coolant flows is due primarily to the fact that the ideal available kinetic energy of the coolant is charged to the stator at a total pressure considerably greater than inlet total pressure. As would be expected, trailing-edge coolant injection causes far less loss of efficiency than either normally-injected film- or transpiration-cooling for both the “test conditions” and “design” cases. In summary, the effects of coolant injection on the flow through an airfoil cascade are admittedly complex and require analyses far more sophisticated than those given here if a detailed description of the resultant flowfield is desired. To the turbine designer, however, the methods presented here allow a relatively rapid determination of the effect of coolant injection on blade-row efficiency by predicting the state of the fully-mixed exit flow, a quantity of great interest to the engineer. Comparisons of predicted efficiency variations with data, such as those presented here, have shown the methods to be reliable and consistent. While their most useful application is in the evaluation of the aerodynamic performance of various cooling designs, reducing the amount of expensive testing required, the one-dimensional model also reveals the relative roles of mainstream Mach number, coolant-to-mainstream temperature and velocity ratios, and coolant injection angle in the generation of observed losses. Case 2. Advanced Technology Engine Supportability: Preliminary Designer’s Challenge*

Figure 19–31. Comparison of measured and predicted stator efficiency for vanes with trailing-edge injection. [19-1]

were carried out for each vane design for two distinctly different cases. One case, shown as the solid line in each figure, was for the tested conditions, i.e., coolant flow variation was achieved by varying the coolant supply pressure. This case obviously allows recirculation of mainstream flow within the vane coolant cavity for the film- and transpiration-cooled vanes at coolant total pressures below the stator inlet value. To calculate a “net” coolant injection distribution over the surface in this range, the surface

The United States Government is currently sponsoring, through industry, an ambitious, high risk engine initiative. One goal is to double fighter engine thrustto-weight by the next century. This initiative is called the “Integrated High Performance Turbine Engine Technology,” or IHPTET. Parts of the initiative are currently under contract to the major military aircraft engine manufacturers in the U.S.A. Major advances are planned and under development in engine materials, design innovations, and performance. All design disciplines are involved including supportability. In the IHPTET engine design program, conventional thinking is out; revolutionary but fundamentally sound thinking is in vogue. It’s back to basics, both in design and supportability. One of the problems in the past was the mistaken and simplistic notion that all that was needed during

*Source: [19-2] Courtesy of J. E. Hartsel. J. J. Ciokajlo and J. E. Hartsel. Extracts from “Advanced Technology Engine Supportability: Preliminary Designer’s Chall-enge.” AIAA-88-2796, 1988.


the preliminary or conceptual design to ensure supportability was simplicity. While simplicity is a virtue, it does not, by itself, ensure that something is inherently reliable, maintainable, or repairable. However, coupled with innovative thinking and a thorough understanding of the mechanisms and relative importance of failure, repair, accessibility, cost, etc., the preliminary designer can make decisions at the outset of a design which will allow an engine to be very supportable; but he must be armed with the proper training, motivation, attitude, and then he can make it simple and supportable. General Electric Aircraft Engine (GEAE) Preliminary Design and Supportability have been cooperating, utilizing advanced new materials and design innovations, in an effort to conceptualize an easily supported engine which can be maintained with standard and special tools which fit in a mechanic’s standard tool box. Historical Trends/Recent GEAE Experience

One of the misconceptions that persists in the aviation industry is “that things were better in the old days.” This holds true for supportability and one may still hear tales of aircraft and engines that “never had to be touched.” The comparison must always be tempered by judging the performance of the machines. It is the development of high energy cores that has allowed the dramatic increases in engine thrust-to-weight ratio and specific thrust and which offers the aircraft designer the option of trading range for payload or lets the engine designer trade fan pressure ratio, T41, and bypass ratio to help the system optimization. Thirty or 40 years ago, the engine power-to-weight ratio was a constant, and the world was trying to design bigger and better superchargers to get more performance out of the engine. The jet age started in the USA with the GE I-A in 1941 with a thrust-to-weight ratio of 1.4. Now fighters are powered by engines with ratios over 7, with ratios of 10, 15, and possibly even 20 foreseen within the next two decades. How has supportability fared? Figure 19–32 shows a few data points from the authors’ personal collection of

Figure 19–32. trends. [19-2]

Tactical aircraft and engine maintenance


Maintenance Man Hours per Flight Hour values. Things have been getting better, at least for tactical aircraft and engines, and current study aircraft and engines seem to fall on the same improving historical trend lines. On the surface, the philosophy of testing, analyzing, and fixing appears to be the framework upon which the engine development process is built. Avionics developers have identified the need for more than one pass through the development cycle as a key to reliability improvements. This strategy is referred to as Maturational Development. In the case of engine development, the Maturational Development approach is totally out of the question, based upon the long lead times involved. A key to supportable engine designs is designing supportability into the components during the earliest phases of component research and development and improving on the supportability throughout the whole technology development process. Care must be taken when integrating these components into a final propulsion system design so that all is not lost in the end product. A recent supportability success story from GE Aircraft Engines is the T700. In this case, durable/reliable components were integrated into a final engine designed for ease of access and overall maintenance. The IHPTET initiative demands major performance improvements in our future generations of engines. The challenge facing today’s engine designers is how to reach these performance goals while still improving supportability. The only way to make this happen is for supportability to be a design criterion from the earliest component research and development projects through preliminary design, demonstration, and production. This case outlines an approach to the design of an easily supportable engine. Advanced Materials

Advanced materials are the most important element in the IHPTET initiative. The supportability community, like the design community, must recognize this fact. Metal matrix composites, ceramic matrix composites, intermetallic compounds, high temperature titanium alloys, sapphire fiber reinforced nickel aluminides, and carbon-carbon will be a way of life. Material costs will dictate net shape manufacturing techniques that are still to be defined. Repairability of these materials is still a question at present. Most of the advanced metallic materials will be powders in their initial manufacturing states. It is envisioned that intricate parts, which are currently castings fabricated from molten metals, will initially be injection molded powder slurries—dried, hardened, and sintered into metallic form. Welding will be replaced by applying a putty-like intermetallic compound and then sintering locally to cure the “weld.” Fiber reinforced matrices will be manufactured by either a metallic spray over ceramic fibers or by layers of metallic foil interspersed with layers of ceramic fibers. In either approach, the final step will be fusion by the Hot Isostatic Press (H.I.P.) process. Proper attachment methods (bolts, flanges, etc.) are currently being defined or developed. Material strength, ductility, and rupture properties may be different in in all three directions. It may be possible to repair “weld” a component in the longitudinal direction but not in the transverse direction. The title “metallurgist” may become obsolete; “materials engineer” will probably be a more apt description.



Engine Preliminary Design General Approach

Attaining the high thrust-to-weight goal will be accomplished by integrating all engineering disciplines. It is estimated that 50% of the goal will come from new materials, 35% from design innovations, and 15% from engine performance (aerodynamic and thermodynamic) advances. Improved engine performance will be helped by higher efficiencies and turbine inlet temperatures. Design innovations will include multifunctional components, high temperature lubricated bearings, 360° static structures, and design simplicity. Fiber reinforced metal matrix composites (silicon carbide and sapphire fiber), carbon-carbon (C-C), ceramic matrix composite (CMC), intermetallics, and high temperature titanium alloys will be the new materials for future, very advanced, lightweight fighter engines. The conceptual engine design process begins with the clear enunciation of the requirements. Before the first cycle calculation has been made, the Design Management and Design Team must understand the requirements for performance, weight, cost, and supportability. Requirements for reliability, maintainability, and repairability must be emphasized and given “teeth” by the Design Management. Engine considerations are initiated with the engine stick flowpath. The “stick” flowpath is a sketch the preliminary engine designer receives from the aerodynamic designers. The engine preliminary designer must know all engine design disciplines and be able to modify the engine flowpath without violating the design intent or engineering laws. The engine preliminary designer at this point must (1) produce a concise compact fan, compressor, combustor, turbine, augmentor, and exhaust nozzle flowpath, (2) mentally and physically determine component mechanical configuration, and (3) determine module configuration. At this point, the preliminary designer must be permitted to struggle alone as he addresses the engine design goals of performance, cost, weight, and supportability. Once the designer sets design direction involving all design disciplines, the engine’s initial design configuration begins. The skill with which the preliminary designer understands and balances the often-conflicting requirements as he sets the design direction can have a major influence on the supportability characteristics of the final design. If supportability isn’t considered here, it can conceivably be locked out of the final product. Specific Approach

The crucial first step in the preliminary mechanical design of an engine is the configuration of the sumps and bearings supporting the rotors. Grossly miscalculate initial rotor dynamics and the preliminary design is time wasted. Current engines have multipiece sump, seal, and bearing configurations requiring manual build-up at engine assembly. Future engines will be lubricated by high temperature lubricants with design simplicity as a top priority. Sumps will be one piece cartridge bearing and seal configurations for easy assembly, maintainability, and removal. The quick replaceability of the cartridge bearing is an example of design simplicity and supportability interaction. Once the sumps and shafts are in place, remaining engine components can be wrapped around them, starting

with the combustor and rotors. Fan, compressor, and turbine rotors are located relative to the bearings as dictated by preliminary rotor dynamic analysis. Advanced compression rotor systems are simple, integrated, lightweight disks and blades called blisks. Compressor blade replaceability is a maintainability tool eliminated by blisks; but to compensate, the rotors will be tolerant of substantial imbalance and will have rugged, damage tolerant, low aspect ratio, high pressure rise airfoils, and a minimum number of compression stages. Finally, the casings, shells, augmentor, and exhaust nozzle are added to form an initial engine configuration. Initial Layouts

Once the responsible designer has received and understands the requirements, has initial cycle data in hand, and has held an initial consultation with all design disciplines and management, a series of configuration options should be created by the designer, the designer-draftsperson, and a small team. Modularity and simplicity should be the guidelines. Upon completion, each configuration is critiqued by the full design group and management. These initial layouts will merely be first attempts to incorporate past experience and design practices, but they should also be allowed to contain the new and creative ideas that have been waiting for a home. During this phase of the design process, the drafting room population should be kept to a minimum except when critiques are invited. Supportability interests and considerations, such as modularity, multifunctional components, ruggedness, accessibility, etc., must be given the same emphasis as the other “traditional” requirements during this critique and iteration phase. Specific Examples Overall Engine

Supportability must be designed into the engine in the preliminary design phase, preferably with little or no increase in engine weight or cost. There must be a game plan for assembly, disassembly, and module selection. Figure 19–33 illustrates a schematic of an engine on an assembly dolly. Here major module assemblies such as the augmentor and exhaust nozzles, fan duct, low pressure turbine, and fan and fan frame are mounted and attached to mini dollies so that after disconnecting electrical and service lines, engine axial disassembly can be attained as illustrated in Figure 19–34. Rapid access to the high pressure turbine and combustor module is attained. This type of disassembly/assembly is considered highly desirable in many military scenarios. The engine core or high pressure section of a turbofan engine, normally a small volume portion of the engine, can be rotated vertically in the dolly for further access to either the high pressure turbine or compressor modules and the compressor rear frame assembly. This engine disassembly approach is nothing new—it has been with us for years. This principle was in General Electric’s J-85 engine design, which now has seen 30 years of service. Component Design

Figures 19–35 and 19–36 show specific examples how the maintainability aspect of supportability can be incorporated in the engine in the preliminary design phase. The advent of new composite materials allows the designer to

BASIC DESIGN THEORY Low pressure turbine and frame



Augmentor and exhaust nozzle

High pressure turbine


Module brackets and rollers

Engine dolly Figure 19–33.

Modular engine and dolly arrangement. [19-2]


Figure 19–34.

LP shaft

HP compressor and turbine

Fan duct

LP turbine and frame

Augmentor and exhaust nozzle

Modular engine disassembly and core access. [19-2]


Bolt Curvic Coupling

Figure 19–35. [19-2]

Conventional spline with backoff bolts. Figure 19–36.

Curvic coupling detail. [19-2]




Figure 19–37.

Altitude-mach number chart. [19-2]

custom tailor materials for specific maintainability problems. Figure 19–35 illustrates a conventional shaft spline detail complete with interference fit pilots. Conventional design practice requires pilot interference fits of 0.0005 inches per inch of pilot radius and special tooling to assemble/disassemble splined components. This brute force assembly technique has been effective for past rotor designs using monolithic, metal rotor materials, but requires simultaneous heating and chilling or large special tools. However, this technique is antiquated when applied to advanced design rotors of different materials operating at elevated temperatures. By selecting the material of the respective shafts, the thermal growth coefficients can be matched so a loose fit or snug close tolerance pilot fit is obtained at assembly room temperature and a very tight interference fit, caused by differential radial thermal growths, is achieved

at pilot/spline operating temperature. This simple, old, but effective technique, where applicable, can be applied throughout the engine, thus eliminating the use of large and heavy special tooling and allowing the use of simple techniques such as “backoff” bolts, as illustrated in Figure 19–35. These simple tools can either remain on the engine or fit in a mechanic’s standard tool box. Controlled shaft heating is another feature available when splined shafts have mismatched thermal growths. Selective heating of the inner shaft by a portable electric heater causes inner and outer shaft relative axial growth, unseating the locking nut for easy nut removal. This simple concept, if properly controlled, eliminates the need of heavy load cells or torque multiplier wrenches for rotor assembly/disassembly. A second simple, but effective, design assembly/disassembly feature is the old technique of “lead-ons” to protect


critical and fragile engine sump seals and other components. For decades engine sumps have been designed as an assortment of small components, hand assembled at engine assembly and requiring interim special dimensional checks. More recent engine sump designs have eliminated special assembly dimensional checks but still require delicate assembly procedures. Why not design the bearings, seals, oil jets, and other related components as a one piece mini module? This principle has been accomplished in electronic design—it’s called the circuit board, used extensively in television sets. If special lead on procedures for components are required, “lead on” rods are a simple and effective method that (1) if left on the engine add little weight, and (2) if removed can fit in a mechanic’s tool box. Long rods or pins, attached via flanges to the engine casing, allow a “lead on” to protect the sumps, shrouds, or other critical components at assembly/disassembly. A circumferential series of rods or pins, with long protrusions, are rigidly attached to one component and engage with and align a second component prior to engagement of the respective component sump seals, rotor shrouds, or other critical parts. A design such as this requires reasonable, but not special, care at assembly. Another design detail that can be utilized in the preliminary design phase is the old design friend, the curvic coupling. The use of engine compressor blisks (integral one piece disks and blades) reduces compressor rotor weight but can add difficulties to rotor blade repairability; and, in some instances, impairs compressor rotor accessibility by eliminating the compressor split casing. This one piece casing unit can further reduce engine weight. Therefore, another method must be devised for compressor rotor accessibility, and curvic couplings is an example of this. As stated in Specific Examples—Overall Engine, the engine core module of a turbofan is a small volume and could be rotated vertically in the engine dolly. By machining curvic couplings into the compressor blisk ends, the compressor rotor can be held together as one piece by a single tie bolt. The T700 compressor rotor is a blisk design held together


in this manner. Figure 12-36 illustrates the rotor blisk curvic coupling feature. With the engine core module in the vertical position, heat can be applied to the core rotor tie bolt shaft, inducing shaft axial growth and unloading the nut. With the axial load reduced or eliminated, the coupling nut can be removed. A final example to aid engine supportability in the preliminary design phase is the design of engine static components. Static components in advanced engines account for approximately 60% of the weight. Engine supportability can best be served by minimizing potential problems. There can be no frame problems if there are no frames. Designing 360°, one piece, multi-functional components which perform functions previously required by two or three units not only saves engine weight but also minimizes supportability problems by component elimination. In summary, the United States military services are participating with the aircraft engine industry in an ambitious program to develop high performance engine technologies for advanced future military applications. This radical program, starting from a “clean sheet of paper,” is a golden opportunity to integrate many radically advanced but fundamentally correct engineering disciplines, including supportability, into future, very high thrust-to-weight fighter engines. The thrust-toweight ratio goal is double that of current military engines under development and almost triple the thrustto-weight ratio of fighter engines currently flying. This accomplishment, scheduled for completion in 15 years, will require the total cooperation and understanding between management, supportability, and engineering. Engine supportability techniques may change but fundamental basics will apply. New materials, not yet commercially available, must be understood. The preliminary design engineer will always be a radically thinking, analytically oriented person with his/her head in the clouds; and the supportability engineer will have both feet on the ground beset with day-to-day problems. Some technical crossbreeding between both will be necessary to meet the supportability challenges of the future.

Additional References and Appendix for Unit Conversion


“The only true wisdom is in knowing you know nothing.” —Socrates


Additional General References 722 Some Specific References 722 Unit Conversions 722



Additional General References* 1. Websites

A great deal more information is available on the websites of the following sources: Siemens Power Generation Rolls Royce Alstom Power Mitsubishi Power Systems The U.S. Department of Energy (DOE) The U.S. Environmental Protection Agency (EPA) Actual web addresses are not included in the location as these can change. The reader is advised to do a Google search as these organizations may have more than one website or subsite. 2. Other firms whose material is sourced or referenced can also be found using the Google search engine, for instance:

Liburdi Engineering, Canada Westfalia Separators, Germany Rotadata, United Kingdom This way the reader can get current information on new branches or country representatives. 3. CD Roms

All of the firms mentioned in 1 and 2 preceding publish their works in conference proceedings such as ASME’s (American Society of Mechanical Engineers) IGTI (International Gas Turbine Institute) and Pennwell PowerGen conferences. Conference proceedings can be purchased from the conference offices, in per-paper format or as a conference CD Rom. 4. Books

Soares, C. Environmental Technology and Economics. Boston: Butterworth–Heinemann, 1999. Soares, C. Process Engineers Equipment Handbook. New York: McGraw Hill, 2001. Bloch, H., and C. Soares. Turboexpanders. Houston: Gulf, 2000. Bloch, H., and C. Soares. Process Plant Machinery, 2nd Edition. Boston: Butterworth–Heinemann, 1998. These books are available from several Internet sources, if unavailable through the publisher. 5. Technical Journals

Throughout this book, I used relevant extracts of articles I have written for various technical journals, including but not limited to the following:

Asian Electricity++, 1997 through 1999. Middle East Electricity++, 1997 through 1999. The Petroleum Economist, 1998. Modern Power Systems, 1998. Pollution Engineering, 2001. International Power Generation (IPG)++, 1997 through 2006. European Power News++, 2006 Some Specific References Chapter 5, Cooling and Load Bearing Systems

Lubrication engineers: Oil analysis: default.asp?sectionlink=LubricantSelection Turbine Oils

Association of Iron and Steel Engineers. The Lubrication Engineers Manual, 2nd edn. Pittsburgh: AISE, 1996. Bloch, H. P. Practical Lubrication for Industrial Facilities. Lithburn, GA: Fairmont Press, 2000. Exxon Mobil Corporation. Turbine Inspection Manual. Fairfax, VA: Exxon. Swift, S. T., D. K. Butler, and W. Dewald. Turbine Oil Quality and Field Applications Requirements: Turbine Lubrication in the 21st Century. ASTM STP 1407. West Conshohocken, PA: ASTM, 2001. ASTM. Standard Practice for In-Service Monitoring of Mineral Turbine Oils for Steam and Gas Turbines. ASTM D4378-97, Annual Book of ASTM Standards, vol. 05.01. ASTM. (1997). Chapter 9, Controls, Instrumentation, and Diagnostics

Re control valves: shtml Electrostatic charge monitoring: getabs/servlet/GetabsServlet?prog=normal&id=JOTRE 9000124000002000288000001&idtype=cvips&gifs=yes Failure prevention: Resensors/transducers: Temperature-sensitive paint: cfm?pageid=231&masterid=62 http://www1.mengr. Ultrasound diagnosis: Chapter 19, Basic Design Theory

Walsh and Fletcher, Gas Turbine Performance, Blackwell Science, 1998. Unit Conversions

*Publishing is a communications mode for engineering technology, not the technology itself. Publishers are also subject to worsening financial conditions in their industry. Therefore, a great deal of still current and useful material has been removed from publishers’ stocking shelves. Several good technical journals are no longer in business. That said, I will acknowledge these books and technical journals where I quoted or referenced extracts of previous work. There sources are available from used book internet-shop outlets and many engineers keep copies of their magazine subscriptions. The reader may be well advised to pursue secondary sources to obtain these and similar references if possible. This material may not always be available in publishers’ latest offerings or on web-published sites.

This section presents, in alphabetical order, all unit conversions likely to be required for gas turbine performance calculations. For all tables, except that covering pressure or stress, a quantity in given units is multiplied by the value in the next column to the right to convert it to the units in the column to the right of the conversion factor. The conversions presented may be combined, for example for acceleration mile/hs may be converted to ft2/s by multiplying by 0.447 and then by 3.28084. ++These

publications are not in print or circulation at this time, so individual article titles are not included here.




Multiply By

To/From This

Multiply By


Acceleration ft/s2 km/hs mile/hs mile/hs

0.3048 0.27778 1.609344 0.447

m/s2 m/s2 km/hs in/s2

3.28084 3.6 0.621371 2.23714

re’s kin/hs mile/hs mile/hs

Area in2 in2 ri2

645.16 6.4516−04 0.092903

MM2 m2 m2

0.00155 1550.0 10.7639

in2 in2 ft2

Density lb/ft3 113/in3 l h/UKgal lb/USgal

16.0185 27.6799 0.0997763 0.0830807

kg/m3 kg/m3 kg/m3 kg/m3

0.062428 0.0361273 10.0224 12.0365

lb/113 lb/in3 lb/UKgal lb/USgal

Calorie Chu Chu hp h hp h kWh kWh

0.555558 778.169 1.05506 401868 0.0022046 1899.105 1400.7 1.98+6 2.68452 2.65522+6 3.600

Chu ft lbf kJ J Chu J ft lbf ft lbf MJ ft lbf MJ

1.8 0.28507−03 0.947817 0.238846 453.597 0.0005265 7.1393−04 5.0505−05 0.372506 3.76617−05 0.277778

Btu Btu Btu Calorie Calorie Chu Chu hp h hp h kWh kWh

Force kgf lhf lhf lhf tonf (Imperial)

9.80665 0.4535924 3.2174 4A4822 9964.02

N kgf lb/ft s2 p(11) N N

0.0101972 2.20462 0.031081 0.224809 1.00361−04

kgf lhf lhf lhf tonf

Fuel consumption mile/UKgal mile/UKgal mile/USgal

0.354006 0.83267 0.29477

km/litre mile/USgal km/litre

2.82481 1.20096 3.39248

mile/UKgal mile/UKgal mile/USgal

Length ft in in mile nautical mile* yard

0.3048 0.0254 25.4 1.609344 1.852 0.9144

m m mm km km m

3.28084 39.3701 0.0393701 0.621371 0.539957 1.09361

ft in in mile nautical mile yard

Mass lb lb ounce tonne UK ton UK ton

0.45359237 0.031056 28.3495 1000 1016.05 1.01605

kg slug g kg kg tonne

2.20462 32.2174 0.035274 0.001 9.84207−04 0.984207

lb lb ounce tonne UK ton UK ton

Moment of inertia lb ft2 in ft2

0.0421401 2.9264−04

kg m2 kg m2

23.7304 3417.17

lb ft2 kg m2

Energy Btu Btu Btu Calorie





Multiply By

To/From This

Multiply By


Momentum—angular lb ft2/s


kg m2/s


lb ft2/s

Momentum—linear lb ft/s


kg m/s


lb ft/s

Power Btu/s Btu/s Btu/s Chu/s Chu/s ft lbf/s hp hp PS** PS PS

0.555558 778.169 1.05506 2.54674 1.899105 1.35582 550 0.7457 0.98632 75 735.499

Chu/s ft lbf/s kW hp kW W ft M/s kW hp kgf m/s W

1.799992 1.28507−03 0.947817 0.39266 0.5265 0.737562 1.81818−03 1.34102 1.01387 0.0133333 1359.62−06

Btu/s Btu/s Btu/s Chu/s Chu/s ft lbfis hp hp PS PS PS

Specific energy Btu/lb Chu/lb Chu/lb ft lbf/lb

2.326 45066.1 4.1868 2.98907

kJ/kg ft2/s2 kJ/kg J/kg

0.429923 2.219−05 0.238846 0.334553

Btu/lb Chu/lb Chu/lb ft lbf/lb

Specific fuel consumption (SFC) kg/kW h lb/lbf h lb/lbf h lb/hp h lb/hp h

0.735499 0.10197 1.0197 0.60828 0.447387

kg/PS h kg/N h kg/daN h kg/kW h kg/PS h

1.35962 9.80665 0.980681 1.64399 2.2352

kg,/kW h lb/lbf h lb/lbf h lb/hp h lb/hp h

Specific heat Chu/lb K Chu/lb K ft lbf/lb R HPs/lb K

1 4186.8 5.38032 1643.99

131u/lb R J/kg K J/kg K J/kg K

1 2.38846−04 0.185863 6.08277−04

Chu/lb K Chu/lb K ft lbf/lb R HPs/lb K

Specific thrust lbf s/lb


N s/kg


lbf s/lb

Torque 114 ft Kit lbf in

0.138255 1.35582 0.112985

kgfm Nm Nm

7.23301 0.737562 8.85075

lbf ft lb ft lbf in

Velocity—angular dcg/s rev/min (rpm) rev/s

0.0174533 0.104720 6.28319

rad/s rad/s rad/s

57.2958 9.54930 0.159155

deg/s rev/min (rpm) rev/s

Velocity—linear ft/s kt† kt mile/h mile/h mile/h mile/h

0.59248 1.852 0.514444 1.46667 1.609344 0.86896 0.44704

kt km/h m/s ft/s km/h kt m/s

1.68782 0.539957 1.94384 0.681818 0.621371 1.1508 2.23694

ft/s kt kt mile/h mile/h mile/h mile/h

Viscosity—dynamic lb/ft s


kg/m s


lb/ft s



Multiply By

To/From This

Multiply By


lb/in s lbfb/ft2 lbfs/ft2 Pa s (kg/m s) Pa s

17.858 0.172369 47.8803 1000 1.0

kg/m s MN s/m2 kg/ms cP N OW

0.055997 5.80151 0.0208854 0.001 1.0

lb/in s lbf h/ft2 lbfs/ft2 kg/m s Pa s

Viscosity cSt ft2/s in2/s

106 0.092903 6.4516

m2/s m2/s cm2/s

106 10,7639 0.155

cSt ft2/s in2/s

Volume in3 ft3 UK gallon UKgallon USgallon yard3

16.3871 28.3168 4.54609 1.20095 3.785 0.764555

cm3 litre litre USgal litre m3

0.0610237 0.0353147 0.219969 0.832674 0.2642 1.30795

in3 ft3 UKgal UKgal USgal yard3


*This is the international nautical mile; the UK Nautical mile is obsolete. **The PS is also called a metric. †This is for the international knot; the UK nautical mile is obsolete.

Pressure and Stress

See the following table for pressure and stress conversions. atm atm bar in Hg in H2O kgf/cm2 mm Hg nun H2O lbf/in2 (psi) kPa

0.986923 0.0334211 0.0024583 0.96784/ 0.0013158 0.0000978 0.068046 0.D098692


in Hg

in H2O


mm Hg

mm H2O

ibf/in2 (psi) kPa


29.9213 29.53

406.782 401.463 13.5951

1.03323 1.01972 0.0345316 0.00254

760.0 750.062 25.4 1.86832 735.559

10332.3 10197.2 345.316 25.4 10 000 13.5951

14.6959 14.5038 0.491154 0.036127 14.2233 0.0193368 0.0014223

0.0338639 0.002491 0.980665 0.0013332 0.0000981 0.0689476 0.01

0.073556 28.959 0.03937 0.002896 2.03602 0.2953

393.701 0.53524 0.0393701 27.68 4.01463

0.0013595 0.0001 0.070307 0.0101972

0.073556 51.7149 703.07 7.50062 101.972

101.325 100 3.38639 0.249089 98.0665 0.133322 0.009807 6.89476


Notes: To convert a value in the units in the left-hand column to those in the top row multiply by the number at the junction of the row and column. The conversion factors for columns of H2O are for water at a uniform density of 1000 kg,/m3 under the standard gravity of 9.80665 m/s2. The conversion factors for columns of Hg are for mercury at a uniform density of 13.590 kg/m3 under the standard gravity of 9.80665 m/s2. 1 kPa is equivalent to 1 kN/m2.


Conversion shown is to convert a quantity from units after the = sign to units before it. C = K − 273.15 F = 1.8 × K − 459.67 R = 1.8 × K K = C + 273.15 C = (R − 491.67)/1.8 F = R − 459.67 R = 1.8 × (C + 273.15) K = (F + 459.67)/1.8 C (F − 32)/1.8 F = 1.8 × C + 32 R = F + 459.67 K = R/I.8

Index Page numbers followed by f, t indicate figures and tables respectively ABB Alstom Power, 145–151, 300, 662, 667 India market entered by, 662–663 ABB Alstom Power Cyclone, 152, 562, 586, 667 ABB Alstom Power Tempest, 151–154, 562, 586, 667 ABB Alstom Power Tornado, 667 ABB Alstom Power Typhoon, 145–147, 150–152, 287, 562, 586, 667 ABB GT8, 565 ABB GT11N2, 565 ABB GT11N-EV, 379, 380f, 381 ABB GT24, 565 ABB GT35, 4, 11–12, 562, 586 ABB Stahl, 645, 669 ABB Stahl GTX-100, 669 ABB Synchrotact, 509 ABET. See Accreditation Board of Engineering and Technology Abrasive blasting, 587 ACC. See Active clearance control; Air-cooled condenser Acceleration control, 219f Acceptance criteria, 574 Accessory cooling, 169 Accessory drives aircraft and, 554–555 construction of, 296, 298 direct, 294 engine mounting and, 554–555 gear train, 294 gearboxes for, 294, 296, 297f, 298f gears for, 296, 298 materials for, 296, 298 mechanical arrangement of, 294, 295f, 296f radial, 294 Accreditation Board of Engineering and Technology (ABET), 646, 647, 653. See also Engineering criteria 2000 ACHP. See High pressure air cooler Acid rain, 665–666 Ackeret, J., 34 Active clearance control (ACC), 74, 160, 564 Active magnetic bearings (AMB), 631, 633 ADC. See Adjusted direct cooling ADH. See Advanced diffusion healing Adiabatic efficiency, 8 Adjusted direct cooling (ADC), 448, 450f, 451 full STIG and, 453, 454f Adjusted indirect cooling (AIC), 448, 454 Advanced diffusion healing (ADH), 530, 536 Advanced Turbine System (ATS), 434–439, 435f. See also Siemens Westinghouse brush seals of, 435–436 coatings in, 435–436, 439 compressor module of, 435 development activities of, 438–439 operating experience with, 437–438 steam cooling in, 436, 438–439

testing of, 436–437, 437f, 437t, 438f turbine blades of, 436 “An Aerodynamic Theory of Turbine Design” (Griffith), 34 Aerodynamische Versuchs-Andstalt (AVA), 34 Aeroelastic instability, 457 Africa, 663 Aft fan, 10 Afterburning, 39, 69f, 74, 191, 389, 390, 568, 652. See also Reheat construction of hardware for, 321, 323 control for, 323–325, 323f, 324f, 325f, 359 fuel consumption and, 325–326, 326f ignition for, 320, 322f jet pipe and, 319–320, 321f, 322f operation of, 320–321 performance and, 393 principles of, 319–320, 320f propelling nozzle and, 320, 323 rate of climb and, 326, 326f thrust calculation and, 339, 339f, 393 thrust increase from, 325, 325f warning panel and, 367 AIC. See Adjusted indirect cooling AIDS. See Aircraft integrated data system Air bleed systems, 129, 133f, 134f. See also Bleed extraction Air resistance, 19 Air separation unit (ASU), 112, 248 Air speed, 23, 689, 692 Airbus A321, 504, 564 Air-cooled condenser (ACC), 470 Aircraft. See also Short takeoff vertical landing accessory system location and, 554–555 aircraft integrated data system and, 367 controls for, 359–368 electronic indicating systems and, 367–368, 368f engine accessibility on, 554f, 555 engine cowlings on, 555 engine installation for, 550–555 engine selection for, 24–25 engines for, 3, 5–11, 23–31 environmental envelope and, 687 exhaust systems for, 189–191 fire warning and, 309, 367 flight envelope of, 680, 689, 690f, 691f, 692 flight phases of, 23 fuel flow rate indicator in, 366, 366f fuel pressure indicator and, 366 fuel temperature indicator and, 366 ingestion tests for engines of, 414 installation pressure losses and, 689 instrumentation for, 359–368 intakes and, 551–552 noise levels of, 193f noise suppression for, 191–196 oil temperature indicator and, 365–366, 366f



Aircraft (Continued ) parameters for control and instrumentation for, 358–359 power plant location in, 550–551, 550f selecting control and instrumentation for, 358 shaft powered, 25–26, 27f, 706 short takeoff vertical landing and control of, 331–335, 335f synchronizing and synchrophasing in, 368 thrust propelled, 26–30, 28f turbojet instrument panel in, 360f vibration indicator for, 366–367, 367f warning systems in, 367 Aircraft integrated data system (AIDS), 367, 497 Aircraft services, 172 Airflow altitude and, 214, 215f apportioning, 136f compressor module and control of, 131 cooling and, 168–169 fuel cells and, 630 internal pattern of, 168f measurement of, 409–411, 410f path of, 8, 10, 10f, 11f, 168f stable, limits of, 131f velocity of, 8 Airforce One, 560 Airmeters, 409–410 Alfa Laval, 670 AlliedSignal, 606 AlliedSignal Parallon 627–628 Allis-Chalmers, 35 Allison, 35, 586, 606. See also Rolls Royce Allison Allison 248, 566, 656f Allison 499, 17 Allison C-18, 566 Allison C-20B, 566 Allison C-30, 566 Alstom, 49t, 106, 114, 121, 142f, 265, 268, 274, 282, 285, 455, 457t, 563, 586, 662, 666, 667. See also ABB Alstom Power Alstom 11N, 670 Alstom 13D-3, 667 Alstom 13E2, 106 Alstom GT 11N2, 3–4, 379 repairing, 536 Alstom GT10, 663 Alstom GT24, 3, 445 Alstom GT26, 3, 113, 445 Alstom GT35, 4 Altair, 203 Alternative energy technologies, 660 Alternator, direct drive, 631–632, 633 Altitude. See also Engine test bed; Pressure altitude airflow and, 214, 215f humidity and, 689f mach number and, 719 performance and, 393–394, 394f shaft horsepower and, 393 Altitude sensing unit (ASU), 221 Altitude test facility (ATF), 401, 403, 526, 526f AMB. See Active magnetic bearings Ambient conditions v. pressure altitude, 681t–683t Ambient pressure, 680 pressure altitude v., 684f Ambient temperature, 680

humidity and, 688f pressure altitude v., 684f American Petroleum Institute (API), 667 American Society of Mechanical Engineers (ASME), 559, 562. See also IGTI performance test codes by, 573–575 Analysis exchange rates, 419 ANalysis-SYNthesis (ANSYN), 383 Annular combustion chamber, 137, 139, 140f, 288, 445 Ansaldo Energia, 49t, 244 ANSYN. See ANalysis-SYNthesis API. See American Petroleum Institute APIC, 54t Appendage resistance, 19 Application testing, 415 APU. See Auxiliary power unit Aquifer flow modeling, 488 Arctic warming, 472 Asea Brown Boveri (ABB), 559, 662, 667. See also ABB Alstom Power; European Gas Turbine ASEAN, 558 Asia, 662–663 Asian currency crises, 662 ASU. See Air separation unit; Altitude sensing unit ATF. See Altitude test facility Athodyd, 36, 37. See also Ramjet Atomizing spray nozzle, 229 ATS. See Advanced Turbine System Audits aims of, 503 assessing findings of, 516–518 detection, assessment, and planning in, 511–516 engine test bed, 413 fuel testing and, 512 maintenance and, 502–503 planning, 503–504 procedures for, 504–505 shutdown/turnaround/postfailure, 388 Austenitic steels, 97, 98, 101 Autoignition measuring delay of, 277–280, 279f, 280f modeling, 276–277 water and, 280, 281f Automotive vehicles, 17–18, 18t installation pressure losses and, 689 Auxiliary power unit (APU), 30–31, 30t, 618 pneumatic, 31 starting with, 302 AVA. See Aerodynamische Versuchs-Andstalt Aviadvigatel JSC, 43t Aviall, 561 Avio SPA, 43t Axial compressor, 5, 12, 14, 34, 40f, 127–128, 137 accessory gearbox and, 294 construction of, 129 operating principles of, 129 pressure changes through, 129f rotors for, 129–131, 130f single-spool, 127f stator vanes for, 131 triple-spool, 128f twin-spool, 127f velocity changes through, 129f water injection and, 312 Axial thrust, 453, 453f

INDEX Baksheesh, 568, 662 Balancing, 132, 523–524, 523f, 524f Barometers, 404–405 Base load power plants, 15 low cycle fatigue and, 570 BAT. See Best available technology Bauersfeld, W., 34 Baylor University, 645, 647, 653–655, 657–658 BBC. See Brown Boveri Company Bearing chamber cooling, 169 Bearing loads, control of, 172 Bearings active magnetic, 631, 633 cooling of, 169 failure of, 517 in generators, 342, 343f lubrication of, 179, 181 squeeze film, 177, 178f steam turbines and, 82, 91f, 92f turbomachinery, 172 Bechtel, 115, 117t, 242, 458, 664 Bell, 568 Bell, Frank, 17 Bell Jet Ranger, 566 Bell Textron/Boeing Osprey, 568 Benson Once-Through Steam Generator (OTSG), 460–462 Bentley Nevada, 558, 586 Berlin University of Technology, 644 Best available technology (BAT), 121, 245, 473, 568 Betz Petromeen, 268 Bharat Heavy Electricals, 49t Biofuels, 655 Biomass, 234, 663, 666, 675t, 676 Blade moment weighting, 524–525, 525f Bleed extract system, 186, 187 Bleed extraction, 385, 385f Blended fuel oil (BFO), 271, 271f Blowdown, 117, 575 Blow-off valves (BOV), 384 BMW, 644 BMW hollow blade, 160, 160f Boeing 745, 23, 567 Bomb calorimeter, 408 Boots Company, 145–151 Boundary conditions, assumed, 578, 578t, 583–584, 584t BOV. See Blow-off valves Boyle’s Law, 6 BP, 485 Brayton cycle, 75f, 102f, 103f, 104f, 653, 654, 695, 699, 701f Brazing, 587 Breather, 177, 178f Bristol Aero-Engine Company, 326 Bristol Engine Company Proteus engine, 19 Brite Euram, 98 British Caledonian Airways, 561 Brown Boveri Company (BBC), 34 Brush seals, 172, 435–436, 558 Buch, Regina, 563 Bulkmeter, 407–408 Bunker fuel, 245. See also Residual fuel Burner. See Combustor module Burns, Tony, 561 Bush, George, 671–672 Business climate, contemporary, 558–559 Butane, 243, 282t, 283f


Bypass doors, 186–188 Bypass principle, 8, 10 Bypass ratio, 10, 25, 27, 28–29, 192f, 703 CAD. See Computer aided design Calibrated air speed (VCAS), 689, 692 California Energy Commission, 672–673, 676–677 California Public Utilities Commission (CPUC), 672–673, 674t, 676 Calorific value, 232, 232f, 234–235 CAM. See Computer aided manufacture Capillary drilling, 594 Capstone Turbine, 60t, 618, 621 Carbon dioxide (CO2), 50f, 472, 475, 666, 667, 671 capturing, 14–22, 480, 489–490 improved oil recovery using, 491–492 mitigation of, 473 power plants and, 582, 582f reinjecting, 473 sequestering of, 568 storing, 14–22, 480 taxes on, 474, 669 transporting, 491 underground injection of, 485, 486–487 undersea injection of, 492 utilizing, 14, 480, 491–492 Carbon Dioxide Capture Project. See CO2 Capture Project Carbon monoxide (CO), 117, 143, 145, 151f, 153f, 287, 474–475 catalytic reduction of, 460–461, 464 combustor and, 570 emission factors for, 477t water injection and, 422 Carbon seals, 171–172 Carnot cycle, 699, 701f Carpet plot, 651f Casings forging of, 589 maintenance and, 598 manufacture of, 588, 603–604 sandwich, 595–596 steam turbines and, 86 Casting, 587, 589, 590f automated, 591f investment, 587, 589, 590f CASTOR, 490 Catalytic reduction systems, 478. See also Sconox; Selective catalytic reduction; Xonon flameless combustor Catalytica, 154–155 Cathedral diesel engines, 18 CC. See Combined cycle power generation CD. See Discharge coefficient CDP. See Compressor differential pressure CEM, 34. See also Continuous emission monitoring Central warning panel (CWP), 367 Centrifugal compressor, 5, 12, 14, 40, 123f, 129, 137 accessory gearbox and, 294 construction of, 126 diffuser for, 126–127, 126f impeller for, 126, 126f, 127 operating principles of, 125–126 pressure changes through, 125f velocity changes through, 125f Centrifugal separation, 254, 255f, 257, 257t, 258f, 259f, 262, 264–265, 266t, 267f



Ceramic components, 605 filters made from, 611–615, 612t, 613t vanes made from, 606–611, 607f, 609f, 610f, 611f Ceramic matrix composite (CMC), 717 CFCC. See Continuous fiber reinforces ceramic composites CFCs. See Chlorofluorocarbons CFE Company, 43t CFM International, 43t Change in enthalpy, 699 Charles’ law, 6 Chavez, Hugo, 663 Chemical forming, 592, 594 Chernobyl, 665 China, 662–663, 669 Chlorofluorocarbons (CFCs), 472 CHP. See Combined heat and power Chromalloy, 527 surface reaction braze by, 530, 536 Chromate sealing, 587 CID. See Controls, instrumentation, and diagnostics system CIP. See Component improvement program Circulating pressurized fluidized bed combustion (CPFBC), 579, 580, 580f, 611 Cleaning, 513 cycle for, 246t off-line, 246, 246t, 274, 350–351 online, 349–352 overhaul and, 520 water injection and, 350 Climate change, 472, 480. See also Arctic warming Closed cycle turbines, 16, 70, 81f, 103f, 233 design points and, 706 CMC. See Ceramic matrix composite CNC. See Computer numerical control CNC rig welding, 515 CO. See Carbon monoxide CO2. See Carbon dioxide CO2 Capture Project, 485, 490 CO2 Store program, 488, 490 CO2 Sink, 490 Coal gas, 666 Coal gasification, 234, 473, 666. See also Integrated coal gasification combined cycle Coalescers, 186, 187 Coal-fired power plants, 578–580, 665–666 COBALT. See Computer based learning and teaching CODAG. See Combined diesel and gas turbine CODLAG. See Combined diesel electric and gas turbine CODOG. See Combined diesel or gas turbine COGAG. See Combined gas turbine and gas turbine Cogeneration, 78–79, 79f, 389, 473, 618, 654, 657–658, 660, 664 factors for, 458 gas turbine integration into, 455–458 power addition in, 511 Combined acceleration and speed control system, 222–225, 223f, 231 Combined cycle power generation (CC), 70, 72, 73f, 74, 101–113, 239, 569, 581f, 597, 664, 667 construction cost and, 106, 111f cost per fired hour and, 110 cycling, 566 design decisions for, 570–572 design points and, 705–706 dual-pressure, 106f economics and, 105–106

equipment selection for, 456, 457t exhaust systems and, 457–458 facility requirements for, 465, 465t fuel for, 108–110, 109f gas-fired, 580 guaranteed values for, 574 integrated gasification, 112–113, 113f, 242, 243–244, 248, 249f, 250f, 576t, 580 load cycling and, 462–470, 465, 466t–467t, 467, 470 modular strategies for, 106, 110 plant configuration for, 455–456 plant design for, 459–462 power generation with, 455 startup of, 458, 468f startup time optimization of, 459–462 steam turbine construction for, 455, 458 thermal efficiency of, 570 thermal performance of, 458 thermodynamic processes in, 576t trends in, 110 Combined diesel and gas turbine (CODAG), 20, 22f Combined diesel electric and gas turbine (CODLAG), 20, 22, 22f Combined diesel or gas turbine (CODOG), 20, 22, 22f Combined gas turbine and gas turbine (COGAG), 20, 22, 22f Combined heat and power (CHP), 12, 15f, 72–73, 73f, 145, 189, 632, 661 design point and, 706 fuel cells and, 626 large scale, 14 microturbines and, 621–622 small scale, 12–14 Combustion, 8 efficiency and, 135, 140, 140f emissions and, 143, 143f, 473, 570 fissions and, 141 intensity of, 139 process of, 135–136, 233 products of, 235, 238, 431, 693–694 sequential, 445–448, 446f, 447f, 565 stability of, 140, 141f temperature of, 143 thrust distribution and, 335 Combustion chambers, 134–135, 135f annular, 137, 139, 140f, 288, 445 emissions controls and, 473 fuel supply to, 136–137 materials for, 141 multiple, 137–138, 138f performance of, 139–141 sequential, 565 steam injection in, 445 thrust calculation and, 337, 339, 339f turbo-annular, 137–139 water injection in, 313, 314f, 422–425, 424f, 425f Combustion turbine (CT), 462–463, 465, 474 thermodynamic processes in, 576t Combustor module, 2, 122, 143, 149f, 284 component tests for, 600f dual-fuel DLE, 145–154, 151f, 154f emissions control and, 570 environmental regulations and, 121 flameless, 141, 154–155, 155f, 476 fouling of, 517 fuel supply in, 136–137 inspection of, 497

INDEX low-NOx, 141 measurement of dynamics of, 149, 150f nitrogen oxide emissions and, 570–572, 598 repairing, 535–536 two-stage, 571 Combustor starter, 302 Community Choice Aggregation law, 672–673 Community Environmental Council (CEC), 661 Comparitor, 227 Component design point, 702 linear scaling and, 704 Component improvement program (CIP), 562, 670 Component maps, 431 Component performance parameters, 703 Composites, 587, 595–596, 596, 715. See also Continuous fiber reinforces ceramic composites Compression, 8 Compression ratio, 17 Compressor differential pressure (CDP), 388 Compressor mass flow rate, 388 Compressor module, 2, 39, 68, 122 airflow control for, 131 airfoils for, 598 assembly for, 124f ATS development for, 435 axial, 5, 12, 14, 34, 40f, 122, 125, 127–131, 127f, 128f, 129f, 130f, 137, 294, 312 balancing, 132, 523–524, 523f, 524f centrifugal, 5, 12, 14, 40, 40f, 122, 123f, 125–127, 125f, 126f, 129, 137, 294 fan blades for, 135f, 592f, 595f, 716, 718 fouling of, 350–351, 517, 708 inspection of, 497 intercooler in, 383 materials for, 131–132 operating conditions for, 131 pressure ratio and, 452 replacing blades in, 570 thrust on, 336 water and modeling, 432–433 water injection in, 313, 314f, 422–424, 423f, 424f Compressor-turbine matching, 160 Computer aided design (CAD), 588 Computer aided manufacture (CAM), 588 Computer based learning and teaching (COBALT), 643 Computer numerical control (CNC), 587, 592 Computer simulation, 588 Concentrating solar power (CSP), 675t, 676 Concorde, 28 Condensate polisher, 461 Condensate system, 465, 466t, 467, 469f, 469t, 470 Condensation, 427–428, 432–433 Condition monitoring, 496–497 Condition monitoring system (CMS), 562 Confidence level, 575 Conglomerate culture, 563 Constant static pressure mixing, 710 Continental Shelf Institute, 485 Continuous emission monitoring (CEM), 146 Continuous fiber reinforces ceramic composites (CFCC), 611 Controlled shaft heating, 718 Controller testing, 415 Controls and instrumentation system (C&I), 361f, 506, 654f aircraft, 359–368 aircraft integrated data system and, 367


digital telemetry and, 380 electronic engine control and, 227–228 electronic indicating systems and, 367–368, 368f fire warning and, 367 fuel flow rate and, 366, 366f fuel pressure and, 366 fuel temperature and, 366 land based, 368–372 modeling and, 382–385 oil temperature and, 365–366, 366f parameters for, 358–359 selection of, 358 synchronizing and synchrophasing and, 368 testing and, 359–362 turbojet instrument panel for, 360f vibration and, 366–367, 367f warning systems and, 367 wear monitoring in, 369 Controls, instrumentation, and diagnostics system (CID), 507 advances in, 372–373 parameters for, 358–359 selection of, 358 Cooldown, 462, 462t Cooling accessory, 169 airflows for, 168–169 bearing chamber, 169 direct, 448, 450f, 451, 453, 454f evaporative, 577 film, 599, 714, 714f fire protection systems and, 309–310, 310f, 311f flame tube and, 136, 137f generator, 171f, 340, 345, 346f heat recovery steam generator and, 470 indirect, 448, 454 injected, 708–709, 714 inlets and, 473, 482, 577 interstage, 577 mass-transfer, 708–709 for oil, 176–177, 177f steam, 74, 99, 117–118, 163–165, 436, 438–439, 564, 566, 597, 598, 667 system for, 171f turbine, 169, 169f, 170f Cooling design, 168 Cooling systems, 14 Cooper RBB, 562 Cooper Rolls Coberra 6000, 17 Coriolis meters, 143 Correction curves, 574–577, 576f. See also Degradation curves thermodynamic processes and, 576, 576f Corrosion fatigue, 463 Corrupt Practices Act, 568, 662 COST, 98 Cost per fired hour, 110 Cowlings, 555 CP. See Specific heat at constant pressure CPFBC. See Circulating pressurized fluidized bed combustion CPUC. See California Public Utilities Commission Crack detection, 521–522 Crandall, Robert, 561 Creep rate, 442, 604, 703 Creep resistance, 605 Creep rupture strength, 98, 101, 601f Creep strain rate, 442



Critical hull speed, 19 CSP. See Concentrating solar power Culture business success and, 560 conglomerate, 563 end-user/operator, 561 environmental technology and, 563 joint venture, 563 market entry monopoly and, 562–563 mergers and, 560 OEM/manufacturer, 561–563 repair and overhaul shop, 559–561 ruggedness and, 562 training and, 563, 638 Curvic coupling, 718f, 719 CUSUM plots, 416, 417f Cycle analysis, 647 Cycle design parameters, 703 Cycle fatigue, 442–443, 462 Cycle matching, 419 Cycle modifications, 74, 101–105 Cycle optimization, 455 Cycle pressure ratio, 395, 462 Cycle selection, 455 Cyclic life. See Low cycle fatigue Daihatsu Diesel Manufacturing, 49t Darrieus, G., 34 DCS. See Distributed control system De Laval bulb root, 160, 160f Deaerating device, 174 Debottlenecking, 638 Decentralization, 665 Degradation curves, 577 Delavan, 284, 285 Denel, 57t Deregulation, 97, 111, 660, 661–664, 662, 663, 669 Desalination, 669–670 Design cycle, 646–647, 647f iterative nature of, 707 Design development, 569 cyclical nature of, 646–647, 647f reliability and, 570–572 Design point closed cycles and, 706 combined cycle and, 705–706 combined heat and power and, 706 component, 702, 704 diagrams of, 703 engine, 701 engine performance parameters for, 702–703 exchange rates for, 704 first cut, 707 intercooled cycle and, 705 performance calculations and, 701 pressure ratio and, 703 recuperated cycle and, 704–705 simple cycle and, 704 Design problem, 647 Design process, concept, 706–707 Design requirements, 648 Development testing steady state, 413–414 transient, 414–415 DFO. See Diesel fuel

Diesel engines, 12, 15, 17, 20, 22f, 632, 643 cathedral, 18 high speed, 18 types of, 18 Diesel fuel, 233–234, 250, 251, 282, 283t, 284, 693, 694, 695f kerosene burned with, 235 operation on, 274–276 Diffuser, 68, 94, 126–127, 126f thrust calculation and, 337 thrust distribution and, 335 vanes of, 125 Digital telemetry, 372, 378–382 failure prevention and, 379 installation of, 381–382 instrumentation for, 380 monitoring with, 379–380 Dilution zone, 136 Dimethyl-ether (DME), 243, 243t Direct drive, 2–3 alternator with, 631–633, 633 Direct firing, 233 Directional solidification, 162 Discharge coefficient (CD), 409–410 Displacement hulls, 19 Dissolved oxygen (DO), 464 Distributed control system (DCS), 462, 463 Distributed power generation, 559, 660, 661, 671–672 DLE. See Dry low-emission combustion system DME forum (JDF), 243 DO. See Dissolved oxygen Doctoral degrees, 644, 644t Dongan Engine Manufacturing Company, 43t Drag, balance of forces for, 391f Dresser-Rand, 49t Dry air, 694 composition of, 693, 693t temperature-entropy diagram for, 695, 700 Dry low-emission combustion system (DLE), 142f, 143, 145–154 Ducted fan, 10, 36, 38 Durand Special Committee on Jet Propulsion, 35 Dynamic head, 693, 699 Dynamic pressure, 693 Dynamic temperature, 693 Dynamic viscosity, 235, 238, 692–693, 699 Ebara, 49t EBI. See Energy and Biodiversity Initiative EC 2000. See Engineering criteria 2000 ECM. See Electro-chemical machining ECMS. See Engine condition monitoring systems EDB/ELSAM, 626 EDM. See Electro-discharge machining EEC, 558 Effective Perceived Noise deciBel (EPNdB), 193 Effective structural repair (ESR), 530, 536 Efficiency adiabatic, 8 combustion, 135, 140, 140f external, 389 internal, 389 isentropic, 695 mandates for, 674t, 677t power generation and, 580–581, 581f propeller, 391 propfans and, 41f

INDEX propulsive, 41f, 128, 155, 389, 395–396, 396, 702 speed and, 396 steam turbines and, 456f stochiometric, 473 thermal, 171, 389, 702 turbine inlet temperature and, 564–565 turbojets and, 41f turboprops and, 41f EGT. See Exhaust gas temperature EHP. See Total equivalent horsepower Electricity generation. See Power generation Electro-chemical machining (ECM), 588, 592, 594, 594f Electro-discharge machining (EDM), 587, 594–595, 595f Electrolytic etching, 587 Electrolytic grinding, 592, 594 Electron beam welding, 587, 590, 592, 593f Electronic engine control, 227–228 Electronic indicating systems, 367–368, 368f Electroplating, 523, 587 Electrostatic separation, 253–254, 255f, 256–257, 257t, 258f, 271, 272, 273 Elements of Gas Turbine Propulsion (Mattingly), 646 Elf, 486, 664 Elf Enterprise Caledonia, 507 Elliot Energy Systems, 60t Emission factors carbon monoxide, 477t criteria pollutants, 478t greenhouse gases, 478t hazardous air pollutants, 479t–480t nitrogen oxides, 477t turbine design and, 117 Emissions activity category form, 481f–484f Emissions control approaches to, 473 combustion and, 143, 143f, 473, 570 culture and, 563 intercooler and, 473 nitrogen oxides and, 141–142 postcombustion, 667 power generation and, 581–582, 582f retrofitting, 665 startup time and, 460–461, 464 strategies used for, 141–142 technologies for, 475–476 testing of, 414 turbine inlet temperatures and, 141, 473, 563 Emissions legislation, 14, 17, 117, 121, 142, 245, 473–477, 477t–480t, 480, 484–485, 505–506, 662, 664, 666 nitrogen oxides and, 141 taxes and, 141, 568 trading and, 141, 661 trends in, 141, 155, 472, 558, 660 Emissions permits, 480 Emissions testing, 414 Emissions trading, 141, 661 ENCAP, 492 Endurance test, 574 End-user groups, 121–122, 670–671 End-user/operator culture, 561 Energi E2, 490 Energy Action Plan, 672 Energy Action Plan II, 672–673 Energy and Biodiversity Initiative (EBI), 484 Energy efficiency mandates, 674t, 677t


Engine concept design process, 706–707 Engine condition indicators, 497 Engine condition monitoring systems (ECMS), 184, 358, 388, 439–440, 494, 495, 559, 564 Engine control, electronic, 227–228 Engine cycle, 650 Engine design point, 701 Engine deterioration, 708 Engine failure investigations, 415 Engine layout, 707 Engine mountings, 552, 554 Engine performance analysis (EPA), 646, 648, 651–653, 652f. See also Performance analysis Engine preliminary design, 716–717 Engine pressure ratio (EPR), 359, 361–362, 362f Engine speed governor, 222, 224f, 225f, 230, 313 Engine speed indicator, 363, 364f Engine supervisory control (ESC), 227–228 Engine test bed altitude test facility, 401, 403, 526, 526f analysis calculations for, 416–418 auditing, 413 calibration of, 412–413 definitions for, 412–413 flying, 401–402, 525 indoor sea level jet, 400 indoor sea level shaft power, 400–401, 401f indoor sea level thrust, 388, 399f, 400 outdoor sea level thrust, 398, 399f sea-level, 525–526, 526f turboshaft gas generator, 400 types of, 398, 400–402 Engine torque indicator, 362–363, 363f Engineering criteria 2000 (EC 2000), 646, 647, 653 Engineering degrees, 644, 644t Enron, 527 Enthalpy. See Specific enthalpy Entropy, 695. See also Specific entropy Environment, human activity and, 472 Environmental envelope, 680, 684–687 aircraft and, 687 international standards for, 680 marine propulsion and, 686–687 mechanical drive and, 686 power generation and, 686 Environmental factors, 666 Environmental Protection Act (EPA), 145 Environmental Protection Agency (EPA), 474 Environmental regulations. See also Emissions legislation culture and, 563 production cost and, 577 trends in, 660 EOH. See Equivalent operating hours EPA. See Engine performance analysis; Environmental Protection Act; Environmental Protection Agency EPNdB. See Effective Perceived Noise deciBel EPR. See Engine pressure ratio EPRI, 567 Equivalent air speed (VEAS), 692 Equivalent horsepower. See Total equivalent horsepower Equivalent operating hours (EOH), 246, 462, 542 Error detection, 416 ESC. See Engine supervisory control ESR. See Effective structural repair Esso, 564, 664



ESV2, 560 ETH Zurich, 34 Ethane, 279 Ethanol, 655, 660, 671 E-trading, 661, 671 EU Energy Charter, 97 Eurojet, 44t European Gas Turbine, 145, 559, 586, 667. See also ABB Alstom Power; Alstom Europrop International, 44t Evaporative cooling, 577 Exhaust gas power, 702 Exhaust gas temperature (EGT), 363, 508 Exhaust heat recovery, 618 Exhaust mass flow, 702 Exhaust mixing, 193, 194f Exhaust silencer, 205 Exhaust systems, 189–191 aircraft and, 189–191 combined cycle steam turbines and, 457–458 construction of, 191 inspecting, 498 noise and, 193 nozzles of, 194f, 195, 196f temperature and, 382, 702 thrust calculation and, 338 turbojets and, 189 turboprops and, 189 Exhaust temperature, 382, 702 Expansion, 8 thermal, 352–353 Expansion joints, 352–356 External efficiency, 389 Extraction control valves, 94, 94f Exxon, 561, 607, 608 Exxon 501-KB5, 606–611, 608f Exxon Mobil, 664, 665 Exxon Valdes (ship), 473 F class technology, 527 coatings and, 528, 528f geometry of, 528–529 rejuvenation and, 529, 529f, 530f repair materials and, 529–533 repairing, 535–536 single crystal and DS materials in, 528, 528f, 529, 531f stripping and, 520 FAA. See Federal Aviation Administration Fabrication, 589 FADEC. See Full authority digital engine control Failure analysis, 645 business decisions and, 558 Fairey Microfiltrex, 614 Fan pressure ratio, 703 FCF turbine. See Fuel cell flexible turbine FCU. See Flow control unit FEA. See Finite element analysis Federal Aviation Administration (FAA), 26, 495, 527 Federal Express, 560 Feedwater heating, 78, 80, 105 Feedwater treatment, 469t, 470 FEP. See Full electric propulsion FFR. See Fuel flow regulator FFT analysis, 494 FGD. See Flue gas desulfurization

FIC. See Fixed indirect cooling Filter systems, 184 ceramic, 611–615, 612t, 613t dust and, 185 fuel, 253, 259 insects and, 185, 185f metal-based, 612t, 614–615, 614f offshore environments and, 186–188 oil, 177, 179f pulse-jet, 184 rainfall and, 184–185 spin-tube, 186, 186f tropical environments and, 184–186 Financial trends, 660 Financing, 662–663 Finite element analysis (FEA), 442 Fir tree root, 160, 160f, 510 Fire protection systems aircraft warnings and, 309, 367 containment methods for, 310, 311 detection systems in, 310, 311f engine fire prevention and, 309 external cooling and ventilation for, 309–310, 310f, 311f extinguishing systems in, 312, 312f overheat detection and, 312 warning system and, 367 Firing direct, 233 indirect, 233 First cut design points, 707 Fixed indirect cooling (FIC), 448 Flame out avoidance, 425 Flame stabilization, 136f, 143, 571 afterburning and, 320, 321 Flame tube, 135–140 annular combustion chamber and, 139 cooling of, 136, 137f igniter plug in, 305 multiple combustion chambers and, 138 Flameless combustors, 141, 154–155, 155f, 476 Flash point, 251 Flashback, 562 Fleet stagger, 519 Flight deck indicators, 497 Flight envelope, 680, 689, 690f, 691f, 692 Flight speed, 689, 692 Floating Production, Storage and Offloading ship (FPSO), 12, 641f Flow control unit (FCU), 215 Flue gas desulfurization (FGD), 505–506 Fluorescent testing, 520 Fly ash, 667 FOD. See Foreign object damage Foreign object damage (FOD), 502, 564, 570 maintenance and, 441 resistance to, 118, 122 Forging, 587, 588–589, 589f Form drag, 19 Fossil fuels, 660 FPA. See Fuel purchase agreement FPSO. See Floating Production, Storage and Offloading ship Free power turbine, 4f, 12, 17, 70, 71f, 155, 157f Free stream total pressure, 689 Free stream total temperature, 689

INDEX Fuel(s). See also specific fuels advanced turbines and, 118 analysis of, 262, 263t, 264f, 266t, 272, 641 autoignition measurement for, 277–281, 279f, 280f autoignition modeling for, 276–277 boiling and, 232–233 calorific value of, 232, 232f, 234 changing, 230–231 chemistry of, 693–694 contamination control for, 233 controls for, 262 density of, 235, 238, 251 design and, 703 economic conditions and strategy for, 238–240 filtering, 253, 259 financial factors and, 513 flash point of, 251 flow rate of, 366 forwarding, 268 gas turbine, 231–232 gaseous, 241t heating, 230 incompatibility of, 251 liquid energy flow measurement of, 407–409 low-btu gases, 74, 243t, 244 maintenance and, 512 new technologies for, 669 nonstandard, 246–250, 248t power generation and, 577, 577f pressure of, 237, 366 prices of, 583–584, 584t properties of, 234–235, 240–245, 249–253 purification of, 254 refining, 252–253, 252f requirements for, 231–232 separation methods for, 254, 255f, 256 specific gravity of, 232f, 235, 236f, 238 specifications of, 245, 273 stability of, 251 storage of, 260–261, 272 synthesis exchange rates of, 235–236 system design and, 240–245 temperature of, 366 testing, 512 trace metals in, 250, 251t treatment of, 245, 250, 251–253, 254f, 256, 262–264, 265–268, 272f types of, 233–234 unconventional, 238, 671 vanadium inhibition for, 253, 259–260, 260f, 261f viscosity of, 235, 236f, 251 washing, 253, 256–263, 259f, 271 water mixed with, 287, 289 Fuel air ratio, 693, 695f, 696f, 697f, 688f Fuel cell flexible turbine (FCF), 625, 625f, 626 Fuel cells, 558, 618, 661. See also Molten carbonate fuel cell; Solid oxide fuel cell combined heat and power and, 626 flow requirements for, 630 heat exchangers v., 623f pressure ratios for, 625 stack pressurization for, 623 turbomachinery and, 624–626 Fuel consumption, 396, 398. See also Specific fuel consumption afterburning and, 325–326, 326f speed and, 392f


Fuel control systems, 214–227 acceleration and speed control for, 222–225, 223f, 231 altitude and, 214, 215f flow control for, 219–222, 220f pressure control for, 215–219, 217f, 218f pressure ratio control for, 225–227, 226f turboprops and, 214 Fuel flow distributor, 230, 232f Fuel flow measurement, 407–409 Fuel flow regulator (FFR), 222, 225–226, 227 Fuel heating value (FHV), 407, 408–409 Fuel independence, 671 Fuel injector, 285f Fuel metering system, 142, 143–146, 284–285 Fuel oil, 289t. See also Diesel fuel blended, 271, 271f intermediate, 271 treated, 269 treating, 258–259 Fuel pumps, 228, 229f Fuel purchase agreement, 112 Fuel shutoff, 144, 645 Fuel spray nozzles, 134, 136, 139, 214, 228–230, 230f, 231f Fuel system, 216f control of, 214–227, 359 flow measurement and, 143–144 low pressure, 228, 228f parts of, 214 pumps for, 228 versatility of, 666 Fuel vaporizer, 285–286 Fuel venting, 144 Full authority digital engine control (FADEC), 15 Full coverage film cooling (FCFC), 599 Full electric propulsion (FEP), 21 Full flow lubrication system, 173–174, 174f Gamma. See Ratio of specific heats Gamma exponent, 699 Gas constant, 692, 694t, 695f, 699 Gas generator, 2, 70 Gas island, 112 Gas path analysis, 510 repairs anticipation with, 511 Gas pipelines, 16 Gas properties, 692–693 Gas Turbine Users Association (GTUA), 121, 562 Gas turbines (GT), 75f, 107. See also Combustion turbine acoustic treatment of, 196–197 adjusting, 498–499 aeroderivative, 2, 4, 14, 15, 17, 22, 73–74, 180–181, 277, 586 aeroengine, 5–11 aircraft applications of, 3, 23–31, 654–657, 687 aircraft installation of, 550–555 applications versatility of, 4–5, 5 assembling, 525, 525f, 526f, 717f, 718–719 automotive applications or, 17–18, 686 basic manufacture of, 587–596 calculating thrust of, 336–339 cleaning, 513, 520 closed cycle, 16, 70, 81f, 103f, 233, 706 configurations of, 68–74 control of, 214 cowlings over, 555 cycles of, 74



Gas turbines (Continued ) design priorities for, 121 development of, 34–35, 114–115, 660 disassembly of, 520, 717f, 718–719 economics and design of, 120–121 emissions status of, 472 enclosures for, 196, 204–205 evolution of, 114–115, 116f exhaust systems of, 189–191, 190f, 192f, 193, 194f, 195, 196f, 338, 457–458, 498 family tree for, 5f flexible connectors in, 203–204 fuel cell flexible, 625–626 fuels for, 231–233 future trends in, 660–661 global fleet of, 43t–66t heavyweight, 14, 15, 73–74 history of, 4, 5 industrial, 4, 586, 686 industrial mechanical drive applications of, 16–17 ingestion tests for, 414 inlet to, 184 on land, 2–5 land based, 2–5, 368–372, 555, 556f, 586 life extension of, 542–547 manufacturers of, 4–5 marine applications of, 4, 11–12, 12f, 18–23, 555, 686–687, 689 markets for, 107f mechanical arrangement of, 37, 40f micro, 4 modular concept for, 122, 123f, 125, 495, 519 new models of, 114–115, 114t noise sources in, 193, 195–196, 195f noise suppression for, 191–211 offshore platforms and, 640 operating principles of, 2 operational modes of, 4 peak power rating of, 5 performance testing of, 574 performance verification of, 388 personal, 559 power generation applications of, 12–16 power of, 3 ramp rate of, 461, 469t reciprocating engines v., 3f recuperated, 628 rivals to, 664–666 schematic of, 2f selection/specification of, 115–117, 563–564 sequential combustion, 445–448, 446f, 447f, 565 simple cycle, 12 as starter units, 303, 303f startup time and, 460 steam injected, 445–455 storage of, 527, 527f transportation of, 527, 527f upgrading, 115, 596–603 uses of, 2 vibration potential of, 192 working cycle of, 2f, 3f, 6 Gas-fired power plants, 580 Gasoline, 283t GE 7EA, 246, 444, 527, 531, 531f, 532, 533f, 534, 670 GE 7FA, 113, 114, 117 GE 7FB, 113, 115

GE 9F, 568 GE 9FB, 115 GE 90, 562 GE CF6-80C2, 495, 569 GE CFM-56, 502, 561, 564, 586 GE Energy, 50t GE F404, 561–562 GE Frame 3, 444, 507, 527, 564 GE Frame 5, 121, 122, 246, 388, 505, 507, 510, 527, 564, 566 GE Frame 6, 264 GE Frame 7, 5, 121, 388, 564 GE Frame 7F, 533–535, 534f, 535f GE Frame 9, 5, 564 GE Frame 9F, 502 GE I-A, 35, 715 GE J79, 124f GE LM1600, 507 GE LM2500, 122, 495, 507, 567, 569, 661, 668 GE LM6000, 668 GE MS7001EA, 539–540 GE Oil & Gas (Nuovo Pignone), 50t–51t GE Speedtronic Mark V, 507 GE T-700, 561–562, 715, 718 Gear box, 2, 11, 172 GEC, 667 GEC Alstom, 662 Gemini, 668 General Dynamics, 564, 568 General Electric, 35, 114, 115, 246, 388, 455, 457t, 514, 558, 561, 563, 564, 586, 643, 662, 715 advanced diffusion healing by, 530, 536 aircraft engines made by, 44t–45t financing by, 563–564, 669 India market entered by, 662–663 licensing by, 667 General Electric CF6, 6, 7f, 564 General Electric CF6-80C2, 4 General Electric Energy Rentals, 668 General Electric LM2500, 4, 17 General Electric LM6000, 4 General Electric Outage Optimizer, 668 General Electric TF39, 7f Generators, 341f. See also Turbogenerator bearings in, 342, 343f configuration of, 340 control of, 347, 349 cooling of, 171f, 340, 345, 346f design of, 340, 341–345 excitation system in, 340, 345–347, 347f operating, 349 rotors in, 343–345, 344f, 345f standby, 12 stators of, 341–342, 341f, 342f testing, 347, 347t Genting Corporation, 662 Geothermal energy, 675t, 676 GE-P&W Engine Elliance, 45t GE/Schnectady TG-100, 35 Gland seals, 94, 95f, 179 Glass bead peening, 516 Global Producer III, 11 Gloster E28139, 23 Goodman Diagram, 442, 443f Governing valves, 93f, 94 Governor spill valve, 215

INDEX Gravimetric monitoring, 487–490 Green, Andrew, 17 Green Building Initiative, 673 Greenhouse gases, 473, 475, 478t, 484. See also Carbon dioxide; Chlorofluorocarbons; Methane GRI mechanism, 277, 279 Griffith, A. A., 34, 326 Ground indicators, 497 Ground testing, 499–500, 501f GT. See Gas turbines GTAP, 444 GTUA. See Gas Turbine Users Association Guarantee points, 668 Guillame, 23 Gulf, 561 H A L, Engine Division, 45t, 57t Hail. See Ice ingestion Hamilton Sunstrand, 54t, 57t HAP. See Hazardous air pollutants Hard particle LPM, 536, 541–542. See also LZN Harrier, 29, 327, 328f Hastelloy, 35 Hastelloy X, 614 Haven, Brenda (Lt. Col.), 647 Haynes Stellite, 35 Hazardous air pollutants (HAP), 474–475 emission factors for, 479t–480t HCF. See High cycle fatigue Head, 693, 699 Heat exchanger, 16 Heat pumps, 660 Heat rate, 78, 575, 702 Heat recovery steam generator (HRSG), 12, 13, 70, 72–73, 73f, 97, 105, 106, 110, 115, 240, 248, 269, 270, 275f, 389, 440, 460, 474 combined cycle performance and, 458 cooling system and, 470 corrosion fatigue and, 463 load cycling issues for, 462–464 modeling, 430 operation of, 274 performance testing of, 574 startup time and, 459, 461 steam injection and, 448 thermal cycling and, 462–463 thermal stress and, 463 thermodynamic processes in, 576t water chemistry and, 464 Heat sink, 119t thermodynamic processes in, 576t Heat treatment, 587 Heating value, 234–235, 508. See also Calorific value formulas for, 237–238 Heavy fuel oil (HFO), 251–253 Heavy metals, 667 Heavy oil, 109t, 109f, 113, 247, 247t, 251 operation on, 274–276 Heavyweight engines, 14, 15, 73–74 HEFPP. See High Efficiency Fossil Power Plants Heinkel He 176, 23 Heinkel He S-3b, 23 Helium, 16 Her Majesty’s Inspectorate of Pollution (HMIP), 145 Herbold, Robert, 644


Hero’s engine, 36, 37f Hertzian stress, 630 HGP. See Hot gas path HGPI. See Hot gas path inspection High cycle fatigue (HCF), 442, 542, 703 High Efficiency Fossil Power Plants (HEFPP), 622, 625 High Efficiency Fuel Cell Power Plant program, 632 High pressure air cooler (ACHP), 448, 449 High speed diesel engines, 18 HIP. See Hot Isostatic Press Hitachi, 51t HMIP. See Her Majesty’s Inspectorate of Pollution HMS Grey Goose, 19 Honeywell, 5t, 45t–46t, 57t, 60t Horsepower, thrust v., 391 Hot components life assessment of, 543–545, 545f life extension of, 545–547 maintenance and upgrading of, 542–543, 543f, 544f Hot corrosion, 441, 505 Hot gas ingestion, 172 Hot gas path (HGP), 542 maintenance for components in, 542–543, 543f Hot gas path inspection (HGPI), 542 Hot gas path inspection protection plan, 670 Hot Isostatic Press (HIP), 715 Hot section inspections (HSI), 388, 495, 670 Hovercraft, 20t, 21 Howmet, 530, 536 HRSG. See Heat recovery steam generator HSDE, 506, 507 HSDE Digicon, 508, 509 HSDE Digitrend, 507 HSI. See Hot section inspections Huff and puff filter. See Pulse-jet filter Humidity altitude and, 689f ambient temperature and, 688f engine performance and, 420, 421f, 422, 422f measuring, 411–412 relative, 685, 688f specific, 685–686, 688f Hush kits, 567 Hybrid electric vehicles, 17–18, 19f Hybrid power systems, 618, 661 cycle parameters for, 634t gas turbine/MFCF, 634t gas turbine/SOFC, 619–621, 620f, 621f, 626–629, 628f, 629f, 630f, 631f, 632, 632f, 633t, 634t improvements in, 634 performance of, 19t, 634–635, 634t pressure ratios and, 625 turbogenerator for, 629–635 Hydraulic fluid, 95 Hydraulic seals, 170–171 Hydrodynamic drag, 19 Hydroelectric power, 675t, 676 Hydrogen, 234, 241–242 embrittlement from, 560 IAEA. See International Atomic Energy Agency I&C. See Controls and instrumentation system IC&D. See Controls, instrumentation, and diagnostics system Ice ingestion, 184, 428 modeling, 430



Ice protection systems cycle for, 308–309, 309f electrical, 307–309, 308 hot air, 306–307, 307f, 308f key areas for, 306, 307f IEA Greenhouse Gas R&D Programme, 484, 485 IED. See Integrated electric drive IEEE. See Institute of Electronics and Electrical Engineers IFO. See Intermediate fuel oil IGCC. See Integrated gasification combined cycle Igniter plug, 136, 304–305, 306f Ignition and starting systems. See Starting and ignition systems Ignition unit, 303–305, 304f, 305f IGTI, 558–559, 661 IGV. See Inlet guide vanes IHPTET. See Integrated High Performance Turbine Engine Technology IMO. See International Maritime Organization Impellers, 126, 127 Improved oil recovery (IOR), 485 carbon dioxide-based, 491–492 subsea, 492 Impulse/reaction turbine, 156, 158f Independent overhaul contractors, 671 Independent power producers (IPP), 111, 587, 660, 663, 668 merchant power producers and, 664 negotiation risk and, 568 OEMs becoming, 558 options for, 662 project development and, 567–568 Independent System Operator, 672 India, 662–663 Indian Air, 561 Indicated air speed (VIAS), 689 Indirect firing, 233 In-flight recorders, 497 Influence coefficient method, 709, 710–711 Infrastructure, 663 Ingersoll Rand (IR), 621. See also Northern Research and Engineering Company Ingersoll-Rand Energy Systems, 61t Inlet air refrigeration, 577 Inlet conditions, 680 Inlet fogging, 577 Inlet guide vanes (IGV), 505, 512 Inlets, 184 air filtration at, 184–188 cooling air to, 473, 482 cooling devices for, 577 water injection and, 313, 314f Inspection hot section, 388 intervals for, 246, 246t manufacture and, 596 overhaul and, 520–522 regular, 388 Installation aircraft engine, 550–555 digital telemetry and, 381–382 land based engine, 555, 556f marine engine, 555 performance and, 687, 709 turboprops and, 551

Installation pressure losses, 680, 687, 689, 709 aircraft engines and, 689 automotive engines and, 689 industrial engines and, 687 marine engines and, 689 Institute of Electronics and Electrical Engineers (IEEE), 626 Instrumentation and controls. See Controls and instrumentation system Insulating blanket, 191, 192f Intake aircraft installation and, 551–552 compression, 553f condensation and, 427–428 fuselage, 552f, 553 ground testing and, 499 inspecting, 498 pitot-type, 551, 551f ram effect and, 551 variable throat area, 552, 553 wing leading edge, 551f Integrated coal gasification combined cycle, 579–580, 580f Integrated electric drive (IED), 21 Integrated gasification combined cycle (IGCC), 112, 242, 243–244, 248, 249f, 250f, 580. See also Combined cycle power generation thermodynamic processes in, 576t Integrated High Performance Turbine Engine Technology (IHPTET), 714–715 Integrated Pollution Control (IPC), 145, 147 Intercooled cycle, 701f, 705 Intercooler, 70, 72f, 383, 385, 389, 568 condensation and, 427–428, 432–433 emissions control and, 473 Intercooling, 102, 104f InterGen, 664 Intermediate fuel oil (IFO), 271 Internal air system, 168 Internal airflow pattern, 168f Internal efficiency, 389 International Aero Engines AG, 46t International Aero Engines V2500, 502, 561, 562, 563, 564, 586 consortium producing, 563 International Atomic Energy Agency (IAEA), 670 International Maritime Organization (IMO), 19 International Organization for Standardization (ISO), 680, 687 International Standard Atmosphere (ISA), 680 Interstage bleeds, 129, 131 Interstage cooling, 577 Interturbo (Zao Interturbo), 51t Investment casting, 587, 589, 591f IOR. See Improved oil recovery IPC. See Integrated Pollution Control IPIECA, 484 IPP. See Independent power producers IR. See Ingersoll Rand ISA. See International Standard Atmosphere Isentropic efficiency, 695 Ishikawajima-Harime, 46t ISO. See International Organization for Standardization JAA. See Joint Aviation Authorities JAEC. See Japanese Aeroengine Consortium Japanese Aeroengine Consortium (JAEC), 586 V2500 and, 563 JDF. See DME forum

INDEX Jet fuel starters, 31 Jet pipe, 68, 70. See also Propelling nozzle afterburning and, 319–320, 321f, 322f, 323 ground testing and, 499 mounting of, 552, 554 pressure in, 324–325 thrust calculation and, 338 thrust reversers and, 317 Jet pipe temperature (JPT), 363 Jet propulsion, 5, 36f basics of, 36–37 methods of, 37–39 Jet Propulsion Laboratory, 644 Jet reaction, 36 John Brown, 667 Joint Aviation Authorities (JAA), 495 Joint ventures, 660, 667 culture of, 563 international negotiation and, 568 OEM/university, 643–644 power generation, 563 tooling and, 563 Joseph Lucas Ltd., 138 JPT. See Jet pipe temperature Kawasaki Heavy Industries, 46t, 51t, 55t Kelleher, Herb, 560, 561 Keller, C., 34 Kerosene, 109f, 232, 233, 238, 250, 251, 693, 694, 695f diesel burned with, 235 Gamma for, 697f specific heat for, 696f KI 150, 246 Kiel head, 405 Kinematic viscosity, 235, 238 Kinetic valve, 219, 221f Kiowa, 561, 566 Klimov Corp., 46t–47t Kværner Energy Limited, 667 Kværner Energy Thermal Power, 667 Kværner Process Systems, 485, 489–490, 663, 667–668 Kyoto protocol, 473, 484, 660, 666, 672 Labyrinth seals, 170 Land based gas turbines, 2–5 controls for, 368–372 installation of, 555, 556f instrumentation for, 368–372 permissives/interlocks for, 371 protective systems for, 370–371 shutdown of, 372 startup sequence for, 371–372 wear monitoring for, 369 Larson-Miller plot, 442, 442f Lasley, R. E., 35 Lasley Turbine Motor Company, 35 Latin America, 663 LCA. See Life cycle assessment LCF. See Low cycle fatigue LD. See Liquidated damages Lead, 253 Leadership in Energy and Environmental Design (LEED), 621 Lead-ons, 719 LEED. See Leadership in Energy and Environmental Design


Legislative requirements, 505–506. See also Emissions legislation Legislative trends, 558 LHTEC, 47t, 56t Liburdi Engineering, 530, 536. See also LPM powder metallurgy Life cycle assessment (LCA), 122, 359, 388–389, 506, 507, 518, 669 algorithms for, 495, 516 maintenance scheduling and, 516 risk management and, 566 Life parameters, 703, 704t Lift fans, 330–331, 332f Lift-jet engine, 326, 330–331, 331f Lift/propulsion engine, 327f types of, 328–329 Light crude, 264f operation on, 264, 267t treatment of, 262–264, 263f Light distillates, 245 Linear approximation method, 710–711 Linear variable differential transformer (LVDT), 361 Liquidated damages (LD), 574, 574t Liquified natural gas (LNG), 242, 242f, 473, 489, 513, 661, 672–677 Liquified petroleum gas (LPG), 109f, 234, 242–243, 282–287, 282t, 489 operation on, 286–287 pumping pressures for, 286, 286t LNCFS. See Low NOx concentric firing system LNG. See Liquified natural gas Load bearing system, 172 Load rejection, 92, 95, 96f, 383–384, 384f, 385f Lobbying, 661, 670–671 Lorin, Rene, 23, 35–36, 36f Low cycle fatigue (LCF), 442–443, 443f, 444, 506, 529, 538–539, 539f, 542, 703 base load power generation and, 570 industrial applications and, 570 LPM and, 538–539, 539f peak lopping and, 570 testing, 545 Low NOx concentric firing system (LNCFS), 666 LPG. See Liquified petroleum gas LPM powder metallurgy, 530–536, 532f, 533f. See also LZN abrading, 542 composition of, 537, 538t creep properties of, 538 hard particle, 536, 541–542 low cycle fatigue and, 538–539, 539f microstructure of, 537 repair process with, 537, 537f, 540f superalloy, 536–541, 542 wear resistant, 541–542 Lubrication, 172–179 bearings and, 179, 181 components of system for, 174–177 flushing, 181–182 full flow system for, 173–174, 174f lifespan of, 179 oils for, 177–182 pressure relief valve system for, 173, 173f procurement standard for, 181 recirculatory, 172–174 steam turbines and, 82, 89, 90



Lubrication (Continued ) systems for, 172–177 total loss system for, 174, 175, 175f turboprops and, 172, 178 Lucas Aerospace, 56t LVDT. See Linear variable differential transformer LZN, 541–542, 541t Mach number, 23–25, 692, 693 altitude and, 719 range factor v., 24f Machining, 587 Magnesium sulfate, 245, 247, 261, 274 Magnetic chip detector, 177, 178f Magnetic crack testing, 521, 522f Maintenance, 495–496. See also Operations and Maintenance; Repair and overhaul assessment of, 513 audits and, 502–503 business decisions and, 558 casings and, 598 changes in specifications for, 515–516 cleaning and, 513 condition monitoring and, 496–497 foreign object damage and, 441 fuel and, 512 ground testing and, 499–500, 501f hot components and, 542–543, 543f, 544f life cycle assessment and, 516 on-wing, 496 performance analysis and, 494 plant, 513–514 precautions for, 498 predictive, 494 preventative, 494 reactive, 494 residual fuel and, 245–246 schedule for, 388, 496f, 516 scheduled, 496–497 standard procedures for, 504 tactical aircraft and, 715f testing and, 499–500, 501f unscheduled, 496–497 Maintenance information systems (MIS), 500, 502 Maintenance, repair, and overhaul (MR&O), 439–440 Man Group Machines, 51t Man-machine interface (MMI), 506, 507, 509 Manometers, 403 Manufacturer culture, 561–563 market entry monopoly and, 562–563 ruggedness and, 562 Manufacturing, 586 automated, 591f, 595f basic, 587–596 casings and, 588, 603–604 computer aided, 588 inspection and, 586 methods for, 587 power generation and, 586 strategy for, 587–588 tolerances for, 588 Marine propulsion, 18–23 engine load characteristics for, 19 environmental envelope for, 686–687 installation of, 555

installation pressure losses and, 689 types of, 20–21, 22f Marine vessels classes of, 19, 20t, 21–23 propulsion of, 18–23, 21f Market assessment risk, 568–569 Market entry monopoly, manufacturer culture and, 562–563 Mass-transfer cooling, 708–709 Material cyclic behavior, 442–443 Material steady behavior, 442 Mattingly, Jack, 646, 648, 650 Maturational development, 715 “MBA-rules” perspective, 644 M-C Power, 623, 624 Mean temperature, 694 Mean time between failures (MTBF), 389, 502, 507 Measurement uncertainty, 575, 575t Mechanical design parameters, 703 Mechanical drive, 2–3, 3 environmental envelope for, 686 Merchant power producers (MPP), 118, 660, 663–664 Metallurgical engineering, 440–444 Methane, 234, 279, 472 Methanol, 312–313 Metropolitan Vickers, 18–19 Metropolitan Vickers Gatric engine, 18 Meyer, A., 34 MHI. See Mitsubishi Heavy Industries MHI M701F, 244 Microsoft, 644 Microstructural degradation, 441 Microturbine Energy Systems, 621 Microturbines, 4, 661 CHP and, 621–622 direct drive alternator and, 631–633 materials for, 605 overview of, 618, 618t recuperated, 618, 619f simple cycle, 618 Microturbo Inc., 56t, 58t Mid merit power plants, 12, 15–16 MIL 210. See US Military Standard 210 Minimum engine, 708 Minitel telemetry unit, 378 MIS. See Maintenance information systems Mission analysis, 647, 648, 649t, 650f Mitsubishi Heavy Industries (MHI), 47t, 52t, 56t, 58t, 115, 162–166, 455, 457t, 565, 569, 596, 667 evolution of turbines by, 570f “H” series turbines technology by, 162–166 steam turbines by, 99–101 Mitsubishi Heavy Industries M501 series, 570–572, 571f, 572f Mitsubishi Heavy Industries M501D, 570, 571f, 572f Mitsubishi Heavy Industries M501F, 570, 571f, 572f, 597t Mitsubishi Heavy Industries M501G, 570, 571f, 572f, 597, 597f, 597t, 598, 599f, 601t, 603f long-term operational testing of, 599–600, 602–603 Mitsubishi Heavy Industries M501H, 163–166, 570, 571f, 572f Mitsubishi Heavy Industries M701 series, 570 Mitsubishi Heavy Industries M701D, 163, 597 Mitsubishi Heavy Industries M701F, 597 Mitsubishi Heavy Industries MF221, 598 Mitusi Babaock, 666 Mixer unit, 189, 190, 191, 191f Mixing layers, 709

INDEX Mixing model, one-dimensional, 710–712, 710f, 712f MMI. See Man-machine interface Model matching, 383 Mohammed, Mahathir, 665 Mole, 692 Molecular weight, 692, 694t Molten carbonate fuel cell (MCFC), 622–624, 622f, 624f, 629 flow requirements for, 630 hybrid gas turbine and, 633t pressure ratio for, 625 solid oxide fuel cell v., 623 Molybdenum, 513 Monopoly, manufacturer culture and, 562–563 Montreal protocol, 660, 666 Motor SICH/Progress, 47t Motoren Turbinen Union (MTU), 562, 586, 644 V2500 and, 563 Motorlet Aero-Engines, 47t Mott Corporation, 614 MPP. See Merchant power producers MR&O. See Maintenance, repair, and overhaul MSF. See Multistage flash MTBF. See Mean time between failures MTFIN, 572 MTR Gmbh, 47t MTU. See Motoren Turbinen Union Multiple combustion chambers, 137–138, 138f Multistage flash (MSF), 669–670 NAFTA, 558 Naked resistance, 19 Naptha, 108, 109f, 234, 247, 247t, 250, 251, 282–284, 283t, 287, 288, 288f, 288t, 289t NASA. See National Aeronautics and Space Administration National Aeronautics and Space Administration (NASA), 4, 34 National Gas Turbine Establishment (NGTE), 186, 187t Natural disasters, 660 Natural gas, 108, 109f, 110, 118, 234, 235, 242, 275, 284, 513, 665, 672f, 677, 694, 695f. See also Liquified natural gas liquid fuels burned with, 235–236 specific heat for, 698f Net thrust, 702 Newton, Isaac (Sir), 36 NGL, 251 Nitrogen oxides (NOx), 121, 141, 147, 148f, 150, 151f, 153f, 154f, 239, 289, 389, 472, 474–475, 505–506, 510, 513, 665, 666, 669 combustor and, 570–572, 598 digital telemetry monitoring of, 381–382 emissions and, 141–142, 477t pressurized fluidized bed combustion and, 579 steam cooling and, 439, 597, 598 taxes on, 568 turbine inlet temperature and, 141, 565 water and, 287, 289, 474–476 Nobel, Richard, 17 Noise suppression aeroengine, 191–196 aircraft and, 191–196 enclosures and, 204–205 exhaust system and, 193 flexible connectors and, 203–204 gas turbines and, 191–211 materials for, 197f methods of, 195–196 nonaeroengine, 196–211


Noise suppressor, 189, 195, 196f Northern Research and Engineering Company (NREC), 627, 628 Northrop, 35 Northrop Gamma, 35 Northrop Turbodyne, 35 NOx. See Nitrogen oxides Nozzle guide vane, 68, 155, 156, 158, 159, 159f, 169, 169f, 170f construction of, 159 inspection of, 497, 497f materials for, 161 NREC. See Northern Research and Engineering Company NTNU, 485, 490 Nuclear power, 660, 664–665 Nuclear reactors, 16, 665, 670 naval, 22–23 Number 2 distillate oil. See Diesel fuel Nuovo Pignone, 50t–51t, 586, 667, 668 OA. See Overfire air Ocean power, 675t, 676 OCMR. See Oil movement control room OEM culture, 561–563 market entry monopoly and, 562–563 ruggedness and, 562 OEM/university joint ventures, 643–644 Off design performance, 707 Off-line cleaning, 246, 246t, 274 advantages and disadvantages of, 350–351 Offshore platforms, 640f Oil aeroderivative gas turbines and, 180–181 characteristics of, 179–181 cooling for, 176–177, 177f debris monitoring for, 369 density of, 237, 238 filters for, 177, 179f flow rate of, 172 flushing, 181–182 gas turbines and, 180 heavy, 247, 247t, 251 lifespan of, 179 lubricating, 177–182 oxidation of, 179–181 procurement standard for, 181 pumps for, 174–175, 176f steam turbines and, 87, 95, 179–180 system inspection for, 498 tank for, 174, 175f temperature of, 365–366, 366f types of, 237, 237f viscosity of, 237f Oil and gas lobby, 661 Oil movement control room (OCMR), 508 Oil pipelines, 16, 640f Oil sands, 561 O&M. See Operations and Maintenance Omsk Engine, 48t Online cleaning systems advantages and disadvantages of, 351–352 methods for, 349–350, 352 selecting, 350 Ontario Hydro, 664–665 Open cycle, 704 Operational assessment, 569



Operational envelope, 680, 684–692 Operations and Maintenance (O&M), 439f, 440f evolving strategy for, 494–495 mechanical engineering approach to, 442–443 metallurgical approach to, 440–441 performance engineering approach to, 443–444 predictive strategy for, 494 preventative strategy for, 494 reactive strategy for, 494 strategies for, 494–495 systems engineering approach to, 444 Opra Optimal Radial Turbine BV, 52t Optical pyrometry, 372–374, 374–378, 374f, 375f, 376f, 377f, 661 Orimulsion, 561 OTSG. See Benson Once-Through Steam Generator Otswald ripening mechanism, 441 Otto cycle, 17 Output power, 702 Overfire air (OA), 666 Overhaul, 518–527. See also Time between overhauls assembly and, 525, 525f, 526f balancing during, 523–524, 523f, 524f cleaning during, 520 contracts for, 670 damage requiring, 519 disassembly for, 520 hot section, 670 independent contractors for, 671 inspection during, 520–522 life extension and, 542–547 planning, 515 testing and, 525–526, 526f workshop layout for, 521f Overheat detection, 312 Overseas subsidiaries, 563 Oxidation, 179–181, 441, 513, 531f, 532, 703 Oxyfuel, 490 PA. See Performance analysis Pall Advanced Separation Systems, 614 Parallel powering, 110, 111f Parametric cycle analysis (PCA), 646, 647, 648, 650–651, 651t Parasitic losses, 631, 633 Parsons, 97 Particulate matter (PM), 474–475, 570, 667 Parts pool, 514 PCA. See Parametric cycle analysis PCC Airfoils, 439 PCFBC. See Circulating pressurized fluidized bed combustion PCU. See Propeller control unit Peak lopping, 15–16, 600 low cycle fatigue and, 570 Peak power rating, 5 Peat, 666 Penwell, 559 Perfect gas, 692, 699 Performance afterburning and, 393 altitude and, 393–394, 394f assessment of design, 708 factors for, 389 humidity and, 420, 421f, 422, 422f margins for, 707–708, 708, 708t modeling, 430–433, 431f off design, 707

optimization of, 389, 440 parameters for, 653 rain/ice ingestion and, 428 sequential combustion and, 447, 447f speed and, 392–393, 392f steam injection and, 426–427, 426f, 430 temperature and, 394–395 testing thermal, 573–577 theoretical, 389–398 thermal, 458 total temperature and, 693 trends in, 416 turbojet, 392f, 393 turboprop, 392–393, 393f uninstalled v. installed, 687, 709 verification of, 388 water and, 420, 422–434 water injection and, 422–425 Performance analysis (PA), 388–389, 389, 439–440, 506, 517, 643 aims of, 509 features of, 510 parameters for, 510 predictive maintenance with, 494 retrofits and, 509–510 risk management and, 566 Performance engineering, 443–444 Performance test codes (PTC), 573–575 measurement uncertainty and, 575 Performance verification, 388. See also Testing Personal turbines, 559, 605, 671 Petrolite, 246 PFBC. See Pressurized fluidized bed combustion PHCR. See Power house control room Photovoltaic generation, 559 Piston engine, 2, 24–25, 30 Plant siting, 569 Plasma spraying, 587 PLC. See Programmable logic controller PM. See Particulate matter Pneumatic auxiliary power units, 31 Political incentives, 663 Political trends, 660, 661 Pollutants, 141 Port Dickson, 662 Powder metallurgy, 514 Power augmentation, 568 Power by hour contracts, 110, 587, 670 Power distribution grid, 12, 14f, 15, 670 Power generation, 2, 3, 4. See also Combined cycle power generation; Combined heat and power base load, 15 carbon dioxide capture and, 489–490 characteristics of, 14f classes of, 13f coal-fired, 578 construction issues and, 118 cycle for, 86f decentralization of, 663 deregulation and, 97, 111, 660, 661–664 design challenges for, 117–118 distributed, 559, 660, 661, 671–672 economic evaluation for, 583–584, 583f, 584t economics of, 238–240, 240f efficiencies and, 580–581, 581f emissions and, 581–582, 582f

INDEX environmental envelope for, 686 equipment selection for, 115–117 field modifications and, 118 fuel types for, 577, 577f heat rate for, 78 industry growth in, 74 infrastructure and, 663, 670 investment and, 582, 583f joint ventures for, 563 manufacturing for, 586 mid merit, 12, 15–16 oil companies and, 664 peak lopping, 15–16 performance comparison for, 78t photovoltaic, 559 plant configuration for, 118 plant startup and, 118 plant thermal performance test for, 573–577 producer mix for, 668 project development for, 567–568 pulverized coal, 578–579, 578f, 579f reference plant for, 108f renewable sources of, 666 supercritical steam and, 96–99, 666–667 technologies for, 112–113, 577–584 trends in, 110–112 Power house control room (PHCR), 508 Power limiter, 222, 225 Power mix, 671–672 Power turbine entry temperature (PTET), 425 Powergen, 559 PowerWorks, 621 PR. See Pressure ratio Prandtl, L., 34 Pratt and Whitney, 35, 48t, 56t, 59t, 61t–62t, 114, 514, 558, 560, 561, 586 V2500 and, 563 Pratt and Whitney JT-8D, 6, 9f, 518, 527 Pratt and Whitney JT9, 567 Pratt and Whitney PT-1, 35 Pratt and Whitney PT6A-20, 653–655, 654f, 655f, 655t, 656f Pratt and Whitney PW FT-8D, 4 Pratt and Whitney PW JT-8D, 4 Pratt and Whitney PW100, 561, 566 Pratt and Whitney PW4000, 569 Predictive flow formulas, 643 Predictive maintenance, 494 Pressure changes in, 6, 8 differential, 405 dynamic, 693 engine static, 405 engine testing and, 402–405, 404f engine total, 405 free stream total, 689 fuel, 237, 366 governors for, 82 installation losses of, 680, 687, 689, 709 jet pipe, 324–325 pumping, 286, 286t resistance to, 19 sound, 198, 202f, 203f test cell static, 405 throttle, 463 thrust, 190


total, 693, 699 transient, 405 Pressure altitude, 680 ambient conditions v., 681t–683t ambient pressure v., 684f ambient temperature v., 684f density and, 684, 685f speed of sound v., 686f Pressure drop control spill valve, 221 Pressure drop control valve, 222 Pressure drop governor, 231 Pressure limiting valves, 174 Pressure ratio (PR), 74, 122, 125f, 128, 129 compressor, 452 design point and, 703 fan, 703 fuel cells and, 625 gauge for, 359, 361–362 high pressure turbine, 451f low pressure turbine, 452f normalized, 453 Pressure relief valve lubrication system, 173, 173f Pressurized circulating fluidized bed combustion. See Circulating pressurized fluidized bed combustion Pressurized fluidized bed combustion (PFBC), 579, 611, 614f Pressurized fluidized bed power plant, 579 Preswirl nozzles, 169 Preventative maintenance, 494 Product pass off test, 416 Programmable logic controller (PLC), 517 Progress (ZMKB Progress), 62t Project application engineer (PAE), 638–642, 639f development of, 641 job description of, 638–640 recruitment for, 640–641 training, 641–642, 642f Project cycle, 639f Project Jet Propulsion, 644–645, 646t Propane, 243, 279, 282t, 283f Propeller control unit (PCU), 359 Propeller efficiency, 391 Propeller propulsion, 36f Propeller slippage, 19 Propeller tip speed, 25 Propelling nozzle, 68, 128, 190, 190f, 687 afterburning and, 320, 323 thrust calculation and, 338 Propfan, 10, 36, 38, 41f propulsive efficiency of, 41f Propulsive efficiency, 41f, 128, 155, 389, 702. See also External efficiency equations for, 395–396 speed and, 396 Prvni Brnenska Strojirna, 56t PTC. See Performance test codes PTET. See Power turbine entry temperature Pulse jet, 36, 37, 38f Pulse-jet filter, 184 Pulverized coal power plants, 578–579, 578f, 579f Punch list, 574 Pure impulse turbine, 158f Pyrometry, 372–374, 661 Quality Acceptance Standards, 590 Quality control, 565



Radial compression engine, 34 Radial thermal growth, 718 Rain ingestion, 428, 433 RAM. See Reliability, availability, and maintainability Ram effect, 551, 552f Ram ratio, 392 RAM-D. See Reliability, availability, maintainability, and durability Ramjet, 3, 25, 30, 36, 37, 38, 38f, 69, 69f thrust cycles of, 706 Range factor, 24–25 Mach number v., 24f Rankine cycle (RC), 76, 76f, 77, 77f, 78f, 455, 699, 701f Ratio of specific heats (Gamma), 692, 694, 609 calculations with, 694 for kerosene, 697f RBD. See Rechargement per brasage diffusion RC. See Rankine cycle Reaction jet, 35, 36f Reaction turbine, 79, 80f, 98, 99, 156 Reactive maintenance, 494 Rechargement per brasage diffusion (RBD), 530, 536 Reciprocating engines, 3f, 17 Recirculatory lubrication systems, 172–174 Recuperated cycle, 704–705 Recuperated engine, 70, 71f, 628 Recuperation, 618, 619f, 625 Recuperator, 70, 704 Re-engineering, 671 Referred parameters, 704 Reforming zone, 629 Regeneration, 74, 77–78, 98, 102, 103f, 104f Regenerative cycle, 75f Regenerator, 70, 704 Reheat, 23, 28, 76–77, 77f, 102, 104f, 319, 446–447, 568, 666–667 GT/fuels cell hybrids and, 620 Reid Vapor Pressure test (RVP), 232 Rejuvenation heat treatment, 441, 441f, 529, 529f, 530f Relative density, 680 Relative humidity, 685, 688f Reliability, availability, and maintainability (RAM), 434 Reliability, availability, maintainability, and durability(RAM-D), 569 Reliability test, 574 Relighting, 306, 306f Renewable energy, 666, 668, 671, 672–673, 672f, 673t, 675t mandates for, 677t Renewable Portfolio Standard (RPS), 672, 673 Rental units, 117 Repair and overhaul (R&O), 388, 502, 522–523, 586, 670. See also Maintenance, repair, and overhaul; Overhaul business decisions and, 558 F class materials and, 529–533 F class technology and, 529–533, 535–536 gas path analysis and, 511 independent contractors for, 671 LPM powder metallurgy and, 537, 537f, 540f OEM agreements for, 518 rotor blades and, 535, 536 shop culture and, 559–561 stator vanes and, 535–536, 536 Repowering, 110, 662, 669, 674t Request for proposal (RFP), 647, 648, 652 Reservation agreements, 117

Residual fuel, 107, 108, 109f, 110, 168, 244–245, 268, 564, 669 cracked, 253 maintenance issues with, 245–246 operation and, 245–246, 270–274 treatment of, 265, 267–268 Resistance bulb thermometer, 406 Resistance welding, 587 Retrofits, 512 emissions control and, 665 life extension and, 506–507 operational optimization and, 506 performance analysis and, 509–510 Return on investment (ROI), 564, 662 Reverse engineering, 587, 671 Reverse osmosis (RO), 669–670 Reynolds number, 692 Ring seals, 170–171 Rio protocol, 660, 666 Risk and weighting analysis, 518 Risk management, 494 design compromise and, 566 design factors and, 565–566 factors for, 564–567 independent power producer negotiation and, 568 life-cycle assessment and, 566 manufacturer guarantees and, 116f, 565 market assessment and, 568–569 negotiation and, 568 new machine supply and, 565 operational compromise and, 566–567 performance analysis and, 566 politics/policies and, 566–567 quality control and, 565 secondhand merchants and, 567 technical risk mitigation for, 567 turbine inlet temperature and, 564–565 turbine selection/specification and, 563–564 vibration analysis and, 566 war and, 566–567 RO. See Reverse osmosis R&O. See Repair and overhaul Robotic welding, 514–515 Rocket engines, 25, 36, 37, 39f ROI. See Return on investment Rolls Royce, 19, 34, 52t, 57t, 59t, 62t–64t, 114, 132, 326, 385, 495, 562, 566, 587, 603, 606, 644, 667 V2500 and, 563 Rolls Royce Allison, 622, 629 Rolls Royce Allison 501-KB5, 606–611, 608f Rolls Royce Avon, 17, 122, 506, 562, 569, 586 Rolls Royce Dart, 23, 36, 125 Rolls Royce Derwent, 36 Rolls Royce Gem 60, 214 Rolls Royce Merlin, 23 Rolls Royce Nene, 36 Rolls Royce Olympus, 4, 562 Rolls Royce Pegasus, 29, 327, 566 Rolls Royce RB211, 2, 23, 122, 139, 530, 531f, 532f, 569, 586 Rolls Royce RM60, 19 Rolls Royce Spey, 4, 17, 562 Rolls Royce Trent, 23, 122, 142–143, 143f, 144, 586 gas fuel system for, 144f Rolls Royce Turbomeca Ltd., 64t Rolls Royce Welland, 36 Rolls Royce WR-21, 382–385, 382f

INDEX Rotadata, 373 Rotatel telemetry unit, 378 Rotoflow, 558 Rotor acceleration rate, 645 Rotor assemblies, 524, 524f axial compressors and, 129–131, 130f generators and, 343–345, 344f, 345f steam turbines and, 82 Rotor blades life extension of, 546, 547f repairing, 535, 536 Rotor inlet temperature, 703 Rover JET1, 17 RPS. See Renewable Portfolio Standard RS5 alloy, 604–605, 604t, 605 Running in, 416 Ruston, 506, 559, 586, 667. See also ABB Alstom Power; Alstom; European Gas Turbine Ruston TA1750, 145 Ruston TB5000, 145, 653, 657 Ruston TD4000, 508 RVP. See Reid Vapor Pressure test Ryder, 561 S curves, 686 Samsung Techwin, 64t Saturn (NPO Saturn), 64t SB. See Service bulletins Sconox, 476 SCR. See Selective catalytic reduction Sea King, 561 Sealing, 169–172 Sealing capacity, 485–486 Seals, 168, 169 brush, 172, 435–436, 558 carbon, 171–172 gland, 94, 95f, 179 hydraulic, 171 labyrinth, 170 ring, 170–171 types of, 171f Secondhand merchants, 567 Segari Ventures, 662 Seismic monitoring, 487 Selective catalytic reduction (SCR), 117, 141, 460–461, 476, 579, 582 startup time and, 464 Semi planing hulls, 19 Sensitivity coefficient, 575 Sensitivity study, 652 Sequential combustion, 445–448, 446f, 565 performance and, 447, 447f Sequential environmental burner (SEV), 565, 667 Sermafill, 530, 536 Service bulletins (SB), 122, 495, 516 life-cycle assessment updates and, 566 Service life extension, 542–547 SEV. See Sequential environmental burner SFC. See Specific fuel consumption SFR. See Steam fuel ratio SGT-600 Industrial Gas Turbine, 4 SH. See Superheater Shaft horsepower (SHP), 389, 390 altitude and, 393, 394f speed and, 393, 393f


Shaft speeds, measuring, 411 Shaft torque measurement, 411, 412f Shaft-power engine. See also Turboshaft aircraft and, 25–26, 27f, 706 intercooled, 70, 72f intercooled recuperator, 70, 72f simple-cycle single-spool, 69–70, 71f Shell, 112, 506, 561, 664, 668 Shenyang Liming Aero Engine, 64t Short takeoff vertical landing (STOVL), 29, 326–335 aircraft control and, 333–335, 335f bleed air for, 332, 333f engine swiveling for, 331–332, 332f lift fans for, 330–331, 332f lift thrust augmentation for, 332–333, 334f lift-jet engine for, 326, 330–331, 331f lift/propulsion engine for, 327f thrust deflection for, 328–329, 328f, 329f, 330f SHP. See Shaft horsepower Shutdown of land based turbines, 372 residual fuel and, 246 Siemens, 53t, 96–99, 108, 110, 112, 244, 245, 247, 373, 374–378, 460–462, 559, 565, 586, 669 Siemens 3A, 287–291 Siemens Power Generation, 618–619 Siemens SGT5-2000, 113 Siemens SGT6-5000, 112 Siemens V.64.3A, 374 Siemens V.84, 374, 375, 535–536 Siemens V.94, 542–547 Siemens V-series, 289t Siemens Westinghouse, 53t, 111, 114, 457t, 563, 611, 614, 626–629, 662 Advanced Turbine System program of, 434–439 India market entered by, 662–663 Siemens Westinghouse 501FD, 113, 114 Siemens Westinghouse 501G, 113 Siemens Westinghouse SGT100, 555f Siemens Westinghouse SGT500, 4, 12, 12f Siemens Westinghouse SGT600, 142f Siemens Westinghouse SGT800, 556f Siemens Westinghouse V84.3, 669 Siemens Westinghouse V94.3, 113, 565, 669 Siemens Westinghouse W501G, 434–439, 540–541, 540f, 541f operating, 51–52 testing of, 436–437, 437f, 437t, 438f Siemens Westinghouse YTL, 568 Simple cycle, 74, 75f, 704 Singapore, 663 SINTEF, 485, 490, 491 SJAE. See Steam jet air ejectors Skin friction resistance, 19 Slug flow, 284 Small power producers (SPP), 111, 660, 663, 668, 670 SMP. See Standard maintenance procedures SNECMA, 65t rechargement per brasage diffusion by, 530, 536 SNECMA CFM-56, 586. See also GE CFM-56 Sodium hydroxide, 272–273 SOFC. See Solid oxide fuel cell SOFC Power Generation, 626 Solar Centaur, 121, 506, 562, 564, 569 Solar energy, 660, 675t, 676 Solar Mars, 17, 564, 569, 667



Solar Saturn, 121, 494, 562, 569 Solar Titan, 569 Solar Turbines, 53t, 121, 621, 628 market entry monopoly and, 562–563 Solid oxide fuel cell (SOFC), 618 CHP application of, 626–627 flow requirements for, 630 hybrid gas turbine and, 619–621, 620f, 621f, 626–629, 628f, 629f, 630f, 631f, 632, 632t, 633t, 634t molten carbonate fuel cells v., 623 pressure ratio for, 625 thermal management of, 628 Soot blowing, 274, 276f SOP. See Standard operating procedures SOT. See Stator outlet temperature Sound intensity, 198, 204 Sound intensity measurement, 196–204, 202f, 203f. See also Effective Perceived Noise deciBel instruments for, 198–199, 199f standards for, 199–201 tonal sources and, 202–203 Sound power, 198, 200t, 204 Sound pressure, 198, 202f, 203f Sound source location, 201, 201f, 204 Sound, speed of, 680, 684, 686f Sound transmission absorptive linings and, 208–211, 209t, 210f, 211f unlined panels and, 205–208, 205f, 206f, 206t, 207f, 208f, 208t, 209t Southwest Airlines, 560, 561 SOx. See Sulfur oxides Spalding, D. B., 643 Specific enthalpy, 693, 694, 699 Specific entropy, 693, 694 Specific fuel consumption (SFC), 125f, 383, 389, 647, 702 speed and, 393, 393f Specific heat, 692, 694 Specific heat at constant pressure (CP), 692, 699 for air, 698 calculations with, 694 for kerosene, 696f for natural gas, 698 Specific humidity, 685–686, 688f Specific power, 702 Specific thrust, 702 Spectrometer, 414 Spectrum analyzer, 517 SPP. See Small power producers Spray forming, 603, 604 Spray nozzles. See Fuel spray nozzles SRB. See Surface reaction braze Stable airflow, limits of, 131f Stack pressurization, 623 Standard day temperature, 680 Standard maintenance procedures (SMP), 504 Standard operating procedures (SOP), 504 Standby generators, 12 Starting and ignition systems, 298–306 air, 300, 302, 302f auxiliary power unit and, 302 cartridge, 299–300, 301f combustor, 302 electric, 299, 299f, 300f gas turbine, 303, 303f hydraulic, 303

ignition units for, 303–305 iso-propyl-nitrate, 300, 301f jet fuel, 31 land based, 372 relighting and, 306 testing, 415 Startup combined cycle systems and, 458, 459–462, 468f emissions controls and, 460–461, 464 heat recovery steam generator and, 459, 461 inspection before, 501f of land based turbines, 371–372 methods of, 299–300, 302–303 plant construction and, 118 plant design and time for, 460–461 residual fuel and, 246 sequence for, 299f steam turbine, 458, 459, 461 tests for, 415 time for, 468f turboprops and, 499 Statement of requirements, 706–707 Static temperature, 693, 699 Statoil, 480, 484–492 Stator case, 124f Stator outlet temperature (SOT), 12, 15, 16, 425, 703 Stator vanes, 128, 129, 131f axial compressor and, 131 life extension of, 546–547 materials for, 132 repair of, 535–536, 536 variable, 131, 132f Steady state development testing, 413–414 Steam chests, 93f, 94 Steam cooling, 74, 99, 118, 163–165, 564, 667 in Advanced Turbine System, 436, 438–439 injected, 566 nitrogen oxides and, 439, 597, 598 Steam flow, measuring, 411 Steam fuel ratio (SFR), 426–427 Steam generation, 76, 446f Steam injected gas turbines (STIG), 445–455 full, 445, 453–455, 454f, 455t partial, 445, 448–453, 450f, 451f, 452f, 453f sequential combustion and, 445–448, 446f Steam injection, 389, 568 augmentation with, 445–455 cogeneration and, 511 combustion chamber and, 445 cooling with, 566 heat recovery steam generator and, 448 performance and, 426–427, 426f, 430 Steam jet air ejectors (SJAE), 464, 466t, 470 Steam load, 95f Steam purity, 463 Steam quality, 118 Steam turbines (ST), 74, 99–101, 100t, 107, 460, 643, 665–666 axial-exhaust, 82 back pressure, 80, 85f, 86f bearings for, 82, 91f casings for, 82 combined cycle applications of, 455, 458 components of, 79, 81f compound, 80, 82f condensing, 80, 83f, 666–667

INDEX construction of, 458 controls for, 82 efficiencies of, 456f extraction back-pressure, 80, 86f extraction control valves and, 94, 94f extraction-condensing, 80, 84f geared, 80, 88f governor systems for, 82, 90–92, 92f, 93f, 96f high-temperature design, 101, 101t hydraulic fluid and, 95–96 impulse blading, 79, 79f load cycling and, 464–465 lubrication for, 82, 89, 90 markets for, 107f mixed pressure, 80, 87f nozzles on, 80, 81f oil and, 90, 179–180 operation of, 92, 94 output of, 459f path optimization for, 456–457 performance testing of, 574 reaction, 79, 80f, 98 reheat and, 85, 89f, 90f reliability of, 458, 459f rotors for, 82 run-up of, 94–95 single-cylinder, 79, 81, 89f startup of, 458, 459, 461 supercritical, 96–99, 666–667 thermodynamic processes in, 576t throttle valve of, 465 tripping, 96 turbine blades for, 80 two-cylinder, 82, 90f Stem drilling, 594 Stewart and Stevenson, 667 STIG. See Steam injected gas turbines Stochiometric efficiency, 473 Strain cycle, 443 Straingauging, 414 Streamlining, 638 Stress rupture test, 606 Sulfur oxides (SOx), 474, 505, 513, 666, 667, 669 gasification systems and, 582 pressurized fluidized bed combustion and, 579, 582 taxes on, 568 Superalloy LPM, 536–541, 542 Supercritical steam systems, 96–99, 666–667 Superheat, 699, 701f Superheater (SH), 448, 449 Supertankers, 22 Supplementary firing, 458 Supportability, 714–715, 719 Surface reaction braze (SRB), 530, 536 Surge avoidance, 425 Surge lines, measurement of, 415 Swan Hunter shipyards, 11 Swirl vanes, 135, 146, 313 Syncrude, 561, 664 Syngas, 243–244, 244t Synthesis exchange rates, 235–236, 419, 704 Synthetic crude, 561 T-55, 566–567 Tangential firing (TF), 666


TAT. See Temperature after Turbine Distribution TBA. See Test bed analysis TBC. See Thermal barrier coatings TBO. See Time between overhauls Technetics, 614 Technology, flow of, 559, 660 Technology licensing, 667–668 Technology transfer, 668–670 Teekay Shipping, 491 TEHP. See Total equivalent horsepower Teledyne, 59t Temperature. See also Stator outlet temperature; Turbine inlet temperature; US Military Standard 208 ambient, 680, 684f, 698f changes in, 6, 8 combustion, 143 dynamic, 693 engine testing and, 405–407, 406f exhaust, 382, 702 exhaust gas, 363, 508 free stream total, 689 mean, 694 oil, 365–366, 366f performance and, 394–395, 693 standard day, 680 static, 693, 699 total, 693, 699 turbine entry, 169, 363, 703 Temperature after Turbine Distribution (TAT), 381 Temperature-entropy diagram, 68, 695. See also T-S diagram dry air, 700f Test bed analysis (TBA), 416–418 Test repeatability, 574 Test tolerance, 575 Testing, 388, 602f. See also Engine test bed; Performance test codes application, 415 ATS results of, 436–437, 437f, 437t, 438f component, 600f controller, 415 controls and instrumentation system, 359–362 data analysis for, 416–420, 430–433 development, 413–415 emissions, 414 engine component performance, 418–420 facilities for, 115t fluorescent, 520 fuel, 512 generator, 347, 347t ground, 499–500, 501f heat transfer, 599 hot cascade, 599, 601f inlet cooling devices and, 577 intake, 499 jet pipe and, 499 long-term operational, 599–600, 602–603 low cycle fatigue, 545 magnetic, 521, 522f maintenance and, 499–500 measurements and instrumentation for, 402–413 mechanical, 441 overhaul and, 525–526, 526f parameters for, 398 performance, 574 plant thermal performance, 573–577



Testing (Continued ) pressure, 402–405 product pass off, 416 significance of, 574–575 starting and ignition systems, 415 steady state development, 413–414 steam turbines, 574 stress rupture, 606 temperature and, 405–407, 406f thermal performance, 573–577 thermal shock, 606 thermodynamic processes and, 576t transducers for, 403–404 transient development, 414–415 turboprops and, 499 verification, 572, 573f water and, 430–433 witness, 202–203, 203f Texas State Technical College (TSTC), 655, 656f TF. See Tangential firing TFO. See Treated fuel oil TGT. See Turbine gas temperature Thailand, 663 Thermal barrier coatings (TBC), 439, 528, 528f, 599 Thermal cycling, 462–463 Thermal efficiency, 169, 389, 702. See also Internal efficiency combined cycle power plants and, 570 Thermal paint, 414 Thermal performance, of combined cycle generation, 458 Thermal performance test, 573–577 endurance test v., 574 inlet cooling and, 577 reliability test v., 574 repeatability of, 574 “Thermal Power-Guidelines for New Plants” (World Bank), 239 Thermal shock test, 606 Thermocouples, 406–407, 608 Thermodyn, 668 Thermodynamic gas properties, 694–699 Thermodynamic parameters, 693 Thermodynamic symbols, 75t Theta exponents, 417, 418f Third law of motion, 36 THP. See Thrust horsepower Three Mile Island, 665 Throttle pressure, 463 Thrust, 389 afterburning and, 325, 325f, 339, 339f, 393 axial, 453, 453f balance of forces for, 391f calculating, 336–339, 339f cycles, 706 deflection, 328–329, 328f, 329f, 330f distribution, 335–339, 389 flight and, 391–398 horsepower v., 391 instrumentation on, 359–362 measuring, 411 pressure, 190 recovery of, 392f test bench measurement of, 390–391 vectoring, 328, 331f water injection and, 312, 313f Thrust 2, 17 Thrust horsepower (THP), 390

Thrust reverser, 189, 315–319 bucket target, 315–316, 316f, 317–318 clamshell door, 315, 316f, 317–318, 317f, 319f cold stream, 316, 316f, 318–319, 319f construction of, 317–319 landing run length and, 315f materials for, 317–319 operation of, 315–317, 316f turboprop reverse pitch, 315–317, 319f warning panel and, 367 Thrust SSC, 17 Tidal power, 666 TIG. See Tungsten inert gas welding Time between overhauls (TBO), 5, 388, 389, 494, 495, 502, 506, 518, 669 extending, 510 fleet stagger and, 519 fuel selection and, 512 growth in, 519, 519f planning, 515 turbine inlet temperature and, 563 TIT. See Turbine inlet temperature Tizard, Gibson & Glauert, 34 Tolerances, 588 Torquemeter, 411 Toshiba, 455, 457t Total equivalent horsepower (TEHP), 390 Total loss lubrication system, 174, 175, 175f Total pressure, 693, 699 Total temperature, 693, 699 TOTLOS method, 712–715, 713f Trace metals, 251, 251t Training academic, 642–645, 643f cogeneration and, 657–658, 657f, 658f culture and, 563, 638 engineering, 644 gas turbine design project for, 645–653 industry and, 638–642 of project application engineers, 641–642, 642f Transducers, engine testing with, 403–404 Transient data, 420 Transient development testing, 414–415 Treated fuel oil (TFO), 269 Tripping signals, 96 Troubleshooting, 498, 498f, 638 True air speed (VTAS), 692 T-S diagram, 68 TSC. See Turbine stress controller TSTC. See Texas State Technical College Tungsten inert gas welding (TIG), 587, 589–590, 592f, 593f Turbec SPA, 61t Turbine blade, 158, 158f, 600f ATS development of, 436 attaching of, 160, 160f ceramic, 606–611, 607f, 609f, 610f, 611f construction of, 160 damaged, 517 impulse, 79f life extension for, 545–546 materials for, 161–162 steam turbines and, 83–84 variable reaction, 98 Turbine bucket, 444, 445f Turbine cooling, 169, 169f, 170f

INDEX Turbine disc, 159–160 materials for, 161 Turbine entry temperature, 169, 363, 703. See also Turbine inlet temperature Turbine exhaust temperature, 382 Turbine flow meter, 408 Turbine gas temperature (TGT), 363–365 Turbine houses, 196 Turbine inlet temperature (TIT), 4, 74, 120–121, 168, 542, 562, 596, 597, 598, 603 efficiency and, 564–565 emissions and, 141, 473, 563 fuel selection and, 512 nitrogen oxides and, 141, 565 reliability and, 564–565 sequential combustion and, 446–447 time between overhauls and, 563 vanadium content and, 567 Turbine module, 2, 68, 122, 155–166 construction of, 159–160 energy transfer in, 156, 158–159 free-power, 4f, 12, 17, 155, 157f gas flow through, 159 inspection of, 497 materials for, 161–163 temperature and, 599, 601 thrust calculation and, 337 triple-stage, 156f, 157f twin-stage, 156f types of, 156 Turbine nozzles, 139 Turbine stress controller (TSC), 461 Turbine trip, 99 Turbo Engineering Corporation, 35 Turbo lag, 17 Turbo-annular combustion chamber, 137–139, 139f Turbocharger, 17, 618 Turbofan, 5, 6, 6f, 25, 26, 27, 41f, 68, 69f, 128, 129, 651, 702 core flow in, 410 cycle for, 699, 701f engine accessibility and, 554f mass flow calculation for, 418, 419 TBA calculations and, 418 thrust cycles of, 706 Turbofix, 530, 536 Turbogenerator, 623, 635 core design for, 632–633 design parameters of, 630–631 fuel cell flexible, 625 hybrid power systems and, 629–635 operating characteristics of, 630 Turbojet, 5, 6f, 25, 27–28, 36, 36f, 38, 39, 40f, 68, 69f, 70, 656f exhaust duct of, 189 ice protection and, 306 instrument panel for, 360f mounting of, 552, 554f pressure control for, 215–219, 218f pressure notation of, 390f propulsive efficiency of, 41f speed and performance of, 392f, 393 temperature notation of, 390f thrust cycles of, 706 triple-spool, 588f water injection and, 312–313, 313f Turbomachinery, 2, 3, 16


aerodynamics of, 645 bearings in, 172 fuel cells and, 624–626 Turbomeca, 53t, 59t, 65t Turboprop, 3, 6f, 8, 10, 23, 25–26, 26t, 27f, 35, 40f, 70, 135, 214, 653–655, 654f, 655f, 656f control of, 214 engine accessibility and, 554f exhaust system for, 189 ground testing and, 499 ice protection and, 306 installation location of, 551 lubrication for, 172, 178 mounting of, 552 pressure control for, 215, 217f propulsive efficiency of, 41f remote adjustment of, 500f speed and performance of, 392–393, 393f starting, 499 thrust reversal and, 315–317, 319f water injection and, 312–313, 313f Turbo/ram jet, 36, 38, 39, 42f Turborocket, 36, 37, 39, 42f Turboshaft, 5, 25–26, 26t, 27f, 40f, 70 Turbosupercharger, 35 Turbothrust, 3 TWA, 35 UCG. See Underground coal gasification Ultramet, 614 Uncertainty analysis, 418 Underground coal gasification (UCG), 666 U.S. Air Force Academy (USAFA), 645 U.S. Filter/Fluid Dynamics, 614 U.S. Green Building Council, 621 US Military Standard 210 (MIL 210), 680, 686 cold day temperature and, 680 hot day temperature and, 680 UTC PWPS, 53t–54t VA. See Vibration analysis VAN. See Variable area nozzles Van Treuren, K. W., 645 Vanadium, 109, 245, 250, 261, 272–274, 441, 512, 513, 567 inhibiting, 253, 259–260, 260f, 261f Vapor locking, 232–233 Vaporizing burner, 228–229 Vaporizing tubes, 136, 137f Variable area nozzles (VAN), 383 Variable metering orifice (V.M.O.), 222–223, 224f, 225–227 Vattenfall, 490 VCAS. See Calibrated air speed VDU. See Visual display unit VEAS. See Equivalent air speed Velocity changes in, 8, 125f, 129 compounding, 79f gradient of, 699 Velocity head, 693 Velox, 34 Vereinigte Energiwerke AG, 490 Vericor Power Systems, 54t Verification testing, 572, 573f Vertical takeoff or landing (VTOL), 29, 326. See also Short takeoff vertical landing (STOVL)



VIAS. See Indicated air speed Vibration analysis (VA), 388 problem detection with, 511 risk management and, 566 Vibratory stress, 602f Vickers Viscount, 36 Vigor AS, 491 Viscosity, 236f, 237f, 251 dynamic, 235, 238, 692–693, 699 fuel, 235, 236f, 251 kinematic, 235, 238 oil, 237f Visual display unit (VDU), 508 VOC. See Volatile organic compounds Volatile organic compounds (VOC), 117, 474–475, 570 Volume, changes in, 6, 8 Volvo/GE, 65t von Ohain, H. P., 23, 34 Vosper Thornycroft, 495 VTAS. See True air speed W. L. Gore and Associates, 490 Warranties, 515 Wash systems, 184 Waste heat recovery, 389, 473, 568 Waste heat recovery generator (WHRG), 12 Waste to energy, 676 Water autoignition and, 280, 281f fuel and, 287, 289 as gas, 420, 421f heat recovery steam generator and, 464 performance modeling and, 420, 422–434 test data analysis and, 430–433 testing and, 430–433 thermodynamics of, 428–430, 429f Water injection, 103, 104f, 117, 225, 263, 389, 390 axial compressor and, 312 carbon monoxide and, 422 cleaning and, 350 combustion chamber, 313, 314f, 422–425, 424f, 425f compressor entry, 422–424, 423f, 424f compressor inlet, 313, 314f emissions control and, 475–476 engine design for, 425 methanol used in, 312–313 methods of, 422–425 nitrogen oxide emissions and, 287, 289, 474–476 on-line cleaning and, 350 power boost from, 312, 313f

systems for, 312–313, 314 thrust restoration from, 312, 313f turbojets and, 312–313, 313f turboprops and, 312–313, 313f Water to fuel ratio (WFR), 422–423 Water treatment system, 465, 467f, 470 Wave energy, 666 Wave making resistance, 19 Weather louvre, 186–187 Weir Westgarth (WW), 669 Welding, 589–590, 592. See also Electron beam welding; Tungsten inert gas welding Western Governors Association, 676–677 Westfalia Separator, 238, 259, 260, 265 Westinghouse, 35, 457t, 514 Westinghouse 19A, 35 Westinghouse W19, 35 Westinghouse W101, 527 Westinghouse W191, 527 Westinghouse W251, 509 Wet compression, 577 WFR. See Water to fuel ratio Whittle combustion chamber, 137, 138f Whittle, Frank (Sir), 23, 34, 35, 36 Whittle W.1.X, 35 WHRG. See Waste heat recovery generator WI. See Wobbe Index Wibault, Michel, 326, 327f Wilks, Maurice, 17 Williams International, 60t, 66t Williams Rolls Inc., 66t Wind power, 666, 673, 675, 676 Windmilling, 413 Witness testing, 202–203, 203f Wobbe Index (WI), 243 Working fluid, 6, 16, 680 Working gases, 168 World Bank, 28, 238, 663 World Business Council for Sustainable Development, 484 World Petroleum Congress, 485 World War II, 4 Wright Aeronautical Corporation, 35 WW. See Weir Westgarth Xonon flameless combustor, 154–155, 155f, 476 Young Generators, 668 YTL-Siemens, 112, 569, 662 Yucca Mountain, 664
Gas Turbines a Handbook of Air, Land and Sea Applications 2nd Edition by Claire Soares

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