Heat Recovery Steam Generator Technology

Heat Recovery Steam Generator Technology

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Heat Recovery SteamGenerator Technology

Edited by

Vernon L. Eriksen

Woodhead Publishing Series in Energy

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Contents

List of contributors xi

1 Introduction 1

Vernon L. Eriksen

1.1 Gas turbine�based power plants 1

1.2 Heat recovery steam generator (HRSG) 4

1.3 Focus and structure of book 14

References 15

2 The combined cycle and variations that use HRSGs 17

Joseph Miller

2.1 Introduction 17

2.2 Combining the Brayton and Rankine cycles 18

2.3 The central role of HRSGs in combined cycle design 22

2.4 Power cycle variations that use HRSGs 34

2.5 Conclusion 43

Reference 43

3 Fundamentals 45

Vernon L. Eriksen and Joseph E. Schroeder

Nomenclature 45

Subscripts 46

3.1 Thermal design 46

3.2 Mechanical design 61

References 63

4 Vertical tube natural circulation evaporators 65

Bradley N. Jackson

4.1 Introduction 65

4.2 Evaporator design fundamentals 66

4.3 Steam drum design 71

4.4 Steam drum operation 75

4.5 Specialty steam drums 77

References 79

5 Economizers and feedwater heaters 81

Yuri Rechtman

5.1 Custom design 82

5.2 Standard design 83

5.3 Flow distribution 84

5.4 Mechanical details 86

5.5 Feedwater heaters 89

Reference 94

6 Superheaters and reheaters 95

Shaun P. Hennessey

6.1 Introduction 95

6.2 General description of superheaters 96

6.3 Design types and considerations 97

6.4 Outlet temperature control 105

6.5 Base load vs fast startup and/or high cycling 109

6.6 Drainability and automation (coils, desuperheater, etc.) 110


6.8 Materials 112

6.9 Conclusions 113

7 Duct burners 115

Peter F. Barry, Stephen L. Somers†, Stephen B. Londerville,

Kenneth Ahn and Kevin Anderson

7.1 Introduction 116

7.2 Applications 116

7.3 Burner technology 118

7.4 Fuels 121

7.5 Combustion air and turbine exhaust gas 122

7.6 Physical modeling 127

7.7 Emissions 131

7.8 Maintenance 138

7.9 Design guidelines and codes 143

References 144

8 Selective catalytic reduction for reduced NOx emissions 145

Nancy D. Stephenson

8.1 History of SCR 146

8.2 Regulatory drivers 147

8.3 Catalyst materials and construction 150

8.4 Impact on HRSG design and performance 153

8.5 Drivers and advances in the SCR field 165

8.6 Future outlook for SCR 170

References 171

vi Contents

9 Carbon monoxide oxidizers 173

Mike Durilla, William J. Hizny and Stan Mack


9.2 Oxidation catalyst fundamentals 174

9.3 The oxidation catalyst 179

9.4 The design 183

9.5 Operation and maintenance 188

9.6 Future trends 196

Supplemental reading 197

10 Mechanical design 199

Kevin W. McGill


10.2 Code of design: mechanical 200

10.3 Code of design: structural 201

10.4 Owner’s specifications and regulatory

Body/organizational review 201

10.5 Pressure parts 202

10.6 Mechanical design 204

10.7 Pressure parts design flexibility 209

10.8 Structural components 215

10.9 Structural solutions 221

10.10 Piping and support solutions 226

10.11 Field erection and constructability 228

10.12 Fabrication 228

10.13 Conclusion 229

References 229

11 Fast-start and transient operation 231Joseph E. Schroeder


11.2 Components most affected 233

11.3 Effect of pressure 233

11.4 Change in temperature 234

11.5 Materials 241

11.6 Construction details 243

11.7 Corrosion 244

11.8 Creep 244

11.9 HRSG operation 245

11.10 Life assessments 248

11.11 National Fire Protection Association purge credit 250

11.12 Miscellaneous cycling considerations 250

References 252

viiContents

12 Miscellaneous ancillary equipment 253

Martin Nygard


12.2 Exhaust gas path components 253

12.3 Water/steam side components 260

12.4 Equipment access 261

12.5 Conclusion 262

13 HRSG construction 263

James R. Hennessey


13.2 Levels of modularization 264

13.3 Coil bundle modularization 266

13.4 Structural frame 276

13.5 Inlet ducts 278

13.6 Exhaust stacks 281

13.7 Piping systems 282

13.8 Platforms and secondary structures 284

13.9 Construction considerations for valves and instrumentation 284

13.10 Auxiliary systems 285


14 Operation and controls 287

Glen L. Bostick


14.2 Operation 288

14.3 Controls 301

References 319

15 Developing the optimum cycle chemistry provides the key

to reliability for combined cycle/HRSG plants 321

Barry Dooley

Nomenclature 322


15.2 Optimum cycle chemistry treatments 324

15.3 Major cycle chemistry-influenced damage/failure in combined

cycle/HRSG plants 328

15.4 Developing an understanding of cycle chemistry-influenced

failure/damage in fossil and combined cycle/HRSG plants

using repeat cycle chemistry situations 339

15.5 Case studies 342

15.6 Bringing everything together to develop the optimum

cycle chemistry for combined cycle/HRSG plants 345

15.7 Summary and concluding remarks 349

15.8 Bibliography and references 350

References 352

viii Contents

16 HRSG inspection, maintenance and repair 355

Paul D. Gremaud


16.2 Inspection and maintenance 355

16.3 Repair 375

References 377

17 Other/unique HRSGs 379

Vernon L. Eriksen and Joseph E. Schroeder

17.1 Vertical gas flow HRSGS 379

17.2 Once-through HRSG 384

17.3 Enhanced oil recovery HRSGs 390

17.4 Very high fired HRSGs 395

References 396

Index 397

ixContents

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List of contributors

Kenneth Ahn John Zink Company, LLC, Hayward, CA, United States

Kevin Anderson John Zink Company, LLC, Hayward, CA, United States

Peter F. Barry

Glen L. Bostick Manager of Systems Engineering (Instrumentation & Controls,

Research & Development, Innovation & Patents), Fenton, MO, United States

Barry Dooley Structural Integrity Associates, Southport, United Kingdom

Mike Durilla BASF Corporation, Iselin, NJ, United States

Vernon L. Eriksen Nooter/Eriksen, Inc., Fenton, MO, United States

Paul D. Gremaud Nooter/Eriksen, Inc., Fenton, MO, United States

James R. Hennessey Nooter/Eriksen, Inc., Fenton, MO, United States

Shaun P. Hennessey Nooter/Eriksen, Inc., Fenton, MO, United States

William J. Hizny BASF Corporation, Iselin, NJ, United States

Bradley N. Jackson Nooter/Eriksen Inc., Fenton, MO, United States

Stephen B. Londerville John Zink Company, LLC, Hayward, CA, United States

Stan Mack BASF Corporation, Iselin, NJ, United States

Kevin W. McGill Nooter/Eriksen Inc., Fenton, MO, United States

Joseph Miller The Energy Corporation, Steamboat Springs, CO, United States

Martin Nygard HRSG Consultant, St. Louis, MO, United States

Yuri Rechtman Nooter/Eriksen Inc., Fenton, MO, United States

Joseph E. Schroeder J.E. Schroeder Consulting LLC, Union, MO, United States

Stephen L. Somers†

Nancy D. Stephenson Environmental Technologies, Durham, NC, United States

xii List of contributors

1IntroductionVernon L. Eriksen

Nooter/Eriksen, Inc., Fenton, MO, United States

Chapter outline

1.1 Gas turbine�based power plants 11.1.1 Advantages 1

1.1.2 History 2

1.1.3 Outlook 3

1.2 Heat recovery steam generator (HRSG) 41.2.1 Role of the HRSG in the power plant 4

1.2.2 Characteristics 5

1.2.3 Types of HRSGs 6

1.3 Focus and structure of book 14

References 15

1.1 Gas turbine�based power plants

A number of different power plants use the gas turbine engine as their primary

driver. Among them are the simple cycle, the combined cycle, many (but not all)

cogeneration facilities, and the recuperative cycle to name a few. Heat recovery

steam generators (HRSGs) are used in combined cycle plants and in cogeneration

plants that utilize the gas turbine as their primary driver, so the expression gas tur-

bine�based power plants will be used to refer to these two types of plants for the

purposes of this book. Furthermore, there is very little difference between the

HRSG used in a combined cycle plant and the HRSG used in a cogeneration

facility, so one often finds the expressions used interchangeably in the industry.

We will try to distinguish between the two when necessary in this book.

1.1.1 Advantages

Combined cycle power plants and cogeneration power plants that use the gas

turbine engine as their primary driver have been popular for a number of years for

a number of reasons.

Efficiencies of over 60% based on lower heating of the fuel have been achieved

by these facilities. Other fossil fuel power plants, such as plants with conventional

Heat Recovery Steam Generator Technology. DOI: http://dx.doi.org/10.1016/B978-0-08-101940-5.00001-4

© 2017 Elsevier Ltd. All rights reserved.

http://dx.doi.org/10.1016/B978-0-08-101940-5.00001-4

boilers, have efficiency in the range 40�42% for supercritical technology and

45�47% for ultrasupercritical technology based on lower heating value of the fuel.

Gaseous emissions from gas turbine�based power plants are very low.

Oxidizing catalysts can be used to convert carbon monoxide to carbon dioxide, and

NOx reduction catalysts that utilize ammonia can be used to convert oxides of nitro-

gen to nitrogen and water vapor and reduce these two types of emissions to 2 ppm.

Due to their high efficiency and the fact that they usually burn natural gas fuel, gas

turbine�based power plants also emit far less carbon dioxide than other types of

fossil fuel power plants.

Capital cost is lower than other power plants.

Reasonably priced natural gas (primarily due to the development of shale gas) is

available at least in the US market.

They have a small footprint and do not require much space when compared to

other modes of power generation.

A small operating and maintenance staff is all that is required.

It is relatively easy to permit them.

Construction time is short compared to other types of power plants.

Lastly, due to its ability to start up quickly and respond to demand changes rap-

idly, the combined cycle power plant has become the ideal companion for renew-

able power generation sources such as wind energy and solar energy, whose output

is variable.

1.1.2 History

Although recent markets for combined cycle power plants have been strong and

there has been rapid development of the technology since the mid-1990s, the basic

technology has existed for a considerable length of time. References to systems

being installed as early as the late 1940s exist in the literature. Development contin-

ued into the 1960s, when systems up to 35 MW in size were being built. The 1970s

brought about demand for larger amounts of power, especially for intermediate load

(run primarily during the workday), and turbine manufacturers responded with

larger gas turbines and larger combined cycle plants. General Electric referred to

their combined cycle plants as STAG (steam and gas) while Westinghouse called

theirs PACE (Power at Combined Efficiency). Plants of this era utilizing a single

gas turbine could be as large as approximately 100 MW. Both the STAG and

PACE plants utilized vertical gas flow, horizontal tube, forced circulation HRSGs

manufactured by both General Electric and Westinghouse at this time.

The oil embargo of the 1970s slowed the market in the United States; however,

a brisk market in Saudi Arabia developed. Both General Electric and Westinghouse

stopped manufacturing HRSGs at this time; however, their partners in Europe and

Asia continued.

Federal legislation (i.e., the Public Utility Regulatory Policies Act or PURPA) in

the United States stimulated a market in the late 1970s and early 1980s for cycles

that only needed to export a small amount of energy to qualify for tax incentives.

This legislation led to the formation of independent power producers (IPPs),

who developed projects to take advantage of the situation. Opportunities increased

2 Heat Recovery Steam Generator Technology

and an entire industry developed. HRSGs at this time were designed to work with

standard gas turbines and meet the various export energy requirements of each indi-

vidual application. Due to wide range of steam flows and conditions encountered

along with the operational flexibility required by the different sites, the vertical

tube, natural circulation HRSG became the technology of choice.

In the late 1990s and early 2000s an extremely large market developed in the

United States and a significant market developed in many other areas for shorter

periods of time for both IPPs and conventional utilities. Development of larger and

more efficient gas turbines continued at an escalating pace and HRSG development

continued in parallel. The very large and efficient HRSGs that we see today are a

result of this development. Fig. 1.1 shows a photograph of a modern combined

cycle facility. Refs. [1�3] were used in the preparation of this section.

1.1.3 Outlook

Looking forward, a strong market for gas turbine�based power generation systems

should continue due to the high efficiency and low emissions achieved by these

systems along with their ability to support intermittent energy sources such as wind

and solar energy. An abundance of reasonably priced natural gas in many areas will

only increase opportunities for them.

Most projections available show growth in power generation from natural gas.

The US Energy Information Administration projects growth of 40% in power

Figure 1.1 Modern large combined cycle power plant with nine gas turbines and HRSGs.

Source: Photo courtesy of Nooter/Eriksen.

3Introduction

generated from natural gas between 2013 and 2040 for their reference case with the

natural gas share of the power generation market growing from 27% to 31% over

that period of time.

1.2 Heat recovery steam generator (HRSG)

The HRSG is a special boiler within the broader category heat recovery boilers.

The expression heat recovery boiler covers a wide range of boilers and boiler sys-

tems that recover energy from a variety of different heat sources. The gas flows

from these sources vary widely in flow rate, pressure, temperature, composition,

and cleanliness of the gas. Most heat recovery boilers, other than the HRSG, utilize

one, or two at the most, levels of steam pressure. The gas flow in a heat recovery

boiler can be either on the inside or outside of the tubes. When the gas flow is

inside of the tubes, the heat recovery boiler is referred to as a firetube heat recovery

boiler. When the gas flow is outside of the tubes, the heat recovery boiler is referred

to as a watertube heat recovery boiler. Firetube heat recovery boilers have been

used in the process industries for many years and have proven to be especially use-

ful when the gas being cooled is pressurized. They are often referred to as waste

heat boilers for these pressurized applications. HRSGs, which are watertube heat

recovery boilers located behind gas turbine engines, have become the largest cate-

gory, both in number of units produced and in physical size, in the general category

of heat recovery boilers. HRSGs have many things in common with conventional

boilers; for example, they contain evaporators, economizers, and superheaters. They

also use round tubes, headers, and drums and need to be designed to boiler codes.

They also have many differences; they rarely contain a water-cooled combustion

chamber, they usually use smaller diameter tubes than a conventional boiler, and

they make extensive use of finned tubing. Many of the differences that HRSGs

have from conventional boilers are features that they share with air-cooled

heat exchangers. The HRSG is thus a cross between a conventional boiler and an

air-cooled heat exchanger.

1.2.1 Role of the HRSG in the power plant

Although the gas turbine engine is the heart of the combined cycle or gas

turbine�based cogeneration power plant, a well-designed HRSG is critical for a

successful application. The gas turbine is usually a somewhat standard product that

comes in a number of fixed sizes. Its output is dependent on ambient conditions.

Steam turbines also tend to come in fixed sizes. The HRSG, on the other hand, can

be custom designed using relatively standard features. This ability for custom

design of the HRSG provides the opportunity to mix and match a number of stan-

dard gas turbines and steam turbines to fit a variety of applications. It is worth not-

ing that a well-designed HRSG does not know or care if it is functioning in a

combined cycle or cogeneration application. It is merely responding to input from

the gas turbine to generate steam at the conditions required by the application.


HRSGs perform several other functions to support not only the gas turbine but

also the entire power plant. When the exhaust gas from the gas turbine does not

contain enough energy to meet the needs of the power plant, a burner can be

included within the HRSG to increase its output. The burner provides very efficient

utilization of the fuel consumed. If the emissions from the gas turbine do not meet

project requirements, a carbon monoxide catalyst can be included to reduce carbon

monoxide levels and a selective catalytic reduction catalyst can be included to

reduce levels of nitrogen oxides. The finned tubing utilized in HRSGs provides sub-

stantial reduction of noise levels present in the gas turbine exhaust and additional

silencing can be included within the HRSG to reduce noise levels even further.

1.2.2 Characteristics

The basic HRSG is generally considered to be the device that starts at the exhaust

of the gas turbine and ends at the exit of a stack that releases exhaust gas to the

atmosphere. The HRSG contains in its most basic form ductwork and casing (enclo-

sure), economizers that heat water to near saturation, evaporators and steam drums

that convert water from the economizers to steam and separate the steam from

water, superheaters and reheaters that heat steam beyond saturation, and a stack

that exhausts to the atmosphere. A substantial amount of piping, valves, controls

and platforms and stairways are necessary to complete the HRSG. Fig. 1.2 contains

a photograph of a typical large HRSG.

Figure 1.2 Typical large HRSG.

Source: Photo courtesy of Nooter/Eriksen, Inc.

5Introduction

HRSGs vary widely in size since they are used behind gas turbines that range in

size from a few MW to over 400 MW. Small HRSGs can be highly modularized

with only a few components that ship on trucks or rail cars and are easily assembled

in the field. The largest HRSGs are approximately 140 ft long, 80 ft wide, and

130 ft tall (excluding the stack, which can be much taller). A large HRSG

could include 28 large modules of tubes, 3 or 4 steam drums, and over 100 truck-

loads of ductwork, casing, piping, and miscellaneous steel. Many tube bundles,

each of which requires a rail car for shipment, weigh as much as 250 tons and total

weight of the HRSG can be 7000 tons. Total heating surface in one of these large

HRSGs can be 7,000,000 ft2. Whereas assembly of a small, modularized HRSG

is quite straightforward, installation of a large, complex HRSG is a major field

construction project.

1.2.3 Types of HRSGs

There are a number of different types of HRSGs to meet the varying needs of

different applications and satisfy the varying preferences of different customers.

HRSG technology has also evolved over the years and new concepts have been

introduced.

Before reviewing the different types of HRSGs, it is useful to discuss the con-

cept of boiler circulation. Most HRSGs and industrial boilers and a substantial num-

ber of conventional utility boilers contain a steam drum and have a circulating

mixture of steam and water in their evaporators. Water from the economizer enters

the steam drum and mixes with saturated water. The water mixture from the steam

drum then flows through downcomer circuitry to the inlets of the evaporator tubes.

This water is heated in the evaporator tubes to form a water/steam mixture that then

flows to the steam drum where the water and steam are separated. Dry steam exits

the steam drum and is replaced by the water entering the drum from the econo-

mizer. Circulating boilers offer several distinct advantages. First, the presence of a

water/steam mixture in the evaporator tubes provides strong cooling of the tubes

and prevents the buildup of scale and dryout of the tubes. Secondly, the use of a cir-

culating boiler and steam drum permits the use of continuous blowdown to maintain

the level of solids in the water at a level where scale will not form on the inside of

the evaporator tubes. Since the solids present in the feedwater will not evaporate,

they remain in solution in the drum water and do not leave the drum with the dry

steam. Continuous blowdown, which is a discharge of a small amount of water

from the steam drum, controls the accumulation of solids. Circulation in a circulat-

ing boiler can be maintained either by taking advantage of the natural buoyant

forces present in the steam/water mixture or through the use of pumps. Water flows

through the economizer to the steam drum in a circulating type of boiler due to the

pressure developed in the boiler feedwater pumps that deliver feedwater to the

boiler system. As it absorbs heat and generates steam, the evaporator establishes

steam pressure adequate to force steam through the superheater. The pressure at the

superheater outlet is established by the equipment receiving the steam.


The most common types of HRSG are listed below and will be described in

greater detail throughout the book.

1.2.3.1 Horizontal gas flow, vertical tube, naturalcirculation design

The horizontal gas flow, vertical tube, natural circulation HRSG shown schemati-

cally in Fig. 1.3 is by far the most common design utilized in today’s market. Gas

enters the HRSG on the left, flows across the vertical tubes where steam is gener-

ated, and then flows up the stack. This design uses the natural buoyant forces of the

steam/water mixture in the vertical evaporator tubes to circulate the mixture and

satisfies virtually any application up to 3000 psi steam pressure. It requires a mini-

mum amount of control and is easy to operate, flexible, responsive, and reliable.

Since it has a steam drum, conventional boiler water treatment can be used.

1.2.3.2 Vertical gas flow, horizontal tube, forcedcirculation design

The vertical gas flow, horizontal tube, forced circulation HRSG shown schemati-

cally on Fig. 1.4 was used in the early days of combined cycle development and

was very common in Europe, Japan, and the Middle East into the 1990s. Gas enters

Reh

eate

r

IP steamdrum

HP steamdrum

Deaerator

LP steamdrum

Silencer

Damper

HP

Sup

erhe

ater

Bur

ner

HP

Eva

pora

tor

CO

Cat

alys

t

AIG

Gri

d

SC

R c

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yst

IP S

uper

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er

IP E

vapo

rato

r

HP

/IP

Eco

nom

izer

LP

Sup

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ater

LP

Eva

pora

tor

FW

Pre

heat

er

Figure 1.3 Schematic drawing of a horizontal gas flow, vertical tube, natural circulation

HRSG.

7Introduction

from the left, turns upward, and flows over the horizontal tubes, where steam is

generated. This design requires pumps to circulate the water/steam mixture through

the tubes to the steam drum. Conventional water treatment can be used.

1.2.3.3 Vertical gas flow, horizontal tube, naturalcirculation design

The vertical gas flow, horizontal tube, natural circulation HRSG shown schemati-

cally in Fig. 1.5 evolved from the vertical gas flow, horizontal tube, forced circula-

tion unit described above. The primary driver in development of this design was the

FW preheater

LP evaporator

LP superheater

HP economizer

HP evaporator

HP superheater

LP steamdrum

HP steamdrum

Circulationpumps

Figure 1.4 Schematic drawing of a vertical gas flow, horizontal tube, forced circulation HRSG.


FW preheater

LP evaporator

LP superheater

HP economizer

HP evaporator

HP superheater

HP steamdrum

LP steamdrum

Figure 1.5 Schematic drawing of a vertical gas flow, horizontal tube, natural (or assisted)

circulation HRSG.

9Introduction

desire to eliminate circulating pumps and the power consumption and maintenance

associated with them. The two designs look similar. The main difference is the

location of the steam drums. Conventional water treatment can be used.

1.2.3.4 Small once-through design

The small, once-through HRSG can have either vertical gas flow as shown schema-

tically in Fig. 1.6 or horizontal gas flow. Tubes are usually horizontal. This design

differs from the natural circulation and forced circulation designs described above

HP water

LP water

LP steam

HP steam

Figure 1.6 Schematic drawing of a small, vertical gas flow, once-through HRSG.


in that the evaporator does not have a circulating water/steam mixture in it: the inlet

of the evaporator contains 100% water, and the outlet contains 100% steam. It is

preferred to have a limited number of continuous water/steam flow paths that

extend from the economizer inlet to the superheater outlet to minimize flow maldis-

tribution. A steam drum is not required; however, feedwater quality must be excep-

tional as any solid material in the boiler feedwater cannot be removed by

blowdown. It will either deposit on the evaporator tubes or flow from the HRSG

into equipment downstream. The most common unit of this type in the market is

highly modularized and uses high-alloy tubes, whereas most HRSGs use carbon

steel tubes in their economizers and evaporators and low-chrome alloy tubes in their

superheaters and reheaters.

1.2.3.5 Large once-through design

A large once-through HRSG would look very similar to the small unit shown in

Fig. 1.7. It would not be as modularized due to its size and would not necessarily

require high-alloy tubes. Exceptional feedwater would again be required. Large

once-through HRSGs utilizing this technology are still in the development phase.

Once-through designs are attractive primarily due to the fact that they can oper-

ate at steam pressures approaching and even exceeding the critical point as they do

not require a density difference between water and steam to circulate. Feedwater

quality must match the purity requirements of the steam entering the steam turbine.

1.2.3.6 Benson design

The Benson HRSG is a once-through design that utilizes horizontal gas flow and

vertical tubes as shown schematically in Fig. 1.8. The hot end of the evaporator is

designed to utilize buoyancy in the hottest tubes to increase flow of the water/steam

mixture to them. The continuous water/steam flow path mentioned in Section 1.2.3.4

is interrupted midway through the evaporator in order to accommodate this feature.

Exceptional feedwater is again required as it is for other once-through designs.

A limited number of plants utilizing this technology have been built in recent years.

1.2.3.7 Enhanced oil recovery design

Enhanced oil recovery (EOR) involves the injection of a steam/water mixture into

an oil well to heat the oil, reduce its viscosity, and improve recovery of the oil from

the well. Water available at these locations is usually of very poor quality contain-

ing high levels of dissolved solids. Since treatment of this water would be very

expensive, steam of approximately 80% quality is generated in the HRSG and then

injected into the ground. The water present in the wet steam carries the dissolved

solids through the HRSG and into the well, preventing the buildup of scale on the

inside of the tubes.

A once-through design is normally used for these applications. Both vertical and

horizontal tubes have been used in these units in the past; however, most recent

11Introduction

applications have been of the horizontal tube design. A typical horizontal gas flow

horizontal tube unit is shown schematically in Fig. 1.9.

1.2.3.8 Very high fired design

When more steam is required than the exhaust gas from the gas turbine can supply,

burners are included within the HRSG to increase its output. The temperature

LP evaporator

HP evaporator

HP superheater

HP

sepa

rato

r

LP

sepa

rato

r

Figure 1.7 Schematic drawing of a large vertical gas flow, once-through HRSG.


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LP

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tor

FW

pre

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er

IP steamdrum

LP steamdrum

Silencer

Damper

HP steamseparator

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2

HP

sup

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ater

#2

HP

sup

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#1

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eate

r #

1

HP

eva

pora

tor

#2

HP

eva

pora

tor

#1

HP

/IP

eco

nom

izer

#1

HP

eco

nom

izer

#2

Figure 1.8 Schematic drawing of a horizontal gas flow, vertical tube, Benson HRSG.

EconomizerEvaporator

Steam/wateroutlet

Waterinlet

Gas

Inle

t

Gas

Out

let

Figure 1.9 Schematic drawing of a typical evaporator and economizer arrangement for an

Enhanced Oil Recovery HRSG (plan view).

13Introduction

leaving the burner is usually limited to approximately 1600�F in order to avoid

damage to the interior walls of the HRSG. Occasionally, far more output is required

and, in these instances, water-cooled walls are provided around the combustion

chamber and the first few rows of tubes. As for conventional HRSGs with a burner,

combustion is very efficient as the combustion air is preheated. In fact, many

of these applications resemble a conventional boiler that is utilizing a small gas

turbine as a combined forced draft fan and air preheater. These units are very

specialized and unique. One style of unit is shown schematically in Fig. 1.10.

1.3 Focus and structure of book

The previous section shows that there are numerous HRSG technologies available

for use. The goal of this book is to provide detailed information related to the fun-

damentals, design, and operation of the prevalent and most relevant technologies in

use. Therefore, a short market analysis was performed to determine which technolo-

gies are being purchased and to prioritize them. The basis for this analysis was a

series of reports published by the McCoy organization (Refs. [4�6] for the years

2013�15. A number of professionals who are active in the power industry were

polled to determine the HRSG technology that was used on these projects listed

in the McCoy reports. Eighty percent of the HRSGs purchased were known.

Radiantevaporator

Convectiveevaporator

Steam drum

Steam out

Economizer

Figure 1.10 Schematic drawing of a small very high fired HRSG.


Horizontal gas flow, vertical tube, natural circulation technology was used for 85%

of the known HRSGs accounting for 84% of the plant output. A similar analysis,

performed by Scapini (Ref. [7]), of 498 units awarded in the period 2007�09

determined that horizontal gas flow technology captured 85% of the market. Since

horizontal gas flow, vertical tube, natural circulation technology is the dominant

technology in the market, this book will focus on this technology.

The technologies described in Section 1.2 have many things in common. Much

of the information included herein will apply to some or all of them. A fundamental

understanding of the material included in this book will be very useful when deal-

ing with the other technologies. Additionally, Chapter 17, Other/Unique Heat

Recovery Steam Generators, will focus on the similarities and differences between

the prevalent other technologies and horizontal gas flow, vertical tube, natural cir-

culation technology.

HRSGs have some things in common with conventional boilers and other heat

exchangers and many things that are unique to themselves. The focus of this book

will be on items that are unique to HRSGs as the other items are covered in many

other sources.

Lastly, it is not the intent of this book to teach someone how to design a HRSG.

The thermodynamics and heat transfer involved could fill a book. The detailed

mechanical design could easily fill another book. Installation and operation are

each worthy of books. The goal of this book is to present the basic material

necessary to fundamentally understand HRSGs and why they are designed as they

are. This fundamental understanding should assist in incorporating a HRSG into a

combined cycle or cogeneration plant, in specifying and procuring a HRSG, or in

installing, operating, maintaining, or repairing one.

I will not go through the individual chapters and their intent as I believe

that they are self-explanatory. The authors are all experts in their fields and

have been involved in actually producing substantial numbers of the products

that they are writing about. I am proud that they have elected to participate in

this book.

References

[1] H. Jaeger, B. Owen, After long and bumpy road gas turbines set for growth,

Gas Turbine World (2011) 19�23.

[2] J.H. Borden, V.C. Tandon, 82-JPGC-GT-7. Combined Cycle Operating Experience,

ASME Paper, 1982.

[3] STAG Times, vol. 1, no. 1, General Electric, July, 1981.

[4] Heat Recovery Steam Generators (HRSGs), 12M ’13 Report, McCoy Power Reports,

February 26, 2014.


February 12, 2015.


February 18, 2016.

[7] P. Scapini, Personal Communication, May 31, 2016.

15Introduction

http://refhub.elsevier.com/B978-0-08-101940-5.00001-4/sbref1






2The combined cycle and variations

that use HRSGsJoseph Miller

The Energy Corporation, Steamboat Springs, CO, United States

Chapter outline

2.1 Introduction 17

2.2 Combining the Brayton and Rankine cycles 18

2.3 The central role of HRSGs in combined cycle design 222.3.1 Pressure levels 23

2.3.2 Reheat 29

2.3.3 Other decisions affecting heat recovery 31

2.4 Power cycle variations that use HRSGs 342.4.1 Cogeneration 35

2.4.2 Steam power augmentation 38

2.4.3 Integrated gasification combined cycle 40

2.4.4 Solar hybrid 41

2.5 Conclusion 43

Reference 43

2.1 Introduction

Without question, energy—or more precisely, the consumption of energy—drives the

world economy. We search the depths of the sea for oil to refine into various grades of

fuel to power aircraft engines, trucks, and automobiles. We mine for coal on all cor-

ners of the globe to combust this fuel source to generate electricity and produce steel.

We split atoms of radioactive substances, unleashing enormous amounts of nuclear

energy from a relatively small amount of mass. We fracture underground shale depos-

its to harvest natural gas for use as an industrial feedstock, to heat homes and water,

and to generate electricity. We harness the wind, we use the sun’s radiation—we even

try to capture the force of ocean tides—to meet mankind’s collective, unyielding

demand for energy. But this needs qualification. The world economy demands not just

energy, but inexpensive energy, especially inexpensive electricity.



http://dx.doi.org/10.1016/B978-0-08-101940-5.00002-6

It is with this global, unchanging backdrop that we explore combined cycle

power plants, and other power cycle variants, that use heat recovery steam genera-

tors (HRSGs). HRSGs fill a unique role in the neverending quest for inexpensive

electricity to power the world.

2.2 Combining the Brayton and Rankine cycles

The Brayton cycle is synonymous with the modern day gas turbine but that is not

how it started. Named after American engineer George Brayton (1830�92), the

cycle was first proposed by Englishman John Barber in the late 1700s. As devel-

oped by Brayton, the machine was a constant pressure reciprocating engine con-

structed of separate piston compressor and expander sections. Compressed air was

heated by combusting a vaporized fuel; useful work, such as driving a water pump

or textile mill, was performed during the expansion process.

Fig. 2.1 depicts the ideal or fully reversible (no entropy production) Brayton cycle

plotted on a temperature�entropy diagram. Comprised of two adiabatic-reversible

and two constant pressure processes, this cycle has evolved into an integral compo-

nent of the world economy. The modern day Brayton cycle efficiently and reliably

powers airplanes and ships, and is used to generate electricity. In its ideal cycle

form, gas is isentropically compressed from Point 1 to Point 2, followed by a con-

stant pressure heat addition (Point 2 to Point 3) raising the working gas temperature.

The gas then isentropically expands from Point 3 to Point 4. To close the ideal cycle,

the working gas undergoes a constant pressure cooling process (Point 4 to Point 1),

returning to Point 1 to restart the cycle at the original state point.

In its modern form (i.e., the gas turbine), the Brayton cycle is built from three

major components: a multistage, axial compressor; one or more combustion cham-

bers (called combustors); and a turbine for expanding the working gas. Fig. 2.2

below illustrates these three components of an open cycle gas turbine driving a gen-

erator for electricity production. It is an open cycle because unlike the ideal

Brayton cycle shown in Fig. 2.1, the working gas is not cooled; rather, it is dis-

charged to the atmosphere after expanding through the turbine. Comparing Figs. 2.1

and 2.2, note the compression of air from Point 1 to Point 2, the heating of the

compressed air by the addition of a vaporized fuel in the combustor from Point 2 to

Point 3, then the expansion of the high temperature and high pressure air/fuel

mixture through the turbine from Point 3 to Point 4. The air/fuel mixture, as

previously mentioned, does not return to state point 1.

What has just been described and depicted in Fig. 2.2 is a simple cycle gas tur-

bine generator used predominately for peaking power service. The Brayton cycle

turbine spins the generator to produce electricity. Depending on the generator rota-

tional speed measured in revolutions per minute (rpm), either 50 or 60 Hz electric-

ity is produced. Simple cycle “peakers,” as they are known in the electrical power

industry, can reach full power output in less than 10 minutes. This is a critically

important capability during electrical grid disturbances where additional power gen-

eration is required to prevent grid underfrequency and possible blackout events. But

the exhaust gas, after expanding through the turbine, is discharged to the


Figure 2.2 Open cycle gas turbine generator.

Figure 2.1 Brayton cycle T-S diagram.

19The combined cycle and variations that use HRSGs

atmosphere at temperatures typically in excess of 1000�F. As we will discuss

shortly, this wastes significant amounts of energy that could still be captured to pro-

duce useful work.

Around the mid-1800s, a Scottish civil engineering professor named William J.M.

Rankine is credited with describing an ideal vapor�liquid cycle that is unquestionably

recognized as the precursor to the modern day steam power plant. In Rankine’s ideal

cycle, shown diagrammatically on the temperature�entropy diagram in Fig. 2.3, the

vapor and liquid undergo a phase change by the addition and subtraction of heat.

At Point 1 the working fluid isentropically expands to a lower pressure at Point

2 and in the process reduces in temperature while performing work. The working

fluid undergoes a constant pressure cooling process from Point 2 to Point 3.

A phase change from a saturated two-phase substance to a fully liquid state occurs

in the cooling process. Point 3 to Point 4 consists of an isentropic compression of

the working fluid followed by a constant pressure heat addition from Point 4 to

Point 1. This ideal closed cycle represents any working fluid that undergoes a phase

change. Brilliantly for mankind, the Rankine cycle has been developed using water

as the working fluid to generate electricity since the late 1880s, only thirty-some

years from the time William Rankine described his heat engine cycle.

In Rankine cycle power plants, superheated steam is expanded through a steam

turbine driving an electrical generator (Point 1 to Point 2). Heat is rejected in a con-

denser that turns the two-phase mixture back to water (Point 2 to Point 3). Pumps

Figure 2.3 Rankine cycle T-S diagram.


are used to feed water into the steam boiler at the desired pressure (Point 3 to

Point 4). Fuel is combusted in the boiler to supply the heat required to change the

water back to superheated steam.

The fuel flexibility of the steam Rankine cycle is tremendous. Boilers have been,

and continue to be, fired on coal, oil, natural gas, wood, other biomass, refuse-derived

fuel, even shredded tires. Nuclear power plants are based on the Rankine cycle, with

the splitting of atoms providing the heat source. Tapping into the heat of the earth’s

inner core, geothermal power plants use vapor or liquid-dominated resources to spin

steam turbines for electrical generation. Organic Rankine cycles use a low boiling

point, carbon-based, working fluid to capture low-grade heat and convert it into elec-

tricity. The Rankine cycle is even adaptable to use the sun’s radiation to heat a work-

ing fluid and generate electricity in concentrated solar power plants (CSP).

We have described two fundamentally very different cycles to generate electricity:

the Brayton cycle, which predominately uses an air/fuel mixture as the working fluid,

and the Rankine cycle, which predominately uses water as the vapor�liquid working

fluid. Air and water are two very abundant earth resources. The crux of the problem

is fossil fuel, being finite, is subject to the forces of supply and demand pricing.

Generating electricity inexpensively then must be done efficiently. So what would

happen if we combined the two power cycles? How much more efficient could this

combined cycle be compared to the Brayton and Rankine cycles separately? And

how do we combine the cycles? What piece of equipment would be necessary?

Remember that the turbine exhaust gas from a simple cycle gas turbine discharges

to the atmosphere. This exhaust stream is still at a high temperature albeit at a low

pressure. The waste heat available in the turbine exhaust gas can be recovered. Early

concepts considered using the gas turbine exhaust in combination with additional

combustion air to burn a fuel source in a boiler. This would generate steam for use in

a Rankine cycle. But advancements in gas turbine firing temperature (Point 3 of the

Brayton cycle) soon yielded turbine exhaust gas temperatures (Point 4) hot enough

to directly generate steam at suitable temperatures for the steam turbine. The gas

turbine (i.e., Brayton cycle) then becomes the “topping cycle” and the steam turbine

(i.e., Rankine cycle) becomes the “bottoming cycle.” With this arrangement, the modern

combined cycle was born, with the HRSG providing the means to capture the waste

heat from the gas turbine.

Fig. 2.4 provides a schematic of a combined cycle power plant. State points

have been modified with a “B” for the Brayton cycle and “R” for the Rankine

cycle. The turbine exhaust gas at Point B4 enters into the HRSG to heat feedwater

and produce steam, with the exhaust gas then exiting the stack at Point B4’ at a

significantly reduced temperature. A single pressure level HRSG is shown simply

for clarity. As will be seen later in this chapter, HRSGs are intricately more

complex than the representation depicted in Fig. 2.4.

Combining the Brayton and Rankine cycles created the need for a new piece of

power plant equipment: the HRSG. Today’s HRSG is the bridge between the two

fundamentally different power cycles. And like a physical bridge connecting two

different towns allowing each town to benefit from the other, the HRSG connects

the two distinct power cycles yielding a large improvement in thermal efficiency

compared to each cycle by itself.


2.3 The central role of HRSGs in combined cycle design

The world’s first gas turbine for electrical power generation reportedly began opera-

tion in Europe in 1939. Ten years later, the first combined cycle power plant in the

United States entered into service in Oklahoma City. Oklahoma Gas & Electric’s

Belle Isle Station had, by today’s standards, a small 3.5 MW gas turbine generator

and used the turbine exhaust to heat boiler feedwater.

Modern combined cycle power plants have gas turbines ranging in size from

single-digit megawatts to in excess of 500 MW. Turbine exhaust gas temperatures

and exhaust flow rates have continually increased as gas turbine manufacturers

strive for higher efficiencies and greater power density.

Central to the success of combined cycle power plants has been the ability of

HRSG design to evolve in step with the gas turbine. As gas turbines became larger,

HRSGs became larger to handle the increase in exhaust gas flow. As gas turbine firing

temperature increased, HRSG heat transfer metallurgy and design adapted to success-

fully contend with the increase in turbine exhaust gas temperatures. As natural gas

prices increased and even higher efficiencies were required to lower the cost of elec-

tricity production, reheat capability was introduced into HRSG design. Because gas

turbine power output and exhaust flow decreases at hotter ambient dry bulb tempera-

tures, supplementary firing capability was added to HRSGs to provide capacity stabili-

zation. Single pressure level HRSG design gave way to two-pressure nonreheat, which

in turn gave way to three-pressure, reheat HRSGs with ever higher high-pressure (HP)

and reheat steam temperatures. This adaptability has time and again proven the unique

and central role HRSGs perform in combining the Brayton and Rankine cycles.

Figure 2.4 Combined cycle power plant schematic.


2.3.1 Pressure levels

Gas turbines for power generation applications can be categorized into two distinct

groups: aeroderivative engines and industrial heavy frame machines. Aeroderivative

gas turbines, as the name implies, were derived from aircraft jet engines.

Lightweight and fast starting, aeroderivatives have power outputs up to 100 MW.

The most efficient aeroderivatives in simple cycle applications are just over 40%

on a lower heating value (LHV) fuel basis. Heavy frame gas turbines were devel-

oped specifically for mechanical drive and power generation service. These gas tur-

bines have an extremely large power output range—from single-digit MW units to

engines over 500 MW in 50 Hz service. The most efficient heavy frame machines

are also over 40% LHV efficiency.

The need for the wide range in gas turbine power outputs is apparent.

This output variability provides the ability to precisely match the load require-

ments. And the need for high thermal efficiency is also readily apparent: higher

efficiency means less fuel burn per megawatt-hour of electrical energy produc-

tion and lower electricity production costs. But how does this impact HRSG

design, and more specifically, the number of pressure levels in the HRSG? To

answer this question, it is important to understand how the air/fuel mixture tem-

perature at Point 3 of the Brayton cycle (i.e., the gas turbine firing temperature)

impacts gas turbine efficiency.

The work done in the expansion turbine of the Brayton cycle is equal to the rate

of change in the working fluid’s enthalpy. This can be expressed by the following

equation:

Wturbine5H3 �H4 ðwith the subscripts 3 and 4 referring to the state points in Fig:2:1Þ

where:

H is the total enthalpy of the working fluid, which is in part a function of

temperature.

The above equation can be also expressed as:

W turbine 5mðh3 � h4Þ

where:

m is the mass rate and h is the specific enthalpy of the working fluid.

The net power output of a gas turbine (Wn) is equal to the turbine section

work minus the power necessary for the compressor section. By numerous variable

substitutions and equation rewrites, the gas turbine net power output can be

expressed as:

Wn 5mcpT1½ðηTðT3=T1Þ � ððrp k21ð Þ=kÞ=ηCÞÞðð1� ð1=rp k21ð Þ=kÞÞÞ�


where:

cp is the specific heat at constant pressure and k is the ratio of specific heats,

T1 and T3 are the ambient and firing temperatures,

rp is the pressure ratio, and

ƞT and ƞC are the polytropic efficiencies of the turbine and compressor sections respectively.

From the equation, the net power output of the gas turbine increases as the T3firing temperature increases. Therefore, for a given amount of heat added to the

cycle, as state Point 3 temperature increases, the gas turbine efficiency also

increases. In the ideal world, gas turbine firing temperatures would approach stoi-

chiometric combustion temperatures. The turbine inlet temperature in the real world

is limited by metallurgy. At some point, the turbine blades would oxidize, yield, and

fail due to excessive temperatures. Fortunately, gas turbine manufacturers have been

able to design and manufacture turbine blades with air and steam cooling as well as

coatings that have pushed the latest model turbine inlet temperatures to 2900�F.This is in excess of the melting point of carbon steel, stainless steels, and Inconel.

For a given compression ratio, an increase in state Point 3 temperature results

in a corresponding increase of state Point 4 temperature. Hence, as gas turbine

manufacturers have increased firing temperature over the years to improve effi-

ciency, the turbine exhaust gas temperature has also increased (see Fig. 2.5 below).

Figure 2.5 Evolution of full load exhaust gas temperatures.


From the very first gas turbine in power plant application to the present heavy

frame models, exhaust gas temperatures have increased nearly fourfold from

roughly 550�F to 1200�F. Considering present state-of-the-art HP and reheat steam

temperatures in the Rankine cycle are slightly higher than 1100�F, gas turbines

make an ideal topping cycle for the combined cycle power plant.

The progression of gas turbine exhaust flow over the years has also been remarkable.

Fig. 2.6 is a graph of the turbine exhaust flow for the largest heavy frame gas turbines

commercially available in each time period for the 60 Hz market. From the late 1970s

to the present, turbine exhaust flow has nearly doubled in a fairly linear progression.

High turbine exhaust flow rates at high temperatures yield a significant amount

of energy for the bottoming cycle. The key to the HRSG’s ability to effectively cap-

ture the topping cycle waste heat as the exhaust energy has progressively increased

has been through the addition of pressure levels within the HRSG. Fig. 2.7 provides

a typical temperature profile of the turbine exhaust gas and the water-steam work-

ing fluids within the HRSG. A single pressure level comprised of an economizer,

an evaporator section, and a superheater is depicted.

Feedwater enters the economizer and is heated by the exhaust gas. The water

temperature increases and approaches the saturation temperature of the evaporator

section pressure. After entering the evaporator section, the water boils, creating a

steam/water mixture. The temperature of the steam/water mixture remains constant

Figure 2.6 Exhaust gas flow progression.


during the phase change. The heat to boil the water and generate steam is provided

by the exhaust gas as it flows past the evaporator section tubes (the exhaust gas

flows externally to the tubes, steam/water flows through the inside of the tubes). As

the exhaust gas exits the evaporator section of the HRSG, its temperature must be

higher than the saturation temperature of the steam/water mixture by what is known

as the “pinch” temperature. Heat transfer can only occur if the heat source is at a

higher temperature than the fluid being heated. For the exhaust gas temperature to

equal the saturation temperature of the steam/water mixture an infinite amount of

heat transfer surface area would be required. Typical pinch temperatures are 14�Fto 20�F based on reasonable economic considerations. The last HRSG section

shown is the superheater. Here the steam generated in the evaporator section is

increased in temperature (i.e., is superheated).

A single pressure level in the HRSG cannot economically capture all of

the available gas turbine waste heat for reasons that will be explained in detail in

Chapter 3. Even if the pinch temperature is reduced to zero and a superheater

section is part of the single-pressure HRSG design, not all of the available waste

heat will be recovered. The HRSG stack temperature will still be relatively high.

One solution for increasing the energy recovery in the HRSG has been to add

pressure levels. Instead of just one pressure level, the HRSG can generate steam at

two or three different pressures. This has worked well since the steam turbines used

Figure 2.7 Typical temperature profile: single pressure level.


in combined cycle power plants can readily accommodate either two or three steam

pressure admissions. For nonreheat cycles, steam generated in the HRSG can be

admitted in the steam turbine as shown in Fig. 2.8.

In a two-pressure nonreheat cycle, HP steam and low-pressure (LP) steam generated

in the HRSG are admitted to the HP/IP and LP sections of the steam turbine

respectively. For a three-pressure nonreheat cycle, IP steam is sent to the intermediate

pressure (IP) steam turbine section in addition to the HP and LP steam flows previ-

ously shown in the two-pressure design.

Fig. 2.9 represents the standard three-pressure reheat cycle configuration for

combined cycle power plants. Similar to the nonreheat steam turbine, HP steam and

LP steam are directly admitted to the steam turbine. However, note that the exhaust

steam from the HP section of the steam turbine is routed back to the HRSG for

“reheating.” This steam flow is also referred to as cold reheat steam. Prior to enter-

ing into the reheater section of the HRSG, the cold reheat steam is combined with

IP steam generated from the HRSG. This combined steam flow is heated in the

HRSG reheater, then routed to the IP steam turbine admission port as hot reheat

steam. The benefit of reheat will be discussed in Section 2.3.2.

Illustrated in Fig. 2.10 is a three-pressure HRSG showing only the evaporator

section for each pressure level. Shown in Fig. 2.10 is the exhaust gas temperature

leaving each evaporator section (HP5 high pressure; IP5 intermediate pressure;

LP5 low pressure) based on a 15�F pinch for each evaporator pressure. The satura-

tion pressure used for each pressure level is representative of present day combined

cycle power plants with large, heavy frame engines. Note the cascading exhaust gas

temperature in the direction of exhaust gas flow. Clearly if only one pressure level

is used, the exhaust gas temperature leaving the HRSG would be too high consider-

ing the importance of cycle efficiency in generating low-cost electricity.

Figure 2.8 Nonreheat steam turbine configurations.


Figure 2.10 Three pressure with 15�F pinch.

Figure 2.9 Reheat steam turbine configuration.


To summarize, gas turbine manufacturers have continually raised engine firing

temperature to improve gas turbine efficiency. Higher firing temperatures result in

higher turbine exhaust gas temperatures. When coupled with the increase in turbine

exhaust flow of the latest gas turbine models, a tremendous amount of waste heat is

available for recovery in the HRSG. One means of capturing more of the waste

heat, thereby improving overall combined cycle efficiency, is to add pressure levels

to the HRSG. This HRSG design technique has been very effective, such that three

pressure levels are the norm for combined cycle power plants. We will now turn

our attention to another means of improving cycle efficiency within the HRSG.

2.3.2 Reheat

The Carnot cycle is an ideal cycle. It contains all fully reversible processes

(see Fig. 2.11). In this cycle there are no friction losses; there is no destruction in

availability, hence no entropy production. Each state point returns to exactly the same

place from whence it started. The Carnot cycle, due to its fully reversible nature,

represents the highest cycle efficiency possible for the two temperature limits of THand TL; where TH represents both the heat source temperature and the temperature of

the working fluid, and TL is both the working fluid temperature and the temperature of

the heat sink.

In the real word, there are friction losses in pipe. Steam and water flow from

high pressure to lower pressure and cannot reverse their path unless additional

energy is consumed. There are unrecoverable losses when steam is throttled across

Figure 2.11 Carnot cycle.


a valve. Once a fuel is combusted it cannot return to its previous state. In the real

world these processes are irreversible. Entropy is increased.

Heat transfer in the Carnot cycle occurs at zero temperature differential, an

impossibility in the real world. For heat to transfer from one fluid to another, there

must be a temperature difference, one fluid hotter than the other. During the heat

transfer process no work is performed between the two fluids. One is simply

increasing the temperature of the lower temperature fluid. Heat transfer is also irre-

versible. The hotter fluid giving up heat cannot return to its original temperature

without additional energy being consumed. The larger the temperature difference,

the larger the irreversibility. The larger the irreversibility, the larger the loss in

availability—and the larger the reduction in efficiency. The goal then to improve

cycle efficiency is to minimize the temperature difference between the heat source

and working fluid. This holds true regardless of the heat source, be it combustion

gases in a boiler or waste heat from a gas turbine exhaust stream.

Employing reheat is one means to reduce the temperature differential between

the heat source and working fluid. Referring back to Fig. 2.9, HP steam,

after expanding through the HP turbine section, is returned to the HRSG so the

steam temperature can be increased (i.e., “reheated”). By reheating the steam, the

composite temperature difference between the heat source (gas turbine exhaust) and

the working fluid (steam/water) is reduced.

A single reheat cycle is shown in Fig. 2.12. Pressure losses (friction) are

assumed to be zero (i.e., constant pressure heat addition). HP steam expands

Figure 2.12 T-S diagram of Rankine cycle with single reheat.


through the HP turbine section (Point 1 to Point 2) and then is returned to the

HRSG for reheating (Point 2 to Point 3). The hot reheat steam is then expanded

through the IP and LP steam turbine sections (Point 3 to Point 4). Point 4 to Point 5

is the constant pressure cooling process, Point 5 to Point 6 is the feedwater pumping

process, and Point 6 to Point 1 is the initial heating step.

It stands to reason then that if one stage of reheat improves overall cycle effi-

ciency then two or more stages of reheat would improve efficiency even more and

be a sound economic choice. In theory yes, but in reality, no. Additional reheat

stages soon experience diminishing returns. Unlike the ideal cycle where piping

losses are ignored, routing steam back and forth between the HRSG and the steam

turbine results in pressure loss, which is irreversible. Further, the additional

steam piping, valves, instrumentation, and insulation for the reheat piping

increases construction costs. The additional capital cost of more than one or two

stages of reheat, in conjunction with the added complexity, has not been economi-

cally viable. To date, only single reheat has been employed for combined cycle

power plants.

With respect to reheat pressure drops and implementing a single stage of reheat

into a combined cycle power plant, it is important to keep the total pressure drop of

the reheat piping and HRSG reheater modules to 10% or less of the HP turbine

exhaust pressure. This design rule yields reasonable cold and hot reheat piping dia-

meters while maximizing the gain in efficiency from employing reheat.

Another tangible benefit of reheat is its impact on steam quality in the last stages

of the LP turbine. Since reheat increases the temperature of steam entering the IP

steam turbine section, the steam moisture level is lower in the L-1 and L-0 (last

two rows) turbine blades. This reduces blade moisture losses, which slightly

improves cycle efficiency. The drier steam also reduces blade leading edge erosion.

2.3.3 Other decisions affecting heat recovery

HRSGs in combined cycle power plants are an amazing bridge between the

Brayton and Rankine cycles. By adding pressure levels, maximum heat recovery

can be achieved, while creating different steam pressures for smooth integration

with the steam turbine. By employing a single reheat stage within the HRSG,

the overall cycle efficiency can be increased by reducing irreversible cycle

losses. But there are other HRSG design decisions that also affect heat recovery,

and hence, cycle efficiency. Four of the major design decisions are briefly dis-

cussed below.

2.3.3.1 Amount of surface area

Without question, the amount of heat transfer surface area included in the HRSG

has the biggest impact on the amount of heat recovered. Even if the HRSG has

three pressure levels and one stage of reheat, without sufficient surface area, energy

will be wasted up the stack and lost. Once the exhaust gas mixes with the atmo-

sphere, the heat is unrecoverable.


The basic equation governing heat transfer in the HRSG is:

Q5U A LMTD

where:

Q is the amount of heat transferred;

U is the overall heat transfer coefficient;

A is the heat transfer surface area; and

LMTD is the log mean temperature difference.

The amount of heat transferred, therefore, is directly a function of the total

amount of heat transfer surface area included in the HRSG. With a multipressure

HRSG, the amount of surface area for each pressure level must be determined.

Since HP steam has the highest availability to do work, the amount of HP surface

area is typically maximized within the previously discussed constraints of the evap-

orator pinch. Adding HP evaporator surface area to achieve a pinch of less than

14�F becomes very costly. Sufficient superheater and reheater surface area must be

selected to achieve the desired steam temperatures. Too much economizer surface

area can lead to steaming economizer problems.

2.3.3.2 Surface area sequencing

Surface area sequencing refers to how the different sections within a pressure level

(economizer, evaporator, superheater) are arranged between the different pressure

levels. Clearly, for each pressure level, feedwater must first be heated in the econo-

mizer section to raise the subcooled liquid’s temperature close to saturation temper-

ature, then sent to the evaporator tubes to boil the feedwater and generate steam.

From the evaporator, the saturated steam enters the superheater to raise the steam

to the desired steam temperature. To obtain the desired steam temperatures for the

hottest steam (HP steam and hot reheat steam), the HP superheater and reheater

sections must be in the front of the HRSG (front being defined as the end closest to

the gas turbine exhaust flange). This is where the exhaust gas temperature is high-

est. Typically, the HP superheater and reheater are split into at least two different

sections each. This allows locating an attemperator between the split sections for

temperature control. Depending on the desired IP steam and LP steam temperatures,

more than one superheater for each of these pressure levels may be required with

the finishing superheater colocated with a higher pressure surface area section

where the exhaust gas temperature is hotter.

2.3.3.3 Supplementary firing

The gas turbine exhaust gas has a sufficient oxygen concentration to support sup-

plementary firing within the HRSG. Supplementary firing or “duct firing” consists

of injecting an additional fuel source inside the HRSG to mix with the turbine

exhaust gas stream, where it is then ignited to increase the energy content of the

exhaust gas. Duct firing can double the HP steam production at base load of the gas


turbine. The practical limit for duct firing is around 1600�F to 1650�F bulk gas

temperature measured downstream of the combustion zone but upstream of the first

downstream surface area from the duct burner.

Figs. 2.13 and 2.14 show two potential duct burner locations within the HRSG.

The duct burner located between split HP superheater sections (Fig. 2.13) is

most common. This location allows the HRSG designer to balance the amount of

superheater and reheater surface areas upstream and downstream of the duct burner

for steam temperature control. HRSGs have also been designed with the duct burner

directly located upstream of the HP evaporator surface. For some cogeneration

applications, two duct burners located in different sections of the HRSG have been

used to increase both HP steam production and a lower-pressure steam flow rate.

The amount of oxygen remaining downstream of the first duct burner limits the size

of the second duct burner.

2.3.3.4 Stack temperature

Intuitively, the lower the HRSG stack temperature, the greater the amount of

energy that has been recovered. The familiar equation to calculate the amount

of heat transferred (or “recovered” in the case of HRGs if losses are ignored) is

presented below:

Q5mcpðT1 � T2Þ

Figure 2.13 Split HP superheater with nested duct burner.


where:

Q is the amount of heat transferred;

m is the mass flow rate of the heat source;

cp is the specific heat of the heat source; and

(T12 T2) is the temperature difference of the heat source between two points in the flow path.

With T1 the temperature of the turbine exhaust gas entering the HRSG and T2the exhaust gas temperature immediately downstream of the last heat transfer sur-

face area, the lower the T2 temperature is, the greater the waste heat recovery in the

HRSG. The practical lower limit for the HRSG stack temperature is 150�F. Thiscan be achieved with the use of proper metallurgy for cold end heat transfer surface

area (i.e., LP economizer; also known as “preheater” or “feedwater heater”). If the

entire LP economizer is fabricated with carbon steel tubes, then the realistic lower

limit for the HRSG stack temperature is approximately 175�F and the condensate

temperature entering the LP economizer should be controlled to around 140�F to

150�F to prevent external corrosion.

2.4 Power cycle variations that use HRSGs

A major attribute of HRSGs is their versatility. HRSGs can recover heat from the

very smallest gas turbines to the very largest. They can also be configured for a

myriad of power cycle variations. A very widely used power cycle variation is

Figure 2.14 Duct burner located in front of all heat transfer surface area.


cogeneration. Cogeneration, as the name implies, is the simultaneous generation of

two different forms of energy, most often electricity and steam. HRSGs are bril-

liantly suited for cogeneration applications with their ability to generate steam at

three different pressure levels. HRSGs can also be used for cogeneration applica-

tions requiring electricity and hot water. Another power cycle variation that uses

HRSGs is steam power augmentation (PAG). In this cycle, a portion or in some

cases the total amount of steam generated in the HRSG is routed to the gas turbine

and injected into the engine upstream of the power turbine. This additional mass

flow into the turbine yields additional power output, hence, the term “power aug-

mentation.” More recent power cycle variations that use HRSGs are the integrated

gasification combined cycle (IGCC)and the solar hybrid cycle. Let’s explore each

one of these power cycle variants in more detail.

2.4.1 Cogeneration

Cogeneration plants, also known as combined heat and power plants, burst onto the

power generation scene in a big way during the Public Utility Regulatory Policies

Act (PURPA) years of the 1980s. Although in use prior to then, cogeneration plants

proliferated as a result of the PURPA of 1978. This US federal law created the quali-

fying facility (QF), entitling the QF owner to sell electricity to the utility company at

an avoided cost rate. In order to meet the requirements of PURPA, the cogeneration

QF had to meet a certain efficiency threshold. This is where the HRSG came into

play. By using the gas turbine’s exhaust energy, the HRSG produced steam and/or

hot water, which could then be sent to another facility for beneficial use. The elec-

tricity generated from the gas turbine, and for many cogeneration QF plants, the

additional electricity from a steam turbine, was then sold to the local utility at the

utility company’s avoided cost rate. Although the PURPA laws have changed,

cogeneration plants continue to be built to service hospitals, universities, food pro-

cessors, refineries, and petrochemical facilities, to name a few industries benefitting

from the efficiency of generating two forms of energy at the same time.

In its basic form, a cogeneration plant can consist of a gas turbine generator exhaust-

ing into a heat recovery steam generator, with the HRSG producing either steam or hot

water as thermal energy. Fig. 2.15 depicts a cogeneration plant with a two-pressure

level HRSG. The HRSG is producing HP steam and LP steam for process use.

Several successful enhanced oil recovery cogeneration plants have been con-

structed, where saturated steam produced in the HRSG is injected into an oil field

to increase oil production rates. In this arrangement the HRSG is only producing

steam at one pressure level.

The versatility of the HRSG makes configuring a cogeneration facility to meet

the needs of the thermal host relatively easy since one, two, or three different

steam pressures can be produced in a quite wide pressure range (25�2500 psig).

Hot water can also be extracted from the HRSG for process use.

Another common adaption is the combined cycle cogeneration plant. In this

power cycle variation, a combined cycle plant provides a portion of the steam pro-

duced in the HRSG for process use. With this cycle, not only do you get the high


efficiency of the combined cycle, but also the added efficiency benefit of the

process steam energy content.

The combined cycle cogeneration plant adds another layer of cycle configuration

flexibility. The steam turbine can be a backpressure machine, a condensing machine,

a condensing machine with a single extraction, or a condensing steam turbine with

double extractions. IP and/or LP steam generated in the HRSG can either be admit-

ted to the steam turbine or matched to a process steam pressure level for direct rout-

ing to the thermal host. Incorporating a duct burner into the HRSG provides even

greater steam production flexibility to match the thermal host’s varying steam needs.

The following two figures illustrate the versatility of the combined cycle cogene-

ration plant. Fig. 2.16 contains a backpressure steam turbine exhausting to a high-

pressure or medium-pressure (MP) process steam header. The LP steam generated

in the HRSG is routed directly to the LP process steam header. Depending on the

gas turbine used and the thermal host’s steam levels, the HRSG could also be fitted

with an IP level, with the IP steam routed to the MP process steam header.

The combined cycle cogeneration plant shown in Fig. 2.17 is a bit more com-

plex. The HRSG has three pressure levels and supplementary firing. The duct

burner is nested within the HP superheater sections. HP steam from the HRSG is

admitted to the steam turbine throttle. A controlled extraction port in the steam tur-

bine supplies the thermal host’s MP process steam header. The HRSG IP steam is

admitted to the steam turbine for power generation. LP steam from the HRSG can

either be sent to the thermal host or admitted into the steam turbine depending on

Figure 2.15 Cogeneration plant with two pressure HRSG.


Figure 2.17 Combined cycle cogeneration plant with three pressure HRSG and condensing

steam turbine.

Figure 2.16 Combined cycle cogeneration plant with two pressure HRSG and backpressure

steam turbine.

process steam flow requirements. This power cycle cogeneration configuration is

suited for F-class gas turbines and larger. Depending on the size of the steam tur-

bine and surface condenser, all or some fraction of the total steam produced in the

HRSG can be admitted to the steam turbine for electricity production.

Most combined cycle cogeneration plants are nonreheat. However, if MP process

steam flow rates are in the 200,000-pound-per-hour range or less, it is possible to

employ a reheat cycle design to marginally improve overall efficiency (Fig. 2.18).

With this power cycle variation, a portion of the cold reheat steam is sent to the

thermal host’s MP process steam header. As more and more cold reheat steam is

diverted to process, the efficiency gain due to reheat becomes less. Furthermore,

too much cold reheat sent to process results in tube metal design temperatures that

start to approach a dry reheater design. It is for these two reasons that the practical

limit of cold reheat steam flow diverted to process is roughly 200,000 pounds per

hour.

Without a doubt, the versatility of the HRSG has greatly contributed to the

success of the modern day combined heat and power plant.

2.4.2 Steam power augmentation

Steam power augmentation, or “steam injection,” is a means of increasing power

output of a gas turbine by injecting additional mass flow through the power turbine

section of the engine. The additional mass flow results in an incremental gain in

power output since turbine work is directly related to mass flow (see the previously

discussed equation: Wturbine 5mðh3 � h4Þ where m is mass flow through the power

turbine). The power augmentation steam is injected upstream of the turbine section

Figure 2.18 Combined cycle cogeneration plant with a reheat HRSG.


either downstream of the combustors or into the combustion section. When steam is

injected into the combustion of the gas turbine, it has the added benefit of reducing

engine NOx formation primarily by reducing the combustion zone mean tempera-

ture. Steam power augmentation for gas turbines with dry low NOx combustors

must have the steam injected downstream of the combustors.

Fig. 2.19 depicts the steam power augmentation cycle for a simple cycle applica-

tion. The HRSG is the source of the power augmentation steam by capturing some

of the waste heat from the gas turbine exhaust. The HRSG shown in Fig. 2.19 has a

drum, but a once-through HRSG design can also be used for simple cycle power

augmentation installations.

Most purpose-built power augmentation plants for simple cycle applications use

smaller gas turbines (less than 50 MW) as the prime mover. There are commercial

installations where once-through HRSGs have been back-fitted to F-class simple

cycle gas turbine installations to boost power output. The HRSGs were designed

such that they could be operated dry (no water in the HRSG pressure parts). This

allows the simple cycle gas turbines to continue in operation and exhausting

through the HRSG without steam power augmentation in-service.

Steam power augmentation can also be used in combined cycle power plants.

When additional power output is desired, cold reheat steam can be diverted

upstream of the HRSG and sent to the gas turbine for power augmentation steam.

This reduces the hot reheat steam flow to the steam turbine so some bottoming

cycle power output is lost, but the gain in gas turbine output from the steam power

augmentation results in an overall incremental gain in plant net output. The incre-

mental heat rate for the additional power output is in the range of 10,000 to

11,000 Btu/kWh (HHV).

Another variation of power augmentation for combined cycle power plants is

referred to as “hybrid power augmentation.” In this variation, the HRSG is fitted

with a duct burner that can generate more HP steam than the steam turbine can

admit through the throttle valves. The excess HP steam is used as power augmenta-

tion steam in total or in combination with cold reheat steam. See Fig. 2.20 for an

illustration of the hybrid power augmentation cycle. The incremental heat rate for

Figure 2.19 Simple cycle steam power augmentation.


the additional power output is in the range of 12,000�15,500 Btu/kWh (HHV)

depending on the amount of HP steam used for power augmentation steam.

Steam power augmentation for simple cycle applications finds a niche where

additional plant output is desired but for some reason the plant cannot be designed

or built out to combined cycle. Steam power augmentation can also be designed

into a combined cycle power plant where the power market is financially attractive

for peaking power at incremental heat rates north of 15,000 Btu/kWh (HHV).

2.4.3 Integrated gasification combined cycle

Coal-fired power plants have long been a mainstay of power generation worldwide.

Predominately, coal is combusted in pulverized form for electricity generation. As

the need for greater efficiency materialized, coal-fired cycle design added additional

regeneration (more feedwater heating), then single reheat, and in some cases double

reheat. Boilers went from subcritical to supercritical, and now are being designed for

ultrasupercritical conditions (in excess of 4000 psia). Even so, the most efficient

coal-fired Rankine cycle cannot match the efficiency of a standard combined cycle

power plant. Yet, what if the fuel cost advantages of coal and petcoke could be mar-

ried to the cycle efficiency of combined cycle power plants with the added bonus of

cleaner coal combustion and possibly CO2 capture? From this economic and envi-

ronmental stimulus, the IGCC was formulated, developed, and brought to commer-

cialization. And once again, the HRSG has a major role in this power cycle variant.

The major components of an IGCC plant are the gasifier; the gas clean-up equip-

ment, which can include CO2 capture; the air separation unit; and the combined cycle

equipment (gas turbine, HRSG, steam turbine, etc.). Oxygen from the air separation

Figure 2.20 Hybrid power augmentation cycle.


unit is mixed with coal in the gasifier to produce synthetic gas (syngas). The hot syn-

gas undergoes cooling, sulfur and particulate removal, and if desired, CO2 removal.

The cooling of the syngas is one area of integration between the gasification process

and the combined cycle power plant. Feedwater can be sent to cool the syngas, and

the saturated steam produced in the syngas cooling stage is then returned to the

HRSG for superheating and power production in the bottoming cycle.

Another area of integration is with the gas turbine. The gasification process

requires relatively pure oxygen. The compressed air feed to the air separation unit

can come from a separate air compressor or a portion of the compressed air can be

obtained from the compressor section of the gas turbine. Nitrogen from the air sepa-

ration unit is piped to the gas turbine and combined with the remaining air from the

compressor, then mixed with the syngas for combustion in the gas turbine’s com-

bustors. The resultant gas turbine exhaust is materially different, with much higher

concentration of nitrogen. The HRSG design can readily accommodate the different

exhaust gas composition. Fig. 2.21 provides a simplified diagram of the integration

between the gasification process and the combined cycle.

2.4.4 Solar hybrid

Since the mid-2000s, solar power has gained traction and is on the cusp of generat-

ing appreciable amounts of electricity as a percentage of total worldwide electrical

consumption. At the present time, photovoltaic (PV) power dominates the solar

power sector due to capital cost and its distributed nature. PV can be installed on

Figure 2.21 IGCC simplified diagram.


carports, residential roofs, even office building exterior walls. Solar power can also

take the form of CSP, where utility scale installations of mirrors (heliostats) con-

centrate solar radiation to a central tower. Within the tower a working fluid is

heated, which in turn transfers heat to water for the generation of steam. The steam

then drives a steam turbine generator in a conventional Rankine cycle. Another

form of solar power is the solar hybrid power plant.

Solar hybrid is a more recent power cycle variant of combined cycle, where

parabolic troughs or linear Fresnel collectors heat a working fluid (see Fig. 2.22 for

the cycle diagram).

Figure 2.22 Concentarted solar power integrated with combined cycle.


The hot working fluid is circulated through a steam generator, which transfers

the heat to water thereby generating saturated steam. The saturated steam exits the

solar steam generator and is sent to the HRSG, where it mixes with saturated

steam exiting the HRSG’s HP drum. The combined saturated steam flow then

flows to the HP superheater section of the HRSG, and once superheated, is sent

to the steam turbine. The HP steam produced from the sun’s energy in the

solar field; in a practical sense, replaces the HRSG duct burner generated HP

steam. It does it though without burning additional fuel; hence, the overall cycle

heat rate improves. This is in contrast to the negative impact on heat rate from the

duct burner.

It is also possible to directly capture the solar radiation right to water thereby

eliminating the heat transfer fluid loop. The steam generated in this fashion would

also mix with the saturated steam generated in the HRSG.

2.5 Conclusion

Energy powers our modern lifestyle, from transportation, to the manufacture of

goods, to keeping the lights on, to everyday tasks such as food storage and prepara-

tion. One form of energy, electricity—especially inexpensive electricity—is crucial

for the world’s economy. It has been humankind’s quest for inexpensive electricity

that has taken us from using the unique Rankine and Brayton cycles to generate

electricity to the present day combination of these two distinct cycles into a

“combined cycle.”

As we have discussed in this chapter, the HRSG is the bridge between the

Brayton (gas turbine) and the Rankine (steam turbine) cycles to technically allow

the combined cycle power plant. HRSGs take the high-temperature but low-

pressure gas turbine exhaust and recover this energy to generate high-temperature

steam at various pressure levels for power generation in the steam turbine. HRSGs

can generate up to three different steam pressures as well as produce reheat steam

for higher cycle efficiencies. Supplementary firing and emission control hardware

can also be integrated into the HRSG design to generate additional steam and

reduce gaseous emissions, respectively.

HRSGs are versatile. They can be used to recover energy from the exhaust gas

on the smallest to the very largest gas turbine models. The versatility of HRSGs is

also demonstrated in the variants of the combined cycle that use HRSGs. Combined

heat and power plants (cogeneration plants), the power augmentation cycle, the

IGCC, and the solar hybrid power plant all require the venerable HRSG to work

efficiently and reliably.

Reference

[1] M.M. EI-Wakil, Powerplant Technology, McGraw-Hill, Inc, San Francisco, 1984.




3FundamentalsVernon L. Eriksen1 and Joseph E. Schroeder2

1Nooter/Eriksen, Inc., Fenton, MO, United States, 2J.E. Schroeder Consulting LLC,

Union, MO, United States

Chapter outline

Nomenclature 45

Subscripts 46

3.1 Thermal design 463.1.1 Energy balance 46

3.1.2 Economizer 48

3.1.3 Superheater 49

3.1.4 Supplemental firing 50

3.1.5 Split superheater 52

3.1.6 Multiple pressure systems 53

3.1.7 Heat exchanger design 54

3.2 Mechanical design 613.2.1 Nonpressure parts 61

3.2.2 Pressure parts 62

3.2.3 Tube vibration and acoustic resonance 62

References 63

Nomenclature

BD continuous blowdown rate as fraction of steam flow

Cp specific heat

h specific enthalpy

Δhs heat required to evaporate one mass unit of water to steam at a specific

temperature

_m mass flow rate

ΔP pressure drop

Q heat transfer rate

Qab heat absorbed

Qrel heat released

T temperature

Tapproach difference between saturation and economizer outlet water temperature

Tpinch difference between gas outlet and saturation temperature in evaporator

w mass velocity



http://dx.doi.org/10.1016/B978-0-08-101940-5.00003-8

y quality

ε void fraction

ρ density

μ viscosity

Subscripts

g gas

in inlet

out outlet

s steam

sat saturation

w water

L liquid

TP two phase

V vapor

3.1 Thermal design

A designer of a heat recovery steam generator (HRSG) usually tries to maximize

the amount of heat recovered and minimize the stack temperature in the face of

three fundamental challenges:

� The HRSG must handle a large amount of gas flow. The HRSG will thus be large with a

large face area.� The temperature difference between the gas turbine exhaust and fluid being heated is

small. The HRSG will therefore have a large amount of heating surface.� A low gas side pressure drop is desired to minimize impact on gas turbine output. This

factor also increases the face area of the HRSG.

A summary of the basic design procedure and some basic concepts follow.

3.1.1 Energy balance

The amount of steam generated by a heat recovery boiler is calculated by an

energy balance. The energy balance must incorporate the concept of “pinch

point,” which is defined as the difference between the evaporator outlet gas

temperature and the saturation temperature of the steam/water mixture inside of

the evaporator:

Tpinch 5 Tg;out 2 T sat (3.1)

The following procedure should be used to properly recognize the concept of

pinch point when calculating the amount of steam generated.


The heat released to generate steam is the product of the mass flow rate, gas

heat capacity, and temperature difference across the evaporator.

Qrel 5 _mgCpðTg;in � Tsat � TpinchÞ (3.2)

The heat absorbed takes into consideration radiation losses through the casing

and other losses, usually taken to be an efficiency (Eff)5 99�99.5%.

Qab 5Eff3Qrel (3.3)

The energy required to generate one unit mass of steam is

Δhs 5 hs;out � hw;in 1BDðhw;sat � hw;inÞ (3.4)

where hs,out is the specific enthalpy of steam leaving the evaporator, hw,in is the spe-

cific enthalpy of water entering the evaporator, and hw,sat is the specific enthalpy of

water at the evaporator saturation temperature. BD is the rate of flow of continuous

water discharge expressed as a fraction of total steam flow. It is easily calculated if

the concentration of solids in the feedwater and that desired in the water in the

steam drum are known. Recommended solids concentrations in steam drum water

are included in Ref. [1].

Continuous blowdown is required to maintain the concentration of solids at a tol-

erable level in the evaporator and is usually in the range of 2�5% for a process

unit and 0.3�0.5% for a combined cycle unit.

The steam flow from the evaporator is calculated with the aid of Eqs. (3.2�3.4)

as follows:

_ms 5Qab

Δhs(3.5)

The pinch point serves two important functions. First, for a given set of gas side

flow conditions, it dictates the maximum attainable steam flow. This maximum is

obtained by setting the evaporator inlet water temperature equal to the saturation

temperature in Eq. (3.4) and substituting this result along with Eqs. (3.2) and (3.3)

into Eq. (3.5). Furthermore, for a lower fixed inlet water temperature, the pinch point

sets the steam flow as well since some of the heat absorbed from the exhaust gas will

be used to heat the inlet water from its reduced temperature to saturation. The tabular

portion of Fig. 3.1 shows the result of such a calculation for a typical evaporator.

Secondly, the selection of the pinch point, which is often between 10�F and 20�F,impacts the heating surface required in the evaporator. Fig. 3.1 shows the variation

of gas outlet temperature (from which the pinch point can be calculated) with heating

surface. For this example, where the gas inlet temperature is 1000�F and the steam

pressure is 1500 psia, 10% extra heating surface is required to reduce the pinch point

from 20�F to 15�F and increase the steam flow approximately 1%. An additional 12%

is required to reduce the pinch point to 10�F and increase the steam flow another approx-

imately 1%. It is easily seen that small changes in the pinch point can significantly

change the heating surface and equipment cost while only increasing the steam flow

marginally.

47Fundamentals

3.1.2 Economizer

The steam flow from a heat recovery boiler can usually be increased by the addition

of an economizer to preheat the feedwater before it enters the evaporator. The

impact of adding an economizer to the evaporator previously analyzed in Fig. 3.1 is

shown in Fig. 3.2. The gas temperature leaving the system is reduced substantially

and the steam flow is increased approximately 75%.

The procedure described earlier must be expanded and an additional important

concept must be introduced to calculate the steam flow from a combined evaporator

and economizer. This concept is that of the approach temperature difference,

i.e., the difference between the saturation temperature of the steam/water mixture in

the evaporator and the economizer outlet water temperature.

The economizer outlet water temperature, Tw,out, is used to determine the evapo-

rator inlet water enthalpy for use in Eq. (3.4) before substitution in Eq. (3.5) to find

the steam flow from the evaporator and economizer combination.

Distance along HRSG in direction of gas flow

Tem

pera

ture

(°F

)

0°

200°

400°

600°

800°

1000°

1200°

1400°

1600°

Gas

Steam/water

612°F597°F

15°F Pinch

Evaporator

Δhs = 986 BTU/lbBD = 2%

Tfw = 220°F

Ps = 1500 psig

Tg, in = 1000°F

ms = 210,000 lb/h

mg = 2,000,000 lb/h

Figure 3.1 Temperature distribution evaporator only.


3.1.3 Superheater

Superheated steam is often required for process reasons or in applications where the

steam will be used in a steam turbine. This need for superheated steam is thus spec-

ified by the steam user rather than the boiler designer. The superheater is added

upstream in the gas flow from the evaporator. Performance of the evaporator and

economizer previously shown in Fig. 3.2 with a superheater now included is shown

in Fig. 3.3. Steam flow from the system with a superheater is calculated by substi-

tuting the enthalpy of superheated steam for the steam enthalpy, hs,out, in Eq. (3.4)

and then proceeding as in the other examples.

Fig. 3.3 shows interesting changes in the example system with the addition of

superheat. First, the pinch temperature has decreased. This decrease is due to the

lower gas temperature entering the evaporator portion of the system. Second, the

gas temperature leaving the economizer has increased, thus decreasing the total


Tem

pera

ture

(°F

)

0°

200°

400°

600°

800°

1000°

1200°

1400°

1600°

Gas

Steam/water5°F Approach

612°F, Pinch = 15°F

309°F

Evaporator

Δhs = 976 BTU/lbBD = 2%Tfw = 220°FPs = 1500 psig

Tg, in = 1000°F

ms = 367,000 lb/h

mg = 2,000,000 lb/h

Economizer

Figure 3.2 Temperature distribution evaporator with economizer.

49Fundamentals

amount of heat recovered. This decrease is due to the lower steam flow rate from

the system. The water flow rate through the economizer has also decreased and

the water can therefore not remove as much heat from the gas as it could with the

higher flow.

A reasonable but not excessive steam side pressure drop is required to ensure

uniform steam flow in a superheater and prevent overheating of tubes. This concept,

which applies to reheaters as well, is especially important in areas where gas tem-

peratures are highest. This subject will be dealt with in more detail in Chapter 6,

Superheaters and reheaters.

3.1.4 Supplemental firing

On many occasions the energy available in the gas turbine exhaust stream is not

sufficient to meet the steam user’s needs. Since the gas turbine exhaust stream is

rich in oxygen, it is possible to locate a supplemental burner downstream of the tur-

bine, increase the gas temperature to the heat recovery system, and thus increase


Tem

pera

ture

(°F

)

0°

200°

400°

600°

800°

1000°

1200°

1400°

1600°

Gas

Steam/water5°F Approach

617°F, Pinch = 15°F

416°F

EvaporatorSuperheater

Δhs = 1269 BTU/lbBD = 2%

Tfw = 220°F

Ps = 1500 psig

Tg, in = 1000°F

ms = 241,000 lb/h

mg = 2,000,000 lb/h

Economizer

Figure 3.3 Temperature distribution superheater, evaporator, and economizer.


the system output. The end result is a very efficient package as the gas turbine is in

effect providing a supply of preheated combustion air to the burner and the addi-

tional fuel required to heat this air is thus saved. Fig. 3.4 shows the increase in per-

formance possible through the addition of a burner to the example problem

previously discussed. By increasing gas temperature to 1400�F, the steam flow has

increased almost 65%. The temperature of the superheated steam has also increased

significantly due to the higher gas temperature. The amount of superheat can be

controlled through the addition of a desuperheater or attemporator and further

increasing the steam flow. The pinch point has increased due to the higher gas inlet

temperature. The increased steam flow rate increases the water flow rate through

the economizer and increases this exchanger’s capability to recover heat. The stack

temperature has in fact decreased even though the inlet temperature increased. The

addition of supplemental combustion has thus enabled us to recover more of the

heat present in the gas turbine exhaust in addition to the heat content of the fuel in

this case.


Tem

pera

ture

(°F

)

0°

200°

400°

600°

800°

1000°

1200°

1400°

1600°

Gas

Steam/water

640°F, Pinch = 26°F

356°F57°F Approach


Δhs = 1432 BTU/lbBD = 2%Tfw = 220°FPs = 1500 psig

Tg, in = 1400°F

ms = 397,000 lb/h

mg = 2,012,000 lb/h

ms = 443,000 lb/h

Economizer

After attemporating steam to 950°F

Figure 3.4 Supplemental fired system with burner upstream of superheater, no steam

temperature control.

51Fundamentals

3.1.5 Split superheater

When a burner is located upstream of a superheater and the HRSG is expected to

operate over a wide range of firing temperatures, control of the steam temperature

exiting the superheater can be difficult. Depending on the size of the superheater,

an excessive amount of spray water could be required. The configuration shown in

Fig. 3.4 and discussed above is a good example of this. Splitting the superheater

into two units and locating the burner between them as shown in Fig. 3.5 is an

effective way to solve this problem. The steam temperature for the fired condition

is now at the desired level and desuperheating is not required. In fact, the stack tem-

perature is lower and the steam flow is higher than in the previous example. This is

because low-temperature water is now not required to cool the steam. When the

superheater is split properly, the steam temperature exiting the superheater will be

constant across the entire firing range of the burner. This concept, which also

applies to reheaters, will be covered in greater detail in Chapter 6, Superheaters and

reheaters.


Tem

pera

ture

(°F

)

0°

200°

400°

600°

800°

1000°

1200°

1400°

1600°

Gas

Steam/water

646°F, Pinch = 30°F

343°F

77°F Approach


Δhs = 1273 BTU/lb

BD = 2%

Tfw = 220°F

Ps = 1500 psig

Tg, in = 1000°F

ms = 453,000 lb/h

mg = 2,012,000 lb/h

Economizer

Figure 3.5 Supplemental fired system with split superheater.


3.1.6 Multiple pressure systems

The examples above show that there is a considerable amount of energy remaining

in the exhaust stream even after the steam flow has been maximized through the

use of a low pinch temperature and the addition of an economizer with a low

approach temperature. This effect is even more prevalent at higher steam pressures.

The exhaust gas temperature can be further reduced through the addition of steam

generation at lower steam pressures. Such a system is shown in Fig. 3.6. Steam is

generated at three pressures (1975, 565 and 93 psig), a feedwater preheater is

included, and the stack temperature is reduced to 196�F. Superheaters and reheaters

are included to provide steam at the required steam conditions and maximize steam

cycle efficiency. Economizers and the feedwater preheater are utilized to maximize

heat recovery. The superheaters, reheaters, evaporators, economizers and feedwater

preheater are arranged with the highest fluid temperatures where the gas tempera-

tures are highest for maximum efficiency. The overall temperature profile is then

similar to that of a countercurrent heat exchanger indicating that maximum use is

being made of the heating surface. The pinch point for each pressure is tight and

approach temperatures are small to take maximum advantage of the energy avail-

able. Multiple pressure level systems such as this are very common in today’s

market, particularly for larger gas turbines where the complexity is easily justified

from an economic standpoint.


Tem

pera

ture

(°F

)

0°

200°

400°

600°

800°

1000°

1200°

Gas

Steam/water

Reheat

T = 196°F

DA - DeaeratorPH - Feedwater preheaterEC - EconomizerEVAP - EvaporatorSH - SuperheaterRH - ReheaterLP - Low pressureIP - Intermediate pressureHP - High pressure

RH

2

SH

2

RH

1

SH

1

PH

2

PH

1

HP

EV

AP

HP

EC

3

HP

EC

2

IP E

VA

P

HP

EC

1

LP/D

A E

VA

P

Figure 3.6 Temperature distribution multiple pressure system with reheat.

53Fundamentals

3.1.7 Heat exchanger design

Once the heat balance has been completed and the heat duties and flows for the

individual exchangers have been determined, the detailed design of each exchanger

can be conducted. The heat balance is often, but not necessarily, conducted by

the end user or their consultant. Standard heat exchanger design procedures can be

used to design the individual heat exchangers so it will not be repeated here.

The design process is usually iterative as the components must fit together mechani-

cally, their inputs and outputs are linked together and the components thus interact.

HRSG suppliers have complex computer programs that automate much of the

design process in order to calculate HRSG performance quickly. Some of these

programs even evaluate the HRSG components on a row-by-row basis.

3.1.7.1 Pressure drop

Pressure drop has not yet been mentioned but it is a very important consideration in

the design of HRSGs. High gas side pressure drops can have detrimental effects on

gas turbine performance. It is therefore advisable to perform pressure drop calcula-

tions early in the design procedure. The pressure drop also dictates the gas side

velocities permissible in the various components and these velocities strongly influ-

ence the overall heat transfer coefficient, the heating surface required, and the cost

of the equipment. The maximum pressure drop is usually specified by either the

end user or gas turbine manufacturer. It is typically about 6 in. of water for a small,

single pressure system and in the range of 10�12 in. of water for larger, more com-

plex systems. Because of the impact on both initial equipment cost and long-term

operating cost, the specification of maximum pressure drop is a very important

decision.

3.1.7.2 Finned tubing

The major resistance to heat flow in an evaporator, economizer, superheater, or

reheater occurs at the interface between the tube wall and gas. Performance of these

components is therefore largely dictated by geometry, flows, and temperatures out-

side of the tubes. The most effective means of reducing this resistance is through

the use of finned tubing. Finned tubing often increases the outside heating surface

area of a tube by a factor of 10, thereby reducing the size of the components

substantially.

Typical finned tubes are shown in Fig. 3.7. The fins on the left and center sam-

ples are referred to as serrated; those on the right sample are called solid. Either

can have more surface area depending on tube diameter, fin height, fin thickness,

and serration size. Serrated fins promote slightly higher heat transfer but also have

slightly higher pressure drop. Thermal performance of the two kinds of fins is simi-

lar when compared at the same pressure drop. Solid fins are somewhat heavier and

usually more expensive than serrated fins.

The fins on the L-foot fin on the left are welded to the tube by a series of over-

lapping spot welds. The I-foot fins on the center and right are electric resistance


welded to the tube. The weld bond for the I-foot fins is superior to the bond for the

L-foot fins.

3.1.7.3 Tube arrangement

Either inline or staggered tube arrangements can be used in the components of a

HRSG. When compared at the same gas velocity, a staggered arrangement will

have higher heat transfer and pressure drop than the inline arrangement. When

compared at the same pressure drop, which is appropriate for a HRSG, the differ-

ence is not as great but the heat transfer is still a bit higher for the staggered

arrangement. Each arrangement has its own benefits from both a thermal and

mechanical standpoint. The arrangement utilized is usually based on the HRSG

supplier’s preference.

3.1.7.4 Two-phase flow

For horizontal gas path HRSGs, upwardly flowing water is evaporated in vertical

tubes. Two-phase flow in vertical tubes is characterized by different flow regimes

as illustrated in Fig. 3.8. Consider the tube to be heated for the purpose of this dis-

cussion. Water enters the bottom of the tube as all liquid. Bubbles will form at the

tube wall but may collapse in the bulk stream depending upon the amount of sub-

cooling present in the water. In this subcooled boiling regime no net steam is pro-

duced. Once the water is at the saturation temperature, bubbles will detach from the

tube wall and flow with the water in the bubble flow regime. Bubbles will start to

coalesce as shown in the slug flow regime. As more vapor is produced, the slugs

will become irregular; this is sometimes referred to as churn flow. As the vapor

flow increases further, it becomes a continuous core with liquid on the tube wall in

the annular flow regime. Vapor will flow faster than the liquid in this case and a

Figure 3.7 Finned tubing.

55Fundamentals

slip condition exists between the phases. Further increasing the quality will result in

small droplets breaking away from the liquid film. When the critical quality is

exceeded, the tube wall will no longer be wetted and all residual water will flow

with the steam as droplets in the mist flow regime. These dry wall conditions result

in poorer heat transfer and elevated tube wall temperatures. In large diameter con-

duits such as riser piping, slug flow does not exist.

Figure 3.8 Two-phase flow regimes in a vertical tube.


The flow regimes can be determined based upon the Fair flow regime map

(Ref. [2]) shown in Fig. 3.9, where y is quality, ρ is density, and μ is viscosity for

liquid (L) and vapor (V) phases.

Flow regimes in horizontal tubes are similar; however, the vapor and liquid can

stratify due to buoyancy. Dry wall conditions will occur at lower qualities in

horizontal tubes due to this stratification.

As vapor is generated in a tube, it will rapidly displace a significant volume of

water. The volume of vapor divided by the total volume for a small tube section is

defined as the void fraction. Void fraction is a function of quality, flow regime, and

pressure as shown in Fig. 3.10. In some flow regimes, the liquid and vapor veloci-

ties are equal; this is called homogeneous flow. In other flow regimes, the vapor

flows faster than the liquid. This is called a separated flow condition.

The two-phase density is a function of the void fraction (εÞ and the liquid and

vapor density.

ρTP 5 ερV 1 12 εð ÞρL (3.6)

In a natural circulation evaporator, the tube side, two-phase pressure drop is a

function of circulating flow, operating pressure, tube geometry, and the amount of

heat being transferred. This pressure drop is a combination of friction, static, and

momentum losses. For a short increment of tube length, the acceleration loss is

minor although more significant changes in momentum can occur during periods of

instability when flow can alternatively slow and surge.

The static loss is equal to the density times the height. The static loss decreases

from a maximum for all liquid flow to a minimum for all vapor flow. The

Figure 3.9 Fair flow regime map for two-phase flow in a vertical tube.

57Fundamentals

two-phase density and thus the static pressure drop decreases rapidly at low

qualities as the quality increases. Two-phase frictional losses increase from a mini-

mum for all liquid flow to a maximum for all vapor flow. The difference is very

significant for low-pressure systems (50�100 psig) thus limiting tube outlet condi-

tions to qualities less than 5% while outlet quality for high-pressure systems

(2000�2500 psig) may be as high as 20%.

Because the static pressure drop decreases and friction pressure drop increases

with increasing quality, there can be conditions where the same pressure drop exists

for two different quality conditions. See Section 3.1.7.6 on flow instability.

3.1.7.5 Evaporation and circulation

Circulation in natural circulation boilers is maintained by the natural buoyant forces

generated by the difference in density between the steam/water mixture in the tubes

and pipes (risers) rising from the evaporator to the steam drum and the water in the

pipes (downcomers) delivering water from the steam drum to the bottom of the

evaporator. Downcomers are usually located outside of the HRSG casing. Vertical

tube, natural circulation HRSGs can be started up easily and have vigorous, well-

defined circulation patterns across their entire operating range. Natural circulation

HRSGs are usually designed with circulation ratios (water mass flow/steam mass

flow) in the range of 5:1 to 25:1 with the high-pressure evaporator having the

lowest circulation ratio.

Generating steam in vertical tubes has many advantages.

First, the tubes are uniformly wetted around their periphery. It is very difficult

for a tube to dry out, overheat, and fail unless the heat flux is exceptionally high.

Wetted surfaces also help prevent the buildup of solids and/or harmful chemicals

that could cause overheating of the tubes or corrosion.

Figure 3.10 Void fraction for a vertical tube.


Second, the flow of water to each tube is controlled by the amount of steam

generated in that individual tube. The higher the heat flux in a tube, the greater

the steam generated in it. The natural buoyant forces in that tube are higher and the

flow of water to it is higher. The tubes in the hot end of an evaporator thus have a

higher flow of water to them than the tubes at the cold end. If there is either gas

flow or temperature maldistribution to a portion of the evaporator, the water flow

will automatically be compensated either upward or downward depending upon the

flow or temperature condition. The water flow is thus strongest in areas where it is

needed the most.

Third, the tubes can easily be drained. Accumulation of solids or chemicals in

undrained portions is not a concern. Neither is freezing of water left behind.

Steam generation in horizontal tubes presents concerns that are not present in

vertical tubes. Two-phase flow patterns in horizontal tubes are dependent on gravity

leading to the potential for “dry out” at the top of the horizontal tubes if the wall is

not continuously wetted. Solids and/or harmful chemicals can accumulate at this

point and cause either overheating of the tube or corrosion. Drainability of the tubes

is also a concern as the tubes sag between the points where they are supported so

solids and/or chemicals can deposit in these areas.

3.1.7.6 Instability

Unstable two-phase flow, where the flow in the tube or circuit varies or fluctuates

with time, can be the result of evaporator geometry or operating conditions. The

fluctuating flow pattern may temporarily stop or even reverse direction from the

intended flow path. Instability can occur in a single flow path or among parallel

connected conduits. Evaporator designs must be carefully checked for flow instabil-

ities as unstable conditions can result in level control problems, performance loss,

and/or mechanical damage. Severe instability can even lead to tube vibration or

burnout. Flow in vertical tubes is inherently more stable than flow in horizontal

channels. While there are other types of instabilities that exist in two-phase flow

systems, the two types of instabilities of concern in HRSG evaporator design are

Ledinegg instability and density wave instability.

Ledinegg instability is considered a static type instability (Ref. [3]), whereas

density wave instability is dynamic. With Ledinegg instability the same pressure

drop can occur for different mass velocities and parallel circuits could thus have

different flow rates. A flow characteristic curve for a system of circuits or channels

where this could occur is illustrated in Fig. 3.11. The right-hand portion of the

curve with positive slope represents flow of a high-quality mixture or all vapor in

the circuit. The left-hand portion of the curve with positive slope represents a low-

quality mixture of all liquid in the circuit. The curved peak, the curved valley, and

the portion of the curve in the center with negative slope represents circuits contain-

ing a liquid/vapor mixture. The external head curves A and B represent the external

driving force or pressure drop that could be supplied by a pump or elevated steam

drum. The intersections between external head curve A and the system characteris-

tic curve show multiple points of intersection and Ledinegg instability. Flow can

59Fundamentals

exist at points 1 and 3 in different circuits. Point 2 is an unstable point; flow will

drift to either point 1 or 3 from this location. External head curve B only crosses

the system characteristic curve once and is thus stable. Note that its negative slope

is steeper than that of the system characteristic curve.

Fig. 3.11 demonstrates that instability can occur if

@ðΔP systemÞ@w

,@ðΔP liquid headÞ

@w(3.7)

where w is the mass velocity and ΔP of the external head is the circulation driving

force, either a pump or the pressure difference of the liquid column from the inlet

of the heated section to the steam drum water level. The ΔP of the system is all

frictional, static, and acceleration losses of the circulation loop and steam drum

internals above the heated section inlet. A negative change in system ΔP can occur

for an increase in mass velocity because at low qualities the two-phase static pres-

sure drop is rapidly decreasing with increasing quality. Ledinegg instability is a

function of heat flux and operating pressure and occurs typically at low heat flux.

An evaporator will tend to be more stable as heat flux or operating pressure

increase. The dip in the system characteristic curve becomes less pronounced or

could even disappear as these quantities increase. Pressure drop at the inlet and out-

let of the system have a significant impact on flow stability. Outlet pressure drop is

destabilizing whereas inlet pressure drop has a stabilizing effect. This is because

high inlet pressure drop will result in a more constant liquid flow and be less sus-

ceptible to effects from downstream pressure drop.

Density wave instability is a dynamic or transient type instability and can occur

at high or low heat flux and can also occur between parallel flow channels. For a

boiling system, there is a difference in density between the tube inlet and outlet to a

Pre

ssur

e dr

op -

ΔP

System(internal)pressure

drop

Externalhead

Mass velocity - w

1

23 4

B

A

Figure 3.11 Characteristic flow curve.


drum. The difference creates a transient distribution of pressure drop through the

system and because of propagation delays, oscillations can occur. Density wave

instability is impacted by mass velocity and pressure with a system being more

stable at higher values of each. For low heat flux with significant riser length, small

flow differences have a significant effect on the two-phase static head. Increasing

heat flux in these conditions can be stabilizing.

For high heat flux, two-phase frictional pressure drop is more significant and

varies with flow and void fraction. Small changes in flow result in greater changes

in the two-phase pressure drop than the liquid phase pressure drop. This difference

in pressure drop has an impact on the flow and can cause instability. As with the

Ledinegg instability, inlet and outlet pressure drop have a significant effect on den-

sity wave stability. A relatively simple solution for flow instability can be to

increase the inlet pressure drop to the heated section by means of a valve or orifice.

For HRSGs, the evaporator approach temperature difference is typically small

with the exception of instances where condensate is fed directly into an LP steam

drum from the condenser. For small approaches, increasing the approach can be sta-

bilizing but at a more significant approach, increasing the approach can be destabi-

lizing especially in low heat flux conditions. If the approach is high enough, at low

heat fluxes, vapor generation can cease.

For a more thorough discussion of flow instability see Ref. [4].

3.2 Mechanical design

3.2.1 Nonpressure parts

Most HRSGs are very large structures and subject to building codes. Analysis of

wind loads and seismic loads is thus usually required.

The exhaust flow leaving a gas turbine engine is a violently turbulent, swirling

flow with average velocities in the range 250�350 ft/s, peak velocities as high as

600 ft/s, and temperatures as high as 1200�F. In addition, a gas turbine engine starts

quickly so these conditions are established in a matter of minutes. Isolation of the

casing and structure from these extreme conditions is thus preferred to eliminate

excessive growth of these components, minimize differential growth between the

structure and casing, and prevent cracking of the casing. This is usually achieved

by utilizing a cold, gas-tight casing insulated on the inside with at least two layers

of blanket insulation as shown in Fig. 3.12. The insulation is covered with a liner to

prevent erosion from the hot gas stream. The liner material is selected to withstand

the temperatures encountered and is designed to expand and contract freely in all

directions. The inner liner is constructed from a series of independent panels that

are covered with floating lap joints at the seams.

Cold casing construction with internal insulation and floating inner liners as

described above permit rapid start-ups and are not damaged by transient gas condi-

tions. It can be used at gas temperatures as high as 1600�F as long as the insulation

and liner materials are selected to withstand the temperatures. At temperatures

61Fundamentals

above 1600�F either dense ceramic pillows with a rigidized surface in place of the

insulation and liner or water-cooled combustion chambers are more appropriate.

Systems containing refractory would be subject to cracking of the refractory and

continual maintenance, and must be started up rather slowly. Refractory is thus

rarely used in HRSGs.

3.2.2 Pressure parts

All pressure parts, such as superheaters, reheaters, evaporators, steam drums, econo-

mizers, feedwater preheaters, and piping must be designed to a boiler code such as

the ASME Boiler and Pressure Vessel Code at a minimum. Parts subjected to very

high temperatures require considerations for creep in addition. If the HRSG will be

cycled through repeated starts and stops a life assessment may also be required.

These subjects are addressed in Chapter 10, Mechanical design and Chapter 11,

Fast start and transient operation.

Of prime consideration in the design of each component is accommodation of

the various thermal expansions occurring in the system. Separation of the expansion

of the pressure parts from that of the casing and structure permits unrestricted

growth of the pressure parts and minimizes stress. Tube bundles are usually sup-

ported at the top, permitting unrestricted thermal growth downward.

3.2.3 Tube vibration and acoustic resonance

It is a well-known phenomenon that a fluid flowing over a bluff surface, in this

case a tube, will generate vortices in the flow downstream of the tube. As the vorti-

ces are shed from first one side of the tube and then the other, surface pressures are

Figure 3.12 Cold casing with internal insulation and floating liner system.


imposed on the tube. The oscillating pressures can cause elastic structures to vibrate

much like the string in a stringed musical instrument vibrates. If the frequency of

the vortices generated and thus the frequency of oscillating pressures on the tube

happens to match the natural frequency (or one of its harmonics) of the tube over

which the fluid is flowing, the tube can be set into vibration and it may fail where

it is joined to a header. This condition is referred to as whirling instability and is

prevented by utilizing tube supports at several locations along the length of the tube

to change its natural frequency to one where whirling instability will not occur.

The oscillating pressures described above also generate aeroacoustic sounds. If

these sounds match the acoustic frequency (or one of its harmonics) of the cavity in

which they are generated, a standing pressure wave can be set up in the cavity. This

condition, referred to as acoustic resonance, can generate a loud noise and possible

casing damage. Acoustic resonance is prevented by installing longitudinal baffles,

parallel to both the gas flow and the tubes, in the bank of tubes to alter the acoustic

frequency of the cavity.

Both whirling instability and acoustic resonance have occurred in HRSGs in

the past and caused failures. Most HRSG suppliers have developed techniques to

predict them and prevent them. Ref. [5] covers both situations in detail.

References

[1] American Boiler Manufacturers Association, Boiler water quality requirements and

associated steam quality for ICI boilers, 2012.

[2] J.R. Fair, What you need to design thermosiphon reboilers, Pet. Refiner 39 (2) (1960)

105.

[3] M. Ledinegg, Instability of flow during natural and forced circulation, Die Warme

61 (1938) 8.

[4] M. Ozawa, Flow Instability in Steam Generating Tubes, in: S. Ishigai (Ed.), Steam

Power Engineering - Thermal and Hydraulic Design Principles, Cambridge University

Press, Cambridge, U.K, 2010, pp. 323�385.

[5] R.D. Blevins, Flow Induced Vibration, Second ed., Van Nostrand Reinhold, 1990.

63Fundamentals











4Vertical tube natural circulation

evaporatorsBradley N. Jackson

Nooter/Eriksen Inc., Fenton, MO, United States

Chapter outline

4.1 Introduction 65

4.2 Evaporator design fundamentals 664.2.1 Heat transfer/heat flux 66

4.2.2 Natural circulation and circulation ratio 68

4.2.3 Flow accelerated corrosion 68

4.3 Steam drum design 714.3.1 Drum water levels and volumes 72

4.3.2 Drum internals 73

4.4 Steam drum operation 754.4.1 Continuous blowdown and intermittent blowoff systems 76

4.4.2 Drum level control 76

4.4.3 Startup drum level 77

4.5 Specialty steam drums 774.5.1 Multiple drum designs for fast start cycles 78

4.5.2 Deaerators 78

References 79

4.1 Introduction

Vertical tube, natural circulation evaporator designs have been the go-to technology

in the combined cycle power industry for decades. They are reliable, easy to

construct, and have a high turndown ratio. They do not require heavy duty circulating

pumps and thus avoid the operating and maintenance costs associated with such

pumps. The use of vertical tube, natural circulation evaporators also increases the

operating flexibility of a power plant.

Natural circulation evaporator designs have seen significant advances over

the years. Early models with steam pressures of 400�500 psig were considered

“high pressure.” Due to the substantial increases in gas turbine size, and the higher

gas flows and temperatures associated with them, operating steam pressures now

routinely reach 2000�2500 psig. Historically, units had very limited cycling

Heat Recovery Steam Generator Technology. DOI: http://dx.doi.org/10.1016/B978-0-08-101940-5.00004-X


http://dx.doi.org/10.1016/B978-0-08-101940-5.00004-X

operation and would generally run at 100% load unless they were shut down.

Today’s units see significant changes in operating load, as well as numerous

“on/off” cycles throughout the year.

With the wide range of operation demanded of today’s evaporators, a thorough

analysis and understanding of the fundamentals associated with a safe and reliable

natural circulation evaporator design is critical to the long-term design life of the

evaporator.

The remainder of this chapter will focus on design fundamentals as well as some

of the details and design considerations of the piping and steam drums that are

included in a completed evaporator coil.

4.2 Evaporator design fundamentals

The basic function of a vertical tube, natural circulation evaporator is to absorb heat

from a heat source (typically the hot exhaust gases from a combustion turbine

(CT)), boil a portion of the water flowing in the tubes, and separate it from the

water. This steam is eventually superheated and sent to a steam turbine for power

generation, a process steam header, or sometimes both.

As mentioned previously, there are several key parameters that must be consid-

ered when designing a natural circulation evaporator system. The remainder of this

section will focus on highlighting these parameters.

4.2.1 Heat transfer/heat flux

Calculation of the heat transfer coefficient between a two-phase flow and the

inside wall of a tube is necessary for an accurate evaporator design. It is a compli-

cated process, but there are numerous correlations, varying in simplicity and

accuracy, available in the literature. The simpler correlations often sacrifice

some accuracy as they generally assume a homogeneous two-phase flow

model. The homogeneous model assumes the steam and water are flowing inside

of the tubes at the same velocity. In reality, the steam flows at a higher velocity

than the liquid water; this is known as separated (or slip) flow. While better corre-

lations exist for two-phase flow heat transfer; they are generally much more

complex in nature. Fortunately for the designer of an evaporator, the heat transfer

coefficient inside of the tube does not have a large impact on the overall thermal

performance of the evaporator. The dominant resistance to heat flow across the

tube is on the outside of the tube where the heat transfer coefficient is determined

by forced convection between the exhaust gas flow and the tube. That does

not mean that heat transfer on the inside of the tube is not important. Heat flowing

through the tube wall must be removed effectively to prevent overheating

of the tube. Thus the two-phase flow pattern inside of the tube and heat flux

at the tube wall are of utmost importance.


The maximum design heat flux, an important factor to consider when designing

a natural circulation evaporator, should be calculated during design and maintained

within appropriate limits to ensure reliable long-term operation. A detailed discus-

sion of it is beyond the scope of this chapter; however, some basics will be

reviewed below.

At higher pressures, the maximum heat flux limit is set to avoid film boiling

(Ref. [1]). Film boiling occurs when the inside surface temperature of the tube

is high enough such that it is not possible for liquid to remain in contact with

the metal surface. A layer of vapor will exist at the inner wall surface and

any liquid will be flowing in the center of the tube. As discussed previously,

a vapor layer at the tube will result in a significant increase in the tube metal

temperature local to the vapor blanket, which can be dangerous if it was not

considered in the design.

Actual maximum heat flux for HRSG is typically well below any film boiling

criteria for a clean tube wall. The problem arises due to deposits on the wall. Any kind

of deposit, such as preoperational oxidation or iron transport into the evaporator,

will elevate the tube wall temperature. Dissolved solids in the water will concentrate

under the deposit because of water flowing through the deposit and evaporating.

This concentration of dissolved solids can be corrosive if the water is not treated prop-

erly. This is especially true for low pH (,8) excursions. Preoperational acid cleaning

of an HRSG is recommended to place a new unit in as clean of a condition as possible

to avoid under-deposit corrosion. See Chapter 15, Developing the optimum cycle

chemistry provides the key to reliability for combined cycle/HRSG plants for more

information on under-deposit corrosion.

At lower pressure, the maximum heat flux limit is set to avoid choke flow

instability (Ref. [2]). The instability occurs when the pressure loss associated with

generating additional vapor exceeds the natural circulation driving force for flow,

causing temporary oscillations where vapor can actually reverse flow direction.

In cases where the pressure is high enough to avoid choke flow instability and

low enough to avoid film boiling, the heat flux can be limited by the mist flow

regime (Ref. [2]). As discussed previously, the mist flow regime occurs when

a high enough vapor fraction exists to tear the liquid from the walls. The wall is

blanketed with a layer of vapor with water droplets dispersed through the vapor

space. If this occurs, local heat transfer coefficients will be greatly reduced and

local metal temperatures greatly increased.

Although “rules of thumb” have existed in the heat recovery boiler industry for

many years (e.g., limit maximum heat flux to 100,000 BTU/ft2-h), the problem is

far more complex than can be represented by a single number and it is possible to

determine a much more applicable limit. The maximum allowable heat flux

is a function of the steam conditions (pressure, temperature, and quality), flow

conditions (primarily mass velocity), and geometry (tube diameter, length, and

orientation). Most HRSG suppliers maintain proprietary databases and correlations

to determine the appropriate maximum design heat flux under various conditions.

Correlations also exist in the literature for calculating the maximum heat flux.

Refs. [3�5] in addition to many others cover the subject in more detail.

67Vertical tube natural circulation evaporators

4.2.2 Natural circulation and circulation ratio

Natural circulation utilizes buoyancy due to density differences within the system

to circulate the fluid in the evaporator. The density of the liquid and the height dif-

ference from the steam drum water level to the evaporator inlet provide the driving

force for natural circulation. Since the density of the two-phase fluid flowing

upwards inside the tubes is lower (due to the boiling of water inside the tubes) than

the density of the liquid water in the downcomer, the gravitational force in the

downcomer is greater than the gravitational force inside the tubes. This ensures

continuous circulation from the drum through the tube field without the need for

circulating pumps. For today’s high-pressure large HRSGs, this driving force is

generally between 22 and 28 psi (Figure 4.1).

The maximum practical drum pressure for natural circulation is approximately

2750 psig. At higher pressures, the difference in density between the water in the

downcomers and the two-phase mixture in the tubes becomes small enough that it

is difficult to provide the driving force needed for natural circulation.

Circulation ratio is defined as the ratio of the mass of the steam/water mixture

to the mass of steam at the exit of the evaporator tube field. A circulation ratio of

5:1 means there is five times as much water flowing through the downcomer and

into the tubes than steam being generated in the tubes. If 100,000 lb/h of steam is

being generated in the tubes at a circulation ratio of 5:1; 500,000 lb/h of water

is flowing in the downcomer (100,000 lb/h of which is boiled while the remaining

400,000 lb/h is separated in the steam drum and will reenter the drum water

storage volume).

Maintaining the circulation ratio within proper design values promotes strong

cooling of the tubes; operation in areas of good flow regime and assists in

maintaining stable circulating flow. As with many other parameters discussed in

this chapter, recommended values for minimum circulation ratio will vary with

operating pressure as shown in Fig. 4.2.

4.2.3 Flow accelerated corrosion

During normal HRSG operation, a thin layer of the inside metal surface of a tube

will corrode and form a protective oxide layer. This oxide layer passivates the

inside surface of the tube, eliminating the risk of further corrosion.

Flow accelerated corrosion (FAC) of an evaporator is a phenomenon that occurs

when the protective oxide layer is dissolved or “stripped” from the inside surface

into the flowing stream of flowing water or the two-phase steam/water mixture.

Since the base metal surface is exposed, another layer of the metal will corrode to

form the protective oxide layer described previously. If the oxide layer continues

to be removed and reformed, eventually the base metal will become thin enough to

rupture, causing failure of the tube and a reduction in performance.

FAC is influenced by four main factors: water chemistry, fluid temperature, flow

velocity (turbulence), and metal composition.


Figure 4.1 (A) Remote drum style evaporator. (B) Integral drum style evaporator.


The influencing factors for FAC can be mitigated by:

1. Water chemistry

Water chemistry is the responsibility of the plant operators and engineers to decide

and implement an appropriate water treatment program. There are many industry accepted

codes and programs available. Generally speaking, if these programs are implemented and

strictly followed, FAC should not be an issue due to water chemistry. This subject is dealt

with in greater detail in Chapter 15, Developing the optimum cycle chemistry provides

the key to reliability for combined cycle/HRSG plants.

2. Fluid temperature

Evaporator operating fluid temperature depends on the evaporator operating pressure.

Temperatures in the range of 250�350�F (corresponding to pressures between 15 and

120 psig) are most susceptible to FAC (Ref. [7]). The solubility of the protective oxide

layer is significantly higher in this range than in other pressure/temperature ranges.

Most modern plant cycles will have low-pressure systems operating in this range, making

it difficult to mitigate the fluid temperature FAC concern. Especially for lower pressure

systems, FAC mitigation is accomplished by minimizing flow velocity and/or changing

metal composition.

3. Flow velocity (turbulence)

Higher velocities generate a larger shearing force that can strip the protective oxide

layer from the inside surface of the tubes. Tube and pipe bends are particularly susceptible

to FAC due to high localized flow velocities. Especially true for the low-pressure systems

where the oxide layer is most soluble, careful design and sizing of the tubes and piping is

necessary to maintain low velocities.

4. Metal composition

Carbon steel material is a common choice for HRSG tube materials. At lower tempera-

ture operation common in evaporator and economizer sections, carbon steel material is a

cost-effective solution. However, typical carbon steel material is susceptible to FAC at an

increased rate. It has been shown that tube materials having a higher chromium content

Figure 4.2 Recommended minimum circulation ratio as a function of drum pressure.


are significantly more resistant to FAC than standard carbon steel material. Often, low-

alloy steels (e.g., SA-213 T11) are used in the low-pressure sections to minimize FAC.

Alternately, specialty carbon steel material with a minimum chromium content can also

be used.

Additional information related to FAC is included in Chapter 15, Developing the

optimum cycle chemistry provides the key to reliability for combined cycle/HRSG

plants.

4.3 Steam drum design

As steam is generated in the evaporator coil, the two-phase mixture will flow from

the evaporator to the steam drum. The two main functions served by the steam

drum are to separate the steam from the steam/water mixture for export from

the drum and to provide a water storage reservoir to maintain water flow to the

natural circulation evaporator for a specified period of time in the event of a loss of

feedwater flow so that the evaporator will not run dry and overheat.

The steam drum is generally an unheated design component; as such, it does not

have the same heat transfer concerns discussed previously for the heated evaporator

tubes. However, the design of the steam drum is just as important for smooth and

reliable operation as the heated evaporator tubes are. The following paragraphs

discuss the main components that go into the overall steam drum sizing and design

(Fig. 4.3).

Figure 4.3 Typical steam drum internal layout showing steam separation devices.


4.3.1 Drum water levels and volumes

Typically, the water level in the steam drum is controlled by introducing an amount

of fresh feedwater into the drum approximately equal to the amount of steam being

generated in the evaporator and exported to the superheater. During normal opera-

tion, the water level is kept at a defined normal water level (NWL). Water levels in

the steam drum are defined as:

4.3.1.1 High high water level trip

High high water level (HHWL) is the maximum allowable water level in the drum.

If the water level reaches this point, the heat source (typically a duct burner or gas

turbine) will be reduced in load or possibly tripped. Operation above the HHWL

increases the risk of water carryover from the drum. Excessive water carryover can

cause tube failures in the high-temperature coils downstream of the drum or result

in poor steam quality being sent to a steam turbine.

4.3.1.2 High water level alarm

If the water in the drum reaches the high water level (HWL), an alarm will be

activated in the control center, alerting operators that the water level is increasing

so they can attempt corrective measures prior to reaching the HHWL.

4.3.1.3 Normal water level

The NWL is generally where the drum level is maintained during normal operation.

Operation at this level allows for water swell and shrink during load changes

without sounding alarms or reaching a trip level.

4.3.1.4 Low water level alarm

If the water in the drum reaches the low water level (LWL), an alarm will be

activated in the control center, alerting operators that the water level is decreasing

so they can attempt corrective measure (such as checking the feedwater source or

reducing duct burner output) prior to reaching the low low water level (LLWL).

4.3.1.5 Low low water level trip

The LLWL is the minimum allowable water level in the drum. If the water level

reaches this point, the heat source (typically a duct burner or gas turbine) will be

tripped. Operation below the LLWL increases the risk the water level will fall into

the evaporator tubes and they will begin to overheat due to a lack of water.

The main parameters used to size the steam drum diameter are the determination

of the appropriate steam separation space and water volume required in the steam

drum. The minimum steam separation space is calculated by determining a

minimum area for steam flow required to ensure proper moisture separation and


to prevent entrainment of water back into the steam. The minimum water volume is

determined either by a defined retention time or a minimum swell/shrink volume.

Swell/shrink volume is the amount of water level change associated with startup/

shutdown or operating load change. As heat input to the HRSG increases during

startup (prior to steam generation), the volume of the water in the drum will

increase, causing a natural swell and a subsequent increase in the operating water

level. During the remainder of startup and normal operation, drum level swell and

shrink will occur as load change demands change. The design and operation must

ensure the change in water level will not result in the system reaching the HHWL

or LLWL during load change.

Retention time is defined as the time for the water level to drop from NWL

to LLWL if there is a complete loss of feedwater flow to the drum when the

system is operating at the maximum continuous flow rate. The larger the retention

time, the longer an operator will have to correct for a loss of feedwater flow.

The loss of feedwater flow is typically caused by the loss of a feedwater

pump. The retention time is used to allow time for a backup pump to start and

begin to refill the drum.

The downside of a larger retention time is the increased steam drum size.

A larger diameter steam drum will not only be heavier and more expensive,

but will also have a much thicker shell, increasing the stress associated with startup

and thermal cycling.

4.3.2 Drum internals

As discussed previously, one of the main functions of the steam drum is to separate the

steam/water mixture exiting the evaporator tubes, sending the steam out of the steam

drum while the water returns to the drum water storage volume. There are typically

two stages of separation.

4.3.2.1 Primary separator

Typically a centrifugal type separator, the primary separator is designed to separate

the largest portion of water from steam. The primary separators will generally fall

into two categories:

1. Baffle type separator. The baffle type separator utilizes the difference in density between

the steam and water to separate them. The steam/water mixture flows around the ID of

the steam drum to a baffle that turns it in a downward flow direction. The heavy water

droplets continue on into the water level while the lighter steam will turn upwards towards

the secondary separators.

2. Cyclone type separator. The cyclone separator utilizes centrifugal force in a different

device than the baffle above. The steam water/mixture enters the cyclone and flows

tangentially around the cyclone. The water will remain at the outside surface and then fall

to the water level. The steam will flow towards the inside area of the cyclone and out of

the top of the cyclone towards the secondary separators (Figs. 4.4 and 4.5).


4.3.2.2 Secondary separator

The secondary separator is typically a chevron style separator with a mesh pad

agglomerator attached to the front of the separator. The steam flow is largely dry

exiting the primary separator. The remaining small water droplets are coalesced in

the stainless steel mesh pad into larger droplets. The large droplets are easily

Figure 4.4 Steam drum sectional view showing cyclone style steam separators.

Figure 4.5 Internal view of steam drum showing primary (baffle style) and secondary

(chevron style) separators.


separated in the chevron style separator. Today’s modern separators will typically

reduce the exiting steam moisture content to 0.2% or less (by weight). See Fig. 4.6

for a chart of typical separator efficiencies as a function of drum pressure.

4.4 Steam drum operation

As discussed in the previous section, the steam drum serves as a water storage

vessel that provides a mechanism to separate the steam/water mixture exiting the

connected evaporator, sending nearly 100% dry steam out of the drum.

Especially critical in a power plant setting is the purity of the steam exiting the

HRSG and being sent to the steam turbine. The steam separators discussed in

the previous section reduce the water droplet content, but it is also important to

limit the impurities in the water itself to ensure the steam exiting the HRSG meets

the purity requirements of the steam turbine. Controlling impurities in the water

is accomplished by a combination of water chemistry, continuous blowdown,

and intermittent blowoff.

Figure 4.6 Secondary separator moisture removal efficiency as a function of drum pressure.


Ref. [6] contains recommended water quality limits to be maintained in the

steam drum. Water chemistry considerations were discussed previously and are

covered in detail in Chapter 15, Developing the optimum cycle chemistry provides

the key to reliability for combined cycle/HRSG plants. The remainder of this

section will discuss the operation of continuous blowdown and intermittent blowoff

systems, as well as the method of drum water level control.

4.4.1 Continuous blowdown and intermittent blowoff systems

As water is continuously circulated through the evaporator system and pure steam

departs, impurities in the steam drum water volume will increase. Since most of the

water is separated from the steam and reintroduced into the drum, the impurities

never leave the system. As additional feedwater is introduced into the drum (with

its own concentration of impurities) to replace the steam generated, impurity levels

would continue to rise unless they are removed via the blowdown lines.

Continuous blowdown is a small stream of water continuously taken from the

drum to a blowdown tank. The amount of water taken depends on the impurities in

the drum water and the required purity in the exit steam, but is typically between

1% and 3% of the incoming feedwater flow. Continuous blowdown thus helps

provide ongoing control of the water impurity levels.

Even with the use of continuous blowdown, some impurities will settle near the

bottom of the drum. It is necessary to occasionally take a larger amount of flow,

blowoff, from the drum to provide additional control of the water impurity level.

The intermittent blowoff connection on the drum is usually located to remove flow

from an area where solid particles tend to settle. Intermittent blowoff connections

are occasionally located in lower evaporator drum, header, or feeder lines where

solid particles may settle. The intermittent blowoff will be a much larger flow rate

than the continuous blowdown flow rate.

4.4.2 Drum level control

During normal operation and startup, it is important to control the drum water level

within the HHWL and LLWL defined previously. In fact, it is preferable to main-

tain it between the HWL and LWL. If a control system fails to maintain the water

between these levels, a costly HRSG trip could occur or excessive carryover of

water droplets could occur, harming steam purity and possibly causing downstream

coil damage.

There are two types of drum level control typically used. Single-element control

is used during startup when the steam flow is less than 30% of maximum flow.

Once the steam flow is high enough, the system will switch to three-element control.

4.4.2.1 Single-element control

Single-element control is the most basic form of drum level control. A single-

element control system is a feedback-only system that uses only the drum level

measurement to adjust the feedwater flow valve. This approach is typically only


used during startup, when steam flow is low (below approximately 25% of the base

load steam flow), but can also be used in the case where there is a failure of a com-

ponent used in three-element control (e.g., loss of a flowmeter).

4.4.2.2 Three-element control

Three-element control adds a feed-forward control loop in an attempt to compensate

for changes or disturbances in steam and feedwater flow by adjusting the control

loop based on a change in volumetric flow rather than simply valve position.

Drum level control is discussed in greater detail in Chapter 14, Operation and

controls.

4.4.3 Startup drum level

During startup, the drum water level is susceptible to swell due to changes in drum

pressure and steam generation. To accommodate this phenomenon and prevent a

CT trip due to HWL, the following philosophy is used.

Before the CT is fired, the startup level is set below the NWL to accommodate

the drum swell that is expected (typically the startup level is approximately 8v(203 mm) below NWL).

Once the CT is fired, the process adds a preceding step to the algorithm. Instead

of simply comparing the startup level (�8v (2203 mm)) with the operator input,

the drum level plus a predefined tracking variable, �3v (275 mm), is also com-

pared with the present set-point.

This effectively holds the set-point at �8v (2203 mm) until the drum level

swells up to approximately �5v (�125 mm). After this threshold the set-point

begins tracking the current drum level with a 3v (75 mm) offset until the set-point

reaches zero (NWL), where the set-point is finally held at zero. At time T1, when

the process variable settles back to zero, the level control valve is permitted to open

and begin controlling to the desired set-point.

The startup set-point of �8v (�203 mm) is based on the expected amount of drum

swell and may be altered from the initial value to meet site-specific startup condi-

tions. The purpose of the �3v (�75 mm) tracking variable is to restrict noise in the

process variable signal from prematurely switching the setpoint to zero. If the noise

in the signal does not come close to 3v, this variable may be changed to an absolute

value less than 3v. If, however, the noise is greater than 3v, changing the variable to

an absolute value greater than 3v must be done with caution; a value greater than an

absolute 3v may force the drum to swell too high, resulting in carryover.

4.5 Specialty steam drums

Much of the previous discussion has focused on design fundamentals and general

operating guidelines for evaporators and their associated steam drums. The typical

arrangement for the HRSG steam drum is to have a single steam drum per pressure


level as shown in Fig. 4.1A. The following section discusses some additional drum

layout scenarios that are available to address specific industry needs.

4.5.1 Multiple drum designs for fast start cycles

As discussed in the introduction, the HRSGs of 2016 are seeing an increased

demand for cycling during operation. In addition to cycling, many combined cycle

power plants are also seeing a requirement to be “fast start” designs. While the defi-

nition of fast start can vary from site to site, fast start designs are typically required

to allow the connected gas turbine to start without the use of any hold points for the

HRSG components to stabilize in temperature.

This is often not possible with a standard single-drum setup. In the high-pressure

system, due to the large diameter of the drum and high pressure within it, a single

drum may be sufficiently thick that hold points on the gas turbine startup would

be required in order to limit the heat input to the HRSG to avoid overstressing the

high-pressure steam drum and other thick HRSG components.

This need can be met by replacing a single steam drum with multiple drums for

the applicable pressure levels. By splitting the volume of one drum between two

drums, each of the multiple steam drums can be significantly reduced in diameter.

The smaller drum diameters, for the same temperature and pressure, can be signifi-

cantly thinner than a single drum. This reduced thickness will allow a faster heat

input ramp, and often can eliminate any need for gas turbine hold points. A single

drum can be split into two, or even more, vessels to reduce the diameter and

thickness as much as possible.

If using multiple drums is not in itself sufficient to reduce the thickness

below the value needed to eliminate gas turbine hold points, the secondary steam

separator assembly described previously can be located outside of the steam drum.

Moving the secondary separator external to the steam drum reduces the volume

required for steam/water separation and further reduces the diameter and thickness

of the steam drum.

Higher-strength materials are an additional option that can be used to reduce

the drum shell thickness. Carbon steel grade SA-516 70 has been a standard

drum shell material for many years due to ready availability and reasonable cost.

However, there are other higher-strength carbon steel materials that can also be

used. These higher-strength materials allow a thinner shell to be used for the same

set of design conditions. Depending on the design specifics and the material chosen,

shell thickness can be reduced by as much as 30%.

4.5.2 Deaerators

Deaerators, when needed, are used to physically remove dissolved oxygen and

carbon dioxide from the condensate/make-up water stream feeding an HRSG.

High levels of oxygen in the HRSG feedwater can cause corrosion and premature

failure of HRSG tubes and other components. Deaerators reduce the oxygen content

to levels low enough to avoid premature corrosion failures.


Deaerators operate on the principle of Henry’s law of partial pressures (the solubil-

ity of any gas dissolved in liquid is directly proportional to the partial pressure of that

gas above the liquid). Thus, the dissolved gases in the feedwater can be removed by

spraying the water into a steam environment in which the partial pressure of the gas is

reduced. The deaerated feedwater eventually flows out of the deaerator into a storage

tank while the oxygen and carbon dioxide are vented to the atmosphere, carried by a

small amount of steam. As a byproduct of this deaeration, the incoming water is

heated to the saturation temperature of the steam.

There are multiple styles of deaerator design but two are predominant within

HRSG systems: integral deaerators and remote deaerators.

4.5.2.1 Integral floating pressure deaerator

An integral deaerator is generally connected to the low-pressure system of the HRSG

and will serve a dual function of providing deaeration and serving as a steam drum

for the low-pressure section of the HRSG. The connected LP evaporator will generate

the steam flow that is used for deaeration. If the plant cycle design has a lower-

pressure steam turbine section, the HRSG will also export LP steam at the pressure

required by the plant operation. If there are cases where the LP evaporator cannot

generate enough steam for deaeration, additional steam from a higher-pressure system

(typically the IP evaporator/drum) can be used to supplement the steam generated in

the LP evaporator. This supplemental steam is known as pegging steam.

In the case where the low-pressure integral deaerator is not used to export steam

to a steam turbine, the pressure can be allowed to float upward and reduce the LP

evaporator heat absorption when there is more heat available in the exhaust stream

than is required to generate steam for deaeration. A general minimum set pressure

for a deaerator is 5 psig, as this allows the maximum range of operation and can

often eliminate the need for pegging steam. However, lower-pressure two-phase

operation increases the velocity and the risk for two-phase FAC. Operation at low

pressures should be carefully reviewed to ensure the connected evaporator coil

is properly designed.

4.5.2.2 Remote deaerator

A remote deaerator is similar in design to an integral deaerator, except it is not

connected to a low-pressure evaporator system of the HRSG. Without a heating

steam source of its own, a remote deaerator will rely on pegging steam from the

HRSG or another source to supply the full amount of steam needed for deaeration.

References

[1] HTRI Design Manual B5.3.2, “Maximum Heat Flux”, January 2011, pp B5.3-1�B5.3-6.

[2] HTRI Design Manual B5.1.3.3, “Maximum Heat Flux in Tubeside Boiling”July 2006,

pp B5.1�B5.13.


[3] J.R. Thome, Post Dryout Heat Transfer, Engineering Data Book III, Wolverine Tube,

Inc, 2007, Chapter 18.

[4] HTRI Design Manual B5.3, “Flow Boiling Inside Tubes”, January 2011, pp B5.3.3-1�B5.3.3-13.

[5] K. Akagawa, in: S. Ishigai (Ed.), Heat Transfer at High Heat Flux”, Steam Power

Engineering � Thermal and Hydraulic Design Principals, Cambridge University Press,

2010, pp. 230�238.

[6] “Boiler Water Quality Requirements and Associated Steam Quality for ICI Boilers”,

American Boiler Manufacturers Association, 2012.

[7] P. Sturla, Oxidation and Deposition Phenomena in Forced Circulating Boilers and

Feedwater Treatment, Fifth National Feedwater Conf, Prague, 1973.


http://refhub.elsevier.com/B978-0-08-101940-5.00004-X/sbref1









5Economizers and feedwater

heatersYuri Rechtman


Chapter outline

5.1 Custom design 825.1.1 Full circuit 82

5.1.2 Half circuit 83

5.2 Standard design 835.2.1 Full circuit 83

5.2.2 Half circuit 84


5.4 Mechanical details 865.4.1 Tube orientation 86

5.4.2 Venting 87

5.4.3 Steaming 87

5.4.4 Corrosion fatigue 88

5.5 Feedwater heaters 895.5.1 Concerns 89

5.5.2 Feedwater heater arrangements 89

5.5.3 Dew point monitoring 93

Reference 94

Two distinctly different approaches to the physical design of an economizer exist in

today’s heat recovery steam generator (HRSG) business. One is driven by design

considerations, another by manufacturing reasons. A custom design allows theoreti-

cal flexibility to satisfy thermal and hydraulic process requirements. A standard

design requires all panels to be the same for ease of manufacturing and utilizes

crossover jumpers to connect panels and build the flow circuitry. This arrangement

often requires more heating surface due to the mix of cross- and counterflow

arrangements. Both custom design and standard design economizers have operated

successfully in HRSGs for over 40 years.



http://dx.doi.org/10.1016/B978-0-08-101940-5.00005-1

5.1 Custom design

A custom designed economizer is shown in Fig. 5.1. The optimal water velocity is

achieved by varying flow circuitries and tube diameters. This design results in the

most effective utilization of heating surface, superior flexibility, and high reliability.

High heating surface efficiency is achieved by using true counterflow arrange-

ment, i.e., the hottest exhaust gas faces the hottest economizer outlet feedwater and

the coldest exhaust gas exits where the feedwater is the coldest.

The two most commonly used arrangements in economizers are full and half

circuit.

5.1.1 Full circuit

Every tube in the inlet tube row is connected to both the inlet and the lower header

as shown in Fig. 5.1. The second row of tubes exits from the same lower header

and carries the entire water flow up. Return bends redirect the feedwater flow up at

the top to the next row of tubes and down to the lower header.

Designs with return bends at the top, as shown in Figs. 5.1 and 5.2, have superior

mechanical flexibility when compared to standard designs where the tubes are

restrained between two headers as described in the next section.

Figure 5.1 Custom designed economizer, full-circuit arrangement.


5.1.2 Half circuit

Every other tube in the inlet row is connected to the inlet header, as shown in

Fig. 5.2. These tubes carry the entire economizer flow into the lower header. All

tubes in the inlet row are connected to the lower header. Half of the lower header

tubes, not connected to the inlet header, carry the entire economizer flow up into

return bends and into the second economizer row. Feedwater makes two passes,

once up and once down within each row.

5.2 Standard design

5.2.1 Full circuit

A typical standard design full circuit economizer is shown in Fig. 5.3.

It has headers at the top and at the bottom of every tube row. Feedwater enters

into one or two full tube rows at the top with jumpers connecting these rows to

following rows at the bottom as shown in Fig. 5.3.

Feedwater velocities could be lower than in the custom design, since the total

flow is distributed to one or two full rows, unless the headers use divider plates so

Figure 5.2 Custom designed economizer, half-circuit arrangement.

83Economizers and feedwater heaters

that the flow can make multiple passes within a row. When water velocities are

low, a vent system is necessary to remove air that is released from the water that

enters the coil.

5.2.2 Half circuit

The feedwater flow entering the economizer, shown in Fig. 5.4, is distributed to

one half of tubes in the inlet row connected at one end of the header. The feedwater

flow crosses over through the lower header to the other half of tubes in the same

row. A divider plate separates the two passes of water flow in the upper header. If

more than two passes of water flow occur in a row of tubes, divider plates are

required in both the upper and the lower headers. The flow out of the tubes at the

bottom of the header converges and flows through the header from one pass to

another. The flow then diverges and enters the tubes in the next pass and flows

upward to the top header. The flow is similar through all rows to the outlet header.

Vents are connected to the ends of the headers.

The principles described above also apply when two rows of tubes are attached

to each upper and lower header.

5.3 Flow distribution

Uniform distribution of the feedwater flow in the tubes is necessary to achieve the

desired thermal performance, provide strong cooling, and maintain uniform tube

temperatures in a row.

Figure 5.3 Standard design, full circuit.


Good flow distribution is dependent on the pressure drop within a coil. The higher

the pressure drop, the better the distribution. Every HRSG manufacturer develops

velocity guidelines for tube side fluid velocity and designs economizer circuitries to

achieve that velocity in their designs.

Feedwater flow distribution in a standard design is not as uniform as in a custom

design due to configuration of the circuitry. Poor flow distribution affects tube wall

temperatures resulting in increased tube stresses, reduced performance, and a poten-

tial for steaming.

Excessive velocities within economizers can result in flow accelerated corrosion

(FAC) issues. Custom designed economizers, shown in Figs. 5.1 and 5.2, have not

had FAC problems.

Figure 5.4 Standard design, half circuit.


Inadequate velocities within economizers can result in severe maldistribution,

which causes uneven heating of tubes leading to reduced performance and mechani-

cal failures.

The converging and diverging water flow encountered as the water leaves a row

of tubes, flows in a header, and enters another row of tubes can make good flow

distribution difficult to achieve.

A typical completed custom designed economizer module is shown in its ship-

ping position in Fig. 5.5.

5.4 Mechanical details

5.4.1 Tube orientation

Economizer tubes are arranged horizontally in a vertical HRSG (exhaust flows verti-

cally) and usually vertically in a horizontal HRSG (exhaust flows horizontally).

Horizontal HRSGs may also have a horizontal tube arrangement. That could occur

when height restrictions are present at the job site, so the width of the HRSG is

greater than its height. For example, a 20 ft W3 10 ft H economizer would have

sixty 10-ft-long vertical tubes per row if a 4-in. tube spacing is used (20 ft3 12 4 4 in.)

while there would only be thirty 20-ft-long tubes if the tubes were horizontal. A horizontal

economizer arrangement in this example would result in a more economical design.

Horizontal tube economizers are easier to vent through the vertical headers.

Figure 5.5 Completed custom designed economizer module in the shipping position.


A vertical tube economizer has a limited capability for circuitry variation due to

the industry standard requirement that each HRSG coil have the ability to be

completely drained. A horizontal economizer has almost an unlimited choice of the

circuitry.

Horizontal economizer tubes in a vertical HRSG, which usually has a long side

and a short side, may run in either direction depending on water velocity needs. For

example, in a district heating application, where the water flow is very high, a large

number of short tubes will have a lower pressure drop than a small number of long

tubes.

5.4.2 Venting

Upper return bends in custom design economizers can get vapor locked, resulting

in reduced or even no flow in several circuits. Economizer performance may signif-

icantly degrade due to vapor locked circuits with no water flow. A minimum tube

side flow must therefore be established for each custom configuration to assure that

water velocity is high enough to clear tubes of any trapped vapor or air.

Standard design economizers have upper headers, but venting from jumper pipes

requires vapor or air to rise to the top of the jumper through buoyancy forces while

water is pumped in to fill the coil. Ends of headers are away from the header nozzle

or jumper connections and could result in trapped vapor or air at these points.

5.4.3 Steaming

Steaming is a phenomenon that can occur at the hot end of any economizer, espe-

cially at startup or during load swings. Steaming can reduce performance by deacti-

vating the heating surface if the steam is not released from the tubes.

Using several up-flow rows of tubes for steam venting is a unique feature of

custom designed economizers. Any steam generated in the hottest rows would flow

up into the steam drum.

Standard designs use a vent connecting the last one or two economizer headers

to the steam drum. The vent may have an automatic valve that can be remotely

opened when steaming conditions exist. This does not help any down-flow tubes

where steam buoyancy forces are countered by flow forces. Once the valves are

closed, there is no provision for venting.

Many users are not comfortable with steaming in economizers. Two simple tech-

niques can be utilized to prevent steaming in economizers:

� The feedwater control valve is usually located at the outlet of the feedwater pump before

the condensate enters the economizer in a typical HRSG arrangement. This control valve

could be located at the outlet instead of the inlet of the economizer. Such an arrangement

could operate at a higher pressure with a saturation temperature that is above the exhaust

gas temperature at the economizer outlet location. Increasing the economizer saturation

temperature above the exhaust gas temperature at the economizer outlet eliminates the

possibility of steaming. Steaming will then occur in the economizer outlet piping at the

feedwater control valve outlet where the pressure is reduced. Feedwater control valves


with cavitational trim are typically provided in order to extend the control valve life. A

safety valve may be required at the economizer outlet piping since the economizer can be

manually isolated by the inlet and the outlet valves. Locating the feedwater control valve

at the economizer outlet costs more than a conventional setup, due to thicker tubes and

headers required for operation at a higher pressure.� A partial water side bypass can eliminate most of the economizer steaming. A certain

percentage of the incoming feedwater, as shown in Fig. 5.6, bypasses the cold end of the

economizer. The outlet feedwater temperature is controlled by the difference between

the saturation temperature in the steam drum that is being fed by the economizer and the

economizer feedwater outlet temperature. The temperature differential is typically set to

less than 5�F, so the economizer does not steam throughout most of the operating modes.

5.4.4 Corrosion fatigue

The Electric Power Research Institute’s Heat Recovery Steam Generator Tube

Failure Manual [1] states that corrosion fatigue is one of the leading causes of

HRSG tube failures. All inlet headers experience some stress because of abrupt

temperature changes when flow is established at startup. Stress and less-than-

optimal water chemistry will lead to corrosion fatigue failures at header

connections.

As can be seen in Fig. 5.4, differential growth between the inlet row and the

following row will create stress at the lower jumper pipes because of the rigidity of

the large bore pipes connecting the rows.

The arrangement shown in Fig. 5.4 has additional stress associated with the tubes

in the down-flow pass within a row being a different temperature than the adjacent

up-flow pass especially at startup. The stress is greatest in the two center tubes

where one has downward flow and the other has hotter upward flow. This stress is

further magnified by the moment created by the tube bends. This additional stress

can be a main contributor to corrosion fatigue in this type design.

Figure 5.6 Partial bypass.


5.5 Feedwater heaters

5.5.1 Concerns

Feedwater heaters are low-pressure and low-temperature economizers. Due to the

low water temperature and the location of the feedwater heater at the cold end of

the HRSG they can be prone to internal and external corrosion concerns. There are

a number of solutions to reduce or eliminate corrosion issues.

� Exhaust from combustion turbines operating on natural gas often contains traces of sulfur

and thus will have a dew point temperature of approximately 140�F. Tubes whose surface

temperatures are below the dew point will experience water condensation, sulfuric acid

formation, and resultant corrosion of tubes. To prevent this, the condensate entering the

feedwater heater should be preheated to a temperature that is equal to or higher than the

dew point temperature. Condensate entering the feedwater heater at an elevated tempera-

ture keeps tube wall temperatures above the dew point effectively eliminating dew point

conditions on the tube surface. The industry accepted minimum condensate inlet tempera-

ture is 140�F.Various methods of condensate preheating to prevent sulfuric acid corrosion in feed-

water heater tubes are utilized in the HRSG industry.� Oxygenated condensate supplied to feedwater heaters exposes tubes to internal corrosion.

A common solution to internal tube corrosion is the use of stainless or duplex stainless

steel tubes.

Several arrangements described below are used in HRSGs to resolve the external

tube corrosion concern in feedwater heaters.

5.5.2 Feedwater heater arrangements

An HRSG with a feedwater heater must satisfy the specified performance require-

ment. Feedwater heaters in different arrangements reviewed here are all designed to

achieve the same performance goal.

� Basic Feedwater Heater

The feedwater heater in Fig. 5.7 is designed to preheat condensate from 95�F to 320�Fwith exhaust gas entering the coil at 365�F and leaving at 185�F. This is a simple arrange-

ment where no consideration is made for sulfur corrosion concerns on the feedwater

heater tube surfaces. The incoming condensate enters the inlet row of tubes without any

preheating. The metal temperature of the inlet tubes in the feedwater heater shown in

Fig. 5.7 with 95�F condensate inlet temperature will be between 105�F and 115�F, whichis well below 140�F. These tubes will corrode in a relatively short time.

� Water Recirculation

One common practice today is to utilize a feedwater heater arrangement with recircu-

lation as shown in Fig. 5.8. Condensate is delivered to the feedwater heater at the same

temperature as in the arrangement in the previous example shown on Fig. 5.7. It is mixed

with a portion of the feedwater heater outlet water that is recirculated back to the inlet

until the mix reaches an acceptable (140�F) feedwater heater tube inlet temperature.

Condensate temperature is monitored at the feedwater heater inlet. A temperature control-

ler adjusts the control valve position at the recirculation pump outlet. The recirculation


pump is sized to provide sufficient flow at maximum HRSG production conditions.

A small percentage of condensate is bypassed from the inlet of the feedwater heater to its

outlet if the maximum recirculation flow the pump can generate is lower than that

required to preheat the condensate to 140�F feedwater heater inlet temperature.

The heat balances for the feedwater heater arrangements shown in Figs. 5.7 and 5.8

are identical. Condensate is delivered at 95�F and leaves the feedwater heater at 320�F.An HRSG equipped with either feedwater heater will produce the same amount of steam.

The advantage of Fig. 5.8’s arrangement is that sulfur dew point conditions are not pres-

ent on the surface of even the coldest tubes of the feedwater heater. The arrangement with

recirculation in Fig. 5.8 requires more heating surface than the basic unit in Fig. 5.7.� External Heat Exchanger

The patented feedwater heater arrangement shown in Fig. 5.9 utilizes an external heat

exchanger instead of a recirculation pump.

95°F320°F

365°F 185°F

Figure 5.7 Basic feedwater heater.

95°F320°F

185°F365°F

Recirculationpump

Figure 5.8 Feedwater Heater (FWHTR) with recirculation.


Condensate enters the cold path of the external heat exchanger (located outside the

HRSG casing) at 95�F and leaves it at 140�F. The preheated condensate enters the coldest

tubes of the feedwater heater at a temperature that is above the sulfur dew point. The cold

end of the feedwater heater is split in two sections parallel to each other and both perpen-

dicular to the exhaust flow. Feedwater is preheated in Coil 1 from 140�F to 185�F and fed

into the hot path of the external heat exchanger for preheating the incoming condensate.

Water from the exchanger’s hot path outlet temperature is fed into Coil 2 of the feedwater

heater at 140�F. Coil 2 outlet flow enters Coil 3 of the feedwater heater for the final

preheating to 320�F, or the temperature required by the process. Conditions for sulfuric

acid formation are eliminated from the exhaust stream, where corrosion may occur, and

moved into the external heat exchanger, where no sulfur is present.

Benefits of the Fig. 5.9 arrangement as compared to feedwater heater arrangement in

the Fig. 5.8 are:� reduced initial cost: less heating surface� reduced operating cost: no pump motor power loss� reduced maintenance cost: no rotating equipment

The feedwater heater energy balance shown in Fig. 5.9 is identical to the energy

balances in Figs. 5.7 and 5.8.� An alternate feedwater heater arrangement with an external heat exchanger that does not

violate the patent utilized in Fig. 5.9 is shown in Fig. 5.10. This arrangement accom-

plishes the same task as the arrangement in Fig. 5.9 except the unit is larger, as the heat-

ing surface efficiency is not as good due to lower-temperature water entering in the

middle of the coil, causing a drop in the exhaust gas temperature for the remainder of the

coil.� High-Efficiency Arrangement

365°F

Coil 3

320°F

95°F

185°F

185°F

140°F

185°F

140°F

Coil 2

Coil 1

Externalheat

exchanger

Figure 5.9 Feedwater Heater (FWHTR) with external heat.


A patented feedwater arrangement shown in Fig. 5.11 can be utilized when

oxygen is present in the incoming condensate and sulfur is present in the fuel. The

oxygen-rich condensate enters the cold side of the external heat exchanger at 95�Fand is preheated to 185�F before entering the deaerator. Deaerated water flows to

the hot side of the external heat exchanger, where it is cooled down to 140�F and

pumped into the cold feedwater heater coil. The outlet flow of that coil is fed to the

hot feedwater heater coil at 230�F for the final preheating to 320�F required by the

process. The feedwater heater evaporator is placed in the split between two sections

of the feedwater heater to generate the required amount of steam for deaeration.

All feedwater heater arrangements shown above satisfy the same process require-

ment of preheating the incoming condensate from 95�F to 320�F. The arrangements

in Figs. 5.8, 5.9, and 5.10 or the arrangement in Fig. 5.11 should be used in HRSGs

with condensate preheating to eliminate cold end corrosion. The arrangements in

Figs. 5.9 and 5.10 provide reliable operation by replacing the recirculation pump

with a heat exchanger. Each arrangement could feed a low-pressure evaporator

operating at 120 psig with the corresponding saturation temperature of 350�F. Thetemperature difference of 30�F between the low-pressure evaporator saturation and

the feedwater heater outlet temperature is required for the deaerating process to

occur when a nondeaerated condensate is introduced to the HRSG in a conventional

arrangement. The arrangement shown in Fig. 5.11 is designed to deaerate the

incoming condensate within the feedwater heater, so that a higher-pressure LP

system (the next pressure level forward in the HRSG) would require no temperature

365°F

320°F 95°F

185°F

140°F

140°FExternalheat

exchanger

185°F

Figure 5.10 Alternate external heat exchanger.


difference between the low-pressure drum saturation and the feedwater heater outlet

temperature. That allows more low-pressure steam to be generated in the low-

pressure system, since a 0�F temperature difference between the economizer outlet

temperature and the drum saturation temperature can be utilized to increase the

HRSG efficiency in a cost-effective manner. The incoming condensate is deaerated

in the integral deaerator, so carbon steel tubes can be used instead of stainless steel

tubes in the feedwater heater, hence the lower cost. Thus the arrangement in

Fig. 5.11 is referred to as the high-efficiency arrangement.

The feedwater heater evaporator drum water can be chemically treated with solid

alkalis, such as phosphates or caustics, reducing the possibility of FAC.

5.5.3 Dew point monitoring

The patented dew point monitor shown in Fig. 5.12 may further improve the HRSG

performance. A conductivity meter is installed outside of the feedwater heater

casing. One wire from the meter is attached to the feedwater heater inlet piping.

The other wire is attached to a clamp that is attached to a tube in the coldest row of

the feedwater heater. There is an electric insulator between the tube and the clamp.

Moisture formed on the insulator bridges the gap between the tube and the clamp

Figure 5.11 High-efficiency feedwater heater.


when the dew point conditions occur. Plant operating personnel can use dew point

monitoring to minimize condensate temperature at the inlet of the feedwater heater

by experiment. The unit could operate with condensate temperature controlled to

130�F or lower instead of 140�F as designed, if no moisture is detected on tubes at

the reduced temperature. The controlled temperature may be adjusted seasonally

depending on the ambient temperature.

Reference

[1] R.B. Dooley, K.J. Shields, S.R. Paterson, T.A. Kuntz, W.P. McNaughton, M. Pearson,

Heat Recovery Steam Generator Tube Failure Manual, 1004503, EPRI, Palo Alto, CA,

2002.

Figure 5.12 Dew Point Temperature Monitor.





6Superheaters and reheatersShaun P. Hennessey


Chapter outline

6.1 Introduction 95

6.2 General description of superheaters 966.2.1 Process steam 96

6.2.2 Power plant steam turbine 97

6.2.3 Steam purity vs various applications 97

6.3 Design types and considerations 976.3.1 Tube External/Outside Heating Surface 97

6.3.2 Staggered/inline 98

6.3.3 Countercurrent/cocurrent/crossflow 98

6.3.4 Headers/jumpers vs upper returns 99

6.3.5 Circuitry 100

6.3.6 Sliding/floating pressure operation 102

6.3.7 Unfired/supplemental fired 103

6.3.8 Bundle support types 104

6.3.9 Tube-to-header connections 105

6.4 Outlet temperature control 1056.4.1 Spraywater desuperheater 106

6.4.2 Steam bypass attemperator 108

6.4.3 Mixing requirements for each 109

6.5 Base load vs fast startup and/or high cycling 109

6.6 Drainability and automation (coils, desuperheater, etc.) 110

6.7 Flow distribution 1106.7.1 Steam side 110

6.7.2 Gas side 111

6.8 Materials 112

6.9 Conclusions 113

6.1 Introduction

The superheater and reheater sections of the heat recovery steam generator (HRSG)

both add sensible heat to steam. The steam may be generated within the HRSG or

can be from another source. Superheaters are used to elevate the temperature



http://dx.doi.org/10.1016/B978-0-08-101940-5.00006-3

of the saturated steam generated in the attached evaporator to the desired level of

superheat above the saturation temperature. Reheaters are similar in that they

elevate the temperature of the entering steam but the steam source is typically the

high-pressure steam turbine exhaust. The pressure losses of the superheater heating

surface, piping, valves, and trim must be included to deliver the steam to the termi-

nal point of supply and/or the receiving device or process at the desired conditions

of temperature and pressure. Steam can be used as the motive fluid for turning a

steam turbine and/or to provide heat to or extract heat from a process. An example

of the latter is the use of steam to remove heat from certain of the gas turbine’s

cooling systems in integrated steam/water cooled gas turbine cycles. Steam is

typically generated in multiple pressure levels within a given HRSG. Each pressure

level can have a specific purpose other than power production and/or be intended

to blend into a steam turbine at the appropriate stage. Steam is required at a nearly

infinite combination of pressures and temperatures, from saturated to highly super-

heated depending on the specific steam consumer. Even saturated steam processes

typically require a small amount of superheat to be added to overcome heat and

pressure losses in the piping between the HRSG and the consumer. The following

discussions provide information toward understanding how superheaters and

reheaters are designed, operate, and fit into the HRSG train.

6.2 General description of superheaters

Superheaters are used to elevate the temperature of steam above its saturation

temperature. The steam typically enters the superheater dry and saturated via

saturated steam piping from the evaporator/steam drum exit to the superheater

inlet header. From there, heat is absorbed from the turbine exhaust gas into the

heating surface and then into the steam, and the steam temperature increases.

At the same time the steam flowing through the heating surface, headers, and

interconnecting piping loses pressure. The heating surface is designed to deliver

the required steam pressure/temperature conditions at the scope of supply terminal

point or at the steam consumer. In general, the pressure loss should be minimized

while maintaining strong cooling of the tubes as the saturation pressure in the

evaporator increases with increasing superheater pressure loss, and the steam flow

then decreases.

6.2.1 Process steam

In process applications, the HRSG generally produces steam at the fixed pressures

of the process steam system headers. Many refineries, for example, utilize steam

systems where several steam producers maintain the header at a constant pressure.

Here the HRSG(s) might produce steam at one or several of these header pressures

depending on the need. The superheaters often have to handle some level of supple-

mental firing to generate additional steam flow but typically the outlet pressure is


fixed over the entire range. These units also tend to function for long periods of

time at relatively stable loads and pressures so that on/off cycling can be a minimal

concern.

6.2.2 Power plant steam turbine

In contrast, HRSGs designed specifically for power generation typically are

designed for maximum efficiency. There are generally multiple pressure levels of

superheated steam generated for use in a steam turbine and/or in cooling streams

for various combustion gas turbine components, and can also include steam

generation for extraction to another process.

6.2.3 Steam purity vs various applications

Required steam purity is generally a function of the consumer of the steam. Steam

turbine suppliers typically require the superheated steam to be of very high purity

to avoid a loss of efficiency due to fouling, erosion, and/or corrosion of the steam

turbine internals. Processes can generally accept steam of lower purity.

6.3 Design types and considerations

Like other components of the HRSG, superheaters and reheaters are fabricated of

tubes, headers, return bends, etc., in the form of tube coils. A coil generally consists

of transverse and longitudinal rows of tubes relative to the turbine exhaust gas flow

as shown in Fig. 6.1.

6.3.1 Tube External/Outside Heating Surface

As discussed in Chapter 3, Fundamentals extended heating surface in the form of

finned tubes is used in HRSGs. In high-pressure superheaters and reheaters the

addition of external finning greatly increases the tube metal temperature. Higher fin

density and/or thicker fins lead to higher tube metal temperatures. Varying the

amount of finning added therefore has a significant impact on the tube material

selections. This allows the tailoring of different alloy materials up to each materi-

al’s maximum temperature for continuous use before stepping to the next higher

grade material. In cases of supplemental firing, the radiant heat flux to the first lon-

gitudinal rows of tubes downstream of the burner can cause a significant increase in

tube metal temperatures. In these cases, it is typical to utilize one or more rows of

bare tubing immediately downstream of the burner to maximize radiant absorption

while minimizing the resulting increase in tube metal temperature. Thereafter it is

typical to find external finning but perhaps at a reduced fin density and fin height,

again to limit tube and fin metal temperatures and required metallurgy.

97Superheaters and reheaters

6.3.2 Staggered/inline

Depending on gas side pressure loss, layout, etc., there can be a benefit with respect

to enhancing turbine exhaust gas flow distribution when using the staggered layout.

At the hot end, where the high-pressure superheaters and reheaters are usually

located, this flow distribution effect can be used to improve turbine exhaust gas

velocity distributions to supplemental firing equipment, catalyst beds, and other

components downstream of the superheater and reheater when required.

6.3.3 Countercurrent/cocurrent/crossflow

The use of the proper flow arrangement is critical to achieve required performance

at minimum cost and maximum reliability. Superheaters and reheaters are no

different in this respect. For optimum heat transfer, the countercurrent arrangement

is preferred. This typically maximizes the effective temperature difference and

therefore minimizes heating surface. Crossflow is generally used for single-row

and single-pass (can be multiple rows in parallel; see Section 6.3.5) coils. Here,

single-pass refers to the working fluid making one pass across the turbine exhaust

gas flow before exiting the gas path for the terminal point or reentering the gas path

at some other location (Fig. 6.2).

Figure 6.1 Typical HRSG sectional elevation indicating a shipping bundle versus an

individual coil.


Cocurrent can be a useful arrangement to minimize temperature excursions and

provide some temperature control by using the natural pinching effect (gas temper-

ature leaving versus steam temperature leaving) at the coil steam outlet. In some

instances, cocurrent arrangement can also be used to optimize metallurgy by plac-

ing the coolest steam with the hottest turbine exhaust gas and the hottest steam in

a cooler turbine exhaust gas zone. Note that a cocurrent arrangement typically

maximizes heating surface and therefore first cost. However, the increase in heat-

ing surface may not be significant if temperature difference between turbine

exhaust gas and steam is substantial (note that in this case the desired “pinching”

effect will be reduced).

6.3.4 Headers/jumpers vs upper returns

Several different typical coil configurations are common in the HRSG industry.

The simplest is a single row of tubes installed into an upper header and a lower

header. Connecting piping then attaches to the nozzles on each header. It is thus

possible to assemble individual single-row panels into a coil with the use of

jumper pipes between the headers. The coil can be drained from the lower

headers. For multiple row coils it is also possible to use return bends between

individual tubes in neighboring rows for the intermediate upper row-to-row

Figure 6.2 Example flow arrangements: (A) countercurrent, (B) cross, (C) cocurrent.


crossovers between the inlet and outlet header connections. It is imperative with

any construction to properly manage internal stresses due to differential thermal

growth from row to row, as well as temperature differences between adjacent

tubes within a row in the coil assembly. This is especially true in high-pressure

superheaters and reheaters located at the hot end of the HRSG. The use of return

bends at the top of intermediate row-to-row connections provides additional

flexibility between adjacent tubes within a row. In turndown cases, for instance,

where greatly reduced steam flows can result in poor distribution through these

hot end tubes, a “starved” hairpin that heats and grows more than its neighbors

will simply lift off its upper support basically stress free. When steam flow

increases and the tube receives better-distributed flow it cools and settles back

onto the upper support with its neighbors.

6.3.5 Circuitry

The steam flow through a coil is directed to follow a predetermined path in each

pass across the turbine exhaust gas that is set by the tube and header arrangements.

Each flow path is referred to as a circuit or parallel path within the tubes in each

pass. Several sample circuitries are shown in Fig. 6.3.

The designer uses a combination of flow circuitry and tube diameter to optimize

performance of the superheater and reheater as well as the other heating surface.

By manipulating these parameters, it is possible to find workable combinations of

tube flow area that satisfy pressure loss requirements and still provide effective

cooling of the tube metal. For example, in the case of the high-pressure system,

pressure loss is important for minimizing pressure part thickness but has a much

smaller impact on steam generation than in lower-pressure systems. Pressure part

thickness is also affected by tube diameter; the smaller the diameter, the thinner the

tube. Thus high-pressure superheaters tend to utilize smaller tube diameters, which

can be further reduced by utilizing multiple-row circuitry. In contrast, reheaters

operate at much lower pressures (pressure of the high-pressure steam turbine

exhaust) but typically at temperatures and mass flows similar to the high-pressure

superheaters. Reheater tubes therefore carry steam of a much lower density (or higher

specific volume) than the high-pressure system. This is compounded by the relatively

high superheat remaining in the cold reheat return from the high-pressure steam

turbine exhaust. Reheater pressure loss should be minimized as the steam turbine

efficiency is sensitive to reheat loop pressure loss. Flowing reheat steam with little

pressure loss requires a significant steam flow area relative to the high-pressure

superheater, for example. This generally forces reheaters to utilize multiple-row

circuitry and larger tube diameters. The intermediate-pressure and low-pressure

system steam outputs are very sensitive to their respective superheater pressure

drops. In combined cycle systems, the intermediate-pressure steam generated is

typically combined with the cold reheat return and sent to the reheater sections

of the HRSG rather than going directly to the steam turbine at the appropriate

stage/admission port. The intermediate-pressure superheaters and low-pressure

superheaters, which are located downstream of the high-pressure evaporator


in most cases, tend to use larger tube diameters to minimize pressure loss.

The intermediate-pressure superheaters add superheat to the intermediate-pressure

steam prior to combining with the cold reheat steam to enter the reheater. This is

to maximize the high-pressure steam generation and overall cycle efficiency.

In Fig. 6.4 this can be seen as the split sections of the intermediate-pressure super-

heater. The intermediate-pressure system of Fig. 6.4 fits into the high-pressure

system of Fig. 6.4 with the hot stage of the intermediate-pressure superheater

located downstream of the high-pressure evaporator.

Location of intermediate-pressure superheaters or low-pressure superheaters

upstream of the high-pressure evaporator is discouraged since steam generation

from these systems lags far behind in time during cold starts. By the time signifi-

cant cooling steam arrives the tubes would be at the temperature of the hot end

exhaust. Even with some prewarming in stages downstream in the turbine exhaust

gas path of the high-pressure evaporator the thermal shock entering the portion in

the hot end would still lead to low cycle fatigue failures.

Figure 6.3 Example flow circuitries: (A) single-/full-row circuitry, (B) multiple-row full

circuit with return bends, (C) multiple-row full circuit with headers and jumper pipes,

(D) double-row circuitry.


6.3.6 Sliding/floating pressure operation

Sliding or floating pressure operation refers to operation of the steam turbine in a

“valves wide open” type configuration allowing the steam turbine inlet pressure to

change up or down with increasing or decreasing steam flow relative to the anchor

pressure in the condenser. This operation can have a significant impact on the

envelope of operating conditions that an individual superheater will experience.

In the case of a 1:1 configuration, i.e., one combustion gas turbine/HRSG to one

steam turbine, the maximum heat input to the system is typically at base load of the

combustion gas turbine yielding the highest steam flows and therefore the highest

pressures at the steam turbine. As the combustion gas turbine load is reduced, the

steam mass flow and therefore pressure fall in tandem. This generally has a small

impact on the design of the HRSG, typically raising the metal temperatures some-

what due to the reduction of steam flow while the turbine exhaust gas temperature

remains high. Moving on to configurations with multiple combustion gas turbine/

HRSGs feeding a single steam turbine (e.g., 2:1, 3:1, etc.), inflow and pressure

increase. The case with all combustion gas turbine/HRSGs operating to generate

the maximum inflow sets the maximum steam flow and therefore pressure to the

steam turbine. As any individual unit is removed from service, the remaining com-

bustion gas turbines can still be operated at base load. This results in maximum

combustion gas turbine heat to each still-operating HRSG but at reduced overall

mass flow and therefore pressure at the common steam turbine. The result is that

each HRSG can generate its maximum steam flow at greatly reduced pressure such

that steam velocities and pressure losses increase substantially.

Figure 6.4 Example HRSG system intermingling (A) HP system breakout, (B) IP system

breakout.


6.3.7 Unfired/supplemental fired

Supplemental firing is generally located in the hot end of the system in order

to minimize emissions and maximize the high pressure and reheat steam flows.

This means that the high-pressure superheaters and reheaters can see greatly

elevated gas temperatures when firing relative to the unfired operating cases.

Since it is usually desirable to maintain the high-pressure superheater and reheater

outlet temperatures (main steam and hot reheat, respectively) when the burner is

not operating, the tube metal temperatures can greatly increase when firing due to

the increased gas temperature.

6.3.7.1 Burner in inlet duct

Locating the burner in the combustion gas turbine exhaust and firing directly into

the high-pressure superheater and/or reheater results in a large additional heat flow

to the high-pressure superheaters and/or reheaters. The temperature of the turbine

exhaust gas can be raised from the unfired 1100�1200�F typical of today’s

machines up to 1600�1800�F, resulting in a temperature increase of 400�600�F to

the hottest superheater rows. If the steam temperature is to be maintained at the ter-

minal point some form of steam temperature control will be required (see

Section 6.4). If these temperatures and the requisite metallurgy to accommodate

them result in cost-prohibitive results, there are two major options to consider.

6.3.7.2 Split superheater/reheater

The optimum solution for a wide range of supplemental firing coupled with today’s

elevated high-pressure main steam and hot reheat temperatures is to split the high--

pressure superheater and reheater and place the burner in the resulting cavity to

reduce the outlet steam temperature when firing, provide a relatively flat steam tem-

perature profile across the firing range, and avoid the need to use high-alloy materials

(mainly austenitic stainless steels). Lower alloy, 9�12% chrome type materials are

usually then adequate. It is often desirable to have some steam temperature control so

that the outlet temperatures can still be met as the ambient temperature is increased.

6.3.7.3 Screen evaporator

A second solution is to attempt to locate a screen boiler (evaporator) section

between the burner and the high-pressure superheater and reheater surface to reduce

the radiant heat flux and the bulk turbine exhaust gas temperature prior to entering

the superheater/reheater surface. The major limitation to this type of configuration

is that any attempt to reduce the turbine exhaust gas temperature in the fired case

and limit the superheater outlet steam temperatures generally results in the unfired

case steam temperature being also reduced due to the similarly reduced turbine

exhaust gas temperature there. There is usually insufficient heat in the unfired

hot end to allow a sufficiently sized screen boiler to be placed upstream of the

superheaters for the fired operation and still meet the required unfired steam outlet


temperature. A combination of screen evaporator and split superheater design is

useful in some cases.

6.3.7.4 Supplemental firing at combustion gas turbine part load

It is most common for supplemental firing to be used only at base load of the com-

bustion gas turbine. In some applications, such as certain process steam generators,

it can be desirable to maintain steam production but minimize power production

by operating the combustion gas turbine at a reduced load. As the combustion gas

turbine load decreases, the turbine exhaust gas temperature remains high, while the

turbine exhaust gas flow decreases. This combination drives the steam flow down

due to the decreasing turbine exhaust gas flow. The steam temperature will increase

at an accelerated rate due to the high turbine exhaust gas temperature coupled with

the decreased steam flow. Add supplemental firing to this mix, especially in the

inlet duct, and the steam temperatures can run away from the desired value quickly.

If supplemental firing at part loads of the combustion gas turbine is desired, it is

imperative to incorporate this in the initial design of the HRSG.

6.3.7.5 Supplemental firing impact downstream of thehigh-pressure evaporator

Downstream of the high-pressure evaporator, there can also be significant impacts

due to supplemental firing. In highly fired systems, the intermediate pressure

superheaters can have little to no cooling steam flow and will soak to the local

turbine exhaust gas temperature at their locations. As the supplemental firing is

later reduced the intermediate pressure steam flow will return.

Similarly, if the low-pressure steam drum/low-pressure evaporator is the source

of the high-pressure and intermediate-pressure boiler feedpump suction and/or

incorporates a deaerator function, then in heavily fired systems the heating require-

ments for the fired combined high-pressure and intermediate-pressure feedwater

flow can exceed the heat contained in the generated low-pressure steam and

the low-pressure system will bottle up (not generate or export steam). As with the

intermediate-pressure system, as the supplemental firing is later reduced the low--

pressure steam flow returns once again.

6.3.8 Bundle support types

Superheaters and reheaters in horizontal gas flow, natural circulation HRSGs are

generally top supported, allowing them to grow thermally down, freely hanging in

tension. An alternative bottom-supported design with the superheater/reheater tubes

growing vertically up in compression and carrying the additional load of piping,

etc., at the top of the unit is possible but is uncommon due to the additional stresses

imposed on the bottom-supported tubes. Even for the vertical top-supported tubes

in a multirow coil configuration it is necessary to maintain good coil flexibility

between the inlet and outlet headers.


6.3.9 Tube-to-header connections

The high-pressure superheater/reheater surfaces at the hot end of the HRSG are

exposed to very large temperature gradients during transient operations such

as startup, load changes, and shutdowns. For this reason, the tube-to-header

connections in this part of the system are critical. Practical steps to minimize the

introduction of additional stress include (1) eliminating bends in the tubes near

the header as these increase stress due to the moment generated near the bend;

(2) using tube-to-header connections, which provide the best reinforcement of the

header at the connection; and (3) using the best inspection practices to minimize

header thicknesses due to the connection. Hillside tube-to-header connections as

shown on Fig. 6.5 can be used to minimize the impact of tube bends. The tube-to-

header joint requires a high-quality weld.

6.4 Outlet temperature control

HRSGs respond to changes in the energy contained in the turbine exhaust gas.

The gas turbine is a constant volume machine so turbine exhaust flow decreases

and temperature increases with increasing ambient temperature. The high-pressure

superheater/reheater portion of the system will respond to these differences by

providing in general higher steam flows at lower steam temperatures on cold days

and lower steam flows at higher steam temperatures on hot days. The steam temper-

ature could thus exceed requirements on a hot day. To prevent this occurrence, the

high-pressure superheater/reheater portions of HRSGs are provided with one of two

types of outlet steam temperature control mechanisms: spraywater desuperheaters

and steam bypass attemperators. If the steam outlet temperature control is lost the

Figure 6.5 Example of Hillside stubs on a reheater header.


combustion gas turbine may trip or be forced to operate at reduced load until

the steam outlet temperatures are acceptable.

6.4.1 Spraywater desuperheater

The basic function of a spraywater desuperheater is to atomize liquid water into a

superheated steam line such that the heat required to evaporate and superheat the

water is taken from the incoming superheated steam. The result is a blended steam

temperature at the outlet equal to the desuperheater’s outlet steam temperature

control set-point. There are many types of spraywater desuperheaters utilizing

single or multiple atomizing nozzles. A few typical desuperheaters are shown

in Fig. 6.6.

Desuperheaters operate under severe conditions with the spray nozzles seeing

temperature differences of several hundred degrees—full local steam temperature

when not spraying to perhaps a few hundred degrees of subcooling when spraying.

In its simplest form the spraywater desuperheater is located on the superheater

outlet as a “terminal point desuperheater” and controls the final steam temperature

to the desired level. There is the remote possibility of water induction into the

steam turbine or process due to unevaporated spraywater. Many codes and stan-

dards contain requirements intended to prevent the induction of liquid water into a

steam turbine so that this “terminal point spraywater desuperheater” can be an

acceptable option. However, many owners and steam turbine suppliers still prefer

Figure 6.6 Examples of ring type and insertion type desuperheaters. Both utilize separate

spraywater control valves.


to use an alternate configuration with the spraywater desuperheater located between

two superheater coils or stages typically referred to as an “interstage spraywater

desuperheater.”

6.4.1.1 Interstage

An interstage spraywater desuperheater is simply a spraywater desuperheater located

in the piping between two stages of superheater heating surface. The set-point

temperature measurement, which is typically located at the HRSG outlet, is thus far

downstream from the interstage spraywater injection point. The perceived advan-

tage of the interstage location is that any unevaporated spraywater must be heated

as it passes through the heating surface downstream of the desuperheater thereby

making the chance of liquid water being inducted into the steam turbine or

process negligible. When an interstage desuperheater is used, the heating surface

absorbs additional heat and thus uses additional spraywater flow relative to the

terminal point desuperheater. Steam purity can suffer if the spraywater purity is

not comparable to that of the steam. In cases where the steam flow is small

compared to normal operation, for example during startup and/or low load

operation, the interstage desuperheater may not be able to supply enough water to

overcome the very high heat absorption of the superheater or reheater. In these

instances, the spraywater flow is typically limited to maintain a minimum amount

of remaining superheat in the mixed steam conditions immediately downstream

of the desuperheater and the spraywater is generally locked closed until some

minimum percentage of normal operating steam flow is achieved to ensure

sufficient velocity to carry the atomized spraywater. To overcome this, it is

necessary in those affected modes to either limit the turbine exhaust gas tempera-

ture for steam temperature control, or provide an additional “terminal point

desuperheater.”

6.4.1.2 Water source vs steam purity

The source and purity of the spraywater can have an impact on final steam purity.

In process units the feedwater can be very impure. Controlling the temperature of

very clean steam with atomized impure water is counterproductive. If spraywater

of sufficient purity cannot be ensured and maintained, one possible solution has

been referred to as a “sweetwater condenser desuperheater.” Here a portion of the

clean steam generated in the HRSG is condensed and pumped into the spraywater

desuperheater as the spraywater source. Since the condensate is created from clean

steam, the purity should be the same as the generated steam and therefore have no

negative impact on the final steam purity. In most HRSGs currently used in

combined cycle power generation, the feedwater purity is excellent since it results

from nearly 100% recycled condensate from the steam turbine. Typically, there is a

very small amount of demineralized makeup water due to blowdown, leaks, etc.

This potential source of steam purity issues is thus generally mitigated in today’s

combined cycle HRSGs.


6.4.2 Steam bypass attemperator

One of the highest-frequency causes of high-pressure superheater/reheater pressure

part failures is improper use and/or control of spraywater desuperheaters. Spraying

typically highly subcooled liquid water into high-temperature steam contained

in high-temperature metal pressure parts provides multiple opportunities for high

stresses, component failures, and sufficient reason to consider options. An alterna-

tive type of steam temperature control is the steam bypass attemperator. In its most

common form, a portion of the incoming stream is bypassed around the heating

surface in a single-valve bypass arrangement and is then blended at the outlet with

the portion of the steam that was heated by flowing through the heating surface.

See Fig. 6.7.

The blended steam temperature is controlled to the desired set-point. Since no

additional fluid (i.e., subcooled water) is being added and evaporated there is a

performance gain in operating modes requiring temperature control. No heat is lost

from the high-temperature portion of the system (hot end high-pressure superheater/

reheater area) to perform low-grade heating of desuperheater liquid. In fact,

since some of the high-pressure superheater/reheater steam flow is bypassed, tighter

pinches are created and the heating surface efficiency is decreased thus decreasing

heat absorption. The result of these changes is that more heat is available to the

high-pressure evaporator to raise steam thereby raising the performance of

the entire process. This is a relatively small but real performance gain in the high--

pressure superheater. In the reheater, however, evaporating a mass unit of spray-

water results in a nearly one-to-one mass unit loss of HP steam flow since the water

is evaporated in the reheater (after the HP steam is expanded in the steam turbine)

upstream in the turbine exhaust gas flow of the high-pressure evaporator outlet

pinch. Thus using the steam bypass attemperator in the reheater represents the

Figure 6.7 Highlighted is the reheater steam bypass attemperator piping and control valve.


majority of the performance gain in modes requiring steam temperature control.

Fortunately, utilizing steam bypass attemperation in the reheater is generally

practical to accomplish.

Intermediate-pressure superheaters and low-pressure superheaters do not generally

require steam temperature control since they are located downstream of the high--

pressure evaporator pinch and the typically tight temperature pinches on all

the surfaces in the colder portions of the system keep the intermediate-pressure and

low-pressure steam temperatures from increasing beyond the desired range.

However, when intermediate-pressure and/or low-pressure steam outlet temperature

control is necessary the preferred method is the steam bypass attemperator.

6.4.3 Mixing requirements for each

The manufacturer of a spraywater desuperheater should determine the amount of

piping required for full evaporation of the atomized spraywater flow. A good rule

of thumb is 10 pipe diameters. For steam bypass attemperation the mixing distance

is a function of the relative heated and bypass steam flows and conditions, the

piping geometry approaching and leaving the mixing point, etc. Here also a good

rule of thumb is 10 diameters for good mixing.

6.5 Base load vs fast startup and/or high cycling

When considering the arrangement and details to utilize in the design of a high-

pressure superheater/reheater it is of primary importance to understand the cyclic

nature of the anticipated service. Cyclic operation can generate a large number

of significant temperature and/or pressure cycles in a relatively short time with a

tremendous impact on the design and/or the life cycle of the HRSG.

This is particularly important in the high-pressure superheaters and reheaters,

high-energy piping, and the high-pressure steam drum.

Superheaters and reheaters must withstand large thermal gradients generated by

absorbing large amounts of energy quickly without generating low cycle fatigue

failures. The components in the high-pressure superheaters and reheaters must be

particularly flexible to minimize stresses due to these severe operating modes. As

discussed earlier the overall temperature rise within a given high-pressure super-

heater/reheater coil can be several hundred degrees, yielding row-to-row tempera-

ture differentials over 100�F. Solutions to minimize stresses and provide flexibility

are described in Chapter 10, Mechanical design and Chapter 11, Fast start and tran-

sient operation. For multirow high-pressure superheaters/reheaters, row-to-row dif-

ferential growths due to the temperature differences can lead to high internal coil

stresses if both the inlet and outlet headers are fixed points. One possible remedy is

to fix one header and allow the other to move on spring-can supports. Stresses can

also occur due to inadequate flexibility in external piping connected to the headers.

Pressure part thicknesses should be minimized for highly cyclic units. The thickest


pressure parts in a typical HRSG tend to be the high-pressure superheater and

reheater coil headers, the high-energy piping, and the high-pressure steam drum.

Proper material selection is critical for tubes and piping. Header thicknesses can be

minimized with proper material selection and the utilization of multiple nozzles to

minimize header diameters.

6.6 Drainability and automation (coils, desuperheater, etc.)

ASME Section I Code requires automated draining of high-pressure superheaters/

reheaters. Draining of these components during operation as well as during shut-

down and restart is very important to prevent quench cooling of the lower headers

and drains and/or poor steam flow distribution as discussed in the next section.

There are many ways to control this drain automation. Some typical configurations

are presented in Fig. 6.8.

6.7 Flow distribution

6.7.1 Steam side

Good steam side flow distribution in the tubes of the high-pressure superheater/

reheater is critical to properly cool the metal pressure parts. Flow distribution is

Figure 6.8 Various drain condensate level sensing methods.


a function of the flow area within the headers and the pressure loss in the tubes

between the headers. Larger header diameters and/or higher tubeside pressure

loss create better distribution. There is a balance to be considered between the

minimum pressure loss to create proper flow distribution and the impact of

that pressure loss on the potential steam generation as discussed earlier.

Additional concerns arise in supplemental fired HRSGs with all or portions of the

high-pressure superheater/reheater downstream of the burner. Here it becomes

necessary to consider the impact of the flame/heat distribution in addition to

the steam distribution based on header and pressure loss impacts. If the flame

distribution is not adequate uneven heating will occur and portions of the high-

pressure superheater/reheater face area will be heated to levels higher than

accounted for in the design process. Duct burners as described in Chapter 7,

Duct burners are generally one of two configurations: fuel element runners that

traverse the entire gas path or cylindrical cans (somewhat similar in form to regis-

ter burners) that contain fuel nozzles in their center and typically fire directly

downstream. These effects can often be seen in differential steam temperatures at

the downstream coil exit nozzles especially if multiple outlet nozzles exist on the

same tube coil. The runner style lends itself to more even heat input across

the coil face by arranging the burner element axis normal to the axis of the down-

stream tubes. In this way all the tubes see an even heat input if the fuel distribu-

tion is correct. Burners of the cylindrical can style can result in relatively uneven

temperature distributions. Great care must be taken to have sufficient coverage of

the overall duct area to avoid serious issues in the downstream high-pressure

superheater/reheater heating surface. Uneven heating of the turbine exhaust gas

can lead to large temperature imbalances across the high-pressure superheater/

reheater coil face resulting in significant differential thermal growth between

heating surface tubes connected to common upper and lower headers. This can

result in low and/or high cycle fatigue issues depending on the magnitude of

the differential growth. Local overheating can lead to catastrophic damage to the

downstream high-pressure superheater and reheater.

6.7.2 Gas side

Turbine exhaust gas distribution coming from the combustion gas turbine is gener-

ally highly nonuniform and varies with the type of combustion gas turbine model.

Peak velocities can be as high as 600 ft/s and pressure pulsations can be 60-in.

W.C. or more. Axial machine swirl can make the turbine exhaust gas profile equiv-

alent to containing a 1000�1200�F3 F2�F5 tornado. Significant reinforcement

in first heating surface in the gas path is often required. The turbine exhaust gas

flow distribution can be improved by flow distribution devices such as a distribu-

tion grid, “egg crate” baffles, etc., as described in Chapter 12, Miscellaneous

ancillary equipment. These devices first must be designed to survive the already

noted severe service. They also generally contribute to the turbine exhaust gas

pressure loss/combustion gas turbine backpressure. As the flow passes through the

heating surface, areas of higher temperature transfer more heat due to the larger


temperature difference and the fact that cooler areas transfer less heat. The tempera-

ture peaks and valleys smooth very quickly over the first row(s) of the heating

surface. The mass flow deviations are more severe. As the flow approaches the

face of the first heating surface (or distribution grid) it sees the backpressure of

the entire remainder of the HRSG gas path. The effect is to force the turbine

exhaust gas flow to distribute from high-velocity areas toward low-velocity areas.

Since there is very little vertical or side/side distribution within the heating surface

due to the close tube spacings, acoustic baffles, and vibration supports, the flow

distribution within the coil at the outlet row is very similar to the inlet distribution.

Thus there will be small penalties on both heat transfer in the low-velocity areas

and pressure loss in the high-velocity areas. As mentioned previously the structural/

mechanical design in the first hot end coil/bundle is a major challenge. Solutions

such as additional vibration supports, installing coil bumpers upstream and down-

stream of the first bundle/module, or tying the first two bundles together with field

installed bracing have been required at various times.

6.8 Materials

In general, intermediate- and low-pressure superheaters are located downstream of

the high-pressure evaporator in the turbine exhaust gas path where turbine exhaust

gas temperatures cannot exceed material temperature limits for these typically

carbon steel components. Design conditions for pressure, temperature, and resulting

pressure part thicknesses can still be exceeded in some instances and should be

monitored carefully.

High-pressure superheaters and reheaters at the hot end of a HRSG utilize low-

alloy materials with increasing chrome content from T11 through T22/T23, and up

to T91/T92 material. Oxidation resistance increases as does the cost. A step toward

austenitic stainless steel has generally been made with materials such as 304H,

Super 304H, 321H, 347H, etc. These austenitic materials are generally able to cover

the maximum range of pressure and temperature being used in HRSGs today and

for the foreseeable future. It is common to find rows of T11, T22, and T91 tubes all

within the same high-pressure superheater/reheater. This is to minimize costs and

provide adequate oxidation resistance for the life of the HRSG. In some recent units

the use of austenitic stainless at the hottest rows of both the high-pressure super-

heater and reheater has been required for both turbine exhaust gas side and steam

side oxidation resistance. Fin material selection is based on oxidation resistance at

the calculated fin tip temperature and compatibility of thermal growth of fin mate-

rial with that of the tube material. If the fin material is not close in thermal growth

to that of the tube material the fin material must be changed to be compatible while

still meeting the required oxidation temperature limits. In general, for high-pressure

superheaters/reheaters in the hot end this means that 300 series fin material must be

used with 300 series tube materials. Fins on the lower-alloy T11, T22, and T91/T92

tubes can generally be available as ferritic and ferritic stainless materials such as


409 stainless steel or a strip of the same material as the base tube. If a proper com-

bination of tube and fin materials cannot be achieved, then the fin is likely too hot

and the fin geometry is adjusted to be shorter and/or thicker to compensate until an

appropriate material combination can be achieved.

6.9 Conclusions

Superheaters and reheaters are complex mixtures of mechanical, structural, and

thermal engineering opportunities. With proper consideration of fundamentals and

good detailed designs it is possible to meet the current and future demanding chal-

lenges of daily start/stop operation, highly cyclic service, and fast startup

requirements.



7Duct burnersPeter F. Barry, Stephen L. Somers†, Stephen B. Londerville1,

Kenneth Ahn1 and Kevin Anderson1

1John Zink Company, LLC, Hayward, CA, United States

Chapter outline


7.2 Applications 1167.2.1 Cogeneration 116

7.2.2 Combined cycle 117

7.2.3 Air heating 117

7.2.4 Fume incineration 118

7.2.5 Stack gas reheat 118

7.3 Burner technology 1187.3.1 In-duct or inline configuration 118

7.3.2 Grid configuration (gas firing) 118

7.3.3 Grid configuration (liquid firing) 119

7.4 Fuels 1217.4.1 Natural gas 121

7.5 Combustion air and turbine exhaust gas 1227.5.1 Temperature and composition 122

7.5.2 Turbine power augmentation 122

7.5.3 Velocity and distribution 123

7.5.4 Ambient air firing (air-only systems and HRSG backup) 124

7.5.5 Augmenting air 125

7.5.6 Equipment configuration and TEG/combustion airflow straightening 126

7.6 Physical modeling 1277.6.1 CFD modeling 127

7.7 Emissions 1317.7.1 Visible plumes 132

7.7.2 NOx and NO versus NO2 132

7.7.3 CO, UBHC, SOx, and particulates 134

7.8 Maintenance 1387.8.1 Accessories 138

7.9 Design guidelines and codes 1437.9.1 NFPA 8506 (National Fire Protection Association) 143

7.9.2 Factory mutual 143

7.9.3 Underwriters’ laboratories 143

7.9.4 ANSI B31.1 and B31.3 (American National Standards Institute) 144

7.9.5 Others 144

References 144



http://dx.doi.org/10.1016/B978-0-08-101940-5.00007-5

7.1 Introduction

Linear and in-duct burners were used for many years to heat air in drying operations

before their general use in cogeneration and combined cycle systems. Some of the

earliest systems premixed fuel and air in an often-complicated configuration that

fired into a recirculating process airstream. The first use was in high-temperature,

depleted oxygen streams downstream of gas turbines, in the early 1960s, to provide

additional steam for process use in industrial applications and for electrical peaking

plants operating steam turbines. As gas turbines have become larger and more

efficient, duct burner supplemental heat input has increased correspondingly.

Linear burners are applied where it is desired to spread heat uniformly across a

duct, whether in ambient air or oxygen-depleted streams. In-duct designs are more

commonly used in fluidized bed boilers and small cogeneration systems.

7.2 Applications

7.2.1 Cogeneration

Cogeneration implies simultaneous production of two or more forms of energy, most

commonly electrical (electric power), thermal (steam, heat transfer fluid, or hot water),

and pressure (compressor). The basic process involves combustion of fossil fuel in an

engine (reciprocating or turbine) that drives an electric generator, coupled with a

recovery device that converts heat from the engine exhaust into a usable energy form.

Production of recovered energy can be increased independently of the engine through

supplementary firing provided by a special type of burner known as a duct burner.

Most modern systems will also include flue gas emission control devices.

Reciprocating engines (typically diesel cycle) are used in smaller systems

(10 MW5 343 106 Btu/h and lower) and offer the advantage of lower capital and

maintenance costs, but produce relatively high levels of pollutants. Turbine engines

are used in both small and large systems (3 MW5 103 106 Btu/h and above) and,

although more expensive, generally emit lower levels of air pollutants.

Fossil fuels used in cogeneration systems can consist of almost any liquid or

gaseous hydrocarbon, although natural gas and various commercial-grade fuel oils

are most commonly used. Mixtures of hydrocarbon gases and hydrogen found

in plant fuel systems are often used in refining and petrochemical applications.

Duct burners are capable of firing all fuels suitable for the engine/turbine, as well

as many that are not, including heavy oils and waste gases.

Supplementary firing is often incorporated into the boiler/heat recovery steam

generator (HRSG) design as it allows increased production of steam as demanded

by the process. The device that provides the supplementary firing is a duct burner,

so called because it is installed in the duct connecting the engine/turbine exhaust

to the heat recovery device, or just downstream of a section of the HRSG super-

heater. Oxygen required for the combustion process is provided by the turbine

exhaust gas (TEG).


7.2.2 Combined cycle

Combined cycle systems incorporate all components of the simple cycle configu-

ration with the addition of a steam turbine/generator set powered by the HRSG.

This arrangement is attractive when the plant cannot be located near an economi-

cally viable steam user. Also, when used in conjunction with a duct burner,

the steam turbine/generator can provide additional power during periods of high

or “peak” demand.

7.2.3 Air heating

Duct burners are suitable for a wide variety of direct-fired air heating applications

where the physical arrangement requires mounting inside a duct, and particularly

for processes where the combustion air is at an elevated temperature and/or contains

less than 21% oxygen. Examples include

� Fluidized bed boilers (see Fig. 7.1): where burners are installed in combustion air ducts

and used only to provide heat to the bed during startup. At cold conditions, the burner is

fired at maximum capacity with fresh ambient air; but as combustion develops in the bed,

cross exchange with hot stack gas increases the air temperature and velocity. Burners are

shut off when the desired air preheat is reached and the bed can sustain combustion

unaided.� Combustion air blower inlet preheaters: where burners are mounted upstream of a

blower inlet to protect against thermal shock caused by ambient air in extremely cold

climates (240�F/�C and below). This arrangement is only suitable when the air will

be used in a combustion process as it will contain combustion products from the

duct burner.� Drying applications: where isolation of combustion products from the work material

is not required, such as certain paper and wallboard manufacturing operations.

Figure 7.1 Fluidized bed startup duct burner.

Source: Londerville, Stephen; Baukal Jr., Charles E. (Eds.), The Coen & Hamworthy

Combustion Handbook: Fundamentals for Power, Marine & Industrial Applications, CRC

Press, 2013.

117Duct burners

7.2.4 Fume incineration

Burners are mounted inside ducts or stacks carrying exhaust streams primarily

composed of air with varying concentrations of organic contaminants. Undesirable

components are destroyed, both by an increase in the gas stream bulk temperature

and through contact with localized high temperatures created in the flame envelope.

Particular advantages of the duct burner include higher thermal efficiency as no

outside air is used, lower operating cost as no blower is required, and improved

destruction efficiency resulting from distribution of the flame across the duct

section with grid-type design.

7.2.5 Stack gas reheat

Mounted at or near the base of a stack, heat added by a duct burner will increase

natural draft, possibly eliminating the need for induced draft or eductor fans.

In streams containing a large concentration of water vapor, the additional heat

can also reduce or eliminate potentially corrosive condensation inside the stack.

A source of ambient augmenting combustion air is often added if the stack gas

oxygen concentration is low. This arrangement may also provide a corollary

emissions reduction benefit (see Section 7.7). A discussion on testing duct burner

performance is given in Ref. [1].

7.3 Burner technology

7.3.1 In-duct or inline configuration

Register or axial flow burner designs are adapted for installation inside a duct.

The burner head is oriented such that the flame will be parallel to and coflow

with the air or TEG stream, and the fuel supply piping is fed through the duct

sidewall, turning 90 degrees as it enters the burner (see Fig. 7.2). Depending on

the total firing rate and duct size, one burner may be sufficient, or several may be

arrayed across the duct cross section. Inline burners typically require more air/TEG

pressure drop, produce longer flames, and offer a less uniform heat distribution

than grid-type. On the other hand, they are more flexible in burning liquid fuels,

can be more easily modified to incorporate augmenting air, and sometimes repre-

sent a less expensive option for high firing rates in small ducts without sufficient

room for grid elements.

7.3.2 Grid configuration (gas firing)

A series of linear burner elements that span the duct width are spaced at vertical

intervals to form a grid. Each element is comprised of a fuel manifold pipe fitted

with a series of flame holders (or wings) along its length. Fuel is fed into one end

of the manifold pipe and discharged through discrete multiport tips attached at


intervals along its length, or through holes drilled directly into the pipe. Gas ports

are positioned such that fuel is injected in coflow with the TEG. The wings meter

the TEG or airflow into the flame zone, thus developing eddy currents that

anchor ignition. They also shield the flame in order to maintain suitably high

flame temperatures, thereby preventing excessive flame cooling that might cause

high emissions. Parts exposed to TEG and the flame zone are typically of

high-temperature alloy construction (see Figs. 7.3 and 7.4).

7.3.3 Grid configuration (liquid firing)

As with the gas-fired arrangement, a series of linear burner elements comprised of

a pipe and flame holders (wings) span the duct width. However, instead of multiple

discharge points along the pipe length, liquid fuel is injected downstream of the

element through the duct sidewall, and directed parallel to the flame holders (cross

flow to the TEG). This configuration utilizes the duct cross section for containment

of the flame length, thus allowing a shorter distance between the burner and down-

stream boiler tubes (see Fig. 7.5). The injection device, referred to as a side-fired

oil gun, utilizes a mechanical nozzle supplemented by low-pressure air (2�8 psi)

(14�55 kPa) to break the liquid fuel into small droplets (atomization) that

will vaporize and readily burn. Although most commonly used for light fuels,

Figure 7.2 Inline burner.

Source: Londerville, Stephen; Baukal Jr., Charles E. (Eds.), The Coen & Hamworthy Combustion

Handbook: Fundamentals for Power, Marine & Industrial Applications, CRC Press, 2013.

119Duct burners

TEG flow + Fuel

injectorspud

Flameholder

Fuelsupplyrunner

Figure 7.3 Linear burner elements.



Figure 7.4 Gas flame from a grid burner.



Figure 7.5 Oil flame from a side-fired oil gun.




this arrangement is also suitable for some heavier fuels, where the viscosity can be

lowered by heating. In some cases, high-pressure steam may be required, instead of

low-pressure air, for adequate atomization of heavy fuels.

7.4 Fuels

7.4.1 Natural gas

Natural gas is, by far, the most commonly used fuel because it is readily available

in large volumes throughout much of the industrialized world. Because of its

ubiquity, its combustion characteristics are well understood, and most burner

designs are developed for this fuel.

7.4.1.1 Refinery/chemical plant fuels

Refineries and chemical plants are large consumers of both electrical and steam

power, which makes them ideal candidates for cogeneration. In addition,

these plants maintain extensive fuel systems to supply the various direct and

indirect-fired processes as well as to make the most economical use of residual

products. This latter purpose presents special challenges for duct burners because

the available fuels often contain high concentrations of unsaturated hydrocarbons

with a tendency to condense and/or decompose inside burner piping. The location

of burner elements inside the TEG duct, surrounded by high-temperature gases,

exacerbates the problem. Plugging and failure of injection nozzles can occur, with

a corresponding decrease in online availability and an increase in maintenance

costs.

With appropriate modifications, however, duct burners can function reliably with

most hydrocarbon-based gaseous fuels. Design techniques include insulation of

burner element manifolds, insulation and heat tracing of external headers and pipe

trains, and fuel/steam blending. Steam can also be used to periodically purge the

burner elements of solid deposits before plugging occurs.

7.4.1.2 Low heating value

Byproduct gases produced in various industrial processes, such as blast furnaces,

coke ovens, and flexicokers, or from mature landfills, contain combustible com-

pounds along with significant concentrations of inert components, thus resulting in

relatively low heating values (range of 50�500 Btu/scf5 1.9�19 MJ/m3). These

fuels burn more slowly and at lower temperatures than conventional fuels, and thus

require special design considerations. Fuel pressure is reduced to match its velocity

to flame speed, and some form of shield or “canister” is employed to provide a pro-

tected flame zone with sufficient residence time to promote complete combustion

before the flame is exposed to the quenching effects of TEG.

Other considerations that must be taken into account are moisture content and

particulate loading. High moisture concentration results in condensation within

121Duct burners

the fuel supply system, which in turn produces corrosion and plugging. Pilots and

igniters are particularly susceptible to the effects of moisture because of small

fuel port sizes, small igniter gap tolerance, and the insulation integrity required to

prevent “shorting” of electrical components. A well-designed system might

include a knockout drum to remove liquids and solids, insulation and heat tracing

of piping to prevent or minimize condensation, and low-point drains to remove

condensed liquids. Problems are usually most evident after a prolonged period of

shutdown.

Solid particulates can cause plugging in gas tip ports or other fuel system

components and should therefore be removed to the maximum practical extent.

In general, particle size should be no greater than 25% of the smallest port, and

overall loading should be no greater than 5 ppm by volume (weight).

7.4.1.3 Liquid fuels

In cogeneration applications, duct burners are commonly fired with the same fuel

as the turbine, which is typically limited to light oils such as No. 2 or naphtha.

For other applications, specially modified side-fired guns or an inline design can be

employed to burn heavier oils such as No. 6 and some waste fuels.

7.5 Combustion air and turbine exhaust gas

7.5.1 Temperature and composition

When used for supplementary firing in HRSG cogeneration applications, the

oxygen required for the combustion reaction is provided by the residual in the TEG

instead of a new, external source of air. Because this gas is already at an elevated

temperature, duct burner thermal efficiency can exceed 90% as very little heat is

required to raise the combustion products’ temperature to the final fired tempera-

ture. TEG contains less oxygen than fresh air, typically between 11% and 16% by

volume, which, in conjunction with the TEG temperature, will have a significant

effect on the combustion process. As the oxygen concentration and TEG tempera-

ture become lower, emissions of CO and unburned hydrocarbons (UHCs) occur

more readily, eventually progressing to combustion instability. The effect of low

oxygen concentration can be partially offset by higher temperatures; conversely,

higher oxygen concentrations will partially offset the detrimental effects of low

TEG temperatures. This relationship is depicted graphically in Fig. 7.6. Duct burner

emissions are discussed in more detail elsewhere in this chapter.

7.5.2 Turbine power augmentation

During periods of high electrical demand, various techniques are employed to

increase power output, and most will increase the concentration of water vapor

in TEG. The corresponding effect is a reduction in TEG oxygen concentration


and temperature with consequent effects on duct burner combustion. Depending on the

amount of water vapor used, CO emissions may simply rise, or in extreme cases the

flame may become unstable. The former effect can be addressed with an allowance in

the facility operating permit or by increasing the amount of CO catalyst in systems so

equipped. The latter requires air augmentation, a process whereby fresh air is injected

at a rate sufficient to raise the TEG oxygen concentration to a suitable level.

7.5.3 Velocity and distribution

Regardless of whether TEG or fresh air is used, velocity across flame stabilizers

must be sufficient to promote mixing of the fuel and oxygen, but not so great as

to prevent the flame from anchoring to the burner. Grid-type configurations can

generally operate at velocities ranging from 20 to 90 ft/s or 6 to 27 m/s and pressure

drops of less than 0.5 in. water column. Inline or register burners typically require

velocities of 100�150 ft/s (31�46 m/s) with a pressure drop of 2�6 in. water

column (5�15 mbar).

Grid burners are designed to distribute heat uniformly across the HRSG or boiler

tube bank, and thus require a reasonably uniform distribution of TEG or air to

supply the fuel with oxygen. Inadequate distribution causes localized areas of low

velocity, resulting in poor flame definition along with high emissions of CO and

UHCs. Turbine exhaust flow patterns, combined with rapidly diverging downstream

duct geometry, will almost always produce an unsatisfactory result that must be

corrected by means of a straightening device. Likewise, the manner in which ambi-

ent air is introduced into a duct can also result in flow maldistribution, requiring

TE

G o

xyge

n, %

(vo

l.,w

et)

17Depends on:

Fuel compositionTEG velocity

No augmenting air required

Augmenting air required

11500 1100

TEG temperature, °F

Figure 7.6 Approximate requirement for augmenting air.



Press, 2013.

123Duct burners

some level of correction. Selection and design of flow-straightening devices are

discussed elsewhere in this chapter (see Fig. 7.7).

In instances where bulk TEG or air velocity is lower than required for proper

burner operation, flow straightening alone is not sufficient and it becomes necessary

to restrict a portion of the duct cross section at or near the plane of the burner ele-

ments, thereby increasing the “local” velocity across flame holders. This restriction,

also referred to as blockage, commonly consists of unfired runners or similar shapes

uniformly distributed between the firing runners to reduce the open flow area.

Inline, or register, burners inject fuel in only a few positions (or possibly only one

position) inside the duct, and can therefore be positioned in an area of favorable flow

conditions, assuming the flow profile is known. On the other hand, downstream heat

distribution is less uniform than with grid designs, and flames may be longer.

As with grid-type burners, in some cases, it may be necessary to block portions

of the duct at or just upstream of the burners to force a sufficient quantity of TEG

or air through the burner.

7.5.4 Ambient air firing (air-only systems and HRSG backup)

Velocity and distribution requirements for air systems are similar to those for TEG,

although inlet temperature is not a concern because of the relatively higher oxygen

concentration. As with TEG applications, the burner elements are exposed to the

products of combustion, so material selection must take into account the maximum

expected fired temperature.

Ambient (or fresh) air backup for HRSGs presents special design challenges.

Because of the temperature difference between ambient air and TEG, designing

Figure 7.7 Drawing of a duct burner arrangement.



Press, 2013.


for the same mass flow and fired temperature will result in velocity across

the burner approximately one-third that of the TEG case. If the cold condition

velocity is outside the acceptable range, it will be necessary to add blockage,

as described earlier. Fuel input capacity must also be increased to provide heat

required to raise the air from ambient to the design firing temperature. By far,

the most difficult challenge is related to flow distribution. Regardless of the

manner in which backup air is fed into the duct, a flow profile different

from that produced by the TEG is virtually certain. Flow-straightening devices

can therefore not be optimized for either case, but instead require a compromise

design that provides acceptable results for both. If the two flow patterns are

radically different, it may ultimately be necessary to alter the air injection

arrangement independently of the TEG duct-straightening device.

7.5.5 Augmenting air

As turbines have become more efficient and more work is extracted in the form of,

for example, electricity, the oxygen level available in the TEG continues to get

lower. To some extent, a correspondingly higher TEG temperature provides some

relief for duct burner operation.

In some applications, however, an additional oxygen source may be required

to augment that available in the TEG when the oxygen content in the TEG is not

sufficient for combustion at the available TEG temperature. If the mixture adiabatic

flame temperature is not high enough to sustain a robust flame in the highly

turbulent stream, the flame may become unstable.

The problem can be exacerbated when the turbine manufacturer adds large

quantities of steam or water for NOx control and power augmentation. A corre-

sponding drop in the TEG temperature and oxygen concentration occurs because

of dilution. The TEG temperature is also reduced in installations where the HRSG

manufacturer splits the steam superheater and places tubes upstream of the duct

burner.

With their research and development facilities, manufacturers have defined

the oxygen requirement with respect to TEG temperature and fuel composition,

and are able to quantify the amount of augmenting air required under most

conditions likely to be encountered. It is usually not practical to add enough air

to the turbine exhaust to increase the oxygen content to an adequate level.

Specially designed runners are therefore used to increase the local oxygen

concentration. In cases where augmenting air is required, the flow may be sub-

stantial: from 30% to 100% of the theoretical air required for the supplemental

fuel.

The augmenting air runner of one manufacturer consists of a graduated air

delivery tube parallel to and upstream of the burner runner. It is designed to ensure

a constant velocity of the augmenting air along the length of the tube. Equal distri-

bution of augmenting air across the face of the tube is imperative. The augmenting

air is discharged from the tube into a plenum and passes through a second distribu-

tion grid to further equalize flow. The air passes through perforations in the flame

125Duct burners

holder, where it is intimately mixed with the fuel in the primary combustion zone.

This intimate mixing ensures corresponding low CO and UHC emissions under most

conditions likely to be encountered. Once the decision has been made to supply

augmenting air to a burner, it is an inevitable result of the design that the augmenting

air will be part of the normal operating regime of the combustion runner.

7.5.6 Equipment configuration and TEG/combustion airflowstraightening

The TEG/combustion air velocity profile at the duct burner plane must be within

certain limits to ensure good combustion efficiency; in cogeneration applications,

this is rarely achieved without flow-straightening devices. Even in nonfired config-

urations, it may be necessary to alter the velocity distribution to make efficient use

of the boiler heat transfer surface. Fig. 7.8 shows a comparison of flow variation

with and without flow straightening.

Duct burners are commonly mounted in the TEG duct upstream of the first bank

of heat transfer tubes, or they may be nested in the boiler superheater between

banks of tubes. In the former case, a straightening device would be mounted

just upstream of the burner, while in the latter it is mounted either upstream of the

first tube bank or between the first tube bank and (upstream of) the burner.

Rel

ativ

e el

evat

ion

Comparison of f low variation

98 No f low

distributiondevices

765432198 With f low

distributiongrid

7654321

50 75 100 125 150

Percent flow relative to mean

Figure 7.8 Comparison of flow variation with and without straightening device.



Press, 2013.


Although not very common, some HRSG design configurations utilize two stages

of duct burners with heat transfer tube banks in between, and a flow-straightening

device upstream of the first burner. Such an arrangement is, however, problematic

because the TEG downstream of the first-stage burner may not have the required

combination of oxygen and temperature properties required for proper operation of

the second-stage burner.

Perforated plates that extend across the entire duct cross section are most

commonly used for flow straightening because experience has shown that they are

less prone to mechanical failure than vane-type devices, even though they require a

relatively high pressure drop. The pattern and size of perforations can be varied to

achieve the desired distribution. Vanes can produce comparable results with signifi-

cantly less pressure loss but require substantial structural reinforcement to withstand

the high velocities, turbulence and flow-induced vibration inherent in HRSG

systems. Regardless of the method used, flow pattern complexity—particularly in

TEG applications—usually dictates the use of either physical or computational fluid

dynamic (CFD) modeling for design optimization.

7.6 Physical modeling

TEG/airflow patterns are determined by inlet flow characteristics and duct geometry,

and are subject to both position and time variation. Design of an efficient (low

pressure loss) flow-straightening device is therefore not a trivial exercise, and

manual computational methods are impractical. For this reason, physical models,

commonly 1:6 or 1:10 scale, are constructed, and flow characteristics are analyzed

by flowing air with smoke tracers or water with polymer beads through the model

(see Fig. 7.9).

Although this method produces reliable results, tests conducted at ambient

conditions (known as “cold flow”) are not capable of simulating the buoyant effects

that may occur at elevated temperatures.

7.6.1 CFD modeling

Flow modeling with CFD, using a computer-generated drawing of the inlet duct

geometry, is capable of predicting flow pattern and pressure drop in the turbine

exhaust flow path. The model can account for swirl flow in three dimensions,

accurately predict pressure drop, and subsequently help design a suitable device to

provide uniform flow. The CFD model must be quite detailed to calculate flow

patterns incident and through a perforated grid or tube bank while also keeping the

overall model solution within reasonable computation time. Combustion effects

can be included in the calculations at the cost of increased computation time.

The biggest obstacle to obtaining a good CFD solution is the difficulty in obtaining

good velocity and temperature profiles of the flow exiting the gas turbine.

127Duct burners

CFD simulation has the capability to provide complete information, provided

the aforementioned is true. The issue of validity has been a hot topic for years.

A Department of Energy report [2] has cited CFD to be capable of

1. predicting catastrophic failure

2. qualitative trends and parametric analysis

3. visualization

4. predicting nonreacting gaseous flows

5. quantitative analysis of gas velocity and temperature patterns

6. qualitative analysis of radiation heat transfer

7. flame dynamics and shape

8. effecting geometry changes

9. models of temperature and heat release patterns and qualitative trends associated with

major species

10. integration of detailed burner codes with heating process

For combustion systems, CFD is the only general-purpose simulation model

capable of modeling reacting flows in order to predict emissions, heat transfer,

and other furnace parameters. Fig. 7.10 shows a sample result of CFD modeling

performed on a HRSG inlet duct.

7.6.1.1 Wing geometry: variations

Flame holdersDesign of the flame stabilizer, or flame holder, is critical to the success of supple-

mentary firing. Effective emission control requires that the TEG be metered into

Figure 7.9 Physical model of duct burner system.




the flame zone in the required ratio to create a combustible mixture and ensure that

the combustion products do not escape before the reactions are complete. In

response to new turbine and HRSG design requirements, each duct burner manufac-

turer has proprietary designs developed to provide the desired results.

Basic flame holderIn its basic form, a fuel injection system and a zone for mixing with oxidant are all

that is required for combustion. For application to supplemental firing, the simple

design shown in Fig. 7.11 consists of an internal manifold or “runner,” usually an

alloy pipe with fuel injection orifices spaced along the length. A bluff body plate,

with or without perforations, is attached to the pipe to protect the flame zone from

the turbulence in the exhaust gas duct. The low-pressure zone pulls the flame back

onto the manifold. This low-cost runner may overheat the manifold, causing distor-

tion of the metallic parts. Emissions are unpredictable with changing geometry and

CO is usually much higher than the current typically permitted levels of under

0.1 lb/MMBtu.

Low-emissions designModifications to the design for lower emission performance generally have a larger

cross section in the plane normal to the exhaust flow. The increased blocked area

protects the fuel injection zone and increases residence time. The NOx is reduced

by the oxygen-depleted TEG and the CO/UHC is reduced by the delayed quench-

ing. The correct flow rate of TEG is metered through the orifices in the flame

holder, and the fuel injection velocity and direction are designed to enhance com-

bustion efficiency. The flame zone is pushed away from the internal manifold

(“runner” pipe), creating space for cooling TEG to bathe the runner and flame

holder and enhance equipment life.

Contours of velocity magnitude (ft/s)Through center of duct

Feb 29, 2000Fluent 5.3 (3d, segregated, rke)

Figure 7.10 Sample result of CFD modeling performed on an HRSG inlet duct.

129Duct burners

Each manufacturer approaches the geometry somewhat differently. One manufac-

turer uses cast alloy pieces welded together to provide the required blockage. These

standard pieces often add significant weight and are difficult to customize to specific

applications. Hot burning fuels, such as hydrogen, may not receive the cooling

needed to protect the metal from oxidation. Alternately, fuels subject to cracking,

such as propylene, may not have the oxygen needed to minimize coke buildup.

Another manufacturer supplies custom designs to accommodate velocity

extremes, while maintaining low emissions. In the design shown in Fig. 7.12, the

Flame holder

Fuelsupplyrunner

TEG flow

Drilled pipe

Flame holder

Figure 7.11 Drilled pipe duct burner.



Figure 7.12 Low-emission duct burner.




flame holder is optimized with CFD and research experimentation to enhance mix-

ing and recirculation rate. Special construction materials are easily accommodated.

This supplier also uses removable fuel tips with multiple orifices, which can be

customized to counteract any unexpected TEG flow distribution discovered after

commercial operation. Fig. 7.13 depicts the flow patterns of air/TEG and fuel in

relation to the duct burner flame holder.

7.7 Emissions

Duct burner systems can either increase or reduce emissions from the generally

large volume of mass flow at the input. Generally this flow includes particulates,

NOx, CO, and a variety of HCs including a subset of HCs defined as VOCs

(volatile organic compounds). VOCs are defined by the EPA (40 CFR 51.100,

February 3, 1992) as “any compound of carbon, excluding carbon monoxide,

carbon dioxide, carbonic acid, metallic carbides or ammonium carbonate, which

participates in atmospheric chemical reaction.” Other compounds are also exempt

such as methane, ethane, methylene chloride, methyl chloroform, and other minor

chemicals.

Figure 7.13 Flow patterns around flame stabilizer.



Press, 2013.

131Duct burners

To accurately predict emission, kinetic equations are created using first-order

equations for oxidation in the general form of

d Chemicalð Þdt

5 2K O2½ � Chemical½ � (7.1)

where

K5Ae

2E

RT

� �(7.2)

and

A is the preexponential factor/frequency factor in appropriate units

R is the universal gas constant in appropriate units

T is the absolute temperature in Kelvin

E is the activation energy, usually listed in kcal/mol

7.7.1 Visible plumes

Stack plumes are caused by moisture and impurities in the exhaust. Emitted NO is

colorless and odorless, and NO2 is brownish in color. If the NO2 level in the flue

gas exceeds about 15�20 ppm, the plume will take on a brownish haze. NOx also

reacts with water vapor to form nitrous and nitric acids. Sulfur in the fuel may oxi-

dize to SO3 and condense in the stack effluent, causing a more persistent white

plume.

7.7.2 NOx and NO versus NO2

Formation of NO and NO2 is the subject of ongoing research to understand the

complex reactions. Potentially, several oxides of nitrogen (NOx) can be formed dur-

ing the combustion process, but only nitric oxide (NO) and nitrogen dioxide (NO2)

occur in significant quantities.

In the elevated temperatures found in the flame zone in a typical HRSG turbine

exhaust duct, NO formation is favored almost exclusively over NO2 formation.

Turbine exhaust NOx is typically 95% NO and 5% NO2. In the high-temperature

zone, NO2 dissociates to NO by the mechanism of

NO2 1O1Heat ! NO1O2

However, after the TEG exits the hot zone and enters the cooling zone at the

boiler tubes, reaction slows down and the NO2 is essentially fixed. At the stack out-

let, the entrained NO is slowly oxidized to NO2 through a complex photochemical

reaction with atmospheric oxygen. The plume will be colorless unless the NO2


increases to about 15 ppm, at which time a yellowish tint is visible. Care must be

taken in duct burner design because NO can also be oxidized to NO2 in the

immediate post-flame region by reactions with hydroperoxyl radicals:

NO1HO2 ! NO2 1OH

if the flame is rapidly quenched. This quenching can occur because of the large

quantity of excess TEG commonly present in duct burner applications. Conversion

to NO2 may be even higher at fuel turndown conditions where the flame is smaller

and colder. NO2 formed in this manner can contribute to “brown plume” problems

and may even convert some of the turbine exhaust NO to NO2.

There are two principal mechanisms through which nitrogen oxides are formed:

1. Thermal NOx: The primary method is thermal oxidation of atmospheric nitrogen in the

TEG. NOx formed in this way is called thermal NOx. As the temperature increases in

the combustion zone and surrounding environment, increased amounts of N2 from the

TEG are converted to NO. Thermal NOx formation is most predominant in the peak

temperature zones of the flame.

2. Fuel-bound nitrogen NOx: The secondary method utilized to form NOx is the reaction of

oxygen with chemically bound nitrogen compounds contained in the fuel. NOx formed in

this manner is called fuel NOx. Large amounts of NOx can be formed by fuels that contain

molecularly bound nitrogen (e.g., amines and mercaptans). If a gaseous fuel such as natu-

ral gas contains diluent N2, it simply behaves as atmospheric nitrogen and will form NOx

only if it disassociates in the high-temperature areas. However, if the gaseous fuel

contains, for example, ammonia (NH3), this nitrogen is considered bound. In the low

concentrations typically found in gaseous fuels, the conversion to NOx is close to 100%

and can have a major impact on NOx emissions.

Bound nitrogen in liquid fuel is contained in the long carbon chain molecules.

Distillate oil is the most common oil fired in duct burners as a liquid fuel. The fuel-

bound nitrogen content is usually low, in the range of 0.05 weight percent.

Conversion to NOx is believed to be 80%�90%. For No. 6 oil, containing 0.30

weight percent nitrogen, the conversion rate to NOx would be about 50%. Other

heavy waste oils or waste gases with high concentrations of various nitrogen com-

pounds may add relatively high emissions. Consequently, fuel NOx can be a major

source of nitrogen oxides and may predominate over thermal NOx.

The impact of temperature on NOx production in duct burners is not as

pronounced as in, for example, fired heaters or package boilers. One reason is

that both the bulk fired temperature and the adiabatic flame temperature are lower

than in fired process equipment.

In the formation of NOx, the equations are similar to formation of thermal NOx

and are presented as follows:

dðNOÞdt

5 2Ae2

E

RT

� �ðO2ÞeqðN2Þ (7.3)

133Duct burners

and

ðO2Þeq 5k0

ðRTÞ:5 ðO2Þ:5eq (7.4)

One generally accepted practice is to assume (O2) in equilibrium with (O) and

(O2) concentration using the Westenberg [3] results for k0 for (O2) equilibrium and

Zeldovich constants, A, E, as measured by Bowman [4].

When used to provide supplementary firing of turbine exhaust, duct burners are

generally considered to be “low NOx” burners. Because the turbine exhaust contains

reduced oxygen, the peak flame temperature is reduced and the reaction speed for O2

and N1 to form NOx is thus lowered. The burners also fire into much lower average

bulk temperatures—usually less than 1600�F (870�C)—than process burners or

fired boilers. The high-temperature zones in the duct burner flames are smaller due

to large amounts of flame quenching by the excess TEG. Finally, mixing is rapid and

therefore retention time in the high-temperature zone is very brief.

The same duct burner, when used to heat atmospheric air, is no longer consid-

ered “low NOx,” because the peak flame temperature approaches the adiabatic

flame temperature in air.

Clearly, operating conditions have a major impact on NO formation during

combustion. To properly assess NOx production levels, the overall operating regime

must be considered, including TEG composition, fuel composition, duct firing

temperature, and TEG flow distribution.

7.7.3 CO, UBHC, SOx, and particulates

7.7.3.1 Carbon monoxide

Carbon monoxide (CO), a product of incomplete combustion, has become a major

permitting concern in gas turbine�based combined cycle and cogeneration plants.

Generally, CO emissions from modern industrial and aeroderivative gas turbines

are very low, in the range of a few parts per million (ppm). There are occasional

situations in which CO emissions from the turbine increase due to high rates of

water injection for NOx control or operation at partial load, but the primary concern

is the sometimes-large CO contribution from supplementary firing. The same low-

temperature combustion environment that suppresses NOx formation is obviously

unfavorable for complete oxidation of CO to CO2. Increased CO is produced when

fuels are combusted under fuel-rich conditions or when a flame is quenched before

complete burnout. These conditions (see Fig. 7.14) can occur if there is poor

distribution of TEG to the duct burner, which causes some burner elements to fire

fuel-rich and others to fire fuel-lean, depending on the efficiency of the TEG

distribution device. The factors affecting CO emissions include

� TEG distribution� low TEG approach temperature� low TEG oxygen content


� flame quench on “cold” screen tubes� improperly designed flame holders that allow flame quench by relatively cold TEG� steam or water injection

For utilization, and performance prediction, kinetic data can be utilized from

the literature. For instance, for CO destruction, several kinetic data are available

such as [5]

d CO½ �dt

521:8107e 225; 000

RT

� �COð Þ O2ð Þ:5 H2Oð Þ:5 P

RT

� �2

(7.5)

Most published CO rates involve H2O because CO destruction requires the

(OH)21 radical to produce the reaction.

7.7.3.2 Unburned hydrocarbons

In the same fashion as carbon monoxide generation, UHCs are formed in the exhaust

gas when fuel is burned without sufficient oxygen, or if the flame is quenched before

combustion is complete. UHCs can consist of hydrocarbons (defined as any

carbon�hydrogen molecule) of one carbon or multiple carbon atoms. The multiple

carbon molecules are often referred to as long-chain hydrocarbons. UHCs are

generally classified in two groups:

1. UHCs as methane

2. Nonmethane hydrocarbons or VOCs

The reason for the distinction and greater concern for VOCs is that longer chain

hydrocarbons play a greater role in the formation of photochemical smog. VOCs

are usually defined as molecules of two carbons or greater, and are sometimes

1200

CO emissions aredepressed by higher

oxygen content in theTEG and with lower

(25–75 fps) TEG velocities

0500 1100

TEG temperature, °F

Figure 7.14 Effect of conditions on CO formation.



Press, 2013.

135Duct burners

considered to be three carbons or greater. These definitions are set by local air

quality control boards and vary across the United States.

UHCs can only be eliminated by correct combustion of the fuel. However,

hydrocarbon compounds will always be present in trace quantities, regardless of

how the HRSG system is operated.

For HC and VOC incineration several sources are available such as Barnes [6].

In general,

d CaHbð Þdt

52 5:52 108� �

P20:815Teð12;200Þ

T ðCaHbÞ:5ðO2Þmoles

cm3sec(7.6)

7.7.3.3 Sulfur dioxide

Sulfur dioxide (SO2) is a colorless gas that has a characteristic smell in concentra-

tions as low as 1 ppm. SO2 is formed when sulfur (S) in the fuel combines with

oxygen (O2) in the TEG. If oxygen is present (from excess of combustion) and the

temperature is correct, the sulfur will further combine and be converted to sulfur

trioxide (SO3). These oxides of sulfur are collectively known as SOx.

Except for sulfur compounds present in the incoming particulate matter (PM),

all of the sulfur contained in the fuel is converted to SO2 or SO3. Sulfur dioxide

will pass through the boiler system to eventually form the familiar “acid rain”

unless a gas-side scrubbing plant is installed. Sulfur trioxide can, in the cooler

stages of the gas path, combine with moisture in the exhaust gas to form sulfuric

acid (H2SO4), which is highly corrosive and will be deposited in ducts and the

economizer if the metal or exhaust gas is below condensing temperatures.

Natural gas fuels are fortunately very low in sulfur and do not usually cause a

problem. However, some oil fuels and plant gases can be troublesome in this

respect.

7.7.3.4 Particulate matter

Particulate emissions are formed from three main sources: ash contained in liquid

fuels, unburned carbon in gas or oil, and SO3. The total amount of particulate is

often called TSP (total suspended particulate). There is concern for the smaller

sized portion of the TSP, as this stays suspended in air for a longer period of time.

The PM-10 is the portion of the total PM that is less than 10 μm (13 1026 m)

in size. Particles smaller than PM-10 are on the order of smoke. Typical NOx and

CO emissions for various fuels are shown in Table 7.1.

For particulate oxidation, an equation can be developed from fundamental

principles, utilizing a combination of diffusion of oxygen and surface reactivity as

follows:

dm

dt5 ð12CogApÞ=

�1

km1

1

kr

�(7.7)


where

m is the mass of particle

t is the time

C is the molar density

A is the surface area

km is the diffusion coefficient of oxygen in nitrogen

kr is the reaction coefficient of the form Ae2E/RT,

where A is the frequency factor, E is the activation energy,

R is the universal gas constant, T is the temperature

The equation can be integrated for constant density particles and using particle

tracking in time steps with constant or varying oxygen and temperature. An excel-

lent source of char rate data is available by Smith and Smoot [7].

Then, in all cases, one can postprocess thermal map data in some discrete volume

form and/or insert into a CFD code using the Rayleigh flux theorem as follows:

@

@t

ðcvn ρ dv5

ðcsnρ ðV � daÞ (7.8)

where

n is the chemical in mass units

t is the time

ρ is the density

v is the volume

a is the area

V is the velocity vector

where described in words, the formation of (n) through the volume surface is equal

to the integrated rate of formation over the control volume.

Table 7.1 Typical NOx and CO emissions from duct burners

Gas NOx (lb/106 Btu fired) CO (lb/106 Btu fired)

Natural gas 0.1 0.08

Hydrogen gas 0.15 0.00

Refinery gas 0.1�0.15 0.03�0.08

Plant gas 0.11 0.04�0.01

Flexicoker gas 0.08 0.01

Blast furnace gas 0.03�0.05 0.12

Producer gas 0.05�0.1 0.08

Syn fuels 0.08�0.12 0.08

Propane 0.14 0.14

Butane 0.14 0.14

Note: NOx emissions from butane and propane can be modified by direct steam injection into a gas or burner flame.CO emissions are highly dependent on TEG approach temperature and HRSG fired temperature.Source: Londerville, Stephen; Baukal Jr., Charles E. (Eds.), The Coen & Hamworthy Combustion Handbook:Fundamentals for Power, Marine & Industrial Applications, CRC Press, 2013.

137Duct burners

It is a simple extrapolation to extend this concept for even coarse volumes as

follows:

X dn

dtρΔv5 nρðV � aÞ (7.9)

This method can be very useful for fully mixed downstream products even with

coarse volumes. But one must be careful with coarse volumes to be sure that the

temperature and concentrations are uniform.

7.8 Maintenance

1. Normal wear and tear: If nothing has been replaced in the past five years and the burner

(or turbine/HRSG set) is operated fairly continuously, it is likely that some tips and wings

may require replacement.

2. Damage due to misuse, system upsets, or poor maintenance practices: Older systems

designed without sufficient safety interlocks (TEG trip, high temperature) sometimes expose

parts to excessively high temperatures, which results in wing warpage and oxidation failure.

3. Fuel quality/composition: Some refinery fuels or waste fuels contain unsaturated compo-

nents and/or liquid carryover. Eventually, these compounds will form solids in the runner

pipes or directly in tips, which results in plugging.

The following are some items to consider when operational problems are encountered:

� Plugged gas ports: These are evidenced by gaps in the flame or high fuel pressure. Gas ports

may simply consist of holes drilled into the element manifold pipe, or they may be located in

individual removable tips. Designs of the former type may be redrilled or else the entire

manifold pipe must be replaced. Discrete tips can be replaced individually as required.� Warped flame holders (wings): Some warping is normal and will not affect flame quality,

but excessive deformation such as “curling” around the gas ports will degrade the

combustion and emission performance. Most grid-type burner designs permit replacement

of individual flame holder segments.� Oxidation of flame holders (wings) or portions of flame holders: If more than one-third of

the flame holder is missing, it is a good candidate for replacement. Fabricated and cast

designs are equally prone to oxidation over time. Most grid-type burner designs permit

replacement of individual flame holder segments.� Severe sagging of runner pipes (grid design only): If the manifold pipe is no longer

supported at both ends, it should be replaced. Beyond that relatively extreme condition,

sagging at midspan in excess of approximately 2�3 in. (5�7 cm) should be corrected by

runner replacement and/or installation of an auxiliary support.

7.8.1 Accessories

7.8.1.1 Burner management system

All fuel-burning systems should incorporate controls that provide for safe manual

light-off and shutdown, as well as automatic emergency shutdown upon detection

of critical failures. Control logic may reside in a packaged flame safeguard module,

a series of electromechanical relays, a programmable logic controller (PLC), or a


distributed control system (DCS). At a minimum, the duct burner management

system should include the following:

� flame supervision for each burner element� proof of completed purge and TEG/combustion airflow before ignition can be initiated� proof of pilot flame before main fuel can be activated� automatic fuel cutoff upon detection of flame failure, loss of TEG/combustion air, and

high or low fuel pressure

Other interlocks designed to protect downstream equipment can also be included,

such as high boiler tube temperature or loss of feed water.

7.8.1.2 Fuel train

Fuel flow to the burners is controlled by a series of valves, safety devices, and

interconnecting piping mounted on a structural steel rack or skid. A properly

designed fuel train will include, at a minimum, the following:

� at least one manual block valve� two automatic block valves in series� one vent valve between the automatic block valves (gas firing only)� flow-control valve� high and low fuel pressure switches� two pressure gauges, one each at the fuel inlet and outlet

Depending on the custom and operating requirements at a particular plant, pressure

regulation, flow-measurement devices, and pressure transmitters can also be incorpo-

rated. See Figs. 7.15�7.22 for typical duct burner fuel system piping arrangements.

FM = Flowmeter V1 = Manual shutoff valvePI = Pressure gauge V2 = Pressure regulator (optional)PSH = High pressure interlock V3 = Main burner safety shutoff valvePSL = Low pressure interlock V4 = Main burner shutoff atmospheric vent valve ST = Cleaner or strainer V5 = Main flow control valve

To Ignitionsystem

(see Figure 7.17)

Vent toatmosphere

Vent toatmosphere

V4V1

PI PSLPI

Gassupply

V1ST

V2

FM

V3 V3 V5

PSH PI

To mainburner

Figure 7.15 Typical main gas fuel train: single element or multiple elements firing simultaneously.



139Duct burners

FM = FlowmeterPI = Pressure gaugePSH = High pressure interlockPSL = Low pressure interlockV1 = Manual shutoff valveV2 = Pressure regulator (optional)V3 = Main safety shutoff valve

V4 = Main burner header shutoff atmospheric vent valveV5 = Main flow control valveV6 = Main flow bypass control valve (optional)V7 = Individual burner safety shutoff valveV8 = Main burner header charging atmospheric vent valve (optional)

Vent toatmosphere

Vent toatmosphere

V8

V7

Tomain

burner

Toothermain

burnersTo ignition

system(see Figure 7.18)

V4

(Optionallocation)

PSL

PSH

PSL

PI

PI

FM

V5V3

V6

V3V2V1

Gassupply

Figure 7.16 Typical main gas fuel train: multiple elements with individual firing capability.



Vent toatmosphere

V4

PI

Gassupply

V1 V2 V3 V3

To igniter

PI = Pressure gaugeV1 = Manual shutoff valveV2 = Igniter flow control valveV3 = Igniter safety shutoff valveV4 = Igniter shutoff atmospheric vent valve

Figure 7.17 Typical pilot gas train: single element or multiple elements firing simultaneously.




Vent toatmosphere

Vent toatmosphere

V4 V8

(Optionallocation)

PSL

Toigniter

(typical) PI

V7

Gassupply

V1 V2 V3 V3

PSH

PSL

Toother

igniters(permanently

installed)

PI = Pressure gaugePSH = High pressure interlockPSL = Low pressure interlockV1 = Manual shutoff valveV2 = Igniter flow control valve

V3 = Igniter header safety shutoff valveV4 = Igniter supply atmospheric vent valveV7 = Individual igniter safety shutoff valveV8 = Igniter header atmospheric vent valve (optional)

Figure 7.18 Typical pilot gas train: multiple elements with individual firing capability.



Figure 7.19 Typical main oil fuel train: single element.



V12 V11aTR

Atomizingmediumsupply

Oilsupply

Oilreturn

V1

ST

PI

FM

PSL TSL PSL PI

V13

V5 V7 V9

V9 V10To mainburner

(typical)

ScavengingmediumTo other

mainburners

Steam or air header V9 V11

PIPDS

V3

V6V3a

(Optionallocation)

Figure 7.20 Typical main oil fuel train: multiple elements.



Press, 2013.

Lightoil

supply

ST

V1

PSL PI

V6 V3 V7 V9

To otherigniters

(permanentlyinstalled)

Scavengingmedium

V9 V10

Toigniter

(typical)

PI = Pressure gaugePSL = Low pressure interlockST = Cleaner or strainerV1 = Manual shutoff valveV3 = Igniter safety shutoff valveV6 = Igniter flow control valveV7 = Individual igniter safety shutoffV9 = Check valveV10 = Scavenging valve

Figure 7.21 Typical pilot oil train: single element.



Press, 2013.


7.9 Design guidelines and codes

7.9.1 NFPA 8506 (National Fire Protection Association)

First issued in 1995, this standard has become the de facto guideline for HRSGs in

the United States and many other countries that have not developed their own

national standards. Specific requirements for burner safety systems are included,

but as stated in the foreword, NFPA 8506 does not encompass specific hardware

applications, nor should it be considered a “cookbook” for the design of a safe

system. Prior to the issuance of NFPA 8506, designers often adapted NFPA boiler

standards to HRSGs, which resulted in design inconsistencies.

7.9.2 Factory mutual

An insurance underwriter that publishes guidelines on combustion system design,

Factory Mutual (FM) also “approves” specific components such as valves, pressure

switches, and flame safeguard equipment that meet specific design and performance

standards. Manufacturers are given permission to display the FM symbol on

approved devices. Although FM approval may be required for an entire combustion

control system, it is more common for designers to simply specify the use of

FM-approved components.

7.9.3 Underwriters’ laboratories

Well known in the United States for its certification of a broad range of consumer

and industrial electrical devices, Underwriters’ Laboratories (UL) authorizes

Lightoil

supply

ST

V1

PSL PI

V6 V3 V7 V9

To otherigniters

(permanentlyinstalled)

Scavengingmedium

V9 V10

Toigniter

(typical)

PDS

Steamor air

V12 V9

PI = Pressure gaugePDS = Differential pressure alarm and trip interlockPSL = Low pressure interlockST = Cleaner or strainer

V1 = Manual shutoff valveV3 = Igniter safety shutoff valveV6 = Igniter flow control valveV7 = Individual igniter safety shutoff valveV9 = Check valve

V10 = Scavenging valveV12 = Differential pressure control valve

Figure 7.22 Typical pilot oil train: multiple elements.



143Duct burners

manufacturers to display their label on specific items that have demonstrated

compliance with UL standards. Combustion system designers will frequently

require the use of UL-approved components in burner management systems and

fuel trains. Approval can also be obtained for custom-designed control systems,

although this requirement generally applies only to a few large cities and a few

regions in the United States.

7.9.4 ANSI B31.1 and B31.3 (American NationalStandards Institute)

These codes address piping design and construction. B31.1 is incorporated in the

NFPA 8506 guideline, while B31.3 is generally used only for refining/petrochemical

applications.

7.9.5 Others

The following may also apply to duct burner system designs, depending on the

country where equipment will be operated:

� National Electrical Code (NEC)� Canadian Standards Association (CSA)� International Electrotechnical Commission (IEC)� European Committee for Electrotechnical Standardization (CENELEC)

References

[1] S. Londerville, Performance prediction of duct burner systems via modeling and testing,

Chapter 26, in: C.E. Baukal (Ed.), Industrial Combustion Testing, CRC Press, Boca

Raton, FL, 2011.

[2] Department of Energy, Improving industrial burner designs with computational fluid

dynamic tools: Progress, Needs and R & D priorities, Workshop Report, September 2002.

[3] A.E. Westenberg, Turbulence modeling for CFD, Combust. Sci. Technol. 4 (1971)

59�67.

[4] C.T. Bowman, Kinetics of pollution formation and destruction in combustion, Prog.

Energy Combust. Sci. 1 (1975) 33�45.

[5] G.C. Williams, H.C. Hottel, A.C. Morgan, The combustion of methane in a jet-mixed

reactor, Twelfth Symposium (International) on Combustion, The Combustion Institute,

Pittsburgh, PA, 1969.

[6] R.H. Barnes, M.H. Saxton, R.E Barrett, and A. Levy, Chemical Aspects of Afterburner

Systems, April 1979, EPA report EPA-600/7-79-096, NTIS PB298465, Page 21.

[7] D.L. Smoot, P. Smith, Coal Combustion and Gasification, Plenum Press, New York, 1985.















8Selective catalytic reduction for

reduced NOx emissionsNancy D. Stephenson

Environmental Technologies, Durham, NC, United States

Chapter outline

8.1 History of SCR 146

8.2 Regulatory drivers 147

8.3 Catalyst materials and construction 150

8.4 Impact on HRSG design and performance 1538.4.1 SCR location within the HRSG 153

8.4.2 SCR configuration 157

8.4.3 SCR support structure 158

8.4.4 Performance impacts 162

8.5 Drivers and advances in the SCR field 1658.5.1 Enhanced reliability and lower pressure loss 165

8.5.2 Transient response 167

8.5.3 Advancements in multifunction catalyst 167

8.6 Future outlook for SCR 170

References 171

Air pollution is a problem that has been building since the first Neanderthals tended

fires in their smoky caves. Regulations go back as far as England in 1273, where

burning of coal was prohibited in London due to being “prejudicial to health” [1].

Throughout the middle of the 20th century, developed countries of the world observed

and dedicated resources to understanding the impact of industrialization on the envi-

ronment. While scientific evidence and its debate remains juxtaposed against the profit

motive, there is no question that investment in protection of our earth is a necessity.

Selective catalytic reduction (SCR) technology is inseparably linked to regula-

tions that require entities relying on energy and its byproducts that are created from

the burning of fossil fuels to minimize their damaging impacts on our health and

environment. Of primary concern here is the reduction of nitrogen oxides (NOx) cre-

ated during energy production. Electric power generation and engine exhausts are

substantial source contributors to this pollutant and it is the focus of this discussion



http://dx.doi.org/10.1016/B978-0-08-101940-5.00008-7

to examine the fundamentals, use, and benefits of SCR as an essential control tech-

nology, with emphasis on its role in the generation of electrical power and steam.

8.1 History of SCR

The first ammonia-based SCR catalyst was developed and patented in the United

States by the Engelhard Corporation in 1957. Many years would pass before devel-

opment of alternative, more cost-effective, base metal catalysts and the deployment

of SCR technology on major industrial pollution sources—notably coal-fired power

boilers. It was Japanese ingenuity and motivation from strict regulatory authority

that launched the electric power application in the 1970s and created an industry

with the use of this catalyst-based control method for controlling NOx from large

combustion sources. Soon after, the technology was put to widespread use in

Europe, in particular Germany, to combat the air quality challenges of an electric

power infrastructure deeply reliant on its coal resources. The United States was

slow to adopt and another decade would pass before it saw the first SCR controls

installed in the late 1980s, and even then, they were limited to refinery, industrial

process, and supporting electric power sources. The first US coal-fired SCR system

on a utility class boiler was commissioned in 1994 at Carney’s Point Station in

New Jersey and employed honeycomb, titania�vanadia catalysts much like the

family of materials reliably operating in combustion turbine systems that run on

natural gas (NG). SCR is now the standard for compliance where emissions are

strictly constrained by permit, particularly as installed in heat recovery steam gener-

ator (HRSG) equipment for combined cycle operation. NOx reduction demands are

often influenced by complementary controls, discussed later in the chapter.

The earliest catalyst materials used precious metals to produce a catalytic reac-

tion that turned the NOx produced from burning fossil fuel into harmless nitrogen

and water vapor. Catalysts are an appealing solution in that they selectively pro-

mote the favorable reaction to these constituents without themselves being affected.

This earliest SCR catalyst that relied on platinum-based metals groups has since

been developed and optimized by an industry of manufacturers into a vanadium and

titanium metals complex that functions to reduce NOx within the flue gas stream

while minimizing side-reactions. These materials of titania complexes have stood

the test of time and remain the foundation of all ammonia-based SCR catalysts pro-

duced today for fossil fuel�fired boilers, combustion turbines, and industrial

process sources. Removal efficiencies of NOx are limited primarily by the physical

and thermal constraints of the host system and are custom designed to achieve a

targeted degree of emission reduction typically ranging from 50% to 95%. SCR sys-

tems rely on the supply of ammonia (NH3) from either direct anhydrous, aqueous,

or urea sources to complete the desired chemical reactions (Fig. 8.1).

As the technology has progressed and adapted to increasingly complex and strin-

gent pollution challenges, traditional SCR catalyst has evolved with specificity to

control carbon monoxide, volatile organic compounds (VOCs), ammonia, and even

mercury species. Its functionality and evolution is a result of relentless product

innovations and reliable performance in practice (Fig. 8.2).


8.2 Regulatory drivers

World bodies, specifically the United Nations, introduced treaties that had a plat-

form of reduction of air pollution and emissions that cause harm. The United

Nations Framework Convention on Climate Change (UNFCCC) ratified by 197 par-

ties including United Nations member countries entered into force in March 1994

to recognize the problem, set goals, direct funds, track changes, chart a path, and

formally consider the charter of enabling the body to face climate change through

mechanisms such as the Kyoto Protocol of 1998 [2].

The United States passed a funding and research bill into law in 1955 entitled

the Air Pollution Control Act and further enacted the Clean Air Act in 1963 for the

control of air pollution [3]. The Clean Air Act of 1970 and its subsequent amend-

ments further developed the legislation to include emission levels and major regula-

tory programs impacting stationary sources (Fig. 8.3).

The Environmental Protection Agency (EPA) of the United States regulates

emission of NOx under the Clean Air Act as one of six criteria pollutants for the

protection of human health. Ground-level ozone is a dangerous pollutant and pre-

cursor to smog; it is created through a chemical reaction when NOx and VOCs

coexist in the presence of sunlight. Air quality improvements in geographic regions

Figure 8.2 Reaction chemistry: NOx.

Figure 8.1 Ozone.

147Selective catalytic reduction for reduced NOx emissions

of high risk, referred to as nonattainment areas, have been achieved in large part

due to dedicated employment of SCR technology in power and steam point sources.

Its use continues to expand both geographically and by host application.

Internationally, Japan passed its own version of legislation to protect the environ-

ment dealing with air pollution, also called the Air Pollution Control Act, in June 1968.

The Council of European Communities released Directive 80/779/EEC in 1980,

setting air quality limit values for 10 member countries at the time (Fig. 8.4).

Figure 8.3 Logo of the United States Environmental Protection Agency.

Figure 8.4 EU member countries in January of 1981 [4].


Concurrent to the emission regulations implemented by the US government and pro-

mulgated throughout the United States since the 1970s, state and local regulators have

also exacted influence and often set the standards of performance required of any given

stationary pollution source with a permit to operate. The relationship between the fed-

eral government and the states is, by nature, in tension in matters of the environment.

The largest emitters of stationary source NOx are unquestionably the power gen-

eration industry. There are approximately 2000 natural gas�fired power plants cur-

rently generating electricity where approximately 1800 are providing electricity for

sale to the grid [5]. When the first National Ambient Air Quality Standards

(NAAQS) were being implemented circa 1993 under the Clean Air Act, gas tur-

bines were available with power outputs ranging from 1 MW (1340 hp) to over

200 MW (268,000 hp). Stationary gas turbines were identified as a category that

emitted more than 25 tons of NOx per year that were subject to the Clean Air Act

Amendments of 1990 (CAAA), under amended Title I of the Clean Air Act (CAA)

to address ozone nonattainment areas, and thereby needed to be regulated [6].

As for a rule, Environmental Protection Agency in 2006 entered Title 40 Code of

Federal Regulations (CFR) part 60 under the Standards of Performance for

Stationary Combustion Turbines into the Federal Register:. . .subpart KKKK. Thestandards reflect changes in nitrogen oxides (NOx) emission control technologies

and turbine design since standards for these units were originally promulgated in

40 CFR part 60, subpart GG. The NOx and sulfur dioxide (SO2) standards have

been established at a level which brings the emissions limits up to date with the

performance of current combustion turbines [7].

With myriad federal and state rules and standards published and viable, the local

governmental requirements for building and operating an industrial emission source

pose the ultimate criterion for the viability of a planned facility, namely procuring

an air emissions permit. Air permitting is a requirement for all site-based emissions

and is set through a process of negotiation with state and local authorities of the

given geographic location. The air permitting process can be lengthy and consum-

ing; hence, many projects for plant expansion or new sources may invest well into

the engineering and procurement phases only to be postponed or canceled due to an

inability to reach a mutual compromise on objectives.

The impact of these rules and standards would be thought to drive demand

upward for control equipment with corresponding lower net emissions. Facilities

firing coal and oil, already fitted with major pollution controls, including SCR,

electrostatic precipitators (ESP), baghouses, and flue gas desulfurization (FGD) sys-

tems remain important utility sources of power. Instead of more controls, the most

evident impact of the EPA’s newer regulations pertaining to NOx and mercury

emissions from coal-fired power plants is the rapid and continuing retirement of

these major electric power assets. In this time of sustained and historically low nat-

ural gas prices, the cost burden to install environmental controls on the aging power

plants is the tipping point of their existence.

And with demand steady and margins of electric capacity reduced, these retire-

ments are driving demand for new natural gas�fired capacity, particularly with


combined cycle capability for its favorable efficiencies with low emissions and also

for renewable energy, such as solar arrays and wind turbines.

The United States electric power base has the largest combustion turbine use

worldwide. Internationally, gas turbine demand for power and steam generation

continues to grow, though the dynamics of regulatory forces and the chosen emis-

sion controls vary. Therefore, it is the intention of this discussion to focus on US

activities and trends.

8.3 Catalyst materials and construction

Early SCR catalyst formulations in the mid-1970s were primarily metal oxides sup-

ported on alumina substrates [8]. These early catalysts lowered emission rates for

oxides of nitrogen, but performance was limited for some formulations and durabil-

ity issues arose in certain applications, motivating further developments in materials

science. Platinum and chromium (III) oxide based catalysts tended to oxidize the

ammonia reagent in the targeted SCR operating range of 500�750�F, effectivelylimiting NOx removal efficiency while consuming excessive reagent. Alumina-

based supports deactivated in the presence of sulfur due to formation of aluminum

sulfates, which are stable in temperatures as high as 1100�1650�F, much higher

than the typical operating range for SCR (Fig. 8.5).

As the technology has progressed to meet criteria defined by the challenges of

industry, current commercial formulations evolved to what is now capable of operating

in a wider temperature window than previously achieved, with NOx reduction efficien-

cies exceeding 90% in the 350�900�F range and having excellent selectivity to

100

NO

X r

emov

al, (

%)

80A

B

BA

FE

D

F

CE

D

C

60

60 Out

let

NH

3, (

ppm

)

1020

392 572

Reaction temperature, (ºF)

A: Cr2O3–Al2O3

B: Pt–Al2O3

C: MeOX –Al2O3

D: Fe2O3–Al2O3

E: Fe2O3–Cr2O3–Al2O3

F: V2O5–Cr2O3–Al2O3

752 932

Figure 8.5 NOx efficiencies of early SCR catalyst.


nitrogen. The vanadia�tungsten (V2O5-WO3) or vanadia�molybdenum (V2O5-

MoO3) on a titania (TiO2) support are by far the most common formulations used in

commercial SCR applications. Low ammonia oxidation, efficient reagent utilization,

as well as excellent sulfur resistance has kept these materials in the predominance of

successful use. The most notable disadvantage of the vanadia�titania based catalyst

materials is that the operating temperature window is necessarily bound to environ-

ments generally below 900�F. Hence, these materials are the workhorses of gas turbine

combined cycle systems (GTCCs) with catalyst installed within the HRSG equipment,

where typical flue gas temperatures of 600�750�F are ideally suited to the materials

employed, providing for the maximum efficiency of catalytic reactions and favorable

conditions for long-term durability. These catalysts are not fatigued or consumed by

the use of reagent, a fact often misjudged in predicting potential operational lifetime.

Catalysts of alternative chemistries and construction were then needed and

developed for simple cycle gas turbine formats to successfully control NOx in ele-

vated thermal environments up to nearly 1100�F with heavy start�stop cycling.

The zeolite family of catalysts has been used in simple cycle gas turbine applica-

tions for thermal operability benefits, but is rarely used for stationary applications

today due to high material costs and inferior resistance to sulfur species. Instead,

dilution air is typically employed to keep the operating temperature below this

boundary, allowing the use of vanadia�titania based catalyst materials or certain

titania-based formulations that are free of vanadium for environments that must

support upwards of 1000�F. These catalysts are engineered for the required perfor-

mance and optimum economics. An active market application of zeolites is

copper�zeolite catalysts employed in mobile diesel SCR applications for high

thermal durability, especially in cases where the SCR is placed downstream of an

actively regenerated diesel particulate filter (DPF).

Along with the chemical composition of the catalyst, catalyst geometries

also play a large part in the equation of applicability. Early catalyst geometry, circa

mid-1970, was in pellet form and assembled in packed beds. This geometry has had

limited use due to physical fouling, pellet attrition, and high back pressure.

Geometries in commercial use today include:

1. Honeycomb

a. Extruded-type, where the entire honeycomb body is composed of catalytic material,

often reinforced with glass fiber that is integral to the composition.

b. Coated-type, where the catalytic material is wash-coated on an inert substrate, primar-

ily using a cordierite extrudate.

2. Plate

a. Catalytic material is pressed onto expanded metal mesh sheet with periodic deforma-

tions to create separation between the plates when stacked.

3. Corrugated

a. Catalytic material is wash-coated or impregnated in solution onto a felted matte sub-

strate comprised of glass fibers. The construction is packaged into “cans” for protec-

tion during transportation, handling, and use.

b. Less common though similar in geometry is a foil structure, comprised of thin metal

substrate coated with catalytic material, pressed into a rippled corrugation, stacked,

and canned in similar fashion (Fig. 8.6).


Extruded type of a honeycomb-like format is the most commonly employed

geometry in GTCC applications for durability to both catalyst poisons and physical

along with thermal stresses. Performance capacity is ultimately customized for the

internal reactor space and controlled back pressure. Product developments have pro-

vided a rapid pace of product geometry benefits in the last decade as more compact

extrusions deliver performance in smaller reactor space and require less investment

in plant footprint as well as steel and catalyst materials. The high geometric surface

area of small pitch catalysts is an effective approach because of the low-dust envi-

ronment. Corrugated types are also employed with the notable feature of being the

lightest weight. Catalyst constructions that have low geometric surface area are

rarely employed today in either simple cycle or GTCC systems, as back pressure

benefits can be engineered through methods of construction and interface (Fig. 8.7).

The two primary NOx formation mechanisms in gas turbines are thermal and

fuel based. In each case, nitrogen and oxygen present in the combustion process

combine to form NOx. Thermal NOx is formed by the dissociation of atmospheric

nitrogen (N2) and oxygen (O2) in the turbine combustor and the subsequent

formation of nitrogen oxides. When fuels containing nitrogen are combusted, this

Figure 8.6 Three types of commonly used SCR catalyst geometries.

Figure 8.7 An example of honeycomb SCR catalyst pitch.


additional source of nitrogen results in fuel�NOx formation. Because most turbine

installations burn natural gas or light distillate oil fuels with low nitrogen content,

thermal NOx is the dominant source of these emissions. In the regulatory environ-

ment, all sources of gaseous oxides of nitrogen are considered in total, controlled

by catalytic and complementary means within the plant process systems and

designed for a maximum stack output in ppm-level concentrations.

8.4 Impact on HRSG design and performance

8.4.1 SCR location within the HRSG

It is evident that catalyst-based solutions have a broad range of suitability to com-

bustion turbine power systems for both simple cycle and for the more efficient com-

bined cycle configuration that employs a HRSG system. What are the key design

considerations of the SCR system for the HRSG equipment supplier and what

impacts must be considered?

The SCR emission control equipment consists of two fundamental components

that function together to deliver clean treated flue gas: reagent supply and SCR

catalyst. Reagent for catalytic reduction of nitrogen oxides may be delivered as

pure anhydrous ammonia, ammonia diluted with water or urea that breaks down to

ammonia by reaction; hence, the reagent is generically referred to as “ammonia.”

The reagent supply system can be further separated into its storage system, flow

control, evaporator, flow-balancing system, and finally the reagent injection grid

(AIG). A feedforward 2 feedback reagent injection control system is typical for

low-emission systems, wherein the reagent volume delivered to the piping system

upstream of the catalyst bed is set by predictive equations triggered off of the key

inlet conditions of load and NOx concentration. Then, the pollutant, NOx, is mea-

sured at the catalyst exit and a feedback loop directs the injection controller to

increment additional reagent or trim back if in excess. Some systems additionally

employ continuous emission monitoring (CEM) of excess ammonia leaving

the SCR, referred to as “slip,” to provide real-time measurement of compliance

when a unit is permitted under concurrent control of emissions from both NOx and

ammonia (Fig. 8.8).

The SCR catalyst component may be considered to include the custom built

ceramic materials housed in modular units for handling and installation, as

described above in Section 8.3, Catalyst Materials and Construction, and an

internal frame or alternate tie-in structure that provides for the catalyst modules

to be aligned, secured, and sealed for effective operation. Catalysts perform pas-

sively with no moving parts and are inherently thermally stable. Hence, the job

of proper assembly and construction that considers thermal expansion behavior

and appropriate metallurgies for stability is most important at the design and

building phases. This housing built for the reagent injection device, supplemental

flue gas mixer(s), and the physical catalyst module array is referred to as the

SCR reactor.


Since catalytic reaction efficiency is strongly thermally influenced, it is an early

stage HRSG design consideration to effectively locate the SCR reactor in the equip-

ment train. This is driven primarily by the temperature zone of flue gas as it passes

through the heat recovery zones of the HRSG. SCR catalyst can operate over a

temperature range approximately equivalent to the full range of temperatures pres-

ent in the flue gas path that a HRSG builder encounters for its performance require-

ments—approximately 1100�F down to 300�F—though there are tradeoffs in back

pressure, undesired chemical reactions, asset cost, and lifecycle costs when not opti-

mized, as well as practical limitations at the extremes (Fig. 8.9).

For this discussion, we will focus on the design case that allows choices in

configuration and build approach. It is recognized that retrofits into existing plants

constrains optimization and therefore the final design within the HRSG will be the

product of balancing trade-offs of cost and risk factors for the desired reactor loca-

tion. For our case here where the SCR is integral to the HRSG, it is relatively sim-

ple to eliminate some of the extremes. The highest temperature zones for SCR

catalysts operating at roughly 800�1100�F are more applicable to the simple cycle

gas turbines built for peaking power that typically run limited hours, often less than

1000 per year. For HRSG applications, catalyst operating lives of greater than

30,000 hours of operation are a typical standard of design. Catalyst performance is

strongest in its new condition and is designed to accommodate a predicted decline

in capacity as it ages from the impacts of the operating environment; therefore, the

Figure 8.8 HRSG diagram.


catalyst designer focuses on conditions described as “end-of-life.” In the opposite

temperature extreme, locating the catalyst after the HRSG where heat recovery has

reduced the flue gas temperature to below 400�F would have several issues. The

primary limitation is related to sulfur in the fuels reacting with the ammonia

injected into the system for the SCR byproduct reaction forming ammonium salts.

8.4.1.1 Ammonium salt formation

Sulfur trioxide 2SO21O2 ! 2SO3

Ammonium sulfate 2NH31SO31H2O ! (NH4)2SO4 solid

Ammonium bisulfate NH31SO31H2O ! NH4HSO4 liquid

Units firing low-sulfur fuels, such as NG and ultra low sulfur diesel (ULSD),

can effectively manage this undesirable byproduct by maintaining balanced distri-

bution of reagent and flue gas in the reactor and inspecting downstream equipment

during annual outages to clean buildup. The deposition may be seen on any surfaces

downstream of the AIG and even on the catalyst itself if sulfur oxides and ammonia

are of elevated concentrations at a temperature that permits formation. The bisulfate

form causes the most maintenance issues as it is wet and sticky, even tar-like, and

can be difficult to remove. Water or CO2 blasting are customary methods

of removal from downstream surfaces beyond the catalyst bed. Its presence in the

catalyst itself is mitigated by extended runtime at elevated load to thermally drive

reversal of the reaction. Sulfates that are solid and dry are less troublesome for

maintenance yet may contribute to particulate emissions. Therefore the potential to

form is incorporated in air permits for units built in regions that control this emis-

sions criteria, regulated as PM2.5. SCR systems have set-points of minimum flue

gas temperature for ammonia injection for the purpose of avoiding unwanted reac-

tions such as these salts; however, when these compounds are present and ambient

temperature falls below the dew point of water, formation will occur. The sulfates

are driven off as the flue gas path elevates in temperature during a load ramp.

Figure 8.9 Catalyst performance vs temperature graph.


Ammonia slip, the unreacted ammonia reagent that passes through the catalyst, is

important to minimize for this reason as well as for the efficient use of this operat-

ing cost item. Dealing with sulfur oxides, alone, is challenging in the HRSG envi-

ronment as SO3 efficiently combines with water, when present, to form sulfuric

acid and this is a powerful corrosive, particularly on carbon steel.

8.4.1.2 Sulfuric acid

SO3 1H2O ! H2SO4

The design goal for SCR location is to find a region of the HRSG where the

location of the SCR allows for tens of thousands of hours of operation, is safely

above the formation temperature of ammonium sulfates during the full range of

operating loads, and takes advantage of the favored reaction kinetics for the

selected catalyst family of materials. For this selected temperature zone, the catalyst

is then optimized for performance and economy. From an optimal temperature for

SCR operation view, the equipment designer looks for a full-load temperature range

above approximately 600�F and not higher than 800�F. In practice this has gener-

ally required the SCR to be located within or just after the HP evaporator section of

the HRSG. These locations typically put the SCR performance close to optimal

with these locations being in the 650�750�F temperature range for the full load

operating mode. The full load flow typically creates the largest demand on the cata-

lyst due to the mass of pollutant being treated. While lower load points may deliver

lower flue gas temperature and thereby reduce the inherent reactivity of the catalyst,

the flue gas volume change is the predominant factor, reducing demand in the net.

Controlling emissions in the low-load phase of the gas turbine and transient load

conditions can be notably challenging and, when control is required here, the high-

est catalyst demand case that sets the equipment design may be reversed. Solutions

and trends are discussed ahead in Section 8.5, Drivers and Advances in the SCR

Field (Fig. 8.10).

Historically, when specifying the minimum ammonia injection temperature and

that for continuous use, it was rare to require start temperatures below 500�550�F.This was influenced most by engaging the air pollution control equipment, SCR in

this case, sufficiently close to the defined load condition for permit compliance and

allowed for the transient load segment to stabilize before SCR equipment was relied

upon. There was limited regulatory or operating rationale to drive the load-point of

injection down. As pressure to control potential emissions has prevailed over sim-

plicity of operation, the SCR range of use continues to expand across a larger load

range. Technically speaking, running on the naturally low-sulfur fuels of NG and

ULSD provides for some freedom to set reagent injection as low as 350�F during

ramp-up with continuous injection temperatures in the 400�F area, dependent upon

the specific unit design. Amending the operating logic may present opportunities

for units to enhance the operating load range, provided the ammonia vaporization

system is verified to be capable at the targeted lowest load points.


8.4.2 SCR configuration

The SCR reactor must contain the reagent delivery device most commonly referred

to as the ammonia injection grid (AIG), any additional mixing devices needed to

achieve proper ammonia-to-NOx distribution in the flue gas such as static mixers,

SCR catalyst support structure, and the SCR catalyst, which is typically built in

modularized structures. It is also common for the carbon monoxide�volatile organ-

ics oxidation (CO/VOC) catalyst to be located in the same area of the HRSG, just

upstream of the AIG. SCR catalysts are reducing by nature while CO/VOC catalysts

rely on oxidation reactions. This location of CO/VOC catalyst avoids the oxidation

of ammonia to NOx, an undesired oxidation reaction that will occur if ammonia

passes over traditional CO/VOC catalyst.

Figure 8.10 HRSG diagram showing SCR catalyst location.


8.4.2.1 Ammonia oxidation to nitric oxide

4NH3 1 5O2 ! 4NO1 6H2O

The ammonia oxidation reaction is also observed in simple cycle SCRs that

inject ammonia to reduce nitric oxide in flue gas temperatures well above that of

the HRSG environment, e.g., 850�1000�F. In this case, the oxidation is thermally

driven and a reaction-competing catalyst like CO/VOC does not have to be present

to prompt this consequence. Effectively, this results in increased performance

demand on the SCR catalyst system for its NOx control job and consumes reagent

without a benefit. And, it is a cautionary concern for potential deposition of oxidiz-

ing metals, such as chromium or platinum, if present in the flue gas stream.

Presence of these competing metals at the SCR region may be due to volatilization

or delamination from upstream surfaces. SCR catalyst that is contaminated with

these oxidizing metals risks exhibiting a directly competing oxidation reaction of

ammonia to oxides of nitrogen in the reaction sites intended for the selective reduc-

tion reaction. Ultimately, in the presence of these competing drivers, the maximum

achievable performance of a SCR system will be limited by the reaction dynamic,

even when a large volume of catalyst is present.

The first design decision for the AIG is where to take the carrier gas for the

ammonia. Typically HRSG applications have evaporated the ammonia at the

ammonia skid and carried the evaporated ammonia to the AIG with air. Older sys-

tems utilize anhydrous ammonia carried by ambient air while many of the more

modern systems utilize flue gas extracted from the HRSG just upstream of the AIG

itself, employing it to both vaporize and carry the ammonia and reintroduce the

mixture through the AIG. New considerations for this style of system may be driven

by requirements for control through transient loads that may necessitate the addition

of auxiliary heaters and/or multiple flue gas extraction points from the HRSG, e.g.,

one by the turbine exit and another downstream in the HRSG. The AIG is the first

tool for delivering a uniform mixture of ammonia reagent with the NOx in the flue

gas stream. Even with a suitable AIG design it is still necessary to achieve a distri-

bution sufficiently homogenous to ensure that the reactive components are colo-

cated at the reaction sites of the catalyst as the flue gas passes over its surface.

Mixing is assisted by the turbulence created by the AIG itself and will be further

aided by the presence of a colocated tube bank or the installation of a supplemental

static mixer. For both the case where the AIG is the source of turbulence for mix-

ing, and when some form of supplemental turbulence is introduced, there still must

be sufficient residence time for the mixing to occur (Fig. 8.11).

8.4.3 SCR support structure

SCR catalyst is delivered in sets of steel framed boxes, commonly referred to as

modules. These steel housings serve to create an efficient means of installing large

volumes of catalyst material, allow uniform and nested configurations that aid in


flue gas sealing, and protect the catalyst material during rigors of transportation and

handling. It is most common for a HRSG-SCR to be built at ground level, with

structurally self-supporting modules of catalyst material stacked in a vertical array

to the roof interface. Flue gas travels horizontally through the equipment in the

large majority of installations. Just as it is important to thoroughly mix flue gas

with reagent ahead of the catalyst, the catalyst array is engineered and built to pro-

vide uniformity in both catalytic properties and flow resistance and to ensure a

high-integrity seal throughout. The back pressure created by the bank of catalyst

contributes favorably to reagent mixing. Flue gas is flowing horizontally through

the open chambers or cells of the high surface area catalyst structure. As the gases

pass over the stationary catalyst surfaces, the catalytic reactions occur rapidly and

the reactive sites are released for the next molecules passing through. The catalyst

volume ultimately required for a given plant service is engineered to fit most effi-

ciently into the liner-to-liner dimensions allowed. In a horizontal flue gas flow

HRSG application for a large-frame turbine, by example, the modules are usually

stacked approximately 10 modules high and from 2 to 4 modules wide (Fig. 8.12).

In a typical arrangement, module stacks are secured to a picture frame�like

assembly that aligns with the steel surfaces of the module perimeters. Each module

is positioned and secured in place with the catalyst faces remaining open to the

reactor chamber. The frame ties in to the reactor wall and a baffle is installed

around this interface to prevent bypass during operation. All connections are

secured with allowance for thermal expansion. There are two general methods of

securing the modules to the support structure: pushing the modules against the

frame using push bolts, or pulling the module to the support structure using a T-clip

type of fixture. Both methods can be used to secure modules to either the upstream

or downstream side of the gas path. Smaller reactors may be built without the

Figure 8.11 SCR catalyst response curves.


structural frame, employing a module, i.e., module nesting for sealing; however,

this approach requires close design and build focus to avoid stability and bypass

issues in use (Fig. 8.13).

It used to be common for the support structure to be designed to install the initial

catalyst supply plus a supplemental layer for future use. The accommodation for

the supplemental layer was incorporated to add catalyst when the initial supply

deactivated to the point it could not sufficiently meet the performance requirements,

or if performance requirements were increased. Since two catalyst layers were

intended to fit in the same support structure, it was typical to pull the initial catalyst

layer to the upstream side of the support frame, allowing the downstream layer to

be pulled to the downstream sealing surface. In practice, it is uncommon for the

supplemental catalyst layer section to be used. The typical use is to boost the NOx

removal efficiency for a system that is demonstrating higher-than-anticipated emis-

sions from the gas turbine or for a catalyst system that is underperforming. It is

popular today to locate, install, and seal the catalyst modules to the downstream

Figure 8.12 Example of SCR catalyst module general arrangement.


side of the equipment, since added distance from the AIG to the catalyst face has

the long-term benefit of mixing length (Fig. 8.14).

For HRSGs that locate the SCR reactor in a vertical flow duct region, the cata-

lyst modules are not stacked and, instead, each module is typically mounted directly

onto a horizontal support structure that allows flue gas to flow unobstructed either

vertically upward or downward. For these installations, the module gravity-seals

itself against its horizontal support frame with sufficient force to prevent the mod-

ules from shifting in use and added methods of securing as employed for horizontal

flow configurations are generally not required. This physical arrangement is unusual

in a HRSG; however, the catalyst behavior principles are unaffected and therefore

the balance of design principles apply. One construction caution for vertical-flow

orientations is to avoid placement where condensing surfaces are aligned above

the catalyst bed, as water shed during shutdown cycling will wet and weaken the

ceramic catalyst materials, particularly risking delamination on a catalyst construc-

tion that is coated.

Figure 8.13 Example SCR catalyst module connection.


8.4.4 Performance impacts

SCR systems do not consume heat and generate miniscule levels of energy from the

reactions that occur in a GTCC environment. The ammonia or urea systems for

reagent present important safety and maintenance considerations that are incorpo-

rated into plant O&M routines. And, the SCR catalyst presents two primary chal-

lenges, one physical and one chemical in nature. Physically, the SCR bed fills the

entire duct cross-section to ensure all gases are treated for removal of the targeted

pollutants. This SCR assembly introduces back pressure due to flow obstruction.

Catalysts alter chemical reaction pathways and while their primary reactions are

extremely favorable, potential for a byproduct reaction is created by their presence

in the HRSG system environment through sulfate formation from oxidation of SO2.

Back pressure through the SCR system consumes a measured portion of the net

HRSG system allowance, and techniques to lower its impact traditionally add costs

Figure 8.14 SCR catalyst seal: push vs pull.


to supply and construction and may complicate flow uniformity. Managing total

HRSG back pressure is an area of relentless continuous improvement because the

gains impact all forms of cost, including operating and opportunity cost of maxi-

mum turbine output. Over the years several approaches have been taken to reduce

the pressure drop across the SCR catalyst bed. Many HRSGs install a duct expan-

sion and corresponding contraction, with catalyst stacks installed in the largest duct

area. Expanding the duct at the SCR catalyst to slow the flue gas, and thereby

decrease the back pressure, can be engineered to the level of desired gain.

Development and product innovation in the area of catalysts and novel mechanical

approaches to the housing has been the norm of recent years, with

notable achievements since approximately 2010. In this time period, back pressure

impact of the SCR has decreased by over 30% without sacrifice to performance.

The net improvement continues to show promise as catalyst advancements com-

bined with innovative architecture of the SCR bed pushes net back pressure impacts

to less than two inches water column. Future savings in pressure drop are most

likely to come from the recent interest in multipollutant catalysts wherein the emis-

sion control performance for NOx, CO, and VOC are combinable into a single reac-

tor housing and compatible reagent systems. Section 8.5, Drivers and Advances in

the SCR Field, explores this in greater detail.

From a maintenance standpoint, the SCR catalyst bed requires only periodic

inspection for damage or deterioration and may require surface vacuuming to

remove accumulated dust and insulation debris that may get trapped over time.

Units that cycle heavily or are laid up in a humid environment may eventually

require inner seal repair to ensure that the catalyst bed retains its compressive integ-

rity. Sulfur, present in both NG and ULSD, forms SO2 during combustion and is

undesirable both operationally and for human health. SO2 further oxidizes to gas-

eous SO3 in this combustion environment, yet at a fraction of total sulfur oxides

(SOx). The presence of catalysts, for either CO/VOC or NOx, promotes this oxida-

tion reaction of SO2, with the latter being only mildly promoting. Of operational

concern in a HRSG system, SO2 forms an acidic solution with water and is then

easily converted to a salt form when metal oxides are present, as is the case in this

flue gas environment. Ammonium salts that remain dry and airborne are a potential

source of PM2.5 emissions; therefore, responsible design and routine maintenance

for detection are important factors.

When temperature and concentrations are favorable for the reactions, these salts

can collect on the colder banks of fin tubes just downstream of the SCR. As the fin

tubes develop increasing levels of deposits, the heat transfer efficiency of the coated

tubes can be negatively impacted. The contribution of SCR equipment on salt for-

mation is not easily quantifiable, though its use is a potential contributor. SCR cata-

lyst weakly promotes the oxidation reaction of SO2, noting the role of vanadium,

primarily. The base concentration level of SO2 in most NG fuel is so low that the

calculable impact of 2�5%, or even 10%, SO3 production is not likely to be consid-

ered a causal source. The formation of salts on tubes may develop in

unpredictable patterns or degree and may not directly parallel temperature within

the tube banks. HRSGs with SCRs that exhibit this byproduct issue are likely to


have an underlying system issue, with excess ammonia reagent present as slip in

concentration and distribution patterns, and have a sulfur source of sufficient con-

sistency and concentration to drive the formation of these undesirable salts. This

may indicate a bypass in the SCR bed, low or inconsistent reactivity in catalyst, or

irregular distribution of reagent into the reactor. Most importantly, this reaction is

thermally reversible and may be mitigated with investigation into preconditions. If

excess ammonia downstream is caused by catalyst that is inefficient in its reaction

capacity or salting has continued unaddressed, it may be necessary to consider a

replacement, repair, or addition to correct.

Catalysts in well-designed GTCC systems often perform for many years

beyond their design goals. The operational factors that most impact asset life of

catalyst in an SCR system are largely controllable. The influence of construction

and quality features of the installed catalyst material is a design consideration

discussed earlier and of primary importance to lifecycle costs. For the plant

operator responsible for this equipment, attention may be focused on thermal

exposure beyond specified limits, wetting of catalyst, water quality of the turbine

deionization system, operation on oil, and timely repair to aging seals or

damaged catalyst.

The primary cause of catalyst decline in HRSG-catalyst performance is loss of

microscopic surface area caused by thermal exposure to elevated temperatures and

the impact of long-term cycling through cold starts. Thermal forces have a perma-

nent effect on catalyst pore structures and this exposure impact is referred to as

“sintering.” Load start�stop cycles may fatigue catalyst, linked to the wetting of

the material as occurs from ambient conditions, exposure from maintenance actions,

or tube ruptures that force a rapid shutdown. Water may weaken the structure of the

ceramic and particularly compromises coated catalyst materials. Catalyst that con-

tains trapped moisture at the time of startup will be subject to excessive physical

forces, that break down porosity of the material as the water molecules expand dur-

ing vaporization. Reactivity of catalysts relies on high surface area, so it is a prior-

ity to keep these materials dry. The contamination of catalysts is typically a

secondary deactivating force in these systems. Chemicals may react with the cata-

lyst and cause a change in character that inhibits the NOx performance or a constitu-

ent may adhere to the surface of the material, masking the reactive pores. The

cleanliness of most GTCC fuel systems limits these exposure factors to sources

other than fuel and what is observed most commonly are salts, metals, and debris.

Water quality of the deionization system is a high-impact item and it is necessary

to avoid direct use of municipal water sources, this being consistent with turbine

standards of care as well. Oil use is noted because the most risk exists from insuffi-

cient combustion wherein unburned hydrocarbons coat the catalyst and damage the

surface as they burn off through temperature elevation. On the reagent system side,

use of quality ammonia sources and routine inspections of the vaporization systems

are a must. Use of agricultural grade ammonia is a common misstep that triggers

maintenance and possible repairs that are not planned due to the lower purity level.

Lastly, annual SCR inspections and quick attention to the factors of wear and tear

will serve the GTCC plant in longer useful asset life.


8.5 Drivers and advances in the SCR field

Catalysts have played an essential role in the expansion of combustion

turbine�based power use over the many years since its first application to this criti-

cal infrastructure sector. In North America, the sustained spark spread has caused a

transformative shift in dispatched electric power sources from coal to natural gas

and driven combustion turbine platforms to be the preferred energy choice over

coal generation. Unrelenting environmental and economic pressures further propel

advancements in catalyst-based technology solutions.

Drivers for investment in catalyst-based technologies are more complex today.

The character of the catalytic system demand can be broken down into three seg-

ments: base load, load following, and enhanced flexibility.

� For the base load segment, higher focus is placed on environmental compliance reliability

and catalyst solutions that minimize parasitic power loss.� The load following segment, especially with larger-frame machines, has driven enhanced

transient response technology and the importance of capability to manage high nitrogen

dioxide (NO2) concentrations that may exist.� For the units that are characteristic of both challenges and require enhanced flexibility,

the capability to expand the load range and run successfully at much lower loads where

emissions are most difficult to control is a driver for multifunctional catalyst solutions.

Multifunction catalysts provide additional economic benefits, as they may facilitate

lower-cost reactors and ammonia injection technology.

8.5.1 Enhanced reliability and lower pressure loss

Driven by ozone nonattainment and local regulatory rules, nitrogen oxides and

ammonia slip emission limits as low as 2 parts per million have been in place since

the early 2000s. Compliance rules define these concentrations by volume dry basis

corrected to 15% O2 (ppmvdc). Depending upon the combustion turbine manufac-

turer and model, ancillary emission controls such as water injection, plus its fuel

type, SCR performance demands range from approximately 78 to 96% reduction

efficiency in NOx emissions during steady state operation. In addition to the basis

value of emissions, the compliance time averaging period and allowances for excess

emissions during startup must also be considered. The trend in this area has also

been tightening. For example, defining compliance as an averaging of data drawn

from 24 hours of operation to 3 hours on a rolling timeline places additional impor-

tance on performance capability, flexibility, and reliability.

As discussed earlier, overall system performance is influenced by both the

system capability to deliver uniform flue gas and achieve adequate distribution of

ammonia to NOx as well as the catalyst performance capability. For most SCR

designs, the addition of catalyst capacity to perform, often defined as its potential,

directly delivers greater reliability. Adding catalyst capacity typically means adding

volume and depth of reactor bed; this may add to the back pressure of the system,

thus, the two design elements have competing effects. A change in system pressure


drop will impact both fuel usage over time due to the impact on thermal efficiency

and electrical output from the combustion turbine (Fig. 8.15).

Catalyst advancements pressured to keep pace with the added reliability

demands while maintaining or enhancing the efficiency of the combustion turbine

have come through both catalyst material developments and module encasement

technologies. Fig. 8.16 illustrates the aggressive progression of improvements in

back pressure, as represented by a leading catalyst supplier.

Figure 8.15 Example of postcombustion emissions without added controls.

Figure 8.16 Improvements in SCR catalyst pressure drop over the years.


8.5.2 Transient response

Due to the increasing size of combustion turbines and segments of the market that are

subject to substantial load following, e.g., areas with high usage of wind or solar

sources, higher focus has been placed on emissions during startup. Fast starts are the

driving challenge for these combined cycle systems. For a large modern combustion tur-

bine that is very effective in limiting NOx emissions, the net output of a given unit trig-

gers special control needs, even when emission concentrations appear to be comparable

to their smaller counterparts. And in the alternate circumstance, the aggregate emissions

generated during the startup periods for a unit that starts and stops frequently can repre-

sent the majority of the plant emissions, thus the additional environmental focus.

Another related item to startup and lower load operation for some turbine classes

relates to the balance of nitrogen dioxide, NO2, to nitric oxide, NO, in the make-up

of total NOx. During steady state operation, a typical NO2:NOx ratio for a combus-

tion turbine is perhaps 5�10%. However, during startup this ratio is typically

reversed and can be as predominant as 90%. It is more demanding on a SCR system

to remove nitrogen dioxides and high NO2 ratios can have a substantial negative

impact on the reaction rates and, thus, net catalytic potential. In parallel, this phe-

nomenon can also be seen at lower load with CO catalyst operating at lower tempera-

tures; the CO catalyst will convert NO to NO2 and in some cases may cause NOx

emission compliance problems if not considered during the initial design. Catalyst

and system suppliers have developed technology to respond to the demands

described above. The technology components include (1) specialization of catalyst

formulations that enhance reaction rates with high NO2, allowing the size of the SCR

to remain practical, (2) characterized catalyst performance under transient conditions

thus allowing predictive modeling for ammonia demand response to be provided to

system suppliers such that ammonia vaporization and delivery systems can be corre-

spondingly designed, and (3) predictive algorithms to assure fast system response.

As an example, a conventional F-class GTCC plant produces approximately 180

lbs of NOx and 1340 lbs of CO (per GT unit) during a cold startup, compared to

approximately 13 lbs NOx and 340 lbs CO for a quick-start plant [9].

Fig. 8.17 shows an example of a hot-start system response curve and how com-

pliance can be achieved with proper catalyst design and system know-how.

8.5.3 Advancements in multifunction catalyst

Catalysts that function to control multiple pollutants simultaneously have been in

existence for more than a decade, yet it has only been since approximately 2012

that multipollutant catalysts have generated much interest. These catalysts combine

NOx reduction behavior with CO and VOC oxidation. Use of multipollutant catalyst

allows the CO/VOC catalyst, and the related frame and supports, to be omitted or

removed from the HRSG. The removal of the CO/VOC catalyst returns on the

magnitude of one inch of water column of pressure loss to the HRSG system. A

fraction of the back pressure savings may be consumed by the multifunction cata-

lyst, though in the end, the total back pressure across the catalyst is reduced.


In addition, multipollutant catalyst will likely have lower SO2 oxidation behavior

than the combined oxidation of the traditional CO/VOC and SCR catalysts.

With the reliance on catalysts to meet stringent emission rules across multiple

pollutant challenges, it would seem compelling to integrate the functionality of

these materials into one solution, if technically achievable. However, prior attempts

at implementation proved to be troubled with narrow operating bands of suitability

and a limited market need. Today’s best solutions provide a wider operating tem-

perature range for multipollutant, NOx 1 CO 1 VOC, control performance. This,

combined with the growing demand for operating load flexibility may result in a

wider adoption of this technology. Operational flexibility plays an increasingly

important role in the viability of most power plants (Fig. 8.18).

Opportunities for implementation of current multipollutant catalyst technology

can be considered in three distinct areas:

1. for existing units with no CO catalyst but with a desire to expand the operating range

capability;

2. for existing units with CO catalyst that wish to either take advantage of lower total system

back pressure through the consolidation of functionality to one bed or supplement existing

CO catalyst to expand the operating load range;

3. for new units that have CO/VOC and NOx emissions requirements and wish to minimize

total pressure loss and/or take advantage of lower capital cost associated with a single

reactor, and for units without burners, potentially take advantage of newer direct injection

ammonia technology.

Figure 8.17 Hot-start combustion turbine transient analysis.


For categories 2 and 3, an additional benefit may be seen as it relates to sulfate

reaction impacts and resultant performance issues and/or increased maintenance

demands on CO/VOC catalyst. As described above, many units have the CO/VOC

and SCR catalyst in the same temperature bay within the HRSG to facilitate ease of

design and cost.

Figure 8.18 SCR catalyst control performance graphs.


With the increasing demand of load flexibility at the low end, the temperature

within that bay drops to levels that make CO/VOC catalyst more susceptible to

sulfate attack. Although SCR catalyst can be affected by salt formation at very low

temperatures, this anticipated issue does not apply in the same way due to the

use of titania versus alumina ceramics as the catalyst foundation for providing reac-

tive surface area. Sulfate byproducts are generally reversible through temperature

exposure as loads ramp up.

The advancements in multipollutant catalyst adds another lever to reliably

meeting emissions requirements while maintaining a high degree of operating

flexibility.

8.6 Future outlook for SCR

SCR is securely situated in the toolbox of controls for many decades to come.

Reducing pollution by transforming a molecule that is characteristically poor for

human health into natural clean products of our air without consumption of the

base material remains an elegant solution. The HRSG provides the perfect host

environment for efficient SCR application and it silently performs its duty without

interference and with minimal maintenance demands. The challenges surround fac-

tors of optimization and efficiency and rarely is there a fundamental question of

suitability. We collectively ask how we can make it better. We do not ask how we

can make it work.

The gas turbine platform is the foundation of low-cost reliable energy, and is

certain to grow in use globally for the foreseeable future. With relentless demands

on air quality, now led by the predominance of ultralow emissions requirements of

the United States, it is essential that innovation is rewarded and environmental solu-

tions that are truly good for the planet and that positively support the dynamics of

economic growth be embraced. Days of gas turbines coming to full load and com-

fortably locking in load settings for extended periods are gone, at least in the North

American power market. The challenges being dealt with to ensure catalytic solu-

tions remain at the forefront are relentless pursuit of minimizing impact factors like

back pressure that scavenges potential generating efficiency; intelligent reagent sys-

tem controls that take advantage of catalytic reaction times while turbine load

ramps up and down to changing dispatch profiles; absolute quality of catalyst mate-

rials to ensure that theoretical achievements of 95% removal efficiencies, and even

higher, are achievable; and aiding the control of emissions of multiple hazardous

pollutants simultaneously—NOx, CO, VOC, particulate matter—in gas-fired com-

bustion systems.

Successful HRSG equipment leaders embrace environmental control demands as

an economic and competitive advantage. The unforgiving regulatory demands of

the North American supply market are a training ground for global advantage.

Lines of trade stretch. Prospective customers are located oceans apart. Information

is virtually available and therefore answers are expected to be. Our environment


is a universal concern among all nations and the politics of who pays is a stalling

question that is fading from play, as proven by the recent scientific confirmation of

the healing of the planet’s ozone layer— the “good” ozone. Susan Solomon, a

renowned atmospheric researcher and professor at MIT in Cambridge MA, et al., as

published in the J. Sci. in July 2016, confirmed that damage is indeed reversing and

that we anticipate a complete recovery by approximately 2050 [10]. Global

response begot global impact, all in the course of a single generation.

Pace of change continues to accelerate. It took nearly 60 years from the inven-

tion of SCR technology for NOx control to be regulated and become the standard of

control in the United States. Its benefits are already employed for mobile emission

sources in diesel engines and marine vessels. China has set a course of rapid trans-

formation of pollution-heavy point sources to burn natural gas and employ controls

consistent with its industrialized neighbors. The latest change-maker for SCR

implementation is India. As of this writing, India has set down a path of environ-

mental stewardship by releasing a new set of rules in order to control emissions

from stationary sources by 2017. As more countries press for economic develop-

ment and establish a manufacturing base that requires substantial energy to operate,

more environmental regulations and rules will be forthcoming and those suppliers

prepared to answer the challenges are set to prosper.

References

[1] B., Jan (1999). History of Air Pollution in the UK. [online] Enviropedia. Available at

,http://www.air-quality.org.uk/02.php. (accessed 14. 07. 16).

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http://science.sciencemag.org/content/353/6296/269

http://science.sciencemag.org/content/353/6296/269

9Carbon monoxide oxidizersMike Durilla, William J. Hizny and Stan Mack

BASF Corporation, Iselin, NJ, United States

Chapter outline


9.2 Oxidation catalyst fundamentals 1749.2.1 Activity and selectivity 174

9.2.2 Catalytic reaction pathway 176

9.2.3 The effect of the rate limiting step 177

9.3 The oxidation catalyst 1799.3.1 The active material 179

9.3.2 The carrier 180

9.3.3 The substrate 181

9.3.4 Putting it all together 182

9.4 The design 1839.4.1 Defining the problem 183

9.4.2 Choosing the catalyst 184

9.4.3 Determining the catalyst volume 186

9.4.4 System considerations 187

9.5 Operation and maintenance 1889.5.1 Initial commissioning 188

9.5.2 Stable operation 188

9.5.3 Data analysis 189

9.5.4 Catalyst deactivation mechanisms 191

9.5.5 Catalyst characterization 194

9.5.6 Reclaim 195


Supplemental reading 197

9.1 Introduction

The combustion of an organic fuel is an exothermic process used to generate the

heat required for the heat recovery steam generator (HRSG). In its simplest form,

fuel and oxygen react to form water and carbon dioxide and heat is released. If this

were only what actually happens, if it were only this simple, then there would be

no need for a discussion about emission controls in the system.



http://dx.doi.org/10.1016/B978-0-08-101940-5.00009-9

The reality is much more complex:

� Fuel is comprised of carbon, hydrogen, and other trace constituents.� Oxygen is typically supplied from air, which is oxygen, nitrogen, and other trace

constituents.� The trace constituents in the fuel and air can react in the combustion process to form other

exhaust components that may be problematic.� The specific conditions of the combustion chamber (oxygen level, temperature, degree of

mixing, residence time) will affect the distribution of actual emissions (NOx, CO, VOC,

SOx, etc.) exiting the combustion chamber.

Environmental regulations specify the maximum allowed levels of CO, VOC,

and NOx in the stack. Typically, each operating site will have a governing environ-

mental permit specific to that site.

This chapter discusses the carbon monoxide oxidizer that is installed in a HRSG

system to directly address the reduction of CO emissions so that the stack CO emis-

sion limit can be met.

The carbon monoxide oxidizer also oxidizes volatile organic compound (VOC).

The actual amount of VOC reduction is determined by the actual hydrocarbons

present, the specific oxidation catalyst being used, and the specific operating condi-

tions. Every hydrocarbon reacts differently and requires potentially different cata-

lyst temperatures and different catalyst volumes to get reductions similar to what

would be expected for CO.

A carbon monoxide oxidizer will convert some NO to NO2. This may impact the

ammonia consumption in an selective catalytic reduction (SCR) system within the

HRSG package.

A carbon monoxide oxidizer will convert some SO2 to SO3. This can impact the

deposition of ammonia salts on HRSG surfaces downstream of an SCR system and

thus affect heat transfer efficiencies over time.

With these considerations, there is no single carbon monoxide oxidation catalyst

that will/can work in all applications regardless of conditions. Rather, the catalyst is

selected based on the performance requirements unique to each site.

9.2 Oxidation catalyst fundamentals

9.2.1 Activity and selectivity

In the combustion chamber of the HRSG, carbon in the fuel reacts with oxygen

from the ingested air to form carbon dioxide and water. In a catalytic oxidizer, the

same chemistry takes place on the catalyst to the residual CO and hydrocarbon

emissions resulting from the incomplete fuel and oxygen reactions in the combus-

tion chamber. However, the oxidation catalyst enables this chemistry to happen at a

much lower temperature and/or within a shorter residence time.

For example, in the case of the CO and oxygen reaction, without a catalyst, a

temperature of about 1300�F is required to make the reaction take place to form


CO2 and water. Using a catalyst can make the same chemical reaction take place at

temperatures, in some applications, as low as 210�F. Most carbon monoxide reac-

tors in HRSG applications are operated between 575�F and 850�F. The hydrocarbonto CO2 reactions typically require 1200�2010�F without a catalyst. Depending on

the specific hydrocarbon, using a catalyst can make these reactions take place at

half these temperatures.

A tunnel through a mountain provides an apt analogy for the role of oxidation

catalyst in emissions control. As shown in Fig. 9.1, just as a tunnel provides an

alternate, faster, lower energy path to scaling a mountain, a catalyst provides an

alternate, lower activation energy path between products, such as CO and O2, to

reactants, like CO2 and water. The catalyst may accelerate the rate of reaction while

remaining unchanged in the process.

The activity of the catalyst relates to the rate of the reaction that is taking place.

Rate can be expressed in a number of ways, often specific to the particular applica-

tion. In HRSG applications, CO conversion across the catalyst is an overall compar-

ative expression of the rate. Comparing two catalysts at a specific set of conditions

and a specific volume of catalyst, a higher level of CO conversion indicates a

higher rate of activity.

The reaction of CO and oxygen can only form CO2. No other reaction products

are possible. However, the reaction of hydrocarbons with oxygen can result in a

number of different reaction products. In a HRSG application, the most desired pro-

ducts are CO2 and water. However, depending on the actual reaction pathway, CO

and aldehydes could also be formed.

Figure 9.1 The catalyst and tunnel analogy.

175Carbon monoxide oxidizers

The selectivity of the catalyst describes its ability to direct the reactants to spe-

cific products. In the chemical industry the term “yield” is often used. This is the

amount of desired product formed per amount of reactant consumed. In HRSG

applications the preferred product is CO2 and the desired yield (from CO or from

hydrocarbons) is 100%. Precious metal catalysts selectively favor the reaction path

that leads to CO2. As a result, the most preferred oxidation catalysts in HRSG

applications are precious metal based. By contrast, in the chemical industry, base

metal (vanadium based) oxidation catalysts are used when the reaction path that

leads to the aldehyde reaction products is desired.

A catalyst can be chosen for its activity, its selectivity, or for both. In HRSG

applications where only CO oxidation is required, the choice is driven by activity

only. When hydrocarbon oxidation also is required, both activity and selectivity

must be considered. Several catalysts can all have similar activity for the CO and

oxygen reaction but can differ greatly in their activity for the hydrocarbon and

oxygen reaction and in their selectivity for the reaction of hydrocarbon and oxygen

to form CO2.

9.2.2 Catalytic reaction pathway

The following is a common way of describing the catalytic process as it relates to

the oxidation catalyst in the carbon monoxide oxidizer. Despite pervasive myths,

catalysis is not “black magic” but rather a well-understood chemical process.

The first step is mass transfer diffusion of the reactants from the bulk exhaust

(fluid) to the external surface of the oxidation catalyst. Bulk mass transfer is

affected by the specific molecules that are diffusing, in this case CO and O2, the

dynamics of the flow conditions, and the geometric surface area characteristics of

the oxidation catalyst.

Although there are some active catalytic sites on the surface, the bulk of the

active sites are within the pores of the carrier. The carrier (or support) is a high-

surface-area material containing a pore structure in which the active catalyst sites

are deposited. The molecules of CO and O2 must diffuse from the surface into the

pores that lead to the active sites.

When the CO and O2 reactants reach an active site, they must adsorb onto the

active catalytic site. The O2 dissociates very quickly and CO and O each chemisorb

onto adjacent catalytic sites.

The desired chemical reaction can now take place. An activated complex forms

between adsorbed CO and adsorbed O. The activated complex converts then to the

product CO2, adsorbed on the surface.

The product CO2 desorbs from the active catalytic site. The desorbed product CO2

diffuses through the pores of the carrier toward the external surface of the catalyst.

The final step is the product CO2 diffusing from the external surface of the oxi-

dation catalyst into the bulk exhaust. This step, like the first, is bulk mass transfer.

The slowest step in the above sequence will be the rate-determining step and

thus control the overall rate of the reaction. Consider the CO and O2 reaction shown

in Fig. 9.2


Referring to the figure, below 500�F, the reaction is controlled by temperature.

This means that the reaction rate of adsorbed CO with adsorbed O is slow relative

to diffusion or mass transfer and is thus the rate-determining step. As the tempera-

ture is increased, the rate of reaction increases proportionally.

In this example, between, B500�F and B650�F, the rate-determining step is

pore diffusion. The rate of conversion of CO and O to CO2 at the active site is fas-

ter than the rate at which the reactants are supplied to the active site. A concentra-

tion gradient exists within the pore. Some active sites deep within the pore may not

be completely utilized. The rate of reaction is thus controlled by the size and shape

of the pores and the diffusion properties of the reactants (CO and O2) and products

(CO2) within the pores. Modifying the size and shape of the pores is one way of

improving performance in this region of the response curve.

Above 650�F, the reaction is no longer controlled by temperature or pore diffu-

sion as the rate-determining step is bulk mass transfer. The rate of mass transfer dif-

fusion from the bulk to the surface is slow compared to the other steps. The CO

and O2 react as soon as they reach the surface. To increase the CO conversion,

more geometric surface area must be added.

9.2.3 The effect of the rate limiting step

The catalyst supplier looks to optimize the design of the catalyst for the particular appli-

cation in which it will be used. Oxidation catalysts being considered for use will each

have a characteristic CO conversion versus temperature response as shown in Fig. 9.3.

Figure 9.2 Conversion temperature response versus region of control.


The actual shape of the curve can shift as the catalyst ages (as shown in

Fig. 9.4). The response curve can provide insight into steps that can be taken to

modify the catalyst performance.

Figure 9.3 Typical CO conversion versus temperature response.

Figure 9.4 Relative changes in conversion/temperature response for various deactivation modes.


This discussion gets more complicated when hydrocarbon conversion also is

required. As shown in Fig. 9.5, each specific hydrocarbon will have a unique char-

acteristic conversion versus temperature response curve. Each response may age

differently.

The desire is always to select a catalyst that is in bulk mass transfer control over

the range of operating conditions in the specific HRSG. The catalyst supplier also

must design for end-of-life performance. What could be under mass transfer control

at the start of the operating period could become under pore diffusion control if the

surface becomes covered with surface deposits. This is referred to as masking and

is discussed in more detail in Section 9.5.4. Masking also can cause the level of

bulk mass transfer to be substantially reduced.

Standard cost-effective catalyst designs have been developed for CO control by

the carbon monoxide oxidizer in the HRSG. Hydrocarbon control typically requires a

more customized catalyst, as the rate-determining step for the reaction of hydrocar-

bons may be temperature (kinetics) rather than mass transfer as is the case for CO.

9.3 The oxidation catalyst

9.3.1 The active material

The catalytic material for the CO plus oxygen and the hydrocarbon plus oxygen

reactions to form carbon dioxide and water has been the subject of many studies.

Figure 9.5 Conversion/temperature response for various hydrocarbons.


Base metal oxides, precious metals, and combinations thereof have been used for

oxidation applications.

Platinum and mixed-metal platinum/palladium catalysts have been the most

commonly used oxidation catalysts in HRSG applications. Platinum typically has

been preferred for applications focused on CO control. When consideration must be

given to the oxidation of saturated hydrocarbons and/or the impact on trace com-

pounds such as NO and SO2, a mixed-metal design of platinum/palladium typically

is considered as an alternative. Adding palladium to platinum can improve the

ignition characteristics for some hydrocarbons. This can help to operate at lower

temperatures than platinum-only designs. Generally speaking, adding palladium

does not improve the ignition characteristics for CO.

Some unique HRSG applications have required the use of palladium-only

catalyst.

Base metal oxides have not yet seen much use in carbon monoxide converters in

HRSG applications.

The catalyst suppliers ultimately determine the optimal active material and its

amount used in the catalysts they are supplying for the conditions specified for the

HRSG. Based on their experience with the specific catalyst formulation and with

the specific application, they must warrant the end-of-life performance of the oxida-

tion catalyst.

9.3.2 The carrier

The carrier (or support) is a high-surface-area material containing a pore structure

in which the active catalyst sites are deposited. The initial carriers were designed as

inert substances to spread out an “expensive” catalytic material, maximizing its

access to the reactants of a desired reaction. Carriers have evolved to incorporate

other benefits to the catalyst. These include improving thermal stability, adding sul-

fur resistance, and adding reaction promoters.

The most commonly used carrier in CO catalysts designed for HRSG applica-

tions is alumina based. There are many types of alumina materials available for use

varying on surface area, pore size distribution, surface acidic properties, and crystal

structure. Each catalyst supplier will have specific preferred materials that they use.

The choice is made to be compatible with their particular catalyst formulations, the

actual manufacturing process they use, and the temperature extremes in the targeted

application.

The actual crystal structure of the carrier is affected by exposure temperature.

As the exposure temperature is increased, the crystal structure can go through irre-

versible phase changes yielding a pore structure different from its original design.

The alumina phase actually seen on a returned catalyst may identify the range of

maximum use temperatures seen in the operating unit.

Silica- and titania-based carriers are of interest to catalyst suppliers because of

their resistance to sulfur. Fuels in HRSG applications may contain varying levels of

sulfur. Silica and titania have been used by themselves as carriers, as well as

blended with alumina, to improve the sulfur resistance of the alumina carrier.


Various trace components also may be added to the carrier to improve its ther-

mal stability by reducing the rate of sintering and phase transition. Ceria and lantha-

num are two common examples.

In some applications the oxidation catalyst may require washing to remove

masking agents. Although deionized water is most commonly used, in some cases,

mild acid or mild caustic solutions may be required. The carrier must be able to

withstand the proposed washing procedure. Whenever washing is being considered,

the proposed washing procedure should be reviewed with the oxidation catalyst

supplier to ensure that the specific catalyst being used will not be damaged by the

washing procedure.

9.3.3 The substrate

Most environmental applications now use honeycomb or monolithic substrates to

minimize the pressure drop associated with the relatively high exhaust flow rates

encountered. These substrates inherently have some surface porosity and could be

coated directly with catalyst but the standard is to coat with a carrier material that

has the catalysts embedded within it or on it. This addresses the need for surface

area in an application where the rate-limiting step for CO conversion is mass trans-

fer diffusion.

Most honeycombs in HRSG applications are ceramic or metallic based.

Cordierite, a blend of alumina, silica, and magnesium, is a material commonly used

to make ceramic honeycombs. Most ceramic honeycombs used in HRSG are

extruded as square blocks made up of square shaped cells within the block. Each

die forms a specific cpsi (cells per square inch). The higher the cpsi the higher the

geometric surface area.

Fecralloy, a ferritic stainless steel with aluminum, is a material commonly used

to make metallic honeycombs. These honeycombs come in a broader range of

shapes and cpsi than ceramic depending on how the structures are actually made.

Many metallic honeycombs start out as flat material that is then crimped, folded,

and shaped into a final assembly. Some assemblies are then brazed to provide addi-

tional structural integrity. The principal advantage of the metallic honeycomb is the

thin wall of the metal monolith relative to the ceramic extrusions, which results in

lower pressure drop than is typically available with ceramic supports.

The actual shape of the honeycomb cell (whether ceramic or metallic) can greatly

impact the flow properties within the honeycomb and thus impact the catalytic perfor-

mance and the pressure drop. While general correlations are available in the literature

to estimate mass transfer and pressure drop characteristics, each catalyst supplier will

fine-tune the coefficients within the correlations to enable more precise performance

calculations for the specific substrate material that is being used.

The honeycomb is typically packaged in some form of metal container. Many

commercial units have the containers sized (2 ft.3 2 ft.3 0.25 ft.) so that they will

fit through an access door and so that an individual can install them within the

housing (,50 lb). Other designs utilize large panels that are dropped into place


using a crane. Normally the design configuration is agreed on between the HRSG

supplier and the catalyst supplier.

9.3.4 Putting it all together

Catalyst design is the art of selecting the right active material to produce the desired

chemistry in the HRSG application, selecting the right carrier to support the active

material in the specific conditions of the HRSG application, and then selecting the

right substrate to provide contact between the catalyst and the exhaust flow being

treated in the HRSG application. To “put it all together,” though, is to exercise the

skill required to consider the characteristics of the HRSG application as well as the

unique characteristics of the specific active material, carrier, and substrate.

For example, by their nature, HRSGs go through thermal cycles during their nor-

mal operation. Just as the HRSG designer must consider the effects of differential

thermal expansion within the components in the HRSG, the catalyst supplier must

also consider these effects as well. Oftentimes, catalyst materials (e.g., substrates,

module assemblies) will be in contact with materials that have different coefficients

of thermal expansion. This must be considered by the catalyst supplier in the design.

To maximize the effectiveness of the catalyst, the exhaust flow must go through

the catalyst and not bypass unreacted through any physical gaps. Various types of

ceramic-based gasket materials are routinely used as part of the catalyst and/or cata-

lyst frame assembly installation into the HRSG duct. Normally, when this is done,

the catalyst supplier provides or approves the material to be used. If the material is

replaced it is important that the replacement material can withstand the same tem-

perature as the original material.

Some HRSGs may be expected to have harsher exhaust environments, perhaps

due to fuel considerations. If acid gases are present or if the oxidation catalyst is

expected to require routine washing, the catalyst supplier may utilize specific car-

riers and specific packaging methods that are more suited for this situation. This

typically is reviewed and discussed early in the project so that it can be factored

into the original design. While many HRSGs require no catalyst maintenance, some

have required periodic washing. However, it is important to consider that the wash-

ing procedure that works for one catalyst could irreparably damage another

catalyst.

Each catalyst supplier has a particular catalyst portfolio, manufacturing process,

and experience list. The more experience a particular catalyst supplier has in a par-

ticular type of HRSG application, the more likely that the catalyst will perform as

expected and withstand the conditions of the application.

When new HRSG applications are encountered, the more experience a catalyst

supplier has in all HRSG applications, the less likely that the catalyst will not per-

form as expected nor withstand the conditions of the application. For new applica-

tions still having serious questions regarding the suitability of a catalyst, it has not

been uncommon to mount a sample of standard catalyst into the duct to see how it

ages and whether the catalyst may be improved with respect to active material,

carrier, and/or substrate.


9.4 The design

9.4.1 Defining the problem

Defining the problem starts with the governing environmental operating permit.

This document not only will define the maximum allowed emission levels in the

stack but it also will determine how compliance to the permit will be measured and

reported. This all must be considered in the design of the emission control system,

which often will include the carbon monoxide oxidizer.

Early operating permits often only applied to full load operating points. No spe-

cific control was required during the transient startup phase of operation. Part load

operating points were subsequently added and now it is more typical that control be

maintained through the whole range of operating conditions, from startup to shut-

down. It is now not that uncommon for catalyst suppliers to be presented with liter-

ally hundreds of sets of potential operating conditions, all of which must be

considered in the design phase.

The fuel intended for use in the application must be considered, especially as

some sites may require the use of multiple fuel sources. This is an important con-

sideration for the catalyst supplier as typically catalysts will age differently depend-

ing on the type of fuel being used due to its trace constituents and contaminants.

Many gas-fired applications are designed to utilize fuel oil as a backup fuel primar-

ily during cold month operation. Determining the exposure of the catalyst to the

trace materials in the fuel, such as by specifying a maximum number of operating

hours expected each year on each fuel, aids the catalyst supplier in optimizing the

design to account for the expected aging of the catalyst.

It is important to identify, when possible, the actual sulfur compound present in

the fuel. Typically seen compounds are hydrogen sulfide, tert-butyl mercaptan, and

thiophane. The general assumption is that these compounds will form SO2 in the

combustion process and that the sulfur compound inlet to the carbon monoxide oxi-

dizer will be all SO2. Catalyst designs are based on that assumption. The chemistry

on the catalyst can be different when non-SO2 sulfur compounds contact the cata-

lyst surface.

The carbon monoxide oxidizer, as its name implies, was originally implemented

when operating permits specified only CO emission limits. However, permits have

evolved to take advantage of the carbon monoxide oxidizer’s cobenefit to reduce

some hydrocarbons.

This practice has really complicated design considerations for catalyst suppliers.

Numerous terms for hydrocarbons have been seen in environmental permits and in

equipment specifications. Terms most often used recently are VOCs and/or HAPs.

What is a VOC? Literally, a VOC is a volatile organic compound, which gener-

ally means a compound that evaporates or sublimes at room temperature. However,

the precise definition for VOC actually varies from country to country, and in the

United States, even from state to state. Often the definition will be linked to a par-

ticular analytical technique, which then will exclude any organic compound not

detected by that particular technique.


What is a HAP? The National Emissions Standards for Hazardous Air Pollutants

(NESHAP) applies to air pollutants that are not covered by the National Ambient

Air Quality Standards (NAAQS). NESHAP lists a number of specific organic com-

pounds deemed hazardous that must be reduced, hence the term hazardous air pol-

lutant” (HAP). Formaldehyde, acetaldehyde, acrolein, and benzene are HAPs

typically seen in HRSG applications.

Why is this important? The issue is defining what specific hydrocarbons are

actually present inlet to the catalyst. Each specific VOC or HAP will react uniquely

across the carbon monoxide converter. While the catalyst may be designed to pro-

vide a constant CO conversion over a wide operating temperature range, the hydro-

carbon conversions can vary widely. This must be considered in the sizing of the

catalyst to meet the specific requirements of the operating permit.

In defining the emissions problem to be solved, the precision of the measurement

technique also must be considered relative to the expected hydrocarbon levels inlet

to and exit from the carbon monoxide oxidizer. Will all of the hydrocarbons be

detected at their actual levels or will some be measured as being lower due to the

actual technique? For example, flame ionization detectors (FIDs) in hydrocarbon

analyzers have a suppressed response for oxygenated hydrocarbons. Within the

errors of the measurement, can a hydrocarbon conversion reasonably be measured?

The carbon monoxide oxidizer will oxidize some of the NO to NO2. This can

become a design consideration for the carbon monoxide oxidizer if there is a down-

stream SCR system having a maximum inlet NO2 level specified in its design basis.

Generally most of the NOx is NO, and in most cases, it can be assumed to be

90�95% NO, although often, the NOx is reported in specifications and in permits

as being NO2.

Suppliers of the oxidation catalyst must consider in their design each of the oper-

ating points covered by the operating permit, including fuel considerations. For

each operating point, the specified volume of oxidation catalyst will have expected

and end-of-life estimates of:

� conversion of CO to CO2

� conversion of VOC/HAP/NMHC to CO2 and H2O� conversion of SO2 to SO3

� conversion of NO to NO2

Based on these conversions, the proposed oxidation catalyst must meet the oper-

ating permit requirements, and be verifiable by field measurement technique, for all

of the specified commercial operating points for the specified warranty period.

9.4.2 Choosing the catalyst

As shown in Fig. 9.6, everything that contacts an oxidation catalyst is oxidized, but

not necessarily to the same degree.

Generally, the oxidation catalyst performance is determined by temperature and

geometric surface area with catalyst formulations modified to enhance or inhibit

certain reaction pathways.


Each oxidation catalyst will have a unique CO conversion versus temperature

response curve. Typically the CO conversion response is flat (reaction rate limited by

mass transfer) over the temperature range of 600�1000�F. To get higher conversion,

more surface area is required. This means higher catalyst volumes and/or higher pres-

sure drops if the catalyst surface is packed more densely (i.e., has a higher cpsi).

Hydrocarbon conversion depends on the type of hydrocarbon that is actually

present inlet to the oxidation catalyst. Each hydrocarbon will have its own charac-

teristic conversion versus temperature response curve. Note that above B700�F, theresponse for formaldehyde can be nearly identical to that for CO. In some cases,

the EPA has allowed the measured conversion of carbon monoxide to be used as a

surrogate measurement for the actual conversion of formaldehyde.

However, if the hydrocarbon is 100 C31 (propane/propylene and larger) and

50% saturated (often referred to as NMNEHC in standards and permits) the conver-

sion can be much lower.

Generally speaking, as the temperature increases, the level of SO2 to SO3

increases. Over a wide range of operating conditions this could result in a wide

range of SO3 levels exit from the oxidation catalyst and each operating point must

then be considered in terms of particulate matter calculations for the stack and/or

solid deposition considerations on heat transfer surfaces downstream of any SCR

component in the system.

The level of SO2 inlet to the oxidation catalyst can also impact the choice of

oxidation catalyst formulation and is typically requested by catalyst suppliers. In

some cases, the sulfur may adsorb on the catalytic surface thereby inhibiting the

Figure 9.6 Representative performance of oxidation catalyst.


surface reactions and reducing expected catalyst performance. Depending on the

extent of inhibition and the actual range of operating conditions, this inhibition may

be overcome by adding more surface area to the design.

When SO3 forms on the catalyst surface, some of it can irreversibly react with

the catalyst surface and cause a permanent reduction in activity. Some formulations

have been developed to reduce the amount of permanent reduction. These have

been used in select applications.

Note that the NO to NO2 conversion response has a temperature where the con-

version peaks. Further increasing the temperature does not further increase the NO

to NO2 conversion. This is caused by the equilibrium relationship between NO and

NO2. The equilibrium relationship drives the distribution to NO as the temperature

is increased. The peak temperature can be affected by the catalyst and by the aging

characteristics of the catalyst.

Improving the oxidation performance at lower temperature can be addressed by

adding more catalyst surface area (brute force) or, more typically, by changing the

catalyst formulation. Oftentimes this can lead to a more expensive solution. In addi-

tion, the effect of more catalyst surface area or a different catalyst formulation on

the other reactions must then also be considered.

For example, adding palladium to platinum to form a mixed-metal oxidation cat-

alyst can improve the ignition characteristics for some hydrocarbons, but palladium

is more sensitive to deactivation from sulfur and thus may deactivate faster. This

must be considered in the overall cost analysis.

The broader an oxidation catalyst supplier’s portfolio of technology, the more

detailed the discussion may be to determine which catalyst is the best fit for the

particular HRSG application.

9.4.3 Determining the catalyst volume

The standard performance warranties for oxidation catalyst will specify a minimum

conversion performance for a specified time period at specified operating condi-

tions. Since pressure drop is an important design consideration in HRSG applica-

tions, a maximum pressure drop through the carbon monoxide oxidizer also will be

stated for each operating point.

In most HRSG applications the typical catalyst aging assumption is to assume a

loss of catalyst surface area over time due to the accumulation of deposits on the

catalyst surface. The rate of accumulation can be affected by a number of factors.

Some “gas fired” applications are known to be “very clean” from a catalyst per-

spective. Some “oil fired” applications are known to be “dirty” from a catalyst per-

spective. Catalyst suppliers, based on their experience, will determine which aging

rate is the most appropriate for their specific catalyst in a specific application.

Additional catalyst surface area may then be added to overcome noncatalyst issues:

� analytical precision issues in performance measurements� flow distribution issues outside standard design assumptions� temperature distribution issues outside standard design assumptions


The calculated fresh conversion minus the conversion loss due to expected aging

and minus the conversion loss due to noncatalyst issues must be equal to or greater

than the end-of-life conversion performance requirement for each of the operating

points. All potential operating points (where the operating permit applies) must be

considered.

For most carbon monoxide oxidizer applications, the design is based on meeting

a CO standard. The hydrocarbon conversion is then reported for that design. More

recently, however, in some applications, the hydrocarbon conversion requirement

has driven the design. The sizing approach remains the same although with a

greater sensitivity to noncatalyst issues associated with hydrocarbon definition, spe-

ciation, and measurement.

9.4.4 System considerations

The supplier of the carbon monoxide oxidizer will typically state its design assump-

tion for the system. Most often, these assumptions pertain to:

� the flow distribution inlet to the oxidizer� the temperature variation inlet to the oxidizer� analyzer resolution

There is always an open question: Is it more cost effective to add catalyst to

overcome the system issues than it is to spend money to improve the system design

and fabrication?

The carbon monoxide oxidizer will add pressure drop within the duct. Pressure

drop can help distribute flow within the duct. However, generally speaking, a prop-

erly designed perforated plate upstream of the oxidation catalyst is a less expensive

means of distributing the flow for optimum catalyst utilization.

When a temperature variation is specified, conversion is calculated at the tem-

perature extents and additional catalyst may be added to the design to raise perfor-

mance at the lower temperature. The higher the temperature, the less the impact of

a temperature variation on carbon monoxide conversion. This is a consequence of

designing catalyst to operate in the region of mass transfer control.

Hydrocarbon ignition on a catalyst design for CO control is much more sensi-

tive to temperature, so oftentimes the temperature variation could be the differ-

ence between very little hydrocarbon conversion and very high hydrocarbon

conversion.

As conversion requirements get greater and greater, the ability to measure abso-

lute conversion values gets more and more difficult and challenges the precision of

the analytical equipment. Even measuring carbon monoxide in the stack at very low

levels can become more difficult. For example, CO2 levels that are present in the

combustion chamber exhaust can interfere (positive bias) with the CO measure-

ment. Although this can be overcome with proper sample conditioning, it can add

additional complexity/cost to the analytical system.


One practical solution to this issue is to specify a maximum allowable stack

limit, size the catalyst volume to provide the required conversion rate, but then

work with the regulator to have the permit accept either condition being met—

emission stack limit or emission conversion rate—but not both. This approach

would enable the operator to realize the benefit should the carbon monoxide from

the combustion process be lower than expected, as it often is.

Adding additional catalyst just to overcome analytical precision issues is

believed to be cost prohibitive. Rather, the money spent on the additional catalyst

could be better spent on an improved analytical system.

9.5 Operation and maintenance

9.5.1 Initial commissioning

The oxidation catalyst should be thought of as a very expensive filter. Any debris

in the duct at startup potentially will collect on the catalyst. Since debris is typically

not catalytic in nature, the result will be lower-than-expected performance as the

fresh catalyst is covered by inert material.

Most catalyst suppliers recommend that the first fire and shakedown period of

the combustion section of the HRSG system be completed before installation of the

catalyst. However, sometimes the operating permit precludes this unless a case can

be made that there is significant risk to the oxidation catalyst. If left in place during

the first fire and shakedown period, care must be taken to ensure that the “very

expensive filter” remains free of debris and undamaged.

Minimally, all of the upstream ducting should be cleaned out of all construction

materials and debris. The floor should be swept or vacuumed. Anything that is

loosely adhering to the walls of the housing or other internal surfaces can poten-

tially break free and deposit onto the oxidation catalyst. Fluid leaks and mechanical

failures of upstream components typically present the biggest potential risks to the

oxidation catalyst and should be minimized during commissioning. Trace compo-

nents in system fluids can irreparably deactivate by chemically poisoning the oxida-

tion function of the catalytic surface. Mechanical failure can result in objects

impacting the catalyst surface and, depending on the nature of the object and the

nature of the catalyst, causing physical damage to the catalyst.

9.5.2 Stable operation

As soon as possible after the initial startup and commissioning phase is completed

the operating conditions and performance values for the main operating points

should be cataloged for future reference. The intent should be to compare the

observed performance against the nearest commercial operating points in the

instruction manual. Significant differences should be reviewed with the supplier for

clarification.


Catalysts are sized based on the conversion required for a particular set of oper-

ating conditions. Commercial installations typically only measure the stack emis-

sion levels for comparison against the operating permit.

For each operating point, a maximum catalyst pressure drop is specified. Early

installations typically monitored the catalyst pressure drop. More recently, only

local gauges might be in use. However the back pressure at the turbine (upstream

of the HRSG train) is typically available.

Going forward, trending the stack CO emission measurement and the pressure

drop/back pressure values for typical operating points is a valuable first “red flag”

indicator as to whether something has changed in the operation of the oxidation

catalyst.

An increase in the back pressure/pressure drop can be an indication of catalyst

plugging. Back pressure caused by the buildup of surface debris will eventually

impact oxidation performance.

Similarly, a noticeable change in the measured stack emission level can be an

indication of a change in catalyst performance.

In the typical HRSG application, the CO conversion rate across the oxidation

catalyst is not affected by the CO concentration inlet to the oxidation catalyst.

When fuel sources change, however, there could be a change in the actual emis-

sions coming from the combustion chamber. An increase in stack CO emissions

could be misinterpreted as a change in oxidation catalyst activity when, in fact, it is

due to a change in the fuel source.

Oxidation catalyst suppliers typically encourage an ongoing dialogue with the

site, particularly when there has been a noticeable change in performance. If the

cause for the change cannot be determined, the oxidation catalyst supplier may

recommend that catalyst samples be removed and evaluated.

9.5.3 Data analysis

The owner of the HRSG cares most about the measured stack emission levels. If

the measured emission levels are lower than the maximum allowable levels speci-

fied in the operating permit, the HRSG can continue to be operated. However, if

the measured stack CO level increases and/or approaches the stack permit limit, a

dialogue may begin with the catalyst supplier. The first step in the discussion is to

compile enough information so that the catalyst supplier can estimate the perfor-

mance expected based on the actual operating conditions and compare this against

the actual measured performance.

In most HRSG applications the % CO conversion across the oxidation catalyst is

independent of the inlet CO concentration. If the stack CO increases, it could sim-

ply be due to an increase in the inlet CO. In most HRSG applications, the CO inlet

to the catalyst is not routinely measured.

If the exhaust flow rate through the catalyst increases, the % CO conversion will

decrease. Oftentimes, in HRSG applications, the exhaust flow through the catalyst

is estimated by a combustion mass balance calculation rather than an actual mea-

surement. However, when formal stack tests are done, an exhaust flow rate


measurement typically is performed. That measured value should be compared with

the estimated flow value for the test period. If the estimated flow value is signifi-

cantly different, the flow calculations should be reviewed and modified as

necessary.

When available, the measured pressure drop across the catalyst can be used to

estimate the exhaust flow through the catalyst by way of the catalyst supplier’s

product performance models.

If the pressure drop through the oxidation increases it could also mean that the cat-

alyst face is plugging with deposits. If the plugging continues to increase, eventually

the stack CO level also will start to increase due to a loss of active surface area.

Once enough information is compiled to determine which design operating point

is closest to the actual operating point, the supplier of the oxidation catalyst can

then begin to assess the significance of the actual measured performance. For each

design operating point there will be an expected fresh level of performance and an

end-of-life performance based on proprietary aging models.

As discussed previously, the end-of-life performance will be based on a number

of factors. From an operational standpoint, typically the most significant piece of

information is the number of operating hours, which acts as a surrogate for catalyst

contaminant accumulation.

A critical assessment is made as to whether the measured performance is consis-

tent with what would be expected based on the operating conditions and the number

of operating hours. Oftentimes, as part of this review, a catalyst sample will be

removed and evaluated in an outside laboratory. Typically, this evaluation will

include an intrinsic activity test and some form of a contaminant analysis. The

results of the activity test can then be used by the catalyst supplier to place the con-

dition of the catalyst on its assumed aging curve between fresh activity and end-of-

life activity.

If there remains a question about the commercial performance or if there is a

discrepancy between the results of the activity test on the catalyst sample and the

commercial performance, the next step in the analysis is to investigate how chang-

ing the operating conditions might explain the anomalies. The catalyst supplier can

investigate possible explanatory scenarios using the same proprietary models under-

lying the original design.

Typical investigations include:

� How much would the catalyst have to be deactivated to explain the commercial results? Is

this deactivation consistent with the activity of the test sample?� If the pressure drop (or the static pressure upstream of the carbon monoxide oxidizer) is

higher than expected, what higher-than-expected flow would explain this? Would this

higher flow explain the higher-than-expected stack level of CO?� If the pressure drop (or the static pressure upstream of the carbon monoxide oxidizer) is

higher than expected, how much of the oxidation catalyst frontal area would need to be

blocked to explain? Would the subsequent reduction in effective oxidation catalyst vol-

ume explain the higher-than-expected stack level of CO?� Based on the activity of the test sample and the measured stack level of CO, what would

the CO inlet to the oxidation catalyst need to be? Could this level be possible?


Leakage of inlet levels of CO around the support framework and/or around the

catalyst modules in the carbon monoxide oxidizer can also cause higher-than-

expected stack numbers. A leakage, or bypass, flow rate of inlet CO sufficient to

explain the observed performance at the operating temperature can be calculated.

However, it is often difficult to relate the calculated gap size to the size of a visual

gap viewed at ambient temperatures. This is why the gasket material in the assem-

bly is carefully positioned during the catalyst installation and routinely inspected

thereafter. Normally, gasket inspections are meant to verify that all gaskets are in

position and snug. A missing or loose gasket at ambient temperatures will only

result in a larger problem at operating temperatures.

9.5.4 Catalyst deactivation mechanisms

All catalysts deactivate eventually. Based on the design conditions of the applica-

tion and considering the expected deactivation mechanisms and deactivation rates

of the catalysts being considered, the oxidation catalyst supplier must provide a cat-

alyst at a volume that will meet the performance required over the warranty period.

Most oxidation catalysts in HRSG applications last long past the specified warranty

period. This section will briefly discuss the standard catalyst deactivation mechan-

isms as they might relate to HRSG applications.

Consider a typical catalyst system comprised of a substrate, a carrier (washcoat),

and an active metal (catalyst) dispersed throughout as shown in Fig. 9.7.

Thermal deactivation, or sintering, is often the first deactivation mechanism con-

sidered by the catalyst supplier. Typically, the oxidation catalyst supplier will detail

in its warranty statement the maximum allowable continuous operating temperature.

Often there will also be a maximum exposure temperature specified along with a

time limit for that exposure.

Sintering causes irreversible changes to take place on the catalyst that result in a

permanent decrease in activity. As shown in Fig. 9.8, as precious metals sinter,

active reaction sites agglomerate resulting in larger crystal sizes and lower disper-

sion. Ultimately this will result in lower activity. As the high-surface-area carrier

material sinters, pores can collapse, blocking access to internal active reaction sites.

This will also result in lower activity.

Figure 9.7 Representation of catalyst system.


Typically, sintering is not seen in HRSG applications during routine operation as

extreme temperature excursions outside the expected operating temperature win-

dows are very rare occurrences.

Poisoning, as defined herein, is the forming of chemical bonds between contami-

nants and the active sites or with the carrier material that results in a permanent

reduction in catalyst activity. This is shown in Fig. 9.9. The oxidation catalyst sup-

plier will include a list of known catalyst poisons in the performance warranty

statement.

Typically, poisoning is not seen in HRSG applications as care is taken during

the quotation process to ensure that known catalyst poisons are not contained in the

HRSG application.

The most common cause for deactivation of the oxidation catalyst in HRSG

applications is masking. As shown in Fig. 9.10, masking involves physical bonds or

weak chemical bonds between contaminants and the active sites or with the carrier

material. Performance loss is due to a decrease in accessibility to the active sites

rather than a chemical change at the active sites.

When masking occurs, the deactivation can be reversed by a suitable cleaning

procedure. For many HRSG applications, masking has resulted from the buildup of

physical deposits on the catalyst surface. Oftentimes this has been the buildup of

ceramic fibrous materials traceable back to insulation material from internally insu-

lated ducts or from failed insulation liner plates. In these cases, compressed air has

Figure 9.8 Representation of thermal deactivation of catalyst.

Figure 9.9 Representation of catalyst poisoning.


often been used to remove the accumulated debris and restore access to the active

sites. In more extreme applications, acid or alkaline solutions have been used espe-

cially to remove nonfibrous contaminants. If the deactivation cannot be reversed by

a cleaning procedure, by assumption, the catalyst has been poisoned rather than

masked.

If a cleaning procedure is being considered it is very important that the catalyst

supplier be part of the discussion. They should review and approve the specific pro-

cedure being considered. For example, compressed air, if used improperly or at an

excessive pressure, can damage the catalyst or drive surface contaminants deeper

into the pore structure. If acid and/or alkaline solutions are considered for use, then

the wrong concentration or the wrong sequencing of the solutions in the wash pro-

cedure may cause irreparable damage to the catalyst surface. For reference, acid

and/or alkane solutions are often used in some chemical processes at concentrations

sufficient to intentionally remove the catalyst coatings from their support.

Inhibition of the active sites is a deactivation mechanism that is temporary and

reversible. Sulfur is present in many HRSG applications since it is present in vary-

ing levels in the fuels being burned in the combustion chamber. When SO2 is pres-

ent near the catalyst surface, the CO and hydrocarbon oxidation reactions can be

inhibited due to the competition with SO2 competing for space on the active site. If

the source of the SO2 is removed, the SO2 near the surface can dissipate and reac-

tivity for CO and hydrocarbons can return to normal.

Factors that can impact the extent of the inhibition effect include the following:

� amount of SO2

� precious metal type� washcoat/carrier additives� temperature

Sulfur is uniquely problematic in that it can act either as an inhibitor or as a poi-

son. For example, some of the SO2 on the active site, for example, may react with

neighboring alumina in the carrier to form alumina sulfate, which remains in the

carrier and blocks access to other active sites. This effect is irreversible and so is

considered to be poisoning.

Figure 9.10 Representation of catalyst masking.


9.5.5 Catalyst characterization

The supplier of the oxidation catalyst for the HRSG may use a myriad of tools to

characterize the condition and performance of a catalyst. Catalyst performance

requirements and catalyst aging mechanisms can vary widely from application to

application and a broader experience base of the catalyst supplier yields greater

access to a greater number of characterization tools they may employ in a more

thorough analysis of the catalyst as necessary. Table 9.1 summarizes typical charac-

terization methods that have been used in HRSG applications. A more detailed dis-

cussion of these tools and their use is beyond the scope of this book.

For most HRSG applications, the standard characterization of an oxidation catalyst

sample includes some form of CO activity test and some form of surface contaminant

analysis. Comparisons are made against “fresh” standards to assess the extent of

deactivation and make qualitative statements about the presence of contaminants.

Each catalyst supplier will have its own recommended catalyst characterization

process. Samples are often provided in the initial installation that can easily be

removed. Ceramic catalyst samples often are removed utilizing a circular drill bit to

extract a core from the bed. In some cases, a complete module assembly is

removed/replaced.

Typically, the supplier of the oxidation catalyst offers this characterization as a

service or can recommend another vendor who has experience working with their

catalyst. While the actual characterization work can be straightforward to perform,

it is the interpretation of the results that can be difficult. Oftentimes only the

Table 9.1 Typical catalyst characterization tools

Characterization tool Purpose

XPS X-ray photoelectron

spectroscopy

Identifies elements on a surface

(,50 angstroms into catalyst) and

their chemical state

TGA/DTA Thermogravimetric analysis Determines temperatures at which

materials undergo a reaction or

phase change

EPMA Electron microprobe analysis Characterize catalyst architecture

SEM Scanning electron microscopy Identify location of elements in

carrier

XRD X-ray diffraction Characterize structure of catalyst,

carrier material

AA Atomic absorption Determination of elements in

prepared solution

ICP Inductively coupled plasma

electron spectrometry

Determination of elements in

prepared solution

XRF X-ray fluorescence Characterize elemental compositions

of catalyst and deposits


original supplier can comment on the extent of deactivation compared to their

design assumptions for that installation or on the qualitative significance of specific

identified contaminants.

The warranty statement provided by the supplier of the oxidation catalyst may

specify specific characterization tests that would be done if there is a warranty

claim. These tests are quantitative in nature and often different from the qualitative

or semiquantitative tests routinely done in the standard characterization of a field

sample. Testing may be performed by third party testing firms and the interpretation

of the results is clearly defined in the warranty statement.

The standard contaminant analyses often focus near the top surface of the cata-

lyst layer and often are looking for anomalies. The contaminant analyses for war-

ranty claims, rather, focuses on the entirety, or bulk, of the catalyst in quantifying

the deposition of known contaminants.

9.5.6 Reclaim

Most oxidation catalysts in HRSG applications use precious metals. Since precious

metals have inherent value the natural question is whether there is value in reclaim-

ing this precious metal. The short answer is, “sometimes.”

If the HRSG owner wants to reclaim the value of the precious metal in the oxi-

dation catalyst, the value will be based on the results of a specific precious metal

analysis technique. Normally, the reclaim vendor will specify the particular test that

will be done to establish the value. The results in this test can be dramatically dif-

ferent than the precious metal results that may be reported by a catalyst characteri-

zation test focused on investigating performance.

Normally, the pricing to reclaim the precious metal is based on a fixed proces-

sing charge plus a percentage of the recovered value of the assayed precious metal

amount. Since the price of the precious metal can vary widely there can be a time

limit or a value limit specified in the quotation to reclaim. Oftentimes there will

also be a minimum amount of material specified before the reclaim job will be

considered.

For these reasons, oftentimes individual HRSG owners have limited options for

their single site. Their oxidation catalyst volume may be too small to justify work-

ing with a specific reclaim company. In many cases, the best option is to consider

working with the original supplier of the oxidation catalyst, who can aggregate sev-

eral reclaim streams into a sufficient amount of material to justify the process.

Alternatively, suppliers of the specific oxidation catalyst in the HRSG can provide

recommendations, based on their experience with their catalysts, on how to best

pursue reclaim options for a particular site.

It is not uncommon for identical samples sent to several reclaim vendors to

result in a wide range of reclaim value. Pricing for reclaim services can vary widely

depending on the actual volume processed and the actual process used. Also, the

reclaimed value of the precious metal can vary widely among the vendors as it is

driven by the metal purity attained during the processing. Higher purity levels may

be achieved but at higher processing costs.


A few customers may have a total oxidation catalyst volume spread among

several HRSG sites that is large enough to consider owning the precious metals

themselves, in what the metal trading industry calls a “pool account.” In these

cases, the precious metal asset can be managed via trading strategies for the custo-

mer’s benefit, being a source of value until required for catalyst production.

9.6 Future trends

Generally speaking, the development of catalysts for environmental applications

has been a continuous process. As regulations have become tighter and more

encompassing in scope, improved oxidation catalyst performance has been required.

These improvements historically have been and will continue to be applied, where

appropriate, in HRSG oxidation catalyst applications.

Improved and increased catalyst functionality is a logical progression that will

ultimately be driven by regulations governing the HRSG. Improving the oxidation

of saturated hydrocarbons and methane and decreasing the oxidation of NO to NO2

and SO2 to SO3 are logical expectations.

The increased use of biofuels has introduced new considerations for the supplier

of the oxidation catalyst. The use of biofuels has introduced new trace contaminants

into the fuel, which through combustion introduces new contaminants to the oxida-

tion catalyst. As more and more uniquely different biomass sources are used to

make the biofuel, more and more new contaminants can be expected. Assessing the

impact of these contaminants, developing predictive models to understand their

expected impact on catalyst aging, and developing catalysts more resistant to these

contaminants will be an ongoing effort.

Similarly, the increased use of the fracking process to derive natural gas has

introduced new potential contaminants to natural gas sources. In particular, unique

sulfur compounds that have not been seen before are appearing in the fuel and ulti-

mately on the oxidation catalyst in the HRSG. Development of oxidation catalysts

that are more resistant to these new types of sulfur compounds is already underway.

Contaminants in the fuel can also impact the corrosion chemistry taking place in

the fuel pipeline system. As fuel sources change or evolve, the procedures being

routinely followed to control corrosion within the transmission pipeline may

become inadequate (even temporarily) resulting in the formation of “black powder,”

primarily a mixture of iron oxide and iron sulfide deposits. Typically this is a big-

ger problem for the combustion and HRSG equipment upstream of the oxidation

catalyst. However, if these types of deposits make it to the catalyst, they may be

very difficult to remove.

Fuels can differ widely from country to country and in the United States can

differ regionally. This is consistent with the sporadic incidence of black powder. As

a result, it is expected that, by necessity, fuel handling systems will become more

complex in order to protect the combustion and HRSG system from contaminants

like black powder.


Supplemental reading

[1] R.M. Heck, R.J. Farrauto, S.T. Gulati, Catalytic Air Pollution Control,

Wiley-Interscience., New York, 2002.

[2] C.N. Satterfield, Heterogeneous Catalysis In Practice, McGraw-Hill, New York, 1980.






10Mechanical designKevin W. McGill


Chapter outline


10.2 Code of design: mechanical 200

10.3 Code of design: structural 201

10.4 Owner’s specifications and regulatory Body/organizational review 201

10.5 Pressure parts 20210.5.1 Design methods 202

10.5.2 Design parameters 202

10.5.3 Material selection 202

10.5.4 Mechanical component geometries and arrangements 203

10.6 Mechanical design 20410.6.1 General information 204

10.6.2 Internal “Hoop” stress 204

10.6.3 Reinforced openings (compensation) 205

10.6.4 Allowable design stress 206

10.7 Pressure parts design flexibility 20910.7.1 General information 209

10.7.2 Coil flexibility 210

10.7.3 Material transitions (dissimilar metals) 213

10.7.4 Others 214

10.8 Structural components 21510.8.1 Dead loads 215

10.8.2 Live loads 216

10.8.3 Wind loads 216

10.8.4 Seismic loads 217

10.8.5 Operating and other loads 221

10.9 Structural solutions 22110.9.1 Design philosophy 221

10.9.2 Lateral force-resisting system 222

10.9.3 Longitudinal force-resisting system 224

10.9.4 Anchorage (embedments) 224

10.9.5 Material selection 226

10.10 Piping and support solutions 226

10.11 Field erection and constructability 228

10.12 Fabrication 228



http://dx.doi.org/10.1016/B978-0-08-101940-5.00010-5

10.13 Conclusion 229

References 229

10.1 Introduction

The heat recovery steam generator (HRSG) is composed of numerous mechanical

heating surface components (superheaters, evaporators and economizers) and steam

drums. The heating surface elements are bare and finned tubes integrated with col-

lector headers and interconnecting piping systems. All of the mechanical pressure

parts systems are constructed with structural details and supports. The entire HRSG

is contained within a gas-tight steel casing system with a main structural system to

support all of the components and is anchored at the concrete foundation.

As such, there is a significant engineering effort to perform all of the mechanical

and structural designs required. Thorough design approaches for these components

are necessary to provide reliable solutions and a final delivered and quality con-

structed product that maintains its design integrity during the expected operational

design life of the HRSG.

For the purposes of this chapter, engineering references will be utilized from the

American Society of Mechanical Engineers (ASME), American Society of Civil

Engineering (ASCE), and American Institute of Steel Construction (AISC). It is

understood and acknowledged that there are many different permissible codes of

design around the world, including local codes establishing alternate or additional

requirements for delivering an acceptable and approved engineering design.

The primary design code utilized for mechanical components, i.e., pressure parts,

is ASME Section 1: Rules for Construction of Power Boilers.

The primary design code utilized for structural components is ASCE Minimum

Design Loads for Buildings and Other Structures. This code’s purpose is for estab-

lishing the design parameters (design loads and analysis approach) for the structure.

Additionally, the AISC Steel Design Manual is used for the specific design of

steel elements.

10.2 Code of design: mechanical

The requirements and design approaches specified by ASME Section 1 are intended

to produce a safe boiler design. The code’s intent is to consider the necessary com-

ponents for safety and then provide detailed engineering rules governing the design

and construction of the various components of the HRSG.

For an HRSG, code rules are specified for [1]:

� material selection� design (formulas, loads, allowable stress, and construction details)� fabrication techniques


� welding� inspection, testing, and certification

It is important to note that this chapter will emphasize the mechanical design of

the HRSG. It is also critical that the following proper efforts are carried out to

deliver a reliable and quality product [1]:

� fabrication� welding and postweld heat treatment� nondestructive examination� hydrostatic testing� quality control system

10.3 Code of design: structural

Similar to any mechanical codes, the basis for building code development is to safe-

guard the health, safety, and welfare of the public. The primary goal of building

codes is the protection of human life from structural collapse. The goal is not to

focus on minimizing damage to the structure.

The codes will provide minimum load requirements for the design of the struc-

tures. Loads and load combinations are developed for the appropriate design

approach. The foundation of the code includes [2]:

� basic requirements (stiffness and serviceability)� general structural integrity (design load combinations and load path)� classification of structures (risk categories)

For the specific design of steel elements, the code species [3]:

� geometric dimensions and properties� material specifications� design of members and their associated structural connections

10.4 Owner’s specifications and regulatoryBody/organizational review

The owner or engineering, procurement, and construction (EPC) contractor will

specify to the HRSG manufacturer their specifications. In addition to the design

codes applicable and the minimum code requirements permitted, the specifications

will define the maximum operating envelope, along with the expected level of oper-

ation over the life of the HRSG. The owner is responsible for defining all applica-

ble loads and conditions acting on the HRSG that affect its design.

Depending upon the requirements for permitting and acceptance of the HRSG,

various regulatory bodies or formal approval processes are required by law or local

jurisdiction. There can be significant differences between the requirements to be

201Mechanical design

supplied and approved, but the main concept is to assure quality in all aspects of

the delivery, installation, and operation of the HRSG.

10.5 Pressure parts

10.5.1 Design methods

ASME Section 1 is an experience-based design methodology and it is referred to as

design by rule. Design by rule is a process requiring the determination of loads, the

choice of design formula, and the determination of an appropriate design stress for

the material or detail to be utilized [1,4].

The basic requirements and rules for pressure vessels are designated for typical

mechanical component shapes under pressure loadings within specified limits. The

design rules do not cover all geometries, loading, and details. Guidance may be pro-

vided for the evaluation of other loadings. When design rules are not presented, the

manufacturer is responsible for determining the stress analysis necessary to validate

the design provided.

Design by analysis may be used to establish the thickness and specific configura-

tions and details in the absence of design by rules for any geometry of loading con-

ditions on the element.

10.5.2 Design parameters

The owner is responsible for providing the operating envelope for all scenarios so

the design parameters can be determined and established by the manufacturer. The

design parameters for the HRSG are established by determining the maximum

design envelope with any additional margin provided based upon appropriate engi-

neering judgment and experience or designated by the owner’s specifications.

Design codes generally do not dictate or specify the criteria for establishing the

design pressure (P) and design temperature (T) for the boiler components and are

the responsibility of the manufacturer.

Design pressure is the pressure used in the design of a vessel component together

with the coinciding design temperature (metal temperature) for the purpose of deter-

mining the acceptable thickness and inherent details of the component.

Design temperature for any component shall not be less than the mean metal

temperature expected coincidentally with the corresponding maximum pressure. If

needed, the mean metal temperature can be determined by analysis using accepted

heat transfer methodologies [1].

10.5.3 Material selection

Based upon the design pressure and design temperature for the component, the

appropriate material is selected. The material selection must be a code permitted

material, but can be chosen to deliver the best economical/value design.


Availability and fabrication processes can factor in determining the best available

material for the intended component.

Material selection is fundamental to the design of the HRSG components. The

codes are developed to take great care in ensuring safety and quality. Each code

permitted material will have a comprehensive defined specification that will sum-

marize the requirements for [5]:

� ordering, the manufacturing process� heat treatment� surface conditions� chemical composition requirements� tensile requirements� hardness requirements� nonmandatory requirements such as stress relief, nondestructive examination, and addi-

tional testing

The customer may designate additional requirements, based upon experience of

specific materials to ensure the consistency and quality required in the design.

10.5.4 Mechanical component geometries and arrangements

The main mechanical (pressure parts) components for the HRSG are:

1. Tubes

Finned tube geometries are defined by tube material, tube diameter, tube thickness, fin

material, fin height, fin thickness, and fin density (Fig. 10.1). Tubes are finned by electric

fusion welding (bonding). The heating surface layout is typically a triangular (or “stag-

gered”) pitch between tubes, although rectangular (or “inline”) pitch is also used.

Other critical pressure parts components include:

2. Headers

Headers are primarily used for the collection of tubes within a coil bundle:

a. Upper headers are also used to support the finned tube arrangements. Furthermore, they

provide the points where piping connects different coil bundles and the steam drum.

b. Lower headers are also used for the collection of drainage. They also provide the

points where piping connects different coil bundles and the steam drum.

Figure 10.1 Typical heating surface tube.


Header-to-tube connection types for openings can be set-on, stick-through, or rein-

forced connection construction depending upon the required design approach or details

specified. See Fig. 10.2 for the applicable arrangements and details.

3. Piping

Piping provides the means for distributing water, saturated steam, or superheated steam

to the integrated coil bundles, steam drums, inlet from the water source, and outlet to the

steam turbine.

4. Steam drums

Steam drums are water reservoirs containing saturated steam/water separators located

above the evaporator coil bundle. They are usually connected to the evaporator coil bun-

dle by external piping systems.

Note that all of the main mechanical components are cylindrical vessels under internal

pressure at an associated temperature.

10.6 Mechanical design

10.6.1 General information

The next sections will describe the basic fundamental design concepts required in

the code.

10.6.2 Internal “Hoop” stress

The basic formula for determining wall thickness (t) for cylindrical components

under internal pressure (tube, pipe, headers, and drums) is [1]:

t5Pdo

2 S1Pð Þ ; codified :ttube 5PD

2SE1P1 0:005D or t pipe

drum5

PD

2SE1 2yP1C

where,

P5 design pressure

D5 outside diameter of cylinder (Same as do)

S5 allowable stress design value at temperature

Figure 10.2 (A) Typical full penetration set-on detail. (B) Typical partial penetration stick-

through detail. Note: See Fig. 10.10 for tube stub reinforced header attachment.


y5 temperature coefficient

C5 stability factor

10.6.3 Reinforced openings (compensation)

Design equations are specified for the evaluation of openings in vessel components

and are based on a system of compensation in which the material removed for the

opening is replaced as reinforcement in the region immediately around the opening.

Openings can exist in shells, headers, and heads of components and are defined

as either single openings or multiple (pattern) openings. Types of connections

include piping nozzles, manways, and inspection openings for maintenance and

repairs. Code requirements provide design rules and guidance for the shape and

size of the opening, as well as limits of reinforcement of the shell to reinforce the

connection (Fig. 10.3).

The general requirements for adequate reinforcement of the opening is given

by [1]:

A1 1A2 1A3 1A41 1A42 1A43 1A5 $A

Depending upon the reinforcement required in the shell, different nozzle details

can be implemented. A self-reinforced nozzle is typical for thicker shells and when

there is little remaining thickness in the shell (for “hoop” stress) to reinforce the

opening (Fig. 10.4).

In the case of multiple openings, the appropriate ligament (distance between

adjacent openings) reduction factor must be considered in the calculation of the

shell thickness for the impact of overlapping compensation between openings. The

controlling ligament reduction is based upon the heating surface layout and the hole

pattern in the header. All of the following must be evaluated (Fig. 10.5):

� openings parallel to vessel axis� openings transverse to vessel axis� openings along a diagonal (if applicable)

General note:Includes consideration of these areas ifSn/Sv < 1.0 (both sides of C)

2.5t or 2.5tn + teUse smaller value

h, 2.5t, 2.5ti

t c

dtj

tr

trn

tn

te

Rn

Dp

hUse smallest value

Use larger value

d or Rn + tn + t d or Rn + tn + t

For nozzle wall inserted through the vessel wall For nozzle wall abutting the vessel wall

Use larger value

See UG-40for limits ofreinforcement

A=

=

=

=

=

=

=

=

A1

A2

A3

A41

A43

A42

A5

Figure 10.3 Typical nozzle in the ASME code (Section 1: Power Boilers, PG-33.1) [1].


The ligament reduction factor is determined by specific calculations of each sur-

face direction indicated. The variables include tube pitch (circumferential and longi-

tudinal) and hole diameter.

10.6.4 Allowable design stress

The following behaviors are the basis for establishing the foundation of the allow-

able stress for the design of the HRSG components.

1. Elastic/plastic behavior

Elastic behavior for steel elements is represented by the region from 0 to A in

Fig. 10.6 and is reversible. As the forces are removed from the element, the element

returns to its original shape. Linear elastic deformation is governed by Hooke’s law,

which states [6]:

σ5EE;

where

σ5 applied stress

E5 elastic modulus

E5 strain

O.D.

I.D.

Nozzleendprep

(A) (B)

Length of nozzle(for reinforcement)

Welddetail

Pipe schedule(thickness)Weld

detail

Outsideof vessel

Figure 10.4 (A) Typical self-reinforced nozzle detail. (B). Typical stick-through nozzle detail.

Axis of cylinder

p = Longitudinal pitchp′ = Diagonal pitchd = Diameter of hole

d

p

Circ

umfe

rent

ial p

itch

p′

Figure 10.5 Ligament reduction factor variables.


This relationship behavior only applies in the elastic range. The slope of the stress/

strain can be used to determine the elastic modulus of the steel.

Plastic behavior for steel elements is irreversible. Any steel element experiencing

plastic deformation will have initially undergone elastic deformation. Steels generally

have large plastic deformation ranges due to the ductile nature of the material.

Under tensile stress, plastic deformation is characterized by a strain hardening

region and then a necking region and finally with fracture/rupture. During strain hard-

ening, the material becomes stronger so that the load required to extend the specimen

increases with further straining. The necking phase and region is indicated by a reduc-

tion in cross-sectional area of the specimen. Necking begins after ultimate strength is

reached. During necking, the material can no longer withstand the maximum stress

and the strain in the specimen rapidly increases. Plastic deformation ends with the

fracture of the material.

It is to be noted that steel materials are assumed to maintain continuous, homogeneous,

and isotropic behaviors.

2. Yield strength

Yield strength of the material is the stress when the material stops deforming elasti-

cally and starts to deform plastically. It is the stress at which a material exhibits a speci-

fied permanent deformation or elastic limit. This fractional amount of deformation will be

permanent and is nonreversible [6].

Plastic behavior

Fracture

Strain

Elastic behavior

Elasticlimit

Ultimatetensile

strength B

D

A

C0

A′S

tres

s

Figure 10.6 Typical stress�strain curve for a metal. A, elastic limit; A0, proportional limit.

Point where the curve deviates from linearity. The slope of the stress�strain curve in this

region is the modulus of elasticity; B, yield strength of the material, defined as the stress that

will produce a minimal amount of strain equal to 0.002 or 0.2% (Pt C);D, ultimate tensile

strength, defined as when the plastic deformation increases, the metal becomes stronger

(strain hardening) until reaching maximum load. Note: linear portion of curve A is the elastic

region following Hooke’s law. Beyond point D, the metal “necks” and reduces in cross-

section under load until failure [6].


3. Ultimate tensile strength

Ultimate tensile strength is the capacity of the material to withstand loads developing

tension and is measured by the maximum stress that a material can withstand while being

stressed/pulled before failure. The ultimate tensile strength of a material is determined by

the maximum load of the element at rupture/failure divided by the original cross-section

area of the material tested. Tensile strength is an important measure of a material’s ability

to perform in an application, and the measurement is widely used when describing the

properties of metals and alloys [6].

4. Creep strength

Creep is the behavior of a solid material that deforms permanently under the influence of

mechanical stresses and can occur as a result of long-term exposure to high levels of stress.

Creep is more severe in materials that are subjected to high temperatures for long periods of

time. The stress levels developed are still below the yield strength of the material.

The rate of creep deformation is dependent upon the material properties, exposure

time, exposure temperature, and the applied structural load. Depending on the magnitude

of the applied stress and its duration, the creep deformation may become large enough

that a component can no longer perform its function or may even ultimately fail.

Unlike brittle fracture, creep deformation does not occur suddenly upon the application

of stress. Instead, strain accumulates as a result of long-term stress and is therefore a

time-dependent deformation (Fig. 10.7).

The stages of creep are:� Primary creep is the initial stage of creep, where the strain rate is relatively high, but

ultimately slows with increasing time due to strain hardening.� Secondary creep is the stage where the strain rate eventually reaches a minimum and

then becomes relatively constant as a result of the balance between work hardening

and annealing (thermal softening) of the material. Stress dependence of this rate

depends on the creep mechanism.� Tertiary creep is the final stage of creep, where the strain rate exponentially increases

with stress because of necking behavior of the material. Fracture will occur during the

tertiary stage of creep.

Creep is a very important critical aspect of the material and dictates how the

materials are selected for the hottest components of the HRSG, i.e., superheaters/

reheaters.

Fracture

FractureHigh temp

Low temp

Time

Secondarycreep

Tertiarycreep

Primarycreep

Initialstrain

Str

ain

Figure 10.7 Typical creep strength curve.


It is important to note that in the ASME code the allowable stress values for

creep established are based upon 100,000 hours of operation. It is typical for

HRSGs to be expected to be designed for 250,000 hours to 300,000 hours, so

other means must be established to consider the design life requirements of

the contract properly.

The established allowable stress value for design is then determined by

the limits defined divided by a factor of safety specified in the code of design.

In the case of the ASME code, the allowable stress value of the following will be

the minimum of [7]:

� yield strength at design temperature/(1.5)� ultimate tensile strength at design temperature/(3.5)� creep strength at design temperature

Note:The values of 1.5 and 3.5 are established by the ASME code as factors of

safety for design.

All material specifications will designate maximums for temperature and provide

all of the necessary requirements for the material to be designed accordingly and

deliver for the design life intended. Other design codes may establish different fac-

tors of safety but may also in conjunction require different testing and inspection

minimums of the material.

10.7 Pressure parts design flexibility

10.7.1 General information

Changes in the market require HRSGs to operate less in base load mode

and more in peaking mode with frequent start-ups and shutdowns. This higher

level of cyclical operation impacts the HRSG, and it has been necessary to

consider a multitude of new design concepts and specific details for a

reliable HRSG.

The engineering design process will help identify any critical detail requirements

or operational limits that will impact the reliability of the components and design

details for the expected design life of the HRSG. Many of these code design rules

are established for the basic purpose of ensuring a safe design but do not ensure

reliable operation or even flexible operation for an intended design life because the

primary design rules are often based on operation at base load (steady load), rather

than cyclical service.

After the HRSG’s basic design has been performed in accordance with the speci-

fied design code and owner’s specifications, it is also then necessary for the manu-

facturer to specify a specific set of design rules to be used for detailed design of the

components whose life may be impacted. Many of the design codes provide guid-

ance useful in the detailed design of some life impacted components, but may not

provide useful guidance or are absent for others.


To provide a quality HRSG, the manufacturer must take the responsibility of

performing all applicable analysis to validate the design. Some key elements in the

HRSG for delivering the final design include [8]:

� coil flexibility� differential temperatures� component thickness� material transitions� condensate management and drain designs� proper use of auxiliary equipment

Without proper consideration of the above factors and a proper design analysis

performed, premature pressure part damage and failures that are attributed to ther-

mal mechanical fatigue can occur. Many of these, known as low-cycle fatigue

(LCF) failures, are common in HRSGs.

10.7.2 Coil flexibility

Before cycling of combined-cycle plants became typical, it was not necessary to

make HRSG coil bundles flexible in designated places to eliminate or at least mini-

mize low-cycle thermal fatigue. Low-cycle fatigue was limited to when expansion

was restricted. With the current operational envelopes, it is now essential to provide

this flexibility for maximizing HRSG longevity. Low-cycle fatigue is almost always

due to unresolved thermal expansion and resulting stresses. Non-corrosion-related

failures of HRSG tubes, pipes, and headers are typically caused by low-cycle ther-

mal fatigue. There are two important aspects of coil flexibility to consider: tube-to-

tube temperature differentials and superheater/reheater interconnecting piping.

1. Temperature differentials

In all high-temperature superheaters/reheaters, differences in tube metal temperatures

develop as steam is heated from inlet to outlet. In most HRSGs, the rows of tubes closest

to the gas turbine will be the hottest and those nearest the stack the coldest. Tubes at dif-

ferent temperatures expand at different rates. These differences in temperatures and

expansion rates are greatest at startup and lessen as full steam flow is established.

There are two commonly used options for configuring coils to deal with row-to-row

temperature differences:

a. Fig. 10.8 (four-row superheater coil with spring support) depicts one of them. Here,

steam enters the inlet header and is heated by the exhaust gas. In the configuration

shown, the inlet header at the top of Row #4 is fixed to provide support while the

lower headers are allowed to move vertically unrestrained. All row-to-row temperature

differentials must be absorbed within the coil by header rotation, tube flexing, and/or

axial compression or tension of the tubes. Under transient conditions (such as during

unit startup and shutdown), the mechanical stresses developed by the temperature dif-

ferentials are at the highest and are sufficient to produce thermal fatigue. As a result,

any HRSG whose mechanical support configuration restrains both upper headers from

moving vertically would develop damage each time it is cycled. To minimize the

impact, the addition of a spring-type support to either header would enable the tube


row to which it is attached to move vertically, decreasing thermally induced stresses

by an order of magnitude.

b. Fig. 10.8 (four-row superheater with fixed headers) illustrates an alternative super-

heater/reheater coil configuration option that has commonly been seen in the industry.

Here, each tube row is supported from above by its own fixed header, and link pipes

connect the lower headers to a collector manifold. In this configuration, the maximum

thermal stresses are at the bends in the link pipes. This layout does not lend itself well

to cycled HRSG operation because components cannot move freely relative to each

other. Absorption of row-to-row temperature differentials depends entirely on the flex-

ibility of the coils and the link pipes and rotation of the manifold.

Note the coil bundle implementing the spring-type support at the outlet header allows

the header to move up or down depending on the temperature difference between the

rows. The spring-type support will both facilitate free relative tube movement and allow

for maximizing row-to-row flexibility.

For contrast, the coil bundle configuration not implementing the spring-type support

will only be able to withstand a minimum row-to-row differential in the magnitude or rate

of thermal expansion. Specifically, the tube rows cannot move freely relative to each

other because they are tied together, either by upper and lower headers or a manifold. It is

worth noting that while these types of layouts work well in evaporators (where row-to-

row temperature differentials are much smaller), these layouts leave superheater/reheater

tubes vulnerable to cycling-induced thermal fatigue.

Interconnecting piping. During HRSG startup, it is common for the piping not heated

by gas flow that interconnects superheaters/reheaters to be hundreds of degrees (�F) coolerthan the coil bundles to which it is attached. During normal operation (after startup), the

temperature differential between the piping and coils is much smaller and might be

accommodated by the piping’s flexibility. Regardless, it is important that the layout of

interconnecting piping consider the temperature differences that occur during startup.

Inletheader

Header fixed againstvertical movement

Strack

Row #4Row #1(hottest)

Spring-supportedheader

Gas flow

Gasturbine

Linkpipes

Collectormanifold

Location ofhighest thermalstress

Header fixed againstvertical movement

Strack

Row #4Row #1(hottest)

Gas flow

Gasturbine

Figure 10.8 Coil flexibility comparisons.


Fig. 10.9 shows a configuration that connects the top of the superheater/reheater coil on

the right to the bottom of the coil on the left. Similar arrangements are used for HRSG

components such as evaporators and economizers, but these components exhibit fewer

thermal-transient problems due to the large amount of water they contain, helping to keep

them at a more constant temperature. During startup, the tube rows closest to the gas tur-

bine will heat up faster than the rows further from it. It is a necessity for the interconnect-

ing piping to be designed with sufficient flexibility to handle the force created by these

differential thermal expansions.

2. Component thickness

Most owner/operators of combined-cycle plants require the HRSG to reach thermal

equilibrium quickly enough to minimize the startup time of the plant. Assuming that all

potential low-cycle fatigue problems have been addressed properly, the next criticalities

in this area are the fatigue damage caused either by pressure gradients or by “through-

thickness” thermal gradients. Of these two gradients, the latter is of greater concern. The

magnitude of these thermal gradients is a function of component thickness, where the

thinner the component will result in a lesser thermal gradient and the resulting stress. It is

good design practice to make HRSG parts, such as superheater/reheater headers and the

high-pressure steam drum, as thin as possible to maximize the HRSG’s heat up rate.

Design approaches include:

a. Keeping high-temperature headers as thin as possible by using a single-row harp con-

struction, with multiple inlet and outlet nozzle branch connections (Fig. 10.8). Because

there is only one tube row per header, the header’s diameter is smaller and its resulting

Superheater/reheatercoil bundles

Externalinterconnectingpiping

Figure 10.9 Interconnecting piping.


thickness can be minimized. Unfortunately, such a configuration requires many inlet

and outlet nozzles to handle the steam flow and creates a more complex layout for the

external piping to the steam drum.

b. Utilizing tube stubs that are thick enough to partially reinforce the hole (Fig. 10.10).

This design detail can reduce the header thickness significantly. For steam service coil

bundles operating in the creep range during thermal transients, a thicker tube stub also

helps to further minimize the temperature difference between the tube and the header

by conducting more heat. The use of stubbed headers also makes it easier to perform

nondestructive examination of the welded joint for a higher-quality fabrication.

c. Use of stronger materials, such as T9l/P9 l chromium steel or even applicable stainless

steel materials, which have good fatigue and creep characteristics to minimize the

thickness of high-temperature HRSG components such as HP superheaters/reheaters.

The outlet headers and steam piping of superheater/reheater sections should use

SS347H stainless steel materials for very high temperature applications.

10.7.3 Material transitions (dissimilar metals)

An HRSG utilizes a number of different materials and resulting metallurgical prop-

erties due to the full range of design conditions existing for the boiler. These differ-

ent materials must be joined at specific locations to reflect the changes in

temperature and even stresses in the system. This is highly important in elevated

temperature regions, where creep is a factor in the service life of the component.

The designer must carefully consider where dissimilar welds should be placed in

the system, as well as the appropriate weld filler material to ensure limiting the

impacts of the dissimilar metallurgical properties.

One main design approach is to implement dissimilar metal transitions at cir-

cumferential joints only and avoid perpendicular joints. An example of where a

material transition can be implemented in a circumferential connection with the

proper weld filler material is Grade 22 to Grade 91 tube or pipe with a Grade 91

filler material (Fig. 10.11).

Perpendicular joints of dissimilar metals to avoid are tube-to-header connections

and piping manifolds with pipe branches. In these cases, the headers should be fit-

ted with a tube stub or pipe branch with the same material as the header moving the

material transition to a circumferential joint where the stronger weld filler material

Tube

Header

Reinforcingtube stub

Figure 10.10 Header reinforcement w/reinforced tube stub.


can be used. These transitions are acceptable using the stronger weld filler metals

because the coefficients of expansion are at a magnitude where the stresses devel-

oped is controlled.

Stricter rules must be used in a type of transition such as from Grade 91 to

TP347H due to the greater difference in the coefficients of expansion. In this spe-

cific case, it is recommended to use a material transition, such as an Inconel mate-

rial that splits the difference in the material differential expansions. The transition

component must be constructed with a proper length to both transition the stress

and be a reasonable length for handling for the fabrication of the component. Due

to the criticality of this material transition, it should be located in an accessible area

for regular monitoring/maintenance, and therefore located in the piping system ver-

sus within the applicable coil bundle.

10.7.4 Others

There are other areas of focus that can significantly assist with delivering a more

reliable HRSG for the expected design life. These include:

1. Preventing quenching

The superheater/reheater sections of the HRSGs are susceptible to desuperheater

problems. It is critical that any water introduction by improper equipment operations,

overspraying, or leakage be detected and removed quickly. Should this happen, the

damage from quenching that results is usually severe and damage may occur within a

single cycle.

For an HRSG, the issue of desuperheater spraying or leaking and entering the hottest

coil bundles can be managed with the implementation of drain pot components, both

upstream and downstream of the desuperheater, located in the steam piping system. The

drain pots are constructed with conductivity probes that detect any water entering them.

When the water level reaches an unsafe height, a corresponding valve automatically

opens, evacuating water.

T91(Stub)

P91(Header)

P91(Header)

T91(Tube)

T91(Stub)T91(Stub)

T22(Tube)

SS304H(Stub)

SS347H(Pipe)

P91(Pipe)

Inconel(Pipe)(min 12”)

Accessibleweld seam

SS347H(Header)

SS304H(Tube)T91(Tube)

Figure 10.11 Material transitions (preferred details).


2. Condensate management

Current and future HRSGs will generally be cycled daily. It is typical practice to keep

the HRSG warm and at pressure to minimize thermal gradients and pressure stresses dur-

ing startup. Condensate that has not been removed from the HRSG superheaters/reheaters

could create large tube-to-tube temperature differentials and resulting severe thermal

stresses.

Additionally, the HRSG is purged prior to igniting the gas turbine to ensure all fuel

gas has been vented. The resulting exhaust gas will be below saturation temperature of

steam in the various sections during the purge cycle resulting in large amounts of conden-

sate forming in the superheaters/reheaters.

Proper drain layouts and sizing are also critical to ensure condensate is removed prop-

erly from the HRSG.

3. Feedwater recirculation

During a hot or warm startup of an HRSG, it is typical for the preheater to be shocked

with cold inlet water. After a shutdown cycle and while the HRSG is bottled up (closed to

the outside air), the temperature of the lower pressure sections will rise to match that of

other sections. At startup, there is normally no demand for feedwater because the water in

the steam drums is swelling.

During these periods, the HRSG components containing feedwater can be steaming or

at saturation temperature. A feedwater recirculation system routes water through the feed-

water heater prior to startup. As the HRSG demands water, the cooler feedwater can be

introduced gradually and mixed with the hotter water already in the feedwater heater.

This eliminates or minimizes temperature shocking.

Other system arrangements minimizing any potential thermal shocking can be

considered.

4. Auxiliary equipment

As previously indicated, it is typical to maintain HRSGs that are cycled daily at both

pressure and temperature between each startup and shutdown of the boiler.

Main components to assist with this are:

a. exhaust stack damper

b. insulation on exhaust stack and outlet breeching

c. steam sparging system

Use of a stack damper is the most effective way to prevent cool air from flowing

through the HRSG. Supplementing the damper by insulating the stack and the stack

breeching up to the damper will enable the heat and pressure to be retained for a

meaningful length of time.

Another supplemental means is to implement is a steam sparging system to

introduce steam into the lower sections of the evaporator coils. Steam sparging is

most effective at preventing the HRSGs from freezing.

10.8 Structural components

10.8.1 Dead loads

Dead loads are gravity loads of constant magnitude and are located at fixed posi-

tions that act permanently on the structure. These loads consist of the weights of


the structural system itself and all other material and equipment contained in and

attached to the structural system.

Dead loads consist of all materials of construction incorporated into the HRSG,

including heating surface components, casing and structural system, steam drums,

all associated piping and support systems, platforming access systems, instrumenta-

tion, and insulation.

The weight of the structure is not known prior to the actual design and aspects are

typically assumed based upon past experience. After the structure has been analyzed

and the member sizes determined, the actual weight is calculated by using the actual

member sizes and the weights of the components to validate any assumptions.

10.8.2 Live loads

Live loads are loads of varying magnitudes and positions and are produced by the

use and occupancy of the HRSG. Live loads include any temporary or transient

forces that act on a structure or structural element. The acceptable live load will

vary based upon the occupancy and classification of the structure or structural ele-

ment, but will be defined in the customer specifications and the specified building

code for each project. It is typical to have both an area live load and concentrated

live load requirements. Thermal forces caused by thermal expansions and vibra-

tional loads developed should be considered as live loads.

The position of a live load may change, so each member of the structure must be

designed for the position of the load that causes the maximum stress in that mem-

ber. Different members of the structure may reach their maximum stress levels at

different positions of the given load.

10.8.3 Wind loads

Wind loads are produced from the flow of wind around a structure. The magnitude

of wind loads that may act on a structure is dependent upon the geographical loca-

tion of the structure, obstructions in its surrounding terrain, and the geometry and

the vibrational characteristics of the structure itself. The determination of wind

loads is based on the relationship between the wind speed (V) and the dynamic

pressure (q) induced on a flat surface normal to the wind flow.

This can be obtained by Bernoulli’s principle [2]:

q51

2ρV2 or codified as qz 5 0:00256KzKztKdV

2 lb

ft2

� �

Kd5wind directionality factor

Kzt5 topographic factor (changes in topography)

Kz5 pressure exposure coefficient

qz5 velocity pressure

V5 basic wind speed


Wind loads are site-specific driven and should be included in the owner’s speci-

fication requirements. This should include the code of design and the main design

parameters. Local codes may also impact the design parameters.

The steps for determining the main wind force-resisting system are [2]:

1. Determine risk category of structure.

2. Determine the basic wind speed (V); the values are based upon a nominal design 3-second

gust wind in miles per hour at 33 ft aboveground for exposure C based upon occupancy

category.

3. Determine the wind load parameters:

a. Wind directionality factor (Kd), exposure category (based upon surface roughness

from natural topography), topographic factor (Kzt) (wind speed-up effects at

abrupt changes in the general topography), gust effect factor (G), enclosure

classification, internal pressure coefficient (GCpi), and velocity pressure exposure

coefficient (Kz)

4. Determine velocity pressure (qz).

5. Determine external pressure coefficient (Cp).

6. Calculate wind pressure, (p):

p5 qGCp 2 qi GCpi

� � lb

ft2

� �

10.8.4 Seismic loads

The foundation of the structure moves with the ground during a seismic event and

the aboveground portion of the structure resists the motion due to the inertia of its

mass causing the structure to vibrate in the horizontal direction. These vibrations

produce horizontal shear forces in the structure.

In order to design a structure to withstand an earthquake, the forces on the

structure must be determined and specified. The seismic forces in a structure

depend on a number of factors, including the size and other characteristics of the

earthquake, the distance from the seismic fault, the site geology, the type of lateral-

load-resisting system, and even the importance of the structure. All of these factors

should be included in the owner’s specifications, including any references to

specific local codes requirements.

The design code�defined forces are generally lower than those that would

occur in an earthquake, even a large-sized earthquake. This is the case because

the structure is designed to carry the specified loads within allowable code stres-

ses and any deflection limitations. The allowable stresses for design are less than

either the ultimate or even yield capacities of the materials within the structure. It

is philosophically assumed that any larger loads that may actually occur will be

accounted for by the factors of safety and by any redundancy and ductility of the

structure [9].


The determination of the design seismic load for the HRSG is dictated by these

controlling variables [2]:

1. seismic ground motion values

a. mapped acceleration parameters, site class, site coefficient, and risk-targeted maximum

considered earthquake spectral response acceleration parameters, design spectral accel-

eration parameters

2. importance factor and risk category

3. seismic design category

4. structure classification

codified as V5CsW

V5 seismic base shear (seismic demand)

Cs5 seismic design coefficient

W5 total dead load

The base shear is dependent upon the estimated mass, stiffness of the structure,

period of vibration, damping of the structure, as well as the characteristics of the

soil. The magnitude of the base shear depends upon the amount of seismic energy

that the structure is expected to dissipate by inelastic displacement.

The structural system designated is dependent upon the level of ductility that the

system is expected to provide. The seismic force-resisting system is designed to

resist the induced forces and dissipate the energy causing the acceleration of the

structure.

1. Analysis procedures

The two primary analyses utilized are [2]:

a. equivalent lateral force procedure

b. modal analysis procedure (response spectrum analysis)

With an equivalent static force procedure, the inertial forces are specified as

static forces using empirical, codified formulas. The formulas do not explicitly

account for the dynamic characteristics of the structure being designed. However,

the formulas were developed to represent the dynamic behavior of regular-type

structures, which generally have uniform distribution of mass and stiffness.

Structures that do not fit into this category are termed irregular structures.

Common irregularities include large variations in mass or center of gravity and

soft stories (openings or noncontinuous elements). These types of structures vio-

late the assumptions on which the empirical formulas are based and this may lead

to wrong or insufficient results. In these cases, a dynamic analysis should be used

to specify and distribute the seismic design forces. A dynamic analysis should

account for the irregularities of the structure by modeling the specific dynamic

characteristics of the structure. This would include the natural frequencies, mode

shapes, and damping.

The equivalent lateral force analysis is permitted for all structures except those with

any structural irregularities. The HRSG structural arrangement meets this criterion.


The modal analysis is permitted for all structures.

Both of these analysis approaches utilize four primary seismic parameters [2]:

� response modification factor (R)� overstrength factor (Ωo)� deflection amplification factor (Cd)� redundancy factor (p)

The equivalent lateral force method applies a set of equivalent forces on each

level of the structure that produces horizontal deflections that approximate the

deflections caused by the ground motion. A total horizontal force (seismic base

shear) is calculated and is distributed vertically to each story. A linear elastic analy-

sis is then performed to determine the seismic force effects in the structural compo-

nents (Fig. 10.12).

The seismic design category and the lateral system type are utilized to estab-

lish a minimum level of inelastic/ductile performance that is required in a struc-

ture. The corresponding expected structure performance is codified in the form of

an R-factor, which is a reduction factor applied to the lateral force. The intent is

to balance the level of ductility in a structural system with the required strength

of the system.

Figure 10.12 Typical seismic loadings profile.


The response modification coefficient (R) represents the ratio of forces that would

develop in the seismic load-resisting system under the specified ground motion if the

structure possessed a pure linearly elastic response to the applied forces.

Fig. 10.13 shows the relationship between (R) and the design-level forces, along

with the corresponding lateral deformation of the structural system.

Factors that determine the magnitude of the response modification factor are the

predicted performance of the structure subjected to strong ground motion, the vul-

nerability of gravity load-resisting system to a failure of elements in the structure,

the level of reliability of the inelasticity the system can attain, and the potential

backup frame resistance such as that which can be provided by dual frame systems.

As illustrated in Fig. 10.13 and in order for a structure to utilize higher R-factors,

the lateral system must have multiple yielding elements, and the other elements of

the structure must have adequate strength and deformation capacity to remain

stable at the maximum lateral deflection levels. A lower value of (R) should be

incorporated into the design and detailing of the structure if the structure redun-

dancy and element overstrength cannot be achieved.

2. Overstrength factors

All seismic load-resisting systems fundamentally rely on dissipation of earthquake

energy through some varying level of inelastic/ductile behavior. To maintain this behav-

ior, an overstrength factor (Ωo) is applied and the specific components that must be

designed to remain elastic are designed with the amplification force [2].

3. Redundancy

Redundancy is ensured when a number of structural hinges form throughout the struc-

ture in a successive manner and when the resistance of the structure is not dependent

upon a single element to provide the full resistance of a seismic event. To consider a

proper minimum level of redundancy in the structure, the reliability factor (p) is used.

R

Elastic response of structure

Fully yielded strength

Design force level

Cd

Ω°

δx• δ•δx

Yielding

Lateral deformation, Δ

Late

ral s

eism

ic fo

rce,

V

Vyield

Vdesign

Velastic

Figure 10.13 Relation between steel behaviors and design [9].


When a structure has redundancy, this factor amplifies the lateral forces used in the design

of the lateral system [2].

The HRSG structure is typically designed with a high level of redundancy due to

the nature of the supporting system. The number of frames with full penetration

moment connections provide considerable means of redundancy in the event of a

member or joint failure to allow load distribution to adjacent structural elements.

Summary impact. It is important to note that the relative size and weight of the

HRSG is significant (substantial) with an overall general profile of 150 ft. long to

40 ft. wide to 100 ft. tall. This results in the HRSG main frame elements typically

being controlled by the seismic design requirements of the project, including even

when the seismic requirements are low in comparison to high wind load requirements.

This then produces the importance of a proper design approach for selecting the appro-

priate steel material grade and overall shape profiles, including any specific welding

details, and finally the necessary frame moment connections details in order for the

actual fabricated components to behave as the analysis has considered. All of this is

integrated into producing a reliable, safe, and most economical design for the system.

10.8.5 Operating and other loads

There are several types of other loads that must be considered. Operating loads

include the weight of the components’ liquid contents and any impacts of move-

ment loads from thermal expansions, unbalanced pressure loads, and erection loads.

Other loads can be self-straining forces and impact loads from machines and equip-

ment integrated within the HRSG, such as cranes and hoists. Snow loads can be of

impact based upon the site location.

10.9 Structural solutions

10.9.1 Design philosophy

The lateral and longitudinal force-resisting system is comprised of a series of steel

moment-resisting frames, roof and floor diaphragms, and side wall shear panels.

The HRSG is designed as a three-dimensional system comprised of these compo-

nents. The load combinations for design are designated by the specific code

required and are calculated and applied to the system in proportion to their mass.

Each frame is designed using the latest AISC LRFD (load and resistance factor

design) strength design method (other analyses can be considered). The frame

moment connections at the column to roof and floor beams are designed for the

appropriate overstrength capacity as specified by the code. The baseplates and shear

blocks transfer lateral forces to the foundation slide plates. The HRSG is typically

made of two basic structural systems, one to resist lateral forces and one to resist

longitudinal forces (Fig. 10.14)


10.9.2 Lateral force-resisting system

In the lateral direction, the equipment is restrained by a series of steel moment-

resisting frames. These frame systems are tied together at both the HRSG roof and

floor by steel plate casing panels. The rigid panels act as diaphragms distributing

the lateral forces to adjacent frames, and provide a redundant lateral resisting

Figure 10.14 HRSG structural systems.


system. Each column, roof, and floor beam is braced against buckling in the weak

axis direction by welding the member directly to these rigid panels at the inside

flange. The outer flange is braced on maximum 15 ft. intervals by casing stiffeners,

which provide both rotational and weak axis directional restraint.

At the foundation, the moment-resisting frames are considered pinned on the lat-

eral fixed side and as a roller on the opposite side of the HRSG to account for ther-

mal displacements (average casing temperature of 140�F). At the foundation, one

side is designated as the lateral fixed side. The other column baseplates are allowed

to expand in the direction away from the lateral fixed side. The cross-section of a

typical moment-resisting frame can be seen in Fig. 10.15.

Figure 10.15 Typical HRSG structural frame cross-section.


The distance between the frames is determined by shipping constraints and max-

imum weight considerations. Casing panels for the sides, roof, and floor are made

of columns, beams, plates, and stiffeners and are shipped to the jobsite in sections

as large as possible.

10.9.3 Longitudinal force-resisting system

In the longitudinal direction, the seismic forces are resisted by large vertical

stiffened steel plate shear walls. These external stiffened panels are designed to

contain the slight internal pressure inside the equipment created during opera-

tion. The combination of vertical shear walls and columns provides for the rigid

element that resists the longitudinal earthquake forces and transfer loads to the

foundation. At the foundation, one or two column lines (depending upon maxi-

mum shear forces developed) are designated as fixed column lines. The other

column baseplates are allowed to expand in the direction away from the fixed

column line. The shear forces are gathered at the base of the shear panel by

using lateral force collectors, also known as drag struts (elements that transfer

lateral forces from one vertical element to another). These loads are then trans-

ferred to the fixed columns through a longitudinal restraint and finally to the

foundation.

Fig. 10.16 provides an illustration for the directional displacement of the HRSG

system at the foundation, dependent upon the designated lateral and longitudinal

fixed point locations.

The boiler components are placed inside this structural box system. For boiler

performance reasons, the gap between the boiler components and the sidewall cas-

ing is kept to an absolute minimum. As the boiler components heat up during oper-

ation, any gap at the sidewalls is taken up by thermal expansion. As a result, the

entire boiler system of casing and boiler components is considered to act together.

No interaction between the casing and boiler components is considered to be signif-

icant in the lateral direction but rather the boiler components will move along with

the stiffened moment-resisting frame system. In the longitudinal direction, the

boiler component inertia forces are transferred to the external system through the

roof and floor panels to the side shear walls in membrane action.

10.9.4 Anchorage (embedments)

The HRSG is supported at the foundation at each column baseplate. One side of the

HRSG is considered as the lateral fixed side and one column line (frame) is desig-

nated as the longitudinal fixed line. The HRSG is permitted to expand in both the

lateral and longitudinal directions away from the fixed lines (points). The expansion

is controlled through the use of shear restraints attached to the concrete

embedments.

The shear load path for the column to the foundation is a direct load path (load

profile #1 in Fig. 10.17).


1. shear load in the column is transferred to the baseplate through the column to

baseplate welds,

2. from the baseplate to the shear blocks that are welded to the slide plates,

3. from the slide plates to the foundation through a shear key-type detail welded to the bot-

tom side of the slide plate.

The uplift load path for the column axial load is through the baseplate for com-

pression and through the anchor bolts for tension. Anchor bolts should not be

designed for resistance to shear loads.

Figure 10.16 Typical HRSG displacement at foundation interface.


Some installations can consider baseplates as all pinned locations. In these cases,

the thermal expansion of the HRSG during operation must be considered as addi-

tional forces in the structural frame system. Different arrangements and variables

can determine which anchorage solution is the most desirable.

10.9.5 Material selection

Due to project economics, material availability, project schedule and other direct

issues, it is often necessary to consider materials other than only American Society

for Testing and Materials (ASTM) materials for the main structural frame members.

Alternate materials from other standards, such as Japanese Industrial Standard (JIS),

Chinese Standard (GB), or European Norm (EN) may be utilized.

In most instances, these materials have limited shapes and the HRSG frames must

then be constructed with built-up beam assemblies from plate fabrication. In all

cases, the grade of steel is roughly 50 ksi and ranges from different material grades

based upon the plate thickness of the element. In these cases, it is also possible and

sometimes advantageous to consider different shape geometries to ultimately mini-

mize the overall weight of the frame elements. This type of approach is permissible

and even preferred, as long as all of the proper code design checks are validated.

10.10 Piping and support solutions

Piping and pipe supports are a large part of the design scope for the HRSG.

Piping connects all of the components within each pressure level from the

Figure 10.17 Typical column baseplate and embedment load path.


economizers to the evaporators, from the evaporator to the steam drum, and the

steam drum to the superheaters. External piping comes from the inlet water

source to the economizer and goes from the superheater outlets to the steam tur-

bine. Due to the nature of all of the integrated components, the general piping

layouts can be congested in order to fit in all of the scope into the space avail-

able. As a result, flexibility in the piping and integration of the supports within

the HRSG external structure is critical. There can be a tremendous difference in

the complexity of support solutions with less-than-desirable pipe routings that

will result in additional design time, fabrication, and erection of the components

adding costs and time for field construction. The code of design is typically

ASME B31.1 Power Piping. It is the general requirement that piping consisting

of a temperature greater than 300�F is analyzed. Piping flexibility analysis must

consider the most severe operating temperature condition sustained during

startup, normal operation, shutdown, and/or any potential upset conditions.

The analysis must also consider all external forces, such as wind and seismic

loadings. The design methodology for allowing flexibility and expansion to

minimize thermally induced loads while restraining the piping sufficiently for

wind and seismic loadings is a balance that requires experience and good

engineering judgment.

Establishing meaningful boundary conditions (how the restraints and end points

are modeled) directly impacts the validity of the results. The appropriate load trans-

fer and restraint reactions with the correct types of forces/moments and magnitudes

to best represent the actual behavior of the system in operation are essential for

proper piping designs.

The steam piping is the most critical piping for the HRSG. From the steam drum

outlet through the final superheater/reheater, the temperature can increase from 650

to 1100�F. As a result, the flexibility and supporting system must be carefully con-

sidered. The operating range for these components will be more severe than just the

designated design pressure and temperature. All components, especially the alloy

components, are impacted significantly by the severity of startup and/or shutdown

and how they introduce temperature differentials to the coil bundles and piping sys-

tems. The analysis must evaluate the operating range where maximum stresses will

occur. In most of these arrangements, spring-type supports for the wider operating

range are required to support the piping properly and maintain stress levels under

the code limits.

Typical piping material for steam piping is alloy steel SA335-P11 (11/4 Cr), P22

(21/4 Cr), or P91 (9Cr) grade.

The water piping will have more inherent flexibility due to the smaller diameters

typically utilized and due to the layout and space available for providing proper

flexibility. The piping stress analysis and supporting solutions will permit utiliza-

tion of more standard supports and supporting configurations.

Typical piping material for water piping is carbon steel SA106B or C-grade.

The designation pipe support refers to all assemblies such as hangers, anchors,

guides, sway braces, restraints, and any supplementary steel required to attached to

the pipe support that is integrated into the HRSG steel. Pipe supports can be either

welded or bolted to the piping.


10.11 Field erection and constructability

Due to the nature of market demands and the cost restrictions, schedule, and avail-

ability of skilled workers for completing site erection, a wide range of design options

and features are required from HRSG manufacturers. Projects often require shop fab-

rication to the greatest extent possible to minimize field work. In many instances,

this has driven design solutions to bolted-type solutions arrangements rather than

those requiring extensive field welding. This applies to both the main HRSG frames

and many casing details. This also includes solutions such as bolted platforms, bolted

pipe supports, and shop-fabricated welded valve and pipe assemblies. These types of

solutions require great flexibility in executing the overall mechanical and structural

design of the project, where a much higher integration of design efforts and coordi-

nation with fabrication is required. Each owner or EPC may evaluate different needs

or simply may evaluate offerings from the HRSG manufacturer differently. This

requires an overall better understanding of how each offering provides the best value

of the final supplied and installed components. This trend of different offerings or

overall innovation in the design and final details will continue.

10.12 Fabrication

Fabrication is not specifically defined in ASME Section I. Fabrication is related to

all of those activities by which the manufacturer converts material (plate, tube,

pipe, etc.) into completed boiler components. These activities include [4]:

� welding� bending� forming� rolling� cutting� machining� punching� drilling� reaming and others

The design codes generally permit the manufacturer a broad range in fabrication

due to the wide range of variation in manufacturing practices. These areas are gen-

erally covered in the requirements of the owner’s specifications. Design codes will

specify requirements for critical fabrication areas, such as specific welding require-

ments, and are to be used in conjunction with the general design requirements of

the code. These requirements can include [3,4]:

� design of welded joints� heat treatment and examination of the welded joint� welding processes� proper alignment of welds


While not covered in this chapter, the fabrication, quality control, transportation

(shipping) of equipment, and reliable construction details are all needed to ensure

the overall quality and ultimately the reliability of the HRSG.

10.13 Conclusion

For an HRSG, there are a significant number of individual mechanical and struc-

tural components integrated into the overall HRSG. The design process is very

involved, considering mechanical elements with an operating temperature range of

300�1200�F and pressure range from 150 psig to 3000 psig. This requires proper

material selection and detailed consideration of thermal impacts to allow for flexi-

bility and freedom of movement and rotation of the components.

All of the mechanical elements must be supported and restrained accordingly.

The overall structural support system must be designed for the combined impacts of

potential high seismic and/or wind loadings based upon the specific site location.

Each of the sections presented contains only the basic considerations required

for the overall mechanical and structural design, as an entire book or series of

books on the design requirements and best design practices could be established.

As gas turbines continue to evolve to larger machines with higher operating tem-

peratures and pressures, and with HRSGs targeted for additional cyclic service, the

design challenges will continue to increase.

References

[1] ASME � American Society of Civil Engineering � Section I Rules for Construction of

Power Boilers.

[2] ASCE � American Society of Civil Engineering 7�10 (Minimum Design Loads for

Buildings and Other Structures).

[3] AISC � American Institute of Steel Construction (Steel Design Manual) � 14th Edition.

[4] ASME � American Society of Civil Engineering � Companion Guide to the ASME

Boiler and Pressure Vessel Code � 2nd Edition.

[5] ASME � American Society of Mechanical Engineering � Section II, Part A.

[6] Mechanics of Metallurgy by George E. Dieter � 3rd Edition.

[7] ASME � American Society of Mechanical Engineering � Section II, Part D.

[8] Designing HRSGs for Cycling by Lew Douglas, PE, Power Magazine 2006.

[9] AISC � American Institute of Steel Construction (Seismic Design Manual) � 2nd Printing.



11Fast-start and transient operationJoseph E. Schroeder

J.E. Schroeder Consulting LLC, Union, MO, United States

Chapter outline


11.2 Components most affected 233

11.3 Effect of pressure 233

11.4 Change in temperature 234

11.5 Materials 241

11.6 Construction details 243

11.7 Corrosion 244

11.8 Creep 244

11.9 HRSG operation 24511.9.1 Startup 246

11.9.2 Shutdown and trips 247

11.9.3 Load changes 247

11.9.4 Layup 248

11.10 Life assessments 24811.10.1 Methods 248

11.10.2 Responsibilities 249

11.10.3 Fast start 249

11.10.4 Scope items for cycling 249

11.11 National Fire Protection Association purge credit 250

11.12 Miscellaneous cycling considerations 25011.12.1 Draining of condensate 250

11.12.2 Stress monitors 251

11.12.3 Water chemistry 251

11.12.4 Valve wear 251

References 252

11.1 Introduction

Today, many power plants are being forced to provide power in a dispatchable

mode. It is common for a power plant to shut down and restart on a daily basis.

Many users are asking how they can protect themselves against problems in the

future due to this cyclic mode of operation.



http://dx.doi.org/10.1016/B978-0-08-101940-5.00011-7

In the highly competitive Heat recovery steam generator (HRSG) marketplace

of 2016, suppliers are faced with the dilemma of furnishing the best equipment

possible for the intended service life and at the same time remaining competitive.

The user or owner on the other hand is concerned about initial cost, delivery,

and reliable operation. Therefore, it is important that both suppliers and users

understand factors that contribute to a good HRSG design under cyclic service

conditions and know what measures can be taken to ensure that the equipment will

perform as desired.

Failures from cycling can be the result of thermal expansion restraint problems.

Restraint problems are normally caused by improperly designed or manufactured

supports, header details, flow distribution, or any other arrangement that prevents

a component from unrestrained expansion relative to another. The end result is

failure within a relatively short period of time. It is very important that restraint

problems be eliminated from the HRSG to ensure proper mechanical reliability.

Most HRSG suppliers from experience do a good job in eliminating these types

of problems. Therefore, this chapter will focus on another main cycling issue:

fatigue.

Transient operation is damaging to combined cycle plants due to fatigue from

temperature and pressure changes that take place during startup, shutdown, and

other modes of operation. Fatigue occurs when material is subjected to cyclic or

repeated stresses. The alternating stress amplitude for a cycle is the most significant

factor for fatigue and not the absolute stress level. Most fatigue issues in HRSGs

are considered to be low-cycle fatigue, in which some plastic strain occurs.

An approximate border between high-cycle and low-cycle fatigue has been found to

be 10,000 cycles. Daily starts for 30 years would equate to 11,000 cycles. A thor-

ough knowledge of the stress and loading conditions is necessary to perform a

fatigue evaluation. A life assessment in the time -independent regime is a fatigue

evaluation that considers the various operating cycles and computes an estimate of

unit life. It is important to recognize that failure in a life assessment is commonly

the point of crack initiation.

HRSG fatigue is related to stress associated with changes in temperature

and pressure. Factors that can significantly influence the alternating stress

amplitude of the fatigue evaluation include construction geometry, construction

details, material type, and corrosion. Creep is the continuous and time-dependent

deformation of a material. At elevated temperatures, creep can become a

significant engineering consideration. These factors will be discussed in more

detail in the following sections. Continuous operation for 30 years would result

in 263,000 hours of operation. This amount of time exceeds the 100,000-hour

rupture life used as the basis for establishing allowable stress values in the

ASME code. Total operating hours should be specified as part of the HRSG

design criteria. There is an interaction between creep and fatigue and it may

be overly conservative to specify for a unit both 11,000 cycles and 250,000 hours

of operation.


11.2 Components most affected

HRSG components that are most affected by fatigue are thick wall components

such as high-pressure steam drums, superheater and reheater headers, manifolds,

piping, and headers with flow divider plates. Depending on the shutdown condi-

tions, lower headers of superheaters and reheaters may be subjected to thermal

shock when condensate is formed in the tubes and drains into the lower headers.

Economizers or preheater inlet headers can experience a significant step change in

temperature at startup. This may also warrant some review but is not typically

included in HRSG life assessments. Although intermediate-pressure and low-

pressure steam drums are much thinner than high-pressure drums and do not limit

transient operation, they should still utilize good details of construction for cyclic

operation.

Junctions of dissimilar metals at high temperatures such as austenitic steel to

ferritic steel are areas of major concern and have resulted in significant failures

(Ref. [1]).

11.3 Effect of pressure

Internal pressure in cylindrical and spherical shells will create a general primary

membrane tension stress in boiler components. Local primary membrane stresses

near nozzles and other openings can exceed the general primary membrane stress.

Pressure stresses are included in the determination of the amplitude of the

alternating stress during a load cycle and are included in a life assessment analysis.

The rate of change of pressure is not significant other than how it influences the

associated change in saturation temperature of the water.

The effect of pressure is illustrated by the following example of two different

pressure cycles of a steam drum. Table 11.1 shows the result of a fatigue evaluation

in which the maximum number of allowable cycles, N, are evaluated. Case 1 is a

full-range pressure cycle in which the stream drum stresses are cycled from zero to

a stress corresponding to 95% of the maximum allowable working pressure

(MAWP), and back to zero. Case 2 cycles the stresses from 95% MAWP to 70%

MAWP and back to 95% MAWP.

Table 11.1 Pressure cycling example

Case σ1 (psi) σ2 (psi) Sa (psi) N (cycles)

1 19,000 0 28,500 33,000

2 19,000 14,000 7500 1 106

233Fast-start and transient operation

where:

N5 number of allowable cycles

Sa5 ((σ1σ2) T scf)/2 (psi)

scf5 stress concentration factor5 3

σ12σ25 alternating stress Intensity (psi)

The number of allowable cycles is directly impacted by the magnitude of

the alternating stress. Using the method defined by ASME Section VIII, Div. 2

for determining allowable cycles, it can be seen that in Case 1 the magnitude of

one half the alternating stress intensity gives an estimated cycle life of 33,000

cycles, whereas in Case 2, the number of allowable cycles is over 1 million. The

only difference between these two operating cases is the magnitude of pressure

decay between cycles. Therefore, it can be seen that larger alternating stress

intensity reduces the number of allowable cycles. Hence, keeping the alternating

stress intensity as small as possible is an important factor for increasing the

fatigue life.

11.4 Change in temperature

Temperature difference in a component creates stress. This section describes the

factors influencing temperature-related stress associated with transient operation.

The temperature difference can be a through-thickness temperature gradient or a

temperature difference can result between adjacent parts of different thickness or

operating conditions. When a metal component such as a steam drum is exposed

to changing fluid boundary conditions, a through-thickness variation in tempera-

ture will result. This variation in temperature will generate thermal stresses

that must be accounted for in the determination of alternating stress amplitude.

The internal surface is the surface that experiences the changing boundary

conditions. As fluid temperature at the inside surface increases during startup, the

material expands and is subjected to compression stress. As fluid temperature

at the inside surface decreases during shutdown, the material contracts and is

subjected to tension stress.

The maximum temperature variation in a metal component is a function of

the metal thickness. thermal diffusivity (β), rate of heat transfer from a fluid to a

surface, fluid temperature, and initial metal temperature. The thicker the compo-

nent, the greater the temperature variation will be. The influence of the fluid

boundary conditions impacts the temperature profile in the metal. A high heat

transfer rate to a metal surface would result from flowing or boiling water or

condensing steam compared to lower heat transfer rates associated with flowing

steam or stagnant conditions. Components in contact with steam would lag in

temperature response due to a temperature change more than a surface in contact

with water.


For a component exposed to a step change in temperature, the maximum tem-

perature difference is equal to the temperature step regardless of the component

thickness. Fig. 11.1 shows the mean and cold face temperature response for

a 100�F hot face step change in temperature for different geometries. There is

some geometric influence as shown by the flat plate temperatures in comparison

to the temperatures for a shell-type configuration. The hot face associated

with the curves in Fig. 11.1 is the shell inside surface. A spherical geometry

such as a drum hemispherical head would have an even different temperature

response.

In many cases, ramp rates are defined for transient conditions where the

temperature boundary conditions change with time. Fig. 11.2 shows the tempera-

ture response for the flat plate where the hot face temperature is ramped at

10�F/minute up from 220�320�F. While the time frame to achieve a certain

mean temperature is extended from that shown in Fig. 11.1, the maximum hot

face to mean temperature difference is significantly reduced. Fig. 11.3 shows the

temperature response for a 5�F/minute ramp rate. Comparing the maximum

hot face to mean temperature difference between Figs. 11.2 and 11.3 shows that

this temperature difference decreases as the ramp rate decreases.

For a temperature ramp condition, the maximum temperature difference of

the hot face to mean depends upon the total absolute temperature change for

a component. The mean through-thickness rate of temperature change will

200

220

240

260

280

300

320

0 5 10 15 20 25 30

Tem

pera

ture

(°F

)

Time (min)

Hot face or inside diameter

Shell OD

Flat plate cold face

Flat plate mean

Shell mean

Carbon steel4� Flat plate4� Thick shell (ro/ri = 2)

Figure 11.1 Temperature response for a step change in the hot face temperature.


200

220

240

260

280

300

320

0 5 10 15 20 25 30

Tem

pera

ture

(°F

)

Time (min)

Mean

Maximum ΔΔT= 25.4 °F

Hot face

Figure 11.3 Temperature response for a 4v thick flat plate for a 5�F/min. ramp rate

(β5 1.0).

200

220

240

260

280

300

320

0 5 10 15 20 25 30

Tem

pera

ture

(°F

)

Time (min)

Mean

Hot face

Maximum ΔΔT= 42.0 °F

Figure 11.2 Temperature response of a 4v thick flat plate for a 10�F/min. ramp rate

(β5 1.0).


approach that of the boundary condition ramp rate for significant periods of

temperature change. A maximum value of this difference will be reached if

the overall temperature change is great enough. This maximum temperature

difference is:

ΔT 5Rate3 thk2

33β(11.1)

ΔT5 hot face minus mean temperature difference (�F)thk5 flat plate thickness (in.)

Rate5 temperature ramp rate (�F)β5 thermal diffusivity (in2/minute)

For radial geometries, the temperature difference needs to be multiplied by a

factor based upon the shell dimensions and can be approximated by

ΔTradial 5ΔT � OD

ID

� �0:506

(11.2)

OD5 outside diameter

ID5 inside diameter

A more exact shell relationship is given by Taler et al. (Ref. [2]). Figs. 11.2

and 11.3 show that the maximum temperature difference exists at the end of the

temperature ramp. The asymptotic value for Fig. 11.2 is 53.3�F. The asymptotic

value for Fig. 11.3 is 26.7�F.Fig. 11.4 shows how the maximum surface temperature difference of a compo-

nent starting at 220�F will vary depending upon the ultimate temperature of the hot

face. Small changes in steady state operating temperatures can be ramped quickly

or even instantaneously without generating damaging temperature differences.

Larger changes in operating temperatures must be ramped more slowly to limit

the temperature difference. Fig. 11.4 also shows the strong effect of component

thickness.

Surface temperatures change as a result of a change in a convective boundary

condition and changing internal fluid temperature. The magnitude of the convective

heat transfer coefficient to the surface will affect the metal temperature profile.

The lower the heat transfer rate, the greater the temperature difference between the

bulk fluid and surface temperatures. Fig. 11.5 shows the hot face and mean

temperatures for a ramp rate of 10�F/minute for two different convective heat

transfer coefficients (btu/h ft2 F). The maximum temperature difference is not

significantly different but there is a significant metal temperature lag from the fluid

temperature for the lower convective rate.

The through-thickness temperature profile for a ramp condition of 10�F/min is

shown in Fig. 11.6. It should be noted that the mean temperature is not located

at the midpoint of the plate because of the nonlinear profile.


500

525

550

575

600

625

650

40 41 42 43 44

Tem

pera

ture

(°F

)

Time (min)

Mean h = 200

Mean h = 2000

ΔΔT = 53.3 °F

ΔT = 52.8 °F

Fluid temperature

Hot face h = 200

Hot face h = 2000

Figure 11.5 Fluid temperature ramp5 10�F/min with different convective boundary

conditions for 4v thick plate (β5 1.0 in2/min).

0

10

20

30

40

50

60

70

80

90

200 250 300 350 400 450 500 550 600 650

Hot

face

min

us m

ean

tem

pera

ture

diff

eren

ce (

°F)

Hot face temperature (°F)

5�

3�

4�

2�

Figure 11.4 Temperature difference for 10�F/minute ramp rate (β5 1.0).


At the beginning of a temperature ramp as shown in Fig. 11.4, there is very little

hot surface to mean temperature difference. An initial step change followed by a

temperature ramp is a way to speed up a large change in temperature without

exceeding the maximum temperature difference from Eqs. (11.2) and (11.3).

Fig. 11.7 shows the temperature difference for a case where there is an initial step

change in temperature of 50�F followed by a rate of 10�F/min. The initial step

change would decrease the startup time 5 minutes in this case without increasing

the maximum temperature difference.

Holding HRSG operating conditions to a specific ramp rate is often not practical.

There can also be confusion as to how a ramp limitation is applied, i.e., as an

instantaneous limit or as an overall temperature/time limit. The varying boundary

conditions and through-thickness temperature differences for components due to

changing flow, temperature, and pressure for various cycles need to be quantified

by a transient thermohydraulic network model. The thermohydraulic model results

are used to determine surface heat transfer rates and fluid temperatures. It is then

necessary to then predict through wall temperature differences from these boundary

conditions. EPRI (Ref. [3]) recommends that for a life assessment analysis “[a]

one-dimensional dynamic thermo-hydraulic network model shall be used to develop

detailed characteristics of steam pressure, temperature and mass flow.” Fig. 11.8

shows a typical high-pressure superheater outlet condition for a cold startup.

The HRSG response for a startup cannot be equated to a simple ramp rate.

560

570

580

590

600

610

620

630

640

650

660

0 0.5 1 1.5 2 2.5 3 3.5 4

Tem

pera

ture

(°F

)

Flat plate thickness (in)

Midpoint temperature = 590 °F

Mean temperature = 596.7 °F

Figure 11.6 Temperature profile in a 4v flat plate when hot face is 650�F for a ramp rate of

10�F/min (β5 1.0 in2/min).


0

300

600

900

1200

1500

1800

2100

0

100,000

200,000

300,000

400,000

500,000

600,000

0 5 10 15 20 25 30 35 40 45

Tem

pera

ture

(°F

) / p

ress

ure

(Psi

g)

Flo

w r

ate

(#/h

r)

Time (minutes)

HS2 Outlet flow (#/h) HS2 Outlet press (psig) HS2 Outlet temp (°F)

Figure 11.8 High-pressure superheater outlet conditions for a cold start.

0

10

20

30

40

50

60

70

80

90

200 250 300 350 400 450 500 550 600 650

Hot

face

min

us m

ean

tem

pera

ture

diff

eren

ce (

°F)

Hot face temperature (°F)

Ramp at 10 °F/min

Initial 50 °F step followed by ramp at 10 °F/min

4� Flat plate

Figure 11.7 Temperature difference for a ramp rate change compared to an initial step

change of 50�F followed by 10�F/min ramp rate (β5 1.0).


11.5 Materials

Material properties not only vary between different materials but also as a function

of temperature. Low-alloy steels are used in HRSG construction.

If we combine Eqs. (11.1) and (11.2) we see that

Startup Rate αβ

E3α(11.3)

In Fig. 11.9, the property group β/(Eα) is illustrated as a function of material

type and temperature. A higher operating temperature will have a lower associated

ramp rate for a given material. Different materials also have different allowable

stresses, which impact component thickness. Fatigue curves can also be material

specific depending upon the design code used for analysis. All of these factors

make it difficult to directly compare different material types.

Table 11.2 shows example life assessment results using EN-12952 (Ref. [4])

methodology for quick-starting HRSG high-pressure drums comparing two

different drum materials and a smaller drum diameter. The SA-302b material,

which is a higher strength material, is advantageous for this application and it

shows a conventionally designed steam drum is capable of significant cycles for

quick-start applications. It does show that the SA-516�70 material is not adequate

for these specific conditions in that the total life percentage exceeds 100%.

0

10

20

30

40

50

60

70

80

0 200 400 600 800 1000

β/E

α (°(°

F in

4 /(lb

min

))

Temperature °F

516-70

302b

1.25Cr-0.5Mo

2.25Cr-1Mo

9Cr-1Mo-V

Figure 11.9 Common material properties versus temperature.


The table also shows the relative fatigue life consumption of the different types

of cycles. The assumed start conditions for the different types of cycles are a major

assumption in life assessments. The starting pressure would be the saturation

pressure consistent with the start temperature.

Table 11.2 also shows the effect of changing drum diameter where

smaller drums result in less stress. Reduced diameter drum concepts can thus be

another option for quick-start HRSGs (Ref. [12]). The shutdown maximum tem-

perature difference in the table is small. Faster cool-down rates would impact the

total life percentages.

Table 11.2 Comparison of drum materials and diameter

HRSG drum type

Conventional Conventional Small drum

HP drum material SA-302 Gr B SA-516 Gr 70 SA-516 Gr 70

Design pressure, psig 2625 2625 2625

Design temp, �F 685 685 685

Inside diameter, in 64 64 48

Min. wall thickness, in. 4.02 5.11 3.85

Cold starts

No. of cold starts over 30 years 300 300 300

Cold start drum temp. at start, �F 60 60 60

Cold start percentage of fatigue life

consumed

17% 63% 20%

Warm starts

No. of warm starts over 30 years 1800 1800 1800

Warm start drum temp. at start, �F 212 212 212

Warm start percentage of fatigue

life consumed

15% 115% 22%

Hot starts

No. of hot starts over 30 years 6000 6000 6000

Warm start drum temp. at start, �F 500 500 500

Hot start percentage of fatigue life

consumed

Negligible 0.20% Negligible

Shutdowns

Shutdowns max. delta-T, �F 8 8.4 7.9

Total percentage of fatigue life

consumed

32% 178% 42%


11.6 Construction details

Design and fabrication details for HRSG components must be suitable for

flexible operation. Construction and weld details for drum and header attachments

have an impact on the stress and fatigue life as they affect component thickness

and have different stress concentration factors. Better details come at an increased

cost.

The EN-12952�3 (Ref. [4]) method considers surface finish and differences in

the nozzle construction detail such as a set-on, stick-through or extruded type.

There is also a difference if a drum nozzle is on a cylindrical shell section or a

hemispherical section such as a drum head. Integrally reinforced nozzles should be

used instead of nozzles with nonintegral type reinforcement. Contouring of nozzles

and blending of nozzle welds also helps minimize peak stresses as compared to

nozzles with sharp corners or sharp welds.

EN 12952�3 distinguishes between partial penetration weld versus full penetra-

tion weld details with a significant penalty associated with partial penetration

welds.

Tube-to-header connections can utilize a tube stub detail, such as that shown in

Fig. 11.10, which can be considered for reinforcement of the opening in the header.

This detail can reduce the required header thickness as compared to other methods,

such as ligament efficiency, and provide a better transition for thermal stress.

Changes in materials within components such as in superheaters and reheaters

also create stress because of different material properties. Material transitions

should be made away from points of fixity, such as at the tube-to-stub welds instead

of at a tube-to-header weld. This will minimize the stresses resulting from the

incompatibility of the material properties.

Drum thickness is greatly affected by drum diameter. Specification of large

drum storage volume (large retention time) for high-pressure drums increases

the drum diameter impacting the HRSG life. Drum water storage volume should be

minimized but must accommodate shrink and swell conditions of the drum level

during transients. Usually transient operation has a larger impact on intermediate-

pressure drums than high-pressure drums and therefore appropriate sizing of the

intermediate-pressure drum is important for cycling. Newer HRSG configurations

for high-pressure drums focus on reducing drum diameter.

Tube

Header

Tube stub

Figure 11.10 Tube-to-header connection utilizing a tube stub.


11.7 Corrosion

Corrosion due to nonideal water chemistry conditions can accelerate damage from

fatigue. If the stress level in a component is great enough to cause the protective

magnetite layer to crack, corrosion fatigue can occur. Fig. 11.11 shows corrosion

fatigue in an evaporator tube.

To preclude magnetite cracking, the component stress should be limited. EN-

12952�3 [Ref] limits water-touched surface principal compressive stress to less

than 600 MPa (87,000 psi, 0.3% strain) and principal tensile stress to less than

200 MPa (29,000 psi, 0.1% strain). It is assumed that the magnetite layer forms dur-

ing normal operating conditions so that there is no stress in the layer at those condi-

tions. EPRI (Ref. [5]) recommends that the life fraction be limited to 0.1 if these

oxide stress level limits are exceeded. The life fraction is defined as the computed

fatigue life divided by the specified fatigue life.

Thermal fatigue is a special type of corrosion fatigue that occurs due to rapid

cooling of a hot surface (Ref. [6]). This condition can exist in lower superheater

and reheater headers during shutdown when steam condenses inside tubes and flows

into the lower header. Oxide layers will crack due to stress in steam-touched sur-

faces as well. Any exposed base metal will oxidize in operation and the cycle

would continue to be repeated when a unit is shut down.

Cycling has an effect on possible exfoliation of oxide from superheater and

reheater tubes. Differences in temperature between the oxide and base metal will

result in interfacial stresses that can cause to oxide to crack. As the oxide layer

increases to a critical thickness, it will spall from the tube surface. Exfoliation

occurs in both ferritic and austenitic steels.

11.8 Creep

Creep is the continuous and time-dependent deformation of a material. For low-

alloy chrome steels used in HRSG construction, creep per ASME Code (Ref. [7])

becomes a significant engineering consideration at temperatures greater than 900�F.

Figure 11.11 Corrosion fatigue.

Source: Photographs courtesy of Nooter/Eriksen, Inc.


For carbon steels, creep may become a consideration at temperatures as low as

700�F. ASME Code allowable stresses are, in part, limited by the stress to produce

creep rupture at the end of 100,000 hours. If the intended HRSG operating hours at

temperature are greater than this, the hours must be taken into account in the HRSG

design by derating the allowable stress. Elevated temperatures at this level are

experienced in superheaters, reheaters, and associated piping. Creep is also a func-

tion of the specific material composition, and the amount of time at the elevated

temperature. The time/temperature relationship for SA-213-T22 is illustrated by

a Larson�Miller curve for stress rupture (Ref. [8]) in Fig. 11.12. Each material

type will have different Larson�Miller parameters (P):

TR ðC 1 log θÞ 5 P

TR is absolute temperature in (�R5 �F1 460)

θ is time at temperature (hours)

P and C are the Larson�Miller parameters, which are material specific

The combination of creep and fatigue can result in synergistic damage. Evaluation

of creep�fatigue combined damage is complex and needs to be evaluated for

components exposed to cyclic loading conditions in the creep range.

11.9 HRSG operation

A fatigue evaluation can be made in great detail but any evaluation is based upon

numerous assumptions. It does not guarantee a design will function for given

1.E+04

1.E+05

1.E+06

1.E+07

1.E+08

900 950 1000 1050 1100

θ =

time

(h)

Temperature (°F)

SA213-T22

(T + 460) (20+log θ) = 38 000

Figure 11.12 Larson�Miller curve for SA213-T22.


number of cycles. How equipment is operated and what construction details have

been provided is far more important than how much analytical work has been

performed.

11.9.1 Startup

For any transient condition, there is a change in HRSG water/steam temperature

and an associated change in the pressure part metal temperature. The heat content

of the water and metal is substantial and creates a significant lag in getting the

HRSG up to operating conditions.

The basic types of HRSG operating cycles are defined by the initial temperature

and pressure conditions of the HRSG. A cold start is defined as the point where

the unit is initially at ambient temperature. As the HRSG is heated up and steam

is produced, the pressure within the system will rise until the normal operating

conditions are obtained. The pressure parts will be cycled from zero to normal

operating stress. The unit is then shut down and allowed to slow cool to ambient

temperature. This cycle is called a full-range pressure cycle.

During cold starts from ambient temperature, water level is established in the

drums prior to start. When a gas turbine is started, heat is supplied to the HRSG.

The gas turbine will start with a purge period and then fuel is combusted

to increase the turbine speed to normal operating conditions. The turbine genera-

tor is synchronized with the power grid and then the turbine can be loaded.

The minimum gas turbine load to be within emissions compliance is approxi-

mately 50%. For fuel efficiency and/or because of dispatch requirements, it is

desirable to increase the turbine to 100% load as quickly as possible. In some

cases, there could be gas turbine hold points in the turbine start to slow the heat

flow to the HRSG. The minimum gas turbine operation at this point is full speed

no load.

Gas turbine exhaust is initially heating up the tubes and water within the system.

This heat-up period cannot be controlled with the exception of a possible turbine

hold point. The tubes being relatively thin will allow the transfer of heat to the

water. There is no circulation in a natural circulation evaporator until some steam

develops in the leading rows of the high-pressure evaporator. As steam is generated,

circulation will be established. As steam flows to the steam drum, the initial steam

generated will condense on both the drum upper surfaces and the water level

surface and the drum will start to heat up. As more steam is produced, the system

pressure will begin to increase. The rate of change of saturation temperature as a

function of pressure is greatest at near ambient pressures. This adds to the difficulty

in controlling the system for cold starts. The system can be controlled after this

point by controlling the increase in system pressure. Steam being produced must be

allowed to exit the HRSG. This can be done by venting the steam to atmosphere or

by opening steam bypass lines to the plant condenser. Superheater and reheater

tubes will heat up quickly to the exhaust temperature. As steam starts to be

produced, it will flow through headers and piping and condense, heating up these

components. The small steam flow is easily superheated once it is flowing through


the tubes but condensation will occur on headers and piping until the steam flow

and superheat temperature are great enough where the components are sensibly

heated. Sensible heat transfer from superheated steam is poor and this creates

additional temperature lag of the headers and piping.

Other types of operating cycles, such as warm start and hot start, occur during

short gas turbine shutdowns. Each type of start is associated with specific initial

temperature and pressure conditions and is related to the time that the unit has been

shut down. Table 11.2 shows the initial temperature of 212�F for a warm start and

500�F for a hot start. The pressure in the HRSG is maintained by isolating the unit

and allowing the components to cool slowly. As the cooling process takes place

the pressure decreases. Before the pressure can drop to zero the GT is restarted and

normal pressure is again achieved. For example, a warm start condition may be

conservatively selected for a high-pressure drum to be 0 psig and 212�F. A hot

start condition for a high-pressure drum could be 500 psig, with the drum at the

associated saturation temperature of 470�F.Warm and hot starts have the advantage of not having the uncontrolled

period associated with the cold starts. Warm and hot starts will establish evapora-

tor steam production quickly. Hotter HRSG conditions at the beginning of the

start decrease the total temperature change for the start, minimizing the HRSG

fatigue damage.

11.9.2 Shutdown and trips

Startup is given the most focus for transient operation but shutdown conditions

are just as important. Shutdown can increase the operating stress range for a

fatigue cycle because the fluid temperatures are lower than the component mean

temperatures. Superheaters and reheaters can be particularly susceptible to

shutdown conditions depending upon when condensation occurs in the tubes.

Condensation will occur in all HRSGs once the gas flowing through the HRSG is

at a temperature below the saturation temperature in the superheater or reheater.

Condensate will flow by gravity down into lower headers. The temperature

difference between the header and saturation temperature must be minimized

to minimize the related thermal stress. This is accomplished by a controlled

shutdown that reduces gas turbine exhaust temperature, slowly allowing the

superheater and reheater headers to be cooled by the steam flow. A controlled

shutdown is not possible with a gas turbine trip and therefore there is some

damage associated with gas turbine trips.

11.9.3 Load changes

Changes to the HRSG operating conditions can occur under different scenarios

such as gas turbine load changes, operation with supplementary duct firing, or

variation of operation of multiple HRSGs connected to a common steam turbine.

Usually the temperature change associated with load changes is small. For example,

increasing the drum operating pressure from 2000 to 2500 psig changes the


saturation temperature 32�F. These changes can occur rapidly but the thermal

inertia of the HRSG slows the temperature change in the boiler components.

Thousands of load change cycles will typically have a negligible or minor impact

on an HRSG life fraction.

There is a certain thermal inertia of an HRSG associated with stored heat

content of the metal and fluid. For example, if duct burner firing is increased,

the system operating pressure would increase as the steam flow increases.

Heat is required to heat up metal components and to increase the stored water

enthalpy. The superheater and reheat sections after the burner would increase in

temperature due to the increased gas temperature, somewhat oversuperheating

the steam until the increase in steam flow is established. The magnitude of the

steam temperature increase during this period is controlled by the rate of change

of burner firing. Conversely, when a burner is decreased in load, stored system

heat maintains the same steam production. The superheater and reheater steam

temperature would be temporarily decreased until the evaporator steam flow

decreases.

11.9.4 Layup

After shutdown, the pressure in the HRSG should be maintained as close to

normal operating pressure as possible. Over time, the pressure will decrease

depending upon the rate of heat loss. Units intended to be cycled frequently

should have stack dampers and insulated stacks and breeching to minimize heat

loss. The higher the pressure and temperature in the unit during layup, the better

for subsequent startups. Valve leaks, which can increase the rate of pressure decay

and therefore decrease the unit cycle life, should be eliminated. Steam sparging

into an HRSG has been used as a means to maintain a minimum pressure and

temperature during shutdown.

11.10 Life assessments

A life assessment evaluation is an analytical method to compute a creep and fatigue

life for a component. The computed fatigue life divided by the specified fatigue life

is defined as the life fraction.

11.10.1 Methods

There are exemption methods, simplified fatigue evaluation methods, and detailed

fatigue evaluation methods. The various methods can be found in ASME Codes,

European EN standards, TRD German Technical Rules for Steam Boilers,

AD-Merkblatt, and the British Standards. A document discussing and comparing

these codes and standards for evaluating cycle life is available from the American

Boiler Manufacturers Association (ABMA) (Ref. [9]). This document also shows


by example comparative results between the methods and how the methods can

vary significantly. The European standards that contain rules for life assessment

that would apply to HRSGs are EN-12952�3 and EN-12952�4.

Magnetite is the protective oxide that forms on the internal pressure part

surfaces. Some design codes include calculations related to magnetite cracking.

Criteria for magnetite cracking can easily limit maximum temperature differences

permitted during transients.

11.10.2 Responsibilities

All parties (owner, engineering-procurement contractor, GT supplier, ST supplier,

and HRSG supplier) associated with the design of a combined cycle plant have a

responsibility to properly define the intended plant transient operating conditions.

Many operational assumptions are made in order to perform a life assessment.

These assumptions should be validated once a unit is operational such that plant

operating procedures are consistent with the analysis. This may require installation

of some additional temporary or even permanent thermocouples. Plants with

multiple HRSGs per steam turbine increase the complexity of plant startup.

Different startup conditions exist for lead and lag HRSGs.

11.10.3 Fast start

“Fast start” is a phrase associated with the startup time frame for some combined

cycle plants. It is desirable to start up a plant quickly to maximize startup fuel

efficiency and minimize time that emissions are out of compliance. Renewable

energy production such as that from wind and solar can fluctuate. Gas turbines in

many cases are expected to come online quickly to meet dispatch requirements.

A combined cycle plant is significantly more efficient than a simple cycle plant

but there is a greater time lag for combined cycle starts to be at full power.

A quick-start plant is expected to be at full load in a 30-minute time frame.

11.10.4 Scope items for cycling

Minimizing heat loss during shutdown is important for a cycling unit. Air flows

through a gas turbine and HRSG during shutdown and this flow will cool the

HRSG. To stop this cooling effect, a stack damper is needed. There can still be

significant heat loss through uninsulated stack shell and breeching below the stack

damper. To minimize this heat loss, casing up to the stack damper should be

insulated.

All stop valves and drains should be closed to minimize depressurization by

means of leakage of steam or water from the HRSG. Valves should be properly

operated and maintained to prevent leakage.

Superheater and reheater drain valves must be operated under pressure to clear

condensate during hot and warm starts. These valves should be metal seated

ball valves to keep from leaking under frequent start conditions.


11.11 National Fire Protection Association purge credit

The National Fire Protection Association (NFPA) in 2011 implemented purge credit

criteria to exempt the need for a gas turbine exhaust purge at startup thus shortening

the time for startup. This was later revised in 2015 (Ref. [10]). This practice utilizes

added hardware, interlocks, and controls to avoid the need for the startup purge

time. It also minimizes the amount of condensate generated in superheaters and

reheaters during warm and hot start conditions. There are two methods for gaseous

fuels and three methods for liquid fuels. The gaseous fuels options are a valve prov-

ing method for a credit up to eight days and a pressurized pipe section method,

which is for an indefinite period. For liquid fuels, there is a valve proving method

for a credit up to eight days, a pressurized pipe section method for an indefinite

period and a liquid level monitoring method for an indefinite period. In all methods,

there are triple block and double bleed valves required for the fuel. For pressurized

pipe section methods, there is an additional requirement for a pressurized gas purge

between the last two block valves. The supply air also requires double block and

bleed valves. For the liquid level monitoring method, a vent and level detection is

included between the second and last block valves.

11.12 Miscellaneous cycling considerations

Fatigue is not the only concern associated with cycling. Many components are

affected by cycling and therefore there is a need for more focused operation and

increased maintenance of units that are cycled. This section addresses miscellaneous

topics related to cycling.

11.12.1 Draining of condensate

Condensate drainage at startup is very important. Condensate blockage can cause

maldistribution of steam flow through superheater and reheater tubes. This maldis-

tribution will result in large average temperature differences between tubes greatly

stressing tube-to-header connections. Many superheaters and reheaters have bowed

tubes caused by improperly drained condensate at startup. Bowing of tubes occurs

when some tubes within a tube row are selectively cooled relative to other tubes

in the same row to the point where the cooled tube is subjected to plastic strain.

When the unit is cooled down, the elongated tube then goes into a bowed shape.

Bowed tubes due to improper drainage should occur randomly across upflow tube

rows. Tube bowing can also occur for other reasons of water inadvertently getting

into certain tubes, such as in the case of water-related problems associated with

attemperator valves. Tube bowing in this case may occur in tubes that are more

clustered within a tube row.

Condensate production is greatest during hot start conditions. This condensate

must be drained away or it can be blown into hot upper headers, creating thermal


shock due to temperature change. The advantage of a hot start is that there is

significant pressure in the HRSG to force out the condensate. Condensate produc-

tion occurs during a cold start from initial steam production heating up metal

components. The condensate produced under these conditions is small but must

still be evacuated. Condensation will occur and condensate will accumulate in

superheaters and reheaters during all shutdowns. Drain systems must be able to

discharge this accumulated water during startup. Drain systems must be properly

designed so that water can drain from coil sections by gravity and so that backflow

of water into coils does not occur.

11.12.2 Stress monitors

There are various systems available to determine damage associated with startup

and shutdown of HRSGs. These systems may use a series of embedded thermo-

couples in drum and header walls. The stress monitors must be calibrated for the

unit-specific HRSG geometry. These systems apply life assessment methods

utilizing the geometry and temperature and pressure information to assess the

overall life consumption. Operation can then be fine-tuned to minimize life

consumption. An increase in life consumption for a typical cycle can indicate

some type of mechanical issue that when caught early, can prevent significant

damage. Different systems will make different assumptions and have different

degrees of sophistication so a review of software functionality is necessary to

compare different products.

11.12.3 Water chemistry

For highly cyclic and especially fast-start HRSGs there is a need to eliminate any

chemistry hold points during starts. Steam purity must be in accordance with steam

turbine manufacturer requirements. Steam purity can be validated more quickly by

measuring a degassed cation conductivity or even by ion chromatography instead

of the normal cation conductivity measurement to discount any contribution from

carbon dioxide.

It is also important to quickly determine any possible contamination of the

feedwater. For plants with water-cooled condensers, the monitoring of condensate

close to the condensate pump discharge or even within the hot well is also

suggested to be accomplished by measuring degassed conductivity (Ref. [11]).

11.12.4 Valve wear

Control valves associated with HRSGs are subject to severe wear. Feedwater control

valves can have a very large pressure drop across the valve at startup. These valves

need anticavitation trim and a class 5 shutoff classification. Sometimes a smaller

sacrificial control valve is placed parallel to the main valve. Control valve wear can

lead to poor control of the feedwater flow especially at startup.


Steam attemperation valves such as high-pressure or reheat attemperators or the

steam bypass attemperator valves (high-pressure to reheat and reheat to condenser)

are exposed to drastic temperature changes. An attemperator will be thermally

shocked several hundreds of degrees when attemperation water flow is initiated.

These valves require regular annual inspection. Operation of these valves may only

occur at startup so cycling will affect valve life. Poor water atomization can also

lead to problems with heat transfer coil sections.

Spray water impingement on hot pipe walls creates a thermal shock condition.

Liners should be used to protect piping close to the attemperator nozzles. Straight

pipe downstream of attemperator nozzles must be of adequate length such that

water droplets do not impinge on downstream elbows.

References

[1] HRSG Life Assessment, Case Studies, EPRI, Palo Alto, CA, 2013, 3002001317.

[2] Taler, J., Dzierwa, P., Taler, D., Determination of allowable heating and cooling rates

of boiler pressure elements, using the quasi � steady state approach ,http://ts2011.

mm.bme.hu/kivonatok/Taler_Dzierwa_TS_2011_1294769637.pdf..

[3] Heat Recovery Steam Generator Procurement Specification, EPRI, Palo Alto, CA:

2013. 3002001315.

[4] EN 12952 Water Tube Boilers, European Committee for Standardization, December

2001 Edition.

[5] Evaluation of Thermal-, Creep- and Corrosion-Fatigue of Heat Recovery Steam

Generator Pressure Parts, EPRI, Palo Alto, CA: 2006. 1010440.

[6] The Nalco Guide to Boiler Failure Analysis, 2nd Edition, McGraw Hill, 2011.

[7] ASME Boiler and Pressure Vessel Code, The American Society of Mechanical

Engineers, New York.

[8] D.N. French, Metallurgical Failures in Fossil Fired Boilers, second ed., John Wiley and

Sons, 1993.

[9] “Comparison of Fatigue Assessment Techniques for Heat Recovery Steam

Generators”, American Boiler Manufacturers Association, ,http://www.abma.com/

index.php?option5com_content&view5article&id577:technical-resources&catid520:

site-content&Itemid5173..

[10] Boiler and Combustion Systems Hazard Code, NFPA 85, 2015 Edition, National Fire

Protection Association, Quincy, NY.

[11] B. Dooley, M. Rhiza, P. McCann, IAPWS Technical Guidance on Power Cycle

Chemistry Monitoring and Control for Frequently Cycling and Fast-Starting of

HRSG’s, Power Plant Chem. Vol 17 (No 3) (May/June, 2015).

[12] G. Komora, personal communication.



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12Miscellaneous ancillary equipmentMartin Nygard

HRSG Consultant, St. Louis, MO, United States

Chapter outline


12.2 Exhaust gas path components 25312.2.1 HRSG inlet duct design and combustion turbine exhaust flow conditioning 253

12.2.2 Outlet duct and stack configuration and mechanical design requirements 256

12.2.3 Exhaust flow control dampers and diverters 257

12.2.4 Acoustics 258

12.3 Water/steam side components 26012.3.1 Feedwater pumps 260

12.3.2 Deaerator 260

12.4 Equipment access 26112.4.1 External access 261

12.4.2 Internal access 261

12.5 Conclusion 262

12.1 Introduction

Just as there are many configurations of the basic HRSG, there are also many

different types of ancillary equipment that may be necessary to integrate the HRSG

to a specific job site or application. These items may be installed internally within

the HRSG gas path or externally to the HRSG casing (Fig. 12.1).

12.2 Exhaust gas path components

12.2.1 HRSG inlet duct design and combustion turbine exhaustflow conditioning

12.2.1.1 Combustion turbine exhaust characteristics

The combustion turbine’s high mass flow and temperature combined with the

turbine’s complex exhaust outlet geometry lead to very turbulent flow conditions



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entering the HRSG (see Item 1 of Fig. 12.1). This results in highly time-variable

dynamic pressures on the HRSG inlet duct components.

12.2.1.2 Inlet duct configuration and mechanical designrequirements

An aerodynamically perfect inlet duct would have a gradually expanding cross

section, which would allow the flow patterns to coalesce and would reduce static

pressure loss or even provide static pressure regain. The constraints of the modern

market seldom allow this costly luxury. The modern HRSG has an inlet duct that

is compromised by the desire to reduce overall length and thus material costs.

A shorter inlet duct also reduces the plot area of the installed HRSG.

The HRSG inlet duct must be designed to resist the flow-induced forces upon it.

These include the static back pressure resulting from the pressure loss through the

downstream HRSG components as well as the varying dynamic pressures of the

exhaust flow-induced turbulence.

Figure 12.1 HRSG configuration.


12.2.1.3 Exhaust flow conditioning

A typical HRSG’s performance is often thought to be self healing with regard to

exhaust mass flow or velocity variations. In other words, a high flow in one region

of a heat transfer module will result in higher heat transfer and will offset lower

heat transfer rates in other regions of the same module.

But what happens to other devices within the HRSG? Supplementary

firing equipment (duct burners) and emissions control catalysts often base their per-

formance guarantees on even or minimally varying flow maldistribution characteris-

tics at the entrance plane of the device.

What can be done to redistribute the uneven flow exiting the combustion turbine

or to correct the flow maldistribution? Generally, there are two different methods,

each with their own costs and benefits.

A single or multiple vane or airfoil array is sometimes used. These generally

have a minimal effect on static pressure loss in the exhaust stream and, when prop-

erly designed, can provide flow straightening without adding substantial and costly

structure within the duct. Unfortunately, poorly designed vanes can be at risk of

mechanical failure resulting from fatigue caused by flow vortex shedding-induced

vibrations. Since the observed incidence of vane failures is quite high, this seems to

indicate that a successful design may not be easy.

Constant or variable porosity perforated plates (distribution grids) can also be

installed across the full cross section of the inlet duct. This configuration is gener-

ally more mechanically robust than a vane array. This comes at a higher initial cost

because of the larger mass of material required to span the duct where the grid is

located. Also, because the grid design requires a static pressure loss across the

entire plate to force the necessary flow redistribution, the grid will always have a

larger permanent static pressure loss than a properly designed vane assembly.

Variable porosity plates do, however, have an advantage in the ease with which the

porosity can be modified in the field, usually with additional blocking plates, to

revise flow distribution.

There are also installations that utilize a combination of these methods.

How do we determine the configuration of the flow-conditioning devices?

The old standby was to install an intuitively designed device, either an elaborate

vane array or a highly restrictive, high-pressure drop distribution grid. Sometimes

these worked, sometimes they didn’t.

Very good results can be obtained through physical, cold flow scale model test-

ing. This testing utilizes an ambient temperature fan forced air flow through a

mostly transparent scale model of the unit under consideration. For the best tests,

the flow is conditioned by a simulation of the combustion turbine outlet geometry

before entering the HRSG model. Flow within the model can be visualized with

smoke plumes or with simple tufts. Flow velocities and directional vectors can also

be measured. All measurements are analyzed and compared to the actual HRSG

through proven scaling equations. These models provide very good visualizations

of the flow. The drawbacks to this style of testing include long model construction

lead times, inaccuracies resulting from incorrect turbine outlet/HRSG inlet flow

255Miscellaneous ancillary equipment

simulation, and the inability to represent flow changes resulting from temperature

changes (i.e., the duct burner) within the actual HRSG.

Computational fluid dynamic (CFD) modeling has become more prevalent due to

the increasing availability of lower-cost, higher-powered, multicore computing

devices. These models can generally be produced faster than the cold flow

models and also offer good visualization of the flow. Temperature effects can also

be included in the model. The results, however, are often flawed by simplistic

or erroneous turbine outlet/HRSG inlet flow condition assumptions, sometimes

provided (but seldom guaranteed) by the combustion turbine manufacturer.

When modeling flow within an HRSG, it is advisable to periodically compare

physical cold flow modeling to CFD modeling of the same unit to ensure the results

correlate.

12.2.2 Outlet duct and stack configuration and mechanicaldesign requirements

The material cost of a stack will vary directly with the diameter and height of the

stack and the mechanical forces acting on the stack during operation.

The height and diameter of the stack is generally determined by emissions con-

cerns, noise requirements, and pressure drop limitations.

For any given stack exhaust temperature and mass flow, the stack outlet exhaust

plume will be influenced by the exit velocity and stack exit height. Because this

plume aids in the dispersion of stack pollutants, which reduces the local ground

level contamination, the plume dispersal requirements are usually dictated by the

local pollution control agency.

Emissions monitoring requirements are also dictated by the pollution control

agency having jurisdiction. Typically, continuous emission monitoring (CEM)

equipment is installed a minimum of two equivalent diameters above any upstream

flow disturbance or obstruction and one half diameter below the stack outlet.

The stack height may also be affected by the installation height requirements of

exhaust silencing baffles or exhaust isolation dampers.

The mechanical design requirements also increase when the stack height increases.

Because of the height of the stack, wind and seismically induced forces on the stack

determine the mechanical design criteria of the stack structure. These forces are

usually defined by local building codes. Additionally, the initial design of the stack

will include a thickness margin to accommodate future stack corrosion degradation.

The stack design is also influenced by mechanical resonance induced by external

airflow (wind) vortex induced vibration. This flow-induced vortex pattern creates

areas of low pressure on alternate sides of the stack, which causes the stack to vibrate

from side to side. It is important to reduce these pressure forces if the frequency of the

induced vibrations are near the resonate frequency of the stack. Strong vortex shedding

may be reduced by using either aerodynamic strakes or a tuned mass damper.

Strakes are either a series of fences arranged in a helical array around

the circumference of the stack or corkscrew-shaped fins in the same location. In

either case, the strakes are placed within the top 20% of the stack height. The strake

height is typically 0.1 times the diameter of the stack and the pitch is five times the


diameter. Although the strakes can actually increase the lateral forces on the stack,

it is important to remember that the magnitude of this force is generally a very

small percentage of the wind drag forces on the stack.

A tuned mass damper is a system of added mass, typically a cylinder larger than

the stack diameter, which is attached to the top of the stack by springs. Both the

mass and the springs are designed to provide damping at the resonate frequency of

the stack. A tuned mass damper is usually more costly than strakes and has a smal-

ler effective range of damping.

12.2.3 Exhaust flow control dampers and diverters

Mechanical dampers can be used within the exhaust flow stream to either modulate

for control of the exhaust flow within the HRSG or to securely isolate portions of

the HRSG gas path from hot turbine exhaust.

12.2.3.1 Isolation dampers

Isolation dampers are either parallel multiblade louver dampers (see Item 9 of

Fig. 12.1) or guillotine-style (see Item 4 of Fig. 12.1) single-blade dampers.

Guillotine dampers generally provide tighter shutoff than multiblade louver dam-

pers and would generally be found downstream of a diverter damper assembly to

provide positive isolation of the HRSG. This is especially important for safety

when work must be performed within the HRSG while the combustion turbine is in

operation with exhaust flowing to bypass.

Louver dampers are usually located in the main HRSG exhaust stack to retain

heat when the system is not operating. In this application, the damper is only

required to resist the rising stack effect flow and thus its sealing system is not as

complicated as other damper applications. Stack dampers generally are designed

with a linkage system that allows one or more blades to open with the differential

pressure associated with a turbine startup. This is intended to prevent damage to the

combustion turbine. In practice, this feature is seldom tested because of the possi-

bility of turbine damage should it not work.

12.2.3.2 Flow diverter dampers

A diverter damper (see Item 2 of Fig. 12.1) may be installed between the combustion

turbine and the main HRSG inlet duct to direct turbine exhaust flow to atmosphere

through the bypass stack (see Item 3 of Fig. 12.1), to the HRSG, or to a combination

of these two. They are typically used to allow a rapid startup of the combustion tur-

bine by avoiding the necessity of lower temperature ramp rates required by thick

metal components within the HRSG. Once the turbine is operating at base load, the

diverter damper may be incrementally opened to modulate the hot exhaust flow into

the HRSG. When the HRSG reaches full load, the damper is required to direct all

exhaust flow to the HRSG by fully sealing the flow path to the bypass stack.

The diverter damper typically uses a single, pivoting “flap”-style blade to provide

the flow control. Because this blade must be designed to function within the highly tur-

bulent flow downstream of the combustion turbine and must accommodate differential


thermal expansions, it usually consists of two metal faces supported by a structural

array and separated by insulation.

The damper blade design will include a system of seals around the perimeter of the

blade. These may be mounted either to the blade or to its support plenum. Both resilient

gasket seals and flexible metal leaf seals have been used successfully in this application.

12.2.3.3 Damper actuation

All damper systems operate in response to an on�off or modulating electrical sig-

nal from the plant control system. This signal will cause an electric, pneumatic, or

hydraulic actuator to act on the damper blades through a system of linkages. It is

important that the actual position of the blade be fed back to the plant control sys-

tem by limit switches (open�closed damper systems) or by position transmitters

(modulating damper systems).

12.2.3.4 Damper seal air systems

Some applications require the damper to include a plenum between two rows of

seals to contain a pressurized flow of ambient air, which serves to further limit the

possibility of hot exhaust gas leaking by the seals. These systems are sometimes

referred to as leakproof or man-safe but their actual effectiveness is largely based

on the “as new” condition of the seals and the alignment of the blades, which tend

to deteriorate with operation thus reducing their effectiveness.

12.2.4 Acoustics

The major noise source at an HRSG installation is that generated by the combustion

process within the turbine or the exhaust flow noise within the turbine or HRSG. The

intensity of the noise generally varies directly with the size or power of the turbine.

Through experience, the expected (but seldom guaranteed) turbine outlet sound power

values provided by the various turbine manufacturers tend to include significant addi-

tional margin. The example below shows one turbine manufacturer’s octave band

sound power level spectrum (Lw, dB re 10212 W) definition for a nominal 200-MW

combustion turbine. This is equivalent to an overall A weighted average of 144.4 dBA.

Combustion turbine sound power levels (Lw, dB re 1 pW)OBCF, Hz 31.5 63 125 250 500 1000 2000 4000 8000

Sound power 143 148 149 145 135 137 137 136 136

Gas turbine acoustic emissions radiate from two principal sources from HRSGs:

the stack exit and the casing surfaces. Stack exit noise emissions are dependent on

the stack geometry and the substantial acoustic attenuation provided when the turbine

exhaust sound power is converted to thermal energy during passage through the

HRSG heat transfer tube field array. Casing radiated noise emissions are dependent on

the wall construction (principally the surface mass and outer plate coincidence fre-

quency) and the attenuation by the tube field array. In many cases additional noise mit-

igation measures, such as sound absorption baffles or acoustic shrouds, are installed to

reduce acoustic emissions downstream of the baffles or outboard of the shrouds.


The turbine outlet sound power radiates from the HRSG stack outlet or through

the casing wall panels to the measurement point of interest where it can be mea-

sured as a sound pressure level (Lp, dB re 20 μPa).

12.2.4.1 Casing radiated noise

Some sound power travels through the HRSG casing panels and is radiated through

the air. This sound power is generally blocked by local plant buildings or structures

and typically only results in localized near-field noise concerns. In cases where the

HRSG is the dominant structure, however, the casing radiated noise can influence

the far-field noise measurements.

For example, with the turbine outlet sound power as described above and a typi-

cal HRSG configuration with 1/4v-thick exterior casing panels, the near-field sound

pressure level external to the inlet duct is predicted to be 80.1 dBA at a 3-ft dis-

tance from the casing.

12.2.4.2 Stack radiated noise

As the turbine outlet noise travels through the HRSG on its way to the stack outlet,

portions of the acoustic sound power are attenuated during passage through the

HRSG heat transfer coils. The remaining acoustic energy spreads hemispherically

from the stack outlet through the air to be measured at the far-field point of

interest.

With a turbine outlet sound power as described above and the attenuation of a

typical HRSG, the far-field sound pressure level as measured 400 ft from the

HRSG stack is predicted to be 54.0 dBA.

12.2.4.3 Attenuation methods

In addition to the attenuation provided by the HRSG tube field, further acoustic

attenuation can be provided:

� The turbine sound power can be attenuated when entering the HRSG through parallel

baffle acoustic absorber panels located within the inlet duct exhaust flow field.

Silencing in this location provides the immediate effect of attenuating all noise down-

stream of the silencer. This may result in reducing the required casing thickness or

eliminating the necessity of external noise shrouds. Unfortunately, because of the high-

temperature, high-velocity turbulent exhaust flows in this location, baffle material costs

are high and their operating life is usually limited with noise attenuation properties

decreasing over time. Also, baffles in this location typically require a higher gas side

pressure drop.� Casing radiated noise can be reduced by increasing the mass (thickness) of the HRSG cas-

ing or adding acoustic shrouds adjacent to portions of the HRSG exterior. Adding casing

thickness will always increase the initial cost of the HRSG but its effectiveness will be

constant throughout the life of the unit. There are times when external shrouds are the

only method of meeting acoustic goals. These increase initial cost, take up valuable space,

and restrict access. When uncertainty exists about their necessity, provisions (space) can

be allowed during design to allow for future retrofit of acoustic shrouds.


� Where stack noise is of concern, parallel baffle acoustic absorber panels can be located

within the ducting between the HRSG heat transfer modules and the stack or inside the

stack cylinder (see Item 8 of Fig. 12.1) itself. As an example, the addition of minimal

length stack baffles to the HRSG example above is predicted to reduce the far-field

sound pressure level from 54.0 to 47.0 dBA. Because of the lower temperatures and

more uniform exhaust flows in the stack, baffles located here can be fabricated of

lower-cost materials and generally exhibit a longer life than inlet duct baffles. Their

use, however, will always increase the height of the stack necessary to allow for proper

location of the continuous emissions monitoring ports. As above, where uncertainty

exists about their necessity, provisions (space) can be allowed during design to

allow for future retrofit of stack baffles although this will still require increasing the

stack height.

12.3 Water/steam side components

12.3.1 Feedwater pumps

Within an HRSG system, a feedwater pump is used to move boiler water from the

deaerator/LP steam drum (see Items 6 and 7 of Fig. 12.1) to the higher pressure

levels (HP and IP) of the HRSG.

All pumps are made up of a rotor with one or more impeller stages housed

within an axially split, barrel, or ring segment casing. These pumps are generally

directly coupled to the drive motor and therefore operate at constant speed.

Variable speed pumps can be provided and are more efficient but much more

costly.

One or more pumps will be supplied per HRSG, each rated for 50% or 100%

duty. Additional flow capacity for non-HRSG usage is generally not included in the

pump design.

The pump will be mounted complete with the electric motor driver on a common

baseplate. An automatic recirculation (ARC) valve will be supplied and incorpo-

rated into the pump outlet piping to ensure a minimum flow through the pump to

prevent cavitation. The flow from this valve is returned to the LP drum. IP feed-

water will either be extracted from an interstage nozzle on the HP pump casing or

will be let down from the HP pressure downstream of the pump discharge nozzle.

Pump skids will be designed for outdoor installation in a nonhazardous area

classification.

12.3.2 Deaerator

Depending on the source of feedwater/condensate to the HRSG, it may be necessary

to remove dissolved oxygen and carbon dioxide from the water. Fortunately,

Henry’s law of partial pressures (the solubility of any gas dissolved in a liquid is

directly proportional to the partial pressure of that gas above the liquid) allows for

that removal. A deaerator sprays the incoming feedwater into a steam environment


in which the partial pressures of the gases are reduced. This water is further cas-

caded over a series of trays while still in the steam environment and eventually

flows out of the deaerator while the oxygen and carbon dioxide are vented to atmo-

sphere. This also raises the temperature of the feedwater to close to the saturation

temperature of the steam environment.

For most HRSG installations, the deaerator vessel (see Item 7 of Fig. 12.1) is

integrally linked to the steam drum of the low-pressure section of the HRSG. This

steam drum also serves as the storage tank for the feedwater pump suctions to the

higher-pressure portions of the HRSG.

12.4 Equipment access

12.4.1 External access

All equipment external to the HRSG that requires periodic maintenance should be

accessible from permanent platforms. These platforms should be readily reached

through permanent stairways, ladders or, in rare instances, elevators. For safety rea-

sons, all maintenance platforms require a minimum of two separate means of

egress.

The majority of equipment on a modern HRSG requiring permanent access will

be located at the top of the unit surrounding the steam drums. This includes valving

and instrumentation required for control and monitoring of the steam and water

flow in the HRSG. The remainder of the permanent access requirements will be on

the exhaust stack (damper actuator access or CEM system access), arrayed along

either side of the HRSG at various elevations or at grade level.

Experience has shown that a freestanding stair tower providing the primary

means of access may initially be more expensive than stairways supported from the

HRSG casing but usually provides substantial labor savings when installed during

the initial HRSG construction phases.

12.4.2 Internal access

Most equipment within the HRSG enclosure will require access for occasional

inspection or repair. This access is typically provided by temporary means such as

field-installed stationary scaffolding or cable-suspended mobile scaffolding man

lifts. Both methods have benefits and drawbacks. The stationary scaffolding is

costly and requires substantial installation time and cost. The suspended scaffolding

platforms can only be used where their support cables can be readily accessed

from the HRSG roof casing. Equipment such as duct burners or emission control

catalyst requiring frequent inspections are best served by suspended scaffolds but

their installation requirements require careful planning during the design phase of

the HRSG.


12.5 Conclusion

Modern HRSGs are complex systems requiring careful design coordination

of all individual components. Each individual job site is different and

may require some or all of the equipment described in this chapter. As future

requirements change, even more equipment may become standard. This ever-

changing nature will always provide opportunities for the talented HRSG design

engineer.


13HRSG constructionJames R. Hennessey


Chapter outline


13.2 Levels of modularization 264

13.3 Coil bundle modularization 26613.3.1 Harp construction 266

13.3.2 Modular or bundle construction 268

13.3.3 Goalpost-style modularization 272

13.3.4 C-frame modularization 273

13.3.5 O-frame (shop modular) construction 275

13.3.6 Super modules and offsite erection 275

13.4 Structural frame 276

13.5 Inlet ducts 278

13.6 Exhaust stacks 281

13.7 Piping systems 282

13.8 Platforms and secondary structures 284

13.9 Construction considerations for valves and instrumentation 284

13.10 Auxiliary systems 285


13.1 Introduction

In this chapter the reader will be taken through the various methods of heat recovery steam

generator (HRSG) construction. HRSG construction varies widely in levels of modulariza-

tion and order of assembly of the components. We’ll explore what is important, considera-

tions for specific jobsites, and design influences. Every part of the HRSG from the inlet

duct to the stack including piping, supports, valves, platforms, and auxiliary systems such

as burners, catalysts, and ammonia injection components will be covered.

In an HRSG construction budget, there are several basic terms that are important

to understand. Direct labor is a cost category that includes labor activities by front-

line craft-people who directly contribute to the completion of the HRSG. These

direct labor activities would include, for example, bolting or welding casing struc-

tural frames, installing coil modules, welding piping, and installing platform



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grating. When most contractors compare man-hour estimates for HRSGs they are

comparing man-hours for direct labor activities.

Indirect labor includes activities by the frontline craft-people that support direct labor

activities, such as setting up welding equipment, bringing materials from lay-down areas,

or being a hole-watch (observer who monitors worker safety) for a confined space area.

Overhead is a cost category in a construction budget that includes craft supervision, engi-

neering support, and scheduling support. Special equipment, such as cranes, are often

placed in their own cost category. Crane costs can be high and involve mobilization and

demobilization costs as well as rental costs. The cost of the heavy cranes must be weighed

carefully against the level of modularization and is a major part of construction planning.

Normally when a conversation about construction comes up, the first question is,

“how many man-hours will it take to erect the unit?” This is a very difficult ques-

tion to answer, so let’s try to get this out of the way up front. Direct labor totals for

constructing HRSGs are very difficult to estimate based on previous work. There

are many variables that change from project to project. Union versus nonunion job-

sites, wage scale factors, competing work in the area, and availability of skilled and

experienced craft are just some of the many factors that can influence productivity.

Levels of modularization, nonobvious scope, scope that is not easily represented on

an estimate, and the amount of direct assistance provided in the field by the HRSG

supplier are factors that can directly affect the number of man-hours required.

Most construction firms rely on ever-increasing detail in their estimates to arrive

at the number of man-hours required. They estimate quantities that can be tracked

during the project execution, such as linear feet of weld, diameter-inches of piping

weld broken out by material type, number of bolted connections and weight of tem-

porary steel to be removed. The higher the resolution in the estimate, the better the

chances that the production work will come in on target. Using a job that is 5�10

years old in comparing estimates can be risky. As of 2016, HRSG manufacturers

have varied their offerings greatly in the past 5 years. HRSGs may look the same to

the untrained eye, but they are actually quite unique in their complexity. The leading

HRSG manufacturers have spent a great deal of time since at least 2010 making sure

their HRSGs are more erector-friendly, while at the same time they have become

larger and contain higher alloys and more difficult details to erect in the field.

Erecting HRSGs is not for the faint of heart, but with good knowledge of the

scope being purchased and careful estimation up front, a successful project is cer-

tainly possible.

13.2 Levels of modularization

The level of modularization in an HRSG can vary widely. The primary driver of

the level of modularization is most often the purchaser. Who is buying the HRSG?

Is it a utility or an engineering, procurement, and construction (EPC) firm? An EPC

firm is an intermediary between the plant owner and HRSG supplier that will be

involved in designing and integrating the plant equipment. Will the EPC firm

be engaged in the construction as well as the design and will they be involved in


the bid evaluation process, looking at the total cost of the installed HRSG, or

just the cost of the HRSG equipment?

Utilities are often constrained by public service commissions, municipal regula-

tions, or other rules or regulatory bodies that promote buying an HRSG based on

the best price of the equipment under consideration, which may not consider instal-

lation. In addition, many specifications do not address modularization or may con-

tain loose, highly interpretable wording. Thus, HRSG scope in projects purchased

by regulated utilities or other end users may not contain all of the features and

options that can reduce the amount of labor required to install the unit.

When the HRSG purchaser is involved with the installation of the equipment

there will usually be more emphasis on total installed cost. The purchaser may

choose to spend more on the unassembled HRSG itself, but with the assumption

that it will require fewer man-hours to erect and assemble at the jobsite.

Jobsites can drive different levels of modularization as well. In areas with high labor

rates, higher levels of modularization are desirable to offset high construction costs. In

underdeveloped countries where labor rates are low, the amount of modularization is rela-

tively unimportant; it may even be advantageous to move work from the shop to the field.

Logistics is a big driver of modularization. Is the jobsite near the coast or on a river,

where good waterway access can allow very large components to be shipped in by barge?

Or is the jobsite far inland and only served by rail or over-the-road transportation?

Availability of construction equipment is also a driver. Are large cranes available

and affordable? Larger cranes to erect larger pieces are not always advantageous.

The balance between crane cost, crane mobilization and demobilization costs and

the size of the equipment being erected must be considered. Of course this balance

is highly dependent on location and will vary around the world (Fig. 13.1).

Figure 13.1 Two HRSGs under construction.

Source: Nooter/Eriksen, Inc.

265HRSG construction

13.3 Coil bundle modularization

The HRSG heating surface is arranged into coil bundles comprised of rows of

finned tubes connected to headers and/or return bends at the top and bottom of each

tube as seen in Fig. 13.2. For design purposes these rows of tubes and connecting

headers are arranged into coils that serve a specific purpose, such as an evaporator

or an economizer. For fabrication purposes these coils are combined (or sometimes

split) into larger coil bundles that are as large as transportation or construction lim-

its will allow.

The level of modularization is usually defined by the size of the coil bundles

and/or how much adjacent steel is attached in the fabrication shop. Each level of

modularization has its advantages and disadvantages and it is to the benefit of the

purchaser or erector to understand those for each type.

13.3.1 Harp construction

In modern HRSGs the coil bundles are comprised of finned tubes, headers, and/or

return bends at the top and bottom of the bundle. Some headers are attached to a

single transverse row of tubes and some are attached to two or three transverse

rows of tubes as illustrated in Figs. 13.3 and 13.4. A single upper header, single

lower header, and the tubes connecting the two is called a harp. When the upper

and lower headers are connected by only a single row of tubes this is called a

single-row harp. A coil bundle could be made from as few as one harp for a rehea-

ter or HP superheater to as many as 20 or more harps for a large economizer or

feedwater preheater.

Harp construction is the lowest level of modularization utilized in modern

HRSGs. Harp construction would be used in cases where large cranes are not avail-

able for erection, or field labor is inexpensive. Harp construction might also be

Figure 13.2 A coil bundle with headers (left) and finned tubes being fabricated in a shop.



used in areas where there are logistical constraints, such as low-capacity bridges or

difficult terrain.

Harp construction requires the most work by the erector in the field. Fig. 13.5

shows an example of the temporary steel used in the installation of harps. The extra

labor cost is not normally offset by lower transportation costs as the harps are still

long, flexible, and require supporting steel. They take up the same footprint in an

ocean freighter as a larger coil bundle. Even by stacking the harps for transport,

which requires a substantial amount of support steel, the transport costs for ocean

freight are usually no lower than what is typical for higher levels of modularization.

Figure 13.3 Single-row harp isometric.

Figure 13.4 Single-row harp (left) and three-row harp (right).


Hence, the harp style of construction is more about limitations than efficiencies.

It is utilized more in developing countries than countries with a more developed

infrastructure and access to heavy lifting equipment.

13.3.2 Modular or bundle construction

The next level of modularization is combining several harps into a coil bundle or

coil module. Coil modules are sized to the clearance or weight limits of the trans-

portation method or the available crane used for lifting. Coil modules are appropri-

ate for inland jobsites where rail transport is used. Stretch trailer trucks and

multiple axle trailers can also be used to transport coil modules to the jobsite as

seen in Fig. 13.6.

In modular construction the coil bundle is furnished as a multitude of harps

assembled into a larger coil. The coils in modern HRSGs are normally top sup-

ported for operation and the modular bundle comes to the site with the top support

steel attached. This is one advantage of this style of construction. The upper headers

are supported in their permanent arrangement and the roof casing is furnished along

Figure 13.5 Installing harps into the HRSG casing.



with the coil bundle. Once the coil module is uprighted and set onto the casing roof

beams it is already supported from the top.

In modular style construction, the casing panels are not attached to the coils,

with the exception of the roof panel. The casing is built first and completed prior to

setting any coil bundles inside of it. In this style of modularization, the casing

panels are more modularized than with the goalpost style, which will be described

next. Casing panels, including the outer steel casing, insulation and inner liner are

attached to the external structural beams. This allows the casing and structural

frame to be constructed in fewer pieces than the goalpost style (which we will cover

next), but the pieces being transported to the site and erected are usually larger.

With the casing and structural supporting frame being erected before the coil

modules are installed, all of the seams that connect the casing panels, called field

seams, can be finished with little effort. This is another advantage to the modular

style of construction. This advantage is leveraged with the availability of pneumatic

man-lifts instead of scaffolding.

Modular construction coil bundles are transported to the jobsite with supporting

steel for transportation attached, but this supporting steel is not used for lifting. It is

used only for supporting the length of the coil bundle during transportation and

facilitating horizontal to horizontal lifting during transit. Such support steel would

facilitate offloading the coils from an ocean vessel and placing it on a rail car or

transporter for transport to the jobsite. It is not utilized as the main structure in

uprighting the coil bundle to the vertical position for insertion into the casing.

Figure 13.6 A large modular coil bundle with roof panel attached in the shop.



For this reason, external lifting devices are needed to upright the modular

construction style bundle into the HRSG. This is one disadvantage to the modu-

lar style of modularization. External lifting device designs vary and are proprie-

tary to the HRSG supplier. There are two main types of lifting devices. One is a

common device that is sized to accommodate different sized coils up to a maxi-

mum size. This device is not custom made for each job and is transported from

jobsite to jobsite as needed. The second, and least common type, is a custom

uprighting device for each coil module. These custom uprighting devices can be

designed to contain less steel, but this savings is more than offset by fact that

each coil needs its own uprighting device. The coil modules are often shipped

inside this device, which also acts as a transport frame.

Using the common-sized uprighting device, as shown in Fig. 13.7, each coil

module is placed into the device and tied down. One to three cranes are then used

to upright the module depending on the design of the uprighting device. One- and

two-crane devices typically pivot off the ground, which eliminates the need for an

additional crane that supports the lower end, also called a tailing crane. Three-crane

Figure 13.7 Standard-sized uprighting device.



devices do not pivot off the ground and so a separate tailing crane is necessary to

support the bottom of the device during uprighting. Three-crane devices offer a

slight advantage in that they are relatively fast to load, upright, and set a coil into

place. However, the total crane cost can be much higher than for one- and two-

crane devices.

Regardless of the method of uprighting, with the modular style design the coils

are simply set into place resting on top of the roof beams, already in their top-

supported and final configuration. Fig. 13.8 shows a coil module being lowered into

position onto its roof beams. This is an advantage over the goalpost style that we

will see in the following section.

The modular style coil sets into the casing without any additional support or lift-

ing steel to remove. This is also an advantage of this style of modularization. As

will be seen in the goalpost style of modularization, the removal of support and lift-

ing steel can be a substantial amount of work.

Figure 13.8 Setting the top-supported modular style bundle onto the casing roof beams.



13.3.3 Goalpost-style modularization

The goalpost style of construction and level of modularization is often compared to

the modular style previously outlined because the casing frame is assembled prior

to and separately from the setting of the module boxes. There is a similar amount

of work associated with each style for the site erector, but the order of the work and

the type of work can differ greatly.

In the goalpost style, the casing frame is erected without any of the casing panels

attached to the columns, roof, or floor. The casing frame is erected first with only

the floor and sidewall columns, giving the appearance of an American football

goalpost. Roof beams are added as the module boxes are set into place. One advan-

tage to goalpost-style construction is that the casing frame can be less expensive to

ship since the columns are not attached to the panels in the shop. This does add

some additional seal welding and field seam work in the field, however, offsetting

some of the transportation savings.

The coil modules, like the modular style, are made up of several harps. The size

of the coil is determined by the clearances or weight capacity of the transportation

route. Goalpost-style construction is appropriate for inland jobsites where rail or

over-the-road transportation is necessary. In goalpost style, the modules also con-

tain a partial box of structural steel around them. This steel serves two purposes.

One, it supports the coil bundle so that when it is set into the goalpost frame, it will

support itself without buckling. Two, there is sufficient truss steel included to allow

the box steel to act as its own uprighting device.

Incorporating the uprighting truss steel into the box is an advantage of the goal-

post style. Two cranes are necessary, including a tailing crane to lift the back end

off the ground, but there is no need for a separate uprighting device. This simplifies

the lifting and setting of the module boxes as compared to the modular style and

gives the appearance that the HRSG is being assembled faster than other types of

construction.

Once installed, each harp in the coil module box, having been installed as

bottom supported, will need to be hung from a roof beam that is added after the

module box is set into the frame. The requirement to hang each harp from a new

position in the structure is a disadvantage of goalpost-style construction. The time

required to perform this work can offset the savings in the ease of uprighting and

setting of the module boxes in the frame.

The sidewall, floor, and roof casing are all three attached to the module box in

the shop and shipped as part of the module. This can offer an advantage in transpor-

tation costs, as mentioned before, as the casing is shipped inside the envelope of

the module box. This may decrease the space available for the coil bundle portion

of the module box when the steel and casing is included and maximum sizes need

to be met to adhere to clearance restrictions. The effect is minimal and does not

usually preclude use of this style of modularization.

Because the module box is enclosed in its own steel frame or “box” and includes

truss steel for lifting, most of this steel has to be modified or removed once the coil

is uprighted, installed, and top supported. Some of the support and lifting steel in


the colder ends of the HRSG can be left in place. The lower ends of the module

boxes need to be prepped for the downward expansion of the module during opera-

tion. In the hotter end of the HRSG, more, if not all, of the steel will need to be

removed. Removal of this steel is one disadvantage of goalpost-style construction

over the modular style.

13.3.4 C-frame modularization

The next highest level of modularization is commonly called the C-frame.

Although the term “C-frame” is broadly used for any level of modularization that

appears to be the same, we will define it specifically for our purposes as a coil

module with the floor, roof, and sidewall casing including the primary structural

frame members that have been attached in the fabrication shop. The term comes

from the fact that the floor, sidewall, and roof frame members form the shape of a

“C.” Goalpost-style module boxes can have the appearance of a C-frame, but the

structural members that surround the module box are not the primary casing frame

members. This is the main difference between the two.

C-frame modules are already top supported, meaning that once they are erected

in place, there is no need to hang each harp from a newly installed roof beam.

C-frames are generally more expensive to purchase, but the savings in field con-

struction usually offsets the premium paid for the equipment. C-frames have limited

applicability as their large size requires that the jobsite be close to a body of water

with barge access or that there is a good route with few obstructions to transport

the equipment. Fig. 13.9 shows the relatively large size of the C-frame on a trans-

port trailer. C-frame modules can also be heavier than modules of lower modulari-

zation levels, so heavier cranes may be required.

Lifting and uprighting C-frames is straightforward. A system of shop-installed

truss steel exists inside the “C.” Usually the C-frame is shipped with the sidewall

Figure 13.9 C-frame module being transported.



casing in the downward orientation, allowing the truss steel to be placed inside the

“C” at the front and rear faces of the coil bundles. Lifting and uprighting requires

two cranes, with the second crane being a tailing crane. A pair of C-frames, shown

in Fig. 13.10, are usually erected in the same day, allowing for a completed moment

frame to be made. A typical arrangement of two modules wide and five modules

long can be installed in a week as compared to several weeks for lower levels of

modularization.

By virtue of its configuration, the C-frame can be tall when shipped. Many

times, C-frame module envelopes can push 22 ft in height or more and when added

to the height of a transporter, overhead obstructions such as bridges or power lines

can become a problem. When overhead clearances are a problem the C-frame can

be rotated 90 degrees so that the sidewall casing ships on the side and the leading

and trailing gas flow surfaces on the coil are facing up and down. This sideways

C-frame or low-profile C-frame will incorporate modifications to the sidewall

casing for lifting reinforcement and there will be steel truss work in what will

become the centerline of the HRSG. This centerline truss steel may be removed or

remain in place depending on the details provided by the supplier.

Figure 13.10 C-frame modules being set on the HRSG foundation.



13.3.5 O-frame (shop modular) construction

Increasing the level of modularization one step past the C-frame gives you the

O-frame or shop modular style of construction. This level of modularization

includes the coil bundle, roof panels, floor panels, both sidewall panels, and all

structural moment frame beams in a single module as seen in Fig. 13.11. All inter-

nal baffling is installed in the shop. Typically, this level of modularization is

reserved for single-wide units where the width of the turbine exhaust gas path is at

12 ft or less and is only applicable for gas turbines less than 100 MW in size.

13.3.6 Super modules and offsite erection

When jobsite access is favorable and the local labor situation is difficult or expen-

sive, it may be worth relocating some of the field labor described previously to a

less expensive location and shipping very large “super modules” by barge to the

Figure 13.11 Single-wide shop modular or O-frame being set.



site. Super modules are usually fabricated in a ship yard or fabrication facility that

has drive-on barge access. Super modules consist of entire sections of the HRSG

complete from right sidewall column to left and comprising two or three coil mod-

ules deep. The entire heat transfer section of the HRSG could be represented in two

to three super modules.

Super modules are built already in the vertical orientation; there is no concern

for uprighting. But there is additional steel and structure added for jacking the mod-

ules onto a transporter and bracing them for shipment. One super module being

transported into its final position inside of a building can be seen in Fig. 13.12.

Many times the drums, piping, and platforms above the HRSG casing roof are

added to further modularize the assembly. In Fig. 13.12 it can be seen that the HP

drum was included as well as some platform steel, but piping was not installed.

To take the concept one step further, entire HRSGs have been fabricated and erected

offsite and transported in one piece to a jobsite. A summary of the different levels of

modularization along with their advantages and disadvantages can be found in Table 13.1.

13.4 Structural frame

Regardless of the level of modularization, all HRSG structures are designed as a

system of moment frames consisting of sidewall columns, roof beams, and floor

beams, as seen in Fig. 13.13. These frames support the coil bundles and the casing

Figure 13.12 Super module being rolled into position inside a building.



that envelops the turbine exhaust gas. The locations in the frame where the frame is

completed in the field are called moment frame connections or simply moment con-

nections. For a modular or goalpost level of modularization, there will be four

moment connections to be completed in the field. Two are required at each floor

beam to sidewall column connection and, likewise, two at each roof beam to side-

wall column connection. These connections can be either bolted or welded. The

types of connections and design details can be found in Chapter 10, Mechanical

Design, but for the purposes of this chapter we will limit the discussion to the

method of construction.

Welding is the more traditional approach. In the case of HRSGs located in high

seismic areas, welding may well be the best or only option. The thickness of flanges

Table 13.1 Modularization summary

Level of

modularization

Advantages Disadvantages

Harps � Lowest shop cost and

transportation cost.� High-capacity cranes not

required.

� Significant time and labor required

to install.

Modules or

bundles

� Lower shop and

transportation cost.� No temporary steel to

remove from module.� Coil bundles are already

top supported when set.

� Requires external uprighting

device.

Goalpost

module box

� Lower shop and

transportation cost.� No external lifting

device required.

� Coil bundles require top

supporting to be done after set into

steel frame.� Temporary support steel requires

removal.

C-frame � Reduced installation

cost.� Casing and frame steel

already attached to coil

bundle module.

� Often requires transport via heavy

haul.� Higher shop and transportation

cost.� Not available for all locations.

O-frame � Highest level of

modularization.

� Only applicable to single-wide

(smaller) HRSGs.

Super modules � Lowest cost of

installation.

� Must have access to a ship yard to

finish fabrication. Transport to

jobsite difficult and requires

special transport skills.


and webs of the moment frames in these jobsites may not lend themselves to a

bolted connection.

For jobsites in areas not prone to high seismic loads, bolted moment connections

have become the norm in recent years. Bolted connections can differ in their config-

uration. Web and flange splice plates, where reinforcing plates are effectively bolted

across the mating web and flanges, have the disadvantage of containing a high quan-

tity of bolts, but have the advantage of being applicable in higher seismic areas.

An alternative to this is a plate flange design, seen in Fig. 13.14, where plates

normal to the axis of the beam are bolted together like flanges on mating pipe.

These contain fewer bolts but cannot be used in very high seismic areas.

With any structural connection quality assurance is of the utmost importance.

Quality assurance with welded connections includes visual inspection and nonde-

structive examination (NDE) normally consisting of magnetic particle testing. For

bolted connections the quality assurance lies in making sure the bolt or nut is tight-

ened the proper amount. Visual aids such as squirting washers, color changing

washers, and twistoff-style bolts can be used to give a visual indication of when the

proper tightness is achieved.

13.5 Inlet ducts

The discussion in this chapter so far has been restricted to the coil modules and the

casing that surrounds them. While recognized as only contributing roughly

25�30% of the total labor in erecting an HRSG, the method for assembling the

Figure 13.13 Structural moment frames with casing panels attached.



casing and coils and the level of modularization are considered by many to be the

most important considerations in HRSG erection.

Externally, the inlet duct assembles much like the casing. The duct consists of a

frame of columns and roof and floor beams. The casing attached to these columns

includes an outer steel layer with reinforcing stiffeners, insulation and a steel liner

on the inside. Duct panels can ship from the shop with the columns and beams

already attached to them or they can be separate from the steel frame. This may

depend on transportation restrictions, but may also depend on the preferences of the

HRSG supplier.

At the other end of the scale, the inlet duct could be shipped to the site in shop-

assembled boxes with the floors, walls, and roof panels and beams already welded.

Transportation restrictions may limit this, but if clearances allow, the purchaser

may require more modularization in this area.

Inlet ducts can contain elements that add complexity to the job. Inlet ducts used to

be sweeping and gradual transitions from the relatively small exit of the combustion

turbine to the much larger face of the first coil. To make the HRSG smaller, less

Figure 13.14 Bolted moment connection at floor to sidewall.



expensive, and to reduce plot space, inlet ducts have become shorter with steeper

angles. Working against this dimensional change is the fact that exhaust from combus-

tion turbines has become hotter, with higher velocities and increased turbulence at the

exit. These factors can combine to create problems if design and construction details

are not given sufficient attention.

The internal liner system of an HRSG contains multiple overlapping plates that

“float” or expand to accommodate the high temperatures of the exhaust gas.

Adjacent liners should not be welded together. They should also not be connected

so tightly that there will be no opportunity for expansion. Ogee clips are small off-

set tabs welded on one side but left free on the other to hold down adjacent liners

and prevent warping. Ogee clips should be used generously as recommended by the

HRSG supplier’s technical field advisor and installation instructions. Square or

round washers holding the liner down should be snug and not reveal gaps when

walking or pushing on the liner. Most inlet duct systems use channels over the

interface of adjacent liners to eliminate warping and for extra reinforcement against

turbulence and high exhaust gas velocities. See Fig. 13.15 for an example of these

components. The service of the HRSG supplier’s field advisor can be invaluable

Figure 13.15 View of inlet duct liner seams.



here as it is easy to overlook the nuances for correctly welding or bolting these

components.

On HRSGs with duct burners or catalyst systems where very good flow distribu-

tion is required, there will usually be a distribution grid in the inlet duct. The grid is

heavy in order to withstand the pressure and turbulence of the exhaust gas velocity.

Expansion of the grid is critical to proper operation and, like the inlet duct liner, the

nuances are in the details. The grid must be installed in a way that allows proper

expansion and not hinder it. There are widely varying levels of shop fabrication in

the supports for distribution grids. Care should be taken to fully understand how

much field work is required to potentially attach supports or guides that may or

may not be installed in the fabrication shop.

Bleed turbulence breakers are accessories occasionally required inside the

HRSG’s inlet duct and subject to high exhaust gas velocities. Care should be taken

to perform the attachment welds carefully and follow the combustion turbine manu-

facturer’s design carefully so these devices are able to withstand the loads to which

they are subjected.

13.6 Exhaust stacks

Like the other parts of the HRSG, exhaust stack modularization is highly dependent

on transportation restrictions. Exhaust stacks involve fairly common methods of

shop fabrication and there is usually a wide selection of local or near local fabrica-

tion shops capable of manufacturing stack components. This makes transport of

larger pieces possible, although not always economical.

The typical size of a knockdown piece of exhaust stack is 180-degree segments

3 10 ft tall. Several of these sized segments can fit onto a truck for transportation

to the jobsite. In some cases it is advantageous to ask for barrel stave sections in

the range of 90- or 120-degree segments by 40 foot long. Although this seam layout

may give the erector fewer linear feet of weld, the equipment needed by a fabrica-

tion shop to roll or bend 40-foot-long staves is not as common as rolling equipment

that can produce 10-foot-long cylinders. Transportation costs may be higher for the

barrel stave configuration.

In some cases, it could be possible to fabricate the entire stack offsite and ship it

in via heavy haul transporter or barge, but this is not normally the case. In cases

where this is possible, stack dampers and stack silencers, if required, should not be

part of a shop-assembled package unless they are engineered to be transported as

part of the package.

Circumferential and longitudinal seams can be welded from both sides. When

welding from both sides the first weld pass or root pass of the first side must be

removed after completion of the first side weld to give the welder a clean surface to

complete the weld from the back side. This is call back gouging. To eliminate the

need for back gouging, backing bars can be added to the shell cans in the shop.

Backing bars allow for the entire weld to be made from one side and eliminate the


need to remove the root pass. Fig. 13.16 shows an exhaust stack outfitted with scaf-

folding to facilitate welding of longitudinal and circumferential seams in place.

13.7 Piping systems

Piping systems can make up the majority of the direct man-hours associated with a

project. The complexity of piping systems varies widely and is directly proportional

to the number of pressure levels in an HRSG and the temperature of the outlet

steam. Fig. 13.17 shows a piping model of a single pressure level HRSG. Modern

HRSGs contain a significant amount of 9-percent chrome alloy materials. These

alloys require skilled welders, are heat treat sensitive, and require a narrow range

on hardness readings for the completed welds. An erector’s quality control system

must acknowledge this and monitor these parameters diligently.

With the advent of CAD drawing it is not necessary to add field trim to the ends

of each pipe spool as in the past, but certain pipe spools still benefit from some

extra tolerance. With evaporator risers it is often helpful to specify some additional

length be left on for trimming to accommodate fit-up in the field. An alternate

option is to provide short make-up spools for each size pipe in case extra length is

needed.

The quantity and size of field welds have an impact on man-hours required.

These are the parameters most closely estimated by construction firms. The source

Figure 13.16 Two HRSGs under construction in Malaysia.



of the fabricated pipe can have an impact on number of field welds. Piping fabri-

cated in another country and shipped in containers oftentimes contains more field

welds than pipe spools fabricated closer to the jobsite and shipped by truck.

Pipe support systems can be equally complex and vary greatly in details. When

possible, the stanchions for pipe supports that weld directly to the pipe should be

welded in the shop to eliminate mistakes, and save the time and cost required for

heat treating in the field. Again, with CAD drawing of intersecting subsystems (pip-

ing, platforms, coils, casing) misalignments are not common and are much easier to

correct than to weld the low-alloy supports to the pipe in the field.

Attachment of pipe support systems to piping can be bolted or welded. In many

cases, bolted is preferred by the erection contractor, but may take longer to design

and fabricate in the shop than is allowed by the contract schedule. This is mostly

true where holes need to be drilled into the casing and duct panels, whose purchase

order was placed many weeks before piping support systems are completely

designed. Requests by purchasers to incorporate more and more bolted connections

in lieu of welded connections are pushing HRSG suppliers to be more creative in

how they design, draw, and procure equipment.

Figure13.17 Secondary steel, access platforms, piping, and drums added to casing and coil

modules of an HRSG.



13.8 Platforms and secondary structures

Secondary structures like the main deck platform, sidewall platforms, silencer

towers, access door platforms, and stair towers can have a big effect on man-hours

as well. As can be seen from Fig. 13.17, the system of steel that is added to the

main casing and coil module structure can be complex. These pieces can be furn-

ished in a number of levels of preassembly. Like piping spools, the location of the

source country and shipping method will also have an effect on preassembly levels.

Handrail and toe plate details can affect man-hours and the appearance of the

HRSG in general. The level of preassembly should match the purchaser’s expecta-

tions, but this is one area where reality can differ greatly from expectations.

Like pipe supports and moment frame connections, the request to have more

bolted connections has also affected the design and supply of secondary structures.

Incorporation of bolted connections is not as difficult from a scheduling standpoint

for platforms as it is for pipe supports. But the desire to have oversized holes to add

the benefit of some tolerance will require slip critical connections. Slip critical

joints rely on friction to join the two connected pieces instead of relying on shear

forces. This can increase the requirements for surface preparation, bolt type, and

tightening method.

Vent silencer supports can be shipped in one piece to the jobsite or they can come

in many pieces. A stair tower will arrive containing anywhere from 100 to 150 pieces

depending on the source. Container shipments of a stair tower from other countries

can be in the range of 150 bolted pieces, where truck shipments of a knockdown

stair tower can be in the range of 100 bolted pieces. It is necessary to understand

how these items are supplied in order to estimate and economically perform the

labor required.

There are more highly modularized options for stair towers as transportation lim-

itations are lessened. Stair towers that are supported off the casing are another

option to reduce the piece count, but the time in the project to erect this stair tower

is not as flexible as it is with a self-standing tower.

13.9 Construction considerations for valvesand instrumentation

In the trend to move labor from the field to the shop, HRSG suppliers often offer

valves to be welded into the pipe spools in the shop. This has a lot of advantages.

Low-alloy chrome piping and valves can more easily be welded and heat treated in

a shop. Groups of valves such as drum level control valve stations and economizer

drain manifolds can be welded in the shop and economically transported to the job-

site due to the compact nature of the arrangement.

Care needs to be given to timing as some control valves can have very long lead

times as well as a long engineering time cycle. This could put certain control valve

pipe assemblies onsite much later than a contract allows. Be sure to evaluate the


benefits of shop fabrication and honestly appraise how early a particular piece is

needed onsite before evaluating options for welding control valves in piping spools.

Small details can make a difference too. It is advantageous to have thermowells

in low-alloy chrome piping welded in the shop so that heat treatment will not be

required in the field. Provisions for heat treating small seal welds such as these are

more expensive in the field than in the shop.

13.10 Auxiliary systems

Auxiliary systems for HRSGs such as duct burners, selective catalytic reduction

(SCR), and carbon monoxide (CO) catalyst systems are not difficult to install as

long as provisions are made for their inclusion in the initial design. All these sys-

tems are furnished in their own duct space. Duct burner runners, which produce the

flame, and burner baffles, which help shape the flame by controlling exhaust gas

flow, are normally fabricated to a high level of modularization. Part of the duct

burner system includes external gas control skids and flame scanner cooling air

blower skids. These are completed in a shop and set on a small foundation next to

the HRSG. The piping is then run and completed between the skids and burner

runners.

Catalyst systems are fairly straightforward. SCR catalyst blocks are large, weigh-

ing approximately 1 ton each, and are stacked on top of each other with a crane and

fastened to a frame to give support against exhaust gas flow. The SCR system

includes an ammonia injection system and lances that inject the ammonia into the

exhaust gas flow. The ammonia injection system includes an ammonia vaporizing

skid, completed in the shop and set on a foundation next to the HRSG. The ammo-

nia vaporizer is connected through a header to the individual injection lances.

These lances are perforated pipes inserted horizontally through the casing and sup-

ported in the center of the duct.

CO catalyst comes in much smaller blocks that can be lifted by a person and are

stacked by hand from scaffolding.

Important considerations for systems equipment are delivery timing of the cata-

lyst systems and time allowed at the end for commissioning and tuning of the

equipment. Catalyst systems should not be delivered too early and subjected to

damage and/or contamination at site. They should be delivered just prior to startup

or as directed by the catalyst manufacturer.

13.11 Future trends

Combined cycle power plant requirements are changing faster and faster every

year. Here are a few trends that are affecting construction details and schedules.

Diminishing quantity of skilled labor in North America is probably the leading

driver of change in how HRSGs are designed for ease of erection. Increased


modularization to minimize field labor and increased use of bolted connections are

two areas that address a shortage of welders.

Changes to the way electric power plants are being developed are putting more

pressure on HRSG suppliers to provide shorter and shorter deliveries. Not only

does this affect the engineering and procurement cycle for the HRSG supplier, but

it affects the construction and commissioning cycle for the erector as well. Once a

customer wins an award to provide power into an area, there is tremendous pressure

to deliver on time.

Outside the North American market and other parts of the developed world, the

trend will be the evaluation of total installed costs as labor costs rise and the cost to

erect the HRSG becomes more significant. Methods of modularization pioneered in

these areas should spread throughout the world and new innovations will appear.


14Operation and controlsGlen L. Bostick

Manager of Systems Engineering (Instrumentation & Controls, Research &

Development, Innovation & Patents), Fenton, MO, United States

Chapter outline


14.2 Operation 28814.2.1 Plant influences 288

14.2.2 Base load 291

14.2.3 Startup 293

14.2.4 Part load/shut down 299

14.2.5 Cycling 300

14.2.6 Alarms 301

14.3 Controls 30114.3.1 Drum level control 301

14.3.2 Steam temperature control (attemperation/bypass) 305

14.3.3 Condensate detection/removal 308

14.3.4 Feedwater preheater inlet temperature 309

14.3.5 Startup vent/steam turbine bypass 312

14.3.6 Deaerator inlet temperature 314

14.3.7 Drum blowdown/blowoff 316

14.3.8 Pressure control (automatic relief valve, control valve bypass) 317

References 319

14.1 Introduction

When starting to write a chapter on operational controls for a major piece of

industrial equipment serving a critical role in an essential national/world market,

one ponders the complexities and intricacies that they will dive into and accurately

expand upon while trying to work within a reasonably allotted space. This chapter

is after all only a part of a greater work directed at the presentation of a concise

and informative treatise on heat recovery steam generators (HRSGs).

The design and application of HRSGs is nearly infinite. The controls and

operation of each plant can vary greatly based upon equipment, location, user

preference, and of course process design. The controls engineer must take all of



http://dx.doi.org/10.1016/B978-0-08-101940-5.00014-2

these facets into consideration to create a suitable and unique operational plan

for each system. The generation of an all-encompassing operational guideline

would be very challenging and fated to be incomplete owing to the vast permuta-

tions that can be encountered. For clarity of scope, this chapter is limited to a

general presentation on operation and controls associated with the HRSG proper

operating behind a combustion turbine (CT), a very typical application. To be

sure, the effects of other plant systems on the HRSG will be addressed in the

applicable discussions, as appropriate, to demonstrate the full range of necessary

controls. However, it is not the intent of this work to address balance of plant

(BoP) equipment or HRSG auxiliary equipment (e.g. burners, selective catalytic

reductions) in detail. The reader is directed to other readily available resources for

a more complete rendering on those components.

14.2 Operation

It is ironic that one charged with the development of a chapter on process controls

and operation must begin by acknowledging, with some chagrin, that at the core

of an HRSG lies a very passive device. In fact, the thermal designer’s job,

while not part of a job description, is effectively to minimize the needs for active

controllers. Proper design and location of heat transfer surfaces allow the HRSG

process parameters (steam temperature and pressure) to submissively follow the

heat source’s lead while staying within acceptable operational ranges.

While the HRSG will “follow” the energy being input, the manner in

which the HRSG responds to these transient conditions is critical for ensuring

operational suitability. Therein lies the opportunity for controls engineers to apply

their trade. Large deviations away from desired set-point conditions can lead

to inefficient operation (i.e., elevated heat rates) and premature failure of compo-

nents (internal and external to HRSG). Control trips and interlocks will generally

serve to provide mechanical protection but excessive process upsets may still

result in operational runbacks costing the plant in lost production. If severe

enough, process upsets will result in the entire plant “tripping,” which is the

immediate halt to all operation. Tripping a power plant or process plant is very

costly in terms of lost production and imposed “loss of life” to components

subject to the stresses that result from large pressure/temperature gradients caused

by an on/off step change in the system. Even part load trips (i.e., the CT is not at

full rated output) result in a disproportionate consumption of the system life when

compared to normal operation.

14.2.1 Plant influences

As noted, the HRSG surface dutifully absorbs energy provided by the upstream

energy source (e.g., CT, coke oven, gas/oil fired fresh air system, etc.).

Consequentially, any influence on the energy delivered to the inlet of the HRSG


will impact the boiler’s performance. Table 14.1 provides a brief list of the largest

influencing factors and the consequential effect on a single-pressure (1-P) HRSG.

While steam temperature is typically controlled, Table 14.1 indicates the impact

on steam temperature while allowing the HRSG output to solely follow the heat

input.

14.2.1.1 Ambient temperature

Specific to an HRSG located on the tail end of a CT, the ambient temperature

influence results from the design fundamentals of the turbomachinery in that a CT

produces a nearly constant volume flow rate with mass flow output following

ambient conditions. A hotter day has less mass flow (i.e., less dense air) yet hotter

gas while a cold day has more mass flow (i.e., more dense air) with cooler exhaust.

As the designer has fixed the surface of the superheaters (SHTR), evaporators

(EVAP), and economizers (ECO) around a “design” point, the surface will respond

according to variations from this point. On a hot day, the SHTRs are essentially

“over designed” owing to the elevated exhaust gas temperature entering the heat

transfer surface and the reduced steam flow being produced by the EVAP system.

As the evaporator system sets the demand for water, on a hot day with less steam

being produced, the flow of water through the economizers is reduced and the

economizers may also over perform.

As many HRSGs contain multiple pressure systems, the net effects of ambient

conditions will vary across pressure levels as will the operational control

of the other systems (i.e., high-pressure (HP) system performance will impact

Table 14.1 Influencing factors on 1-P HRSG steam output

Influencing factor Steam flow

(m k 2)

Steam temperature

(m k 2)

Ambient temperature� Hotter� Colder

km

mk

CT load� Base� Part

2k

2m

BoP operating pressure� Higher� Lower

km

mk

Auxiliary heat input� Split SHTR burner� Inlet burner

mm

2m

Gas turbine inlet chillers, foggers m kFuel (same GT load)� Natural gas� Oil

2k

2m

289Operation and controls

intermediate-pressure and low-pressure performance). For example, the influence

of a reheater (RHTR) bypass on the high-pressure system steam production

is almost one to one, meaning that an increase in flow through the RHTR bypass

for RHTR temperature control will result in an increase in HP steam production,

which in turn further reduces the RHTR steam temperature owing to the

increased steam flow passing through the same RHTR surface.

14.2.1.2 Combustion turbine load

CT load makes reference to the relative output of the turbine when compared to

the defined rated output at the present ambient conditions when operating at the

design firing limits of the CT. Thus CT “base load,” or rated CT power output

at ambient, is not a fixed single value but can vary significantly with changing

ambient conditions.

As base load operation reflects the optimum efficiency point for the CT, it is

desirable for the plant to function in this mode. However, HRSG plants often require

large amounts of flexibility in operation to accommodate process needs or power

output requirements and CTs/HRSGs in modern designs are often required to

operate at “part load” (i.e., a CT power output less than base load). While each

family of CTs is different, part load operation typically results in a throttling of

intake air and burner staging so to address flame stability and emission requirements.

The consequence on the energy input to the HRSG is similar to that of a hot day

(i.e., less mass flow at a higher temperature) as depicted in Table 14.1.

14.2.1.3 Balance of plant operating pressure

Whether as a result of process or steam turbine operation (i.e., 13 1 operation vs

23 1 operation), a parametric elevation of the steam outlet pressure results in less

steam production. The elevated pressure results in a higher saturation temperature

in the evaporator system and subsequently a smaller temperature differential

between the exhaust gas and the working fluid (i.e., less thermal driving force).

At the same time, the lower steam flow through the SHTR surface results in

elevated steam temperatures unless suitably controlled by some external action.

14.2.1.4 Auxiliary heat input

The inclusion of auxiliary heat into the HRSG, via a duct burner system, significantly

increases the operational envelope of the HRSG. Oftentimes the HRSG thermal

designer may find ways to arrange (i.e., split) the SHTR surface in just the right way

to allow for the final steam temperature to remain relatively constant across the

intended operating range, which is desirable in that it works to maximize the

efficiency of the system. For some processes, an inlet burner with the entire SHTR

surface located downstream in the exhaust path may be utilized although this is not

as efficient as a split SHTR design and will typically be limited to relatively small

HRSGs with low auxiliary heat input.


In either SHTR arrangement, there will be a net increase in main steam

production when operating with duct burners in service with a consequential

reduction in IP and LP steam production. At elevated burner duties, the increased

HP steam production can result in a complete loss of LP system pressure, owing

to increased energy absorption of the HP economizer circuits. To counter this

potential concern, the burner system must be controlled to either limit burner heat

input (a feature that is always in place to one degree or another regardless

of influence from other systems) or by controlling the LP system pressure by

introducing a steam from a higher-pressure system. This control, called “pegging

steam,” will be covered later in this chapter.

14.2.1.5 Inlet chillers/foggers

In particularly arid or high-ambient-temperature environments, the use of CT inlet

air conditioning provides for an effective means to increase the plant efficiency.

Effectively, the inlet chiller/fogger device works to simulate a cooler ambient tem-

perature condition due to the evaporative cooling of the indirect or direct cooling of

the CT inlet system. Direct cooling systems rely on the complete evaporation of

an introduced water mist or fog prior to entering the compressor stage of the CT.

The direct injection method has the added benefit of increasing mass flow into the

HRSG although water chemistry for the foggers must be monitored to ensure that

potentially damaging chemistries are not created.

14.2.1.6 CT fuel (natural gas or fuel oil)

The fuel type utilized to create the exhaust energy entering the HRSG plays a key

role in the ultimate operation of the HRSG. The specific hydrocarbons making

up the carbon-based fuel directly impact the exhaust composition in both the

major and minor species. Major exhaust gas species (e.g., N2, H2O, and CO2)

work to define the majority of the specific heat into the system and thus

the amount of energy exchanged for a certain temperature difference. While the

impact of the polar molecules (i.e., H2O and CO2) is primarily responsible for

the radiant heat exchange in the elevated temperature zones of the HRSG, the

minority species (i.e., SO2) impacts the operation of the HRSG by requiring

operators to concern themselves with the potential formation of damaging acidic

species or salt formations in the cooler end of the boiler. As a consequence,

HRSGs operating with higher sulfur content fuels are generally required to

maintain elevated temperatures on the heating surface, resulting in lower overall

efficiencies for the boiler.

14.2.2 Base load

In the power industry one often hears the term “base load” used with some

flippancy. Unfortunately, the term is not universally defined and often conveys

different ideas depending on the topic at hand. A broad base definition suggests


that a base load plant is one that can consistently generate reliable power to meet

the demands of the grid/users. For a designer, base load more typically means

that the power plant will be operated at or very near the design point for long

continuous periods of time with relatively small transients and infrequent startups

and shutdowns. Base load operation allows for the most efficient production of

power (i.e., equipment operates closest to design point) while minimizing the life-

draining stresses that are encountered during transient operation. While generally

uneventful, even a base loaded plant will suffer changes in operation as discussed

in Section 14.2.1 and must have the appropriate logic in place to ensure peak

performance of the plant as well as a safe environment.

From a controls perspective focusing on the HRSG, base load operation is

typically the most straightforward and concise mode of operation with most plants

employing very similar control schemes founded upon decades of field experience.

Many of these control loops have recommended schemes outlined in national publi-

cations (e.g., Instrument Society of America) or have been so developed that many

larger distributed control system (DCS) suppliers have standard macros or function

blocks that may be readily employed and suitably capture the necessary influences.

Each HRSG supplier may have nuances that they consider in their controls based

upon their own experiences but each approach shares a large number of similar

fundamentals.

Common/typical HRSG controls include:

� drum level� steam temperature� condensate detection (drains, downstream attemperators)� feedwater preheater inlet temperature� deaerator inlet temperature� drum blowdown/blowoff� pressure control (over pressure)

These controls are more fully defined and expanded upon in Section 14.3.

There are a large amount of variations as well as other smaller controllers that

are commonly employed. This list is not intended to be all inclusive but simply a

reflection of the more common loops employed.

Outside of the HRSG volume, which employs many of the previously noted

schemes for local/focused control of the HRSG, the HRSG as a whole is enveloped in

a broader plant control concept that strongly follows the plant process. For example,

for power plant applications a MW load controller, which seeks to achieve

an operator-defined power load (e.g., 500 MW) by modulation of CT load and

if available, duct burner load. On the other hand, a process plant may need to maintain

a steam header at a defined pressure for proper control of the facility. This is very

common for paper mills, pharmaceuticals and the food industry. Still other plants

may employ a flow controller that seeks to maintain a certain quantity of steam for

supply to a third party user. While each of these controllers captures the HRSG within

its respective umbrella, it is the previously noted controls that allow the HRSG to

stay operating within the defined safe operational guidelines.


14.2.3 Startup

If there is an opposite to “base load” it certainly must be transient operation and

few things are more transient than starting up a power/process plant. This section

discusses the normal considerations for placing a mature HRSG in service and does

not address startup activities associated with putting a new plant in service.

Starting up a plant requires a significant increase in the factors that must be

monitored/controlled so to ensure the safety of the system, the life of the equipment,

and regulatory compliance. In addition to the controls listed in Section 14.2.2, the

following controls must also be employed/considered:

� startup vent (pressure rate control)� CT ramp rate (load)� startup type (cold, warm, hot definition)� SHTR/RHTR drain� steam temperature (interstage/final)� lead/lag unit� general comments for automatic startup

CT ramp rate, startup type, steam temperature (interstage/final), lead/lag, and general

comments are addressed in the following sections, while startup vent, SHTR/RHTR

drain, and further steam temperature control will be elaborated upon in the appropriate

subsections of Section 14.3.

14.2.3.1 CT ramp rate

While the HRSG’s startup vent (SUV) or bypass, if provided, may have the role of

limiting the rate of pressurization within its respective systems (e.g., HP, IP, LP),

these valves and their ability to control the pressure increase are once again subject

to the influence of the incoming exhaust energy. Subjecting the HRSG to unlim-

ited/unrestrained energy input can lead to excessive pressure stresses, temperature

maldistributions (again stresses), overheating (again stresses), deposit formation,

departure from nucleate boiling, and a whole assortment of potentially life-limiting

factors within the HRSG if the HRSG is not properly designed to accommodate

such rapid loading.

As design pressures at which systems operate continue to rise, so do the drum

wall and header thicknesses. The increased drum wall thickness lends itself to

the generation of large temperature differences across the drum shell thickness.

These gradients must be considered in the design and operation of the HRSG.

During the earliest stages of startup, the specific volume of the steam is very large

and subsequently limits the capacity of the provided vents. As pressure builds,

the density of the steam increases and once again the startup vents can become

effective tools for controlling the rate of pressure increase within the system, often

measured at the associated steam drum.

Prior to the SUV being able to suitably control the rate of pressure increase, the

energy from the CT is the limiting factor and the operator must consider limiting


the rate of CT load increase to similarly control the drum pressure increase in each

system. For cold startups, when the largest temperature differences can be realized,

it is desirable to maintain the CT at a very low load (full speed no load (FSNL),

spinning reserve, etc.) to allow the HRSG to heat up to the point of steam produc-

tion. This will help minimize stresses within the system and promote the longest

life possible for the HRSG. At odds with this hold point is the ever-increasing

stringency imposed by emission regulations. Often, the CTs need to achieve a

certain minimum load (e.g., 60%) so that the emissions control techniques provided

for in the CT design may be effective. This creates a dichotomy where the HRSG

would like to operate at lower loads to minimize stresses imposed as the unit

starts up and the CT wants to vault to higher loads to support getting emissions in

compliance. A careful balance must be achieved to address both concerns with

the understanding that the emissions regulations are generally not flexible once the

plant air permits have been established. Maintaining the drum pressures during

periods of nonoperation helps to minimize the stresses associated with startup.

Sparge steam systems, drum heaters, and other techniques have been employed to

varying degrees of success.

14.2.3.2 Startup type

Similar to that of other large industrial equipment, the startup of the HRSG must

take into consideration the present state of the system. While power plants often

look to a timer associated with the steam turbine (e.g., less than 8 hours since

operation5 hot start), the HRSG condition for startup is more commonly defined

by the current pressure/temperature within the steam drum(s).

The rate of temperature increase allowed within the drums is a function of

the current drum pressure at the time of startup with greater rates of increase

being allowed for higher starting pressures. For simplicity, the complete pressure

spectrum for a drum is often defined in two or three specific ranges depending

on the design of the system with each range having a required limit. For higher

operating pressure systems (i.e., thicker drum shells), cold startup ramp rates

may be as low as 1.5�2�F/min while the same drum in a hot startup condition may

have an unlimited rate. Low-pressure systems may have very high ramp rates due

to the much thinner components.

As the change in the drum metal temperature is understood to follow the saturation

temperature of the water/steam in the associated drum, the drum pressure may be

monitored and converted to the associated saturation temperature with a derivative

function for determination of the change in drum water/metal temperature. The CT

loading and SUV controls work to ensure that this change in temperature does

not exceed defined limits. In this simple approach, the ramp rate allowed does not

change during the startup process (i.e., if a cold startup is defined, the cold startup

ramp rate must be sustained throughout the startup).

For processes that require minimal startup time, a more detailed analysis may be

performed via a finite element model that then allows for variable ramp rates to

be employed as the unit pressure increases. The use of this approach has become


more frequent recently as a means to address required emission limits allowed

during startup.

The ramp rate defined previously is one approach for starting the unit that makes

use of standard equipment. Additional temperature measurements may be taken

at various points throughout the drum wall thickness to more accurately define the

instantaneous temperature gradient with the goal of maintaining this gradient as

close as possible to the limiting value determined by the transient analysis.

14.2.3.3 Superheater/reheater drain(s)

The even distribution of energy recovery across the face of the HRSG is

imperative to ensure the unit meets the required process performance as well as to

ensure the mechanical integrity of the components. Uneven temperatures across

the tube field (left to right) can result in large stresses due to varying levels of

thermal expansion. One of the largest contributors to uneven recovery in the

SHTRS and RHTRs is trapped condensation and/or condensation formed during

the startup process.

Several schemes exist for ensuring the removal of condensate during the startup

of the HRSG, each relying on different instruments/devices. All have been shown

to be effective to varying degrees. Of note is that the drain operation is best

performed when associated with the type of startup being considered.

Cold Start. SHTR/RHTR drains can be or should be opened prior to introducing

energy into the HRSG and are typically closed upon achieving a targeted system

pressure.

Warm/Hot Start. Prior to starting the CT/HRSG (cold, warm, or hot), National

Fire Protection Agency rules require that the exhaust side system be purged to

ensure that potentially explosive environments are expunged. For warm/hot starts,

where elevated levels of energy still reside in the HRSG, the purging of the HRSG,

as required, will result in condensation of steam previously “trapped” in the SHTR/

RHTR coils following the last shutdown of HRSG. As this steam condenses,

a locally lower pressure exists, creating a vacuum effect that can in turn flash steam

off of the associated steam drum, thus perpetuating the delivery of steam into the

coil and the subsequent condensation.

Should one open the SHTR/RHTR drain prior to the completion of the purge,

the open path will work to increase the level of flashing thus increasing concerns

associated with condensation in the SHTR/RHTR coils. Extending this further,

if the drains are opened prior to the exhaust temperature, entering the HRSG,

having reached an elevated level (e.g., greater than current saturation temperature

in the high-pressure drum), any steam drawn from the steam drum will once again

be quenched in the SHTR/RHTR coil. Thus, it is good practice to ensure the

exhaust temperature entering the HRSG is sufficiently elevated to minimize/reduce

the quenching potential prior to opening the SHTR/RHTR drains. Once opened,

the drains are closed after a predefined time period (e.g., minutes), depending

on the operating pressure at the start of the startup (i.e., warm or hot start) and the

HRSG manufacturer’s experience. If the unit has been designed to American


Society of Mechanical Engineering (ASME) code, the HPSH and RHTR drains are

then placed in automatic operation where the drains serve to automatically ensure

that any formed condensate is evacuated from the system. Note that the 2013

ASME Section 1 Code, PHRSG section only requires automatic condensate

detection for the HP superheater and RHTR systems (i.e., it is not required for

intermittent- and low-pressure systems).

Quenching of tubes during startup has rightfully received a large amount

of attention over the years and there are several documents available that offer

guidance on this subject. While some approaches may work to minimize losses

(e.g., steam flow out the drains), they generally come with a higher price tag that

is not always easy to justify understanding that the steam losses are quite small

and only occur during startup (i.e., one is not losing power production or process

steam just yet).

14.2.3.4 Steam temperature (interstage/final)

During startup, regardless of the type of startup being considered (i.e., hot, warm,

or cold), the superheaters are considerably “oversized.” One need only think of

what happens to the temperature of the first pound of steam produced when it then

passes through a three-module-wide (approximately 36 ft. across and 75 ft. tall)

HRSG suitable for elevating 5,000,000 lbs/h of high-pressure steam from 596�Fto 1050�F.

During these low steam flow conditions, one will see the pinch at the outlet of the

SHTR (i.e., difference between gas temperature and steam temperature) effectively

reach 0�F. As there is insufficient steam flow to introduce a cooling medium

(i.e., water), the typically provided interstage desuperheater(s) will be unable to

control the final steam temperature to the desired level, which can be less than 700�Fon a cold plant start. Even once sufficient steam flow has been established as defined

by desuperheater suppliers, the operational mismatch is so “gross” at this point that

an interstage desuperheater will encroach on the saturation temperature limit while

the final steam exiting the last superheater coil will still be very close to the measured

gas temperature. Therefore, limiting controls on the desuperheater outlet temperature

must be employed to accommodate this startup effect.

This temperature effect has been magnified over the years by two factors:

(1) increased sizes of gas turbines, which have correspondingly higher part load

operating temperatures; and (2) environmental regulations that are reducing or in

some cases eliminating the period during startup when the plant may legally be

operated with emissions that are exceeding defined limits. In 2016, FSNL tempera-

tures on the larger GTs are in the range of 800�900�F, while as recently as

the 1990s one could sit at FSNL and experience a gas temperature that was well

below 700�F.Due to the encroachment on saturation by the interstage desuperheater, designers

have sought other approaches to limit steam temperature during startup. More often

than not, adjusting firing parameters on the GT is not allowed and many plant

designers have defaulted to the use of a final stage attemperator (i.e., an attemperator


located at the outlet of the superheater). The use of a final stage attemperators,

like most features, has a number of pros and cons:

PRO: The amount of superheat entering the final stage attemperator is typically much

higher, allowing for more attemperator flow to be introduced.

There are no additional heating surfaces located downstream and a fairly simple feed-

back loop may be employed for control.

CON: Final stage attemperators, similar to interstage designs, must have a certain

minimum steam flow/line velocity prior to being able to introduce cooling water, meaning

the earliest stages of startup are still unable to be temperature controlled (different

manufacturers’ designs seek to minimize these requirements but few allow spray water at

the very earliest stages of steam production).

While listed as a pro, the fact that there is no additional heating surface downstream

of the final stage attemperator is also a very strong con. While excess water injection in

an interstage desuperheater can lead to damage to the downstream tube field and/or piping

and present a hazardous condition, it is generally felt to be much better than having

water injection into a steam turbine or process operation. The downstream surface on an

interstage design essentially eliminates the potential for ST/process water ingestion in all

but the most grievous of cases.

14.2.3.5 Lead/lag

Plants often employ more than a single HRSG. The reasons for multiple units

are varied and can include such considerations as required capacity, availability

guarantees, and process needs. The arrangement of multiple boiler designs and/or

operation is typically more complex than that associated with facilities employing

a single boiler. The startup of a multi-HRSG plant whose layout has parallel

heat sources (e.g., CT) feeding separate HRSGs, which in turn feed separate

consumers, need not consider an approach that is different than if a single boiler

only existed.

Multiple HRSGs feeding a single, common user is a very common arrangement

(i.e., 2 CTs�2 HRSGs�1 ST, multiple HRSGs feeding a common steam header

to process) and necessitates that one consider the “other” unit(s) not only for startup

but also normal operation. For example, the loss of a boiler sends a traumatic shock

through the facility as the back pressure at the outlet of the operating boilers

decreases rapidly, disrupting drum levels, steam production, and steam tempera-

tures. Similarly, the pressure imposed on the HRSG during normal operation will

swing greatly as the total steam flow delivered to the common collector varies

(i.e., back pressure from steam turbine is much less if only a single unit is in service

when the facility is predicted on four HRSGs delivering steam to the steam turbine)

and the various intended modes of operation must be clearly defined early in

the design phase to ensure satisfactory operation at desired loads. An absolute

minimum or floor pressure must be defined and one needs to determine if an inlet

pressure controller should be employed for the steam turbine admission at the lower

ends of operation.

Power plants today are very streamlined and while resources onsite are

elevated during a plant startup, it is very common for a single operator to be at


the DCS directing the startup operations. As a result, during plant startup of a

multi-HRSG facility, a very common approach is for the operator to select

a “lead” unit (i.e., a unit to start first), bring this lead unit to a desired load

(e.g., FSNL, spinning reserve, emission compliance, base load, etc.), and then

return to the next unit (i.e., the “lag” unit), match the load on the two units,

and then bring the facility to the desired plant load (e.g., base load).

Multiple HRSGs feeding into a common process creates potential hazards and

requires additional provisions to be made within the BoP systems. Boiler codes

universally require that if multiple units deliver into a common collector, then

special devices capable of preventing flow from backing into down systems

(i.e., online unit feeding steam into offline unit) and/or redundant isolation devices

should be employed to ensure safety. For the ASME code, this means that either

two steam stop isolation valves should be provided or that a single steam stop valve

and a stop check (e.g., non�return valve) should be incorporated into the piping

network when multiple units are considered.

During startup, the lead unit often is brought to a load that will provide the

necessary steam conditions for warming up the BoP piping/systems (e.g., steam

turbine). If one considers a steam turbine application, the desired steam pressure for

initial warming/rolling of the steam turbine is often 25�30% of the rated pressure.

This means that for a 2000-psi HP system, the lead unit will target a pressure in

the range of 500 psi, with the steam developed during startup of the lead unit

passing through an HRSG-specific sky vent/startup vent until the steam is delivered

to the steam turbine. BoP pipe warming is addressed through well-engineered

steam traps and drain connections on the piping network. When appropriate steam

conditions have been achieved for the steam turbine, the lead HRSG unit’s sky

valve is controllably closed (mindful of ramp rate limitations for the HRSG

pressure system) and the generated steam passed to the steam turbine. At this point,

the operator returns to the lag unit.

Once started, the steam produced from the lag unit does not initially have

adequate pressure to enter into the pressurized plant piping, therefore the lag

unit must similarly have a dedicated sky vent (or bypass to a condenser should the

facility have such an arrangement) that can be used to increase the lag unit’s steam

pressure in a controlled manner to a value that is sufficient (i.e., higher than plant

header). Once a suitable pressure in the lag unit is achieved, isolation of the lag

unit is terminated (or the non�return valve automatically allows lag steam to be

introduced) and the lag unit steam is delivered to the plant header/distribution

piping. This process continues for HRSG 3, 4, etc.

As noted, there are several items that need to be addressed when bringing a

multi-HRSG facility online. One is to ensure that the steam flow passing back

to RHTR coils, when RHTRs are utilized in the process, is equal or proportioned to

the heat input that is being delivered to the specific HRSG. While plant layout

can work to create flow balances (i.e., symmetric layout should have similar

pressure drop at similar process conditions), often an active balancing valve and

flow meter must be employed on the cold reheat line feeding each unit to ensure


suitable distribution. Furthermore, even at facilities with a single HRSG, unless

HPSH and RHTR have been specifically designed for run dry conditions, it is

important to have steam flow established in the SHTR/RHTR coils to promote

uniform cooling of the heating surface prior to introducing elevated energy from

the heat source.

14.2.3.6 General comments for automatic Startup

Similar to other industries, there is a growing trend for ever-increasing automation

within the operation of the HRSG. One of the challenges for the controls engineer

is to determine what “level” of automation is truly desired for the facility.

While specifications may provide language such as “HRSG shall include automatic

operation” or “HRSG shall be designed for automatic startup,” one quickly realizes

that these statements are not as definitive as required to allow the designer full

comprehension of the desired final product. Often, once the designer has had the

opportunity to discuss a startup plan for the plant with the owner/operator, it is

highlighted that the plant still wants the operator “involved.” Again this is ambigu-

ous and the engineer must strive to achieve clarity of direction from the end user or

the engineering procurement contractor (EPC). A fully automatic facility requires

logic/code that greatly exceeds that necessary for normal operation owing to the

multitude of startup/shutdown influences as well as auxiliary systems.

14.2.4 Part load/shut down

Historically, combined cycle (CC) units (CT1HRSG) enjoyed the luxury of

primarily serving in base load operation. Today, most designs must consider HRSG

operation at reduced CT loads. While the exhaust energy is a direct function

of ambient conditions and CT load, the part load characteristics from every CT

manufacturer are different and typically are presented as a family of expected

performance curves or data sets. A properly equipped HRSG should have no

problem operating at conditions that were well defined during the design phase.

The designer is advised to seek clarity (i.e., definitive heat and mass balance

information) for each desired operating condition of the facility and should address

ambiguous statements such as “the HRSG shall be designed to operate under all

operating conditions” with a request for the details of such operation. Most plants

will pass through part load operation on their way to shutdown (i.e., most

plants would prefer to avoid hard trips from base load as this places the equipment

under considerable strain/stress).

Should a plant suffer a trip (i.e., complete loss of operation of one or more

critical components), there is very little that the operators may do proactively to

prepare and they will generally find themselves scrambling to minimize impacts of

the trip and determine the cause of the disruption. However, if the shutdown is

scheduled, there are a few items that the operator may employ prior to or during

the shutdown to help protect the boiler.


Prior to shutdown:

1. Ensure water chemistry is in line with desired values for nonoperational periods.

This may take the form of increased blowdown, extra operation of the intermittent

blowoff (IBO), tweak of chemical levels to ensure targeted values are maintained, etc.

2. Develop a work list or list of tasks to be performed during the next outage and ensure that

all required parts/components/personnel are prepared.

When shutting down the HRSG, one generally desires to reduce the boiler load to

the minimum value it has been designed for prior to tripping (i.e., stopping fuel flow)

the GT. This allows for as smooth a transfer from operation to offline as possible.

Nonetheless, as soon as the heat source is removed from the HRSG, the generation of

steam will discontinue and the steam bubbles previously occupying a large volume

within the evaporator tube field will collapse resulting in an immediate “shrink” to the

drum water level (level will reduce). Although the heat source has been removed, there

is still considerable energy within the HRSG gas side components due to their respec-

tive specific heats/heat capacities (i.e., lots of energy in the casing liners, SHTR/

RHTR tube fields, etc.) and the operator is advised/required to ensure that the drum

water level remains above the lowest allowed operating level even though the heat

source has been removed until gas side temperature measurements confirm that it is

safe to allow the water level to decay or even to empty the boiler. There have been

numerous reported cases where damage has been encountered during shutdown due to

overheating (e.g., discontinuous thermal expansion, overheating of catalyst systems).

Once the CT is offline and rotating at an appropriate rate, it is desirable to

isolate the gas side of the HRSG to prevent an accelerated rate of decay of pressure

within the pressure systems. Similar to startup, large stresses can be imposed if

excessive cooling is imposed on the system. Spin cooling of the equipment should

be avoided. Ideally, the HRSG can be allowed to cool down naturally. The use

of stack dampers and sparge steam systems have been used successfully to help

maintain the HRSG system pressure and facilitate the next startup (i.e., allow the

next start to be a warm start rather than a cold start).

While the HGRSG manufacturer’s recommendations need to be adhered to,

in general, it should be safe to begin draining the system once the associated system

pressure has decayed to 10 psig or less. For units without a stack damper, this

pressure may typically be reached in under 12 hours. Units with dampers may take

over 24 hours to realize the same pressure decay.

14.2.5 Cycling

In a broad sense of the word, cycling suggests that the HRSG has been, is, or will

be subject to alternating stresses. These stresses are imposed as the unit pressure

and temperature are raised and lowered to meet process demands. From a controls/

operation perspective, the changing conditions introduced as a result of cycling are

an extension or reflection of the unit operation (i.e., load change, startup, shutdown)

and do not necessitate significant description here. The more fundamental issues

associated with cycling, the imposed alternating stresses and consumption of boiler

life, are addressed in other chapters of this book.


14.2.6 Alarms

The safe and efficient operation of the HRSG requires that process conditions

be maintained within a set of defined operating parameters. Alarms that initiate

automatic actions within the control system or annunciate so that the control room

operators are notified that conditions are outside the “normal” range allow the opera-

tors to take appropriate actions to maintain the parameters within the appropriate

range.

While every facility will employ alarms that have found purpose specific to their

needs and/or experiences, the list of process variables in Table 14.2 is commonly

included in alarm lists for CC HRSG facilities.

14.3 Controls

14.3.1 Drum level control

Maintaining the proper drum water level is one of the most important controls

employed for an HRSG. Certainly, the HRSG will not perform as desired if the

other controls are not properly employed but low drum level is the only controller

addressed in both the ASME code, the National Fire Protection Association code

[1], and all other nationally recognized safety codes. The concern associated with a

reduced drum water level is associated with the knowledge that should the evapora-

tor tube field not be sufficiently cooled, the carbon steel evaporator tubes may fail

due to short-term overheating, excessive deposits, or the formation of chemical

concentrations at the tube steam/water interface ultimately leading to failures.

Excessive tube growth as a result of elevated tube temperatures can damage piping

and cause rupturing of tubes.

Drum level controls are very well established with many DCS suppliers having

developed standard macros that have demonstrated successful operation for

hundreds of units. The type of controller and the final scheme to be employed

must consider the available measurements and the current operation of the system.

Most steam drums make use of one of two options: single-element control and

three-element control. While duel element control (feedwater flow and drum level)

has some applications, in general a single-element control is more appropriate and

offers the same general level of performance.

14.3.1.1 Single-element control

A single-element control (SEC) looks only at the water level in the steam drum and

adjusts the feedwater flow via a proportional integral derivative (PID) controller.

Although simple by nature, an SEC is very useful and is the dominant controller for

reservoir tanks (i.e., steam drums where large quantities of water are being

extracted for other use compared to the net steam production of the evaporator) and

simple water tanks.


Table 14.2 Typical HRSG alarms

HP drum level HP steam flow @ max capacity and HP drum pressure at HIHI HP SH1 drain line level� Hi Hi� Hi� Lo� Lo Lo (BMS trip)� Lo Lo (CT trip)

HP steam flow designed steaming capacity � Open� Close

RHTR steam flow @ max capacity and HRHTR pressure at HIHI

RHTR steam flow designed streaming capacity Final HP steam outlet temperature� Hi Hi� HiIP drum level IP steam flow @ max capacity and IP drum pressure at HIHI

� Hi Hi� Hi� Lo� Lo Lo

IP steam flow designed steaming capacity

RHTR2 drain line temperature

LP steam flow @ max capacity and LP drum pressure at HIHI � Open� CloseLP steam flow designed steaming capacity

LP drum level Steam temperature: uncontrolled HP SHTR outlet (ind. coils) RHTR1 drain line level� Hi Hi� Hi� Lo� Lo Lo

� Hi Hi� Hi

� Open� Close

Steam temperature: HP DSHTR inlet (common pipe) Final RHTR steam outlet temperature� Hi Hi� Hi

� Hi Hi� Hi

Exhaust gas flow path inlet pressure Steam temperature: HP DSHTR outlet Feedwater system available� Hi Hi� Hi

� Lo� Lo Lo Exhaust gas path not open

HP drum pressure Duct temperature: dstream burner� Hi Hi Hi� Hi Hi� Hi

� Hi Hi� Hi

Loss of CT/CT trip

Loss of interlock power

IP drum pressure HP DSHTR isolation valve open/close count� Hi Hi Hi� Hi Hi� Hi

� Hi Loss of control power

Steam temperature: CRHTR inlet� Hi Hi� Hi

LP drum pressure Steam temperature: uncontrolled RHTR coil (ind. coils)� Hi Hi Hi� Hi Hi� Hi

� Hi Hi� Hi

HP steam outlet temperature Steam temperature: RHTR DSHTR (common pipe)� Hi Hi� Hi

� Hi Hi� Hi

HRHTR steam outlet temperature RHTR DSHTR isolation valve open/close count� Hi Hi� Hi

� Hi

IP Steam outlet temperature Steam temperature: RHTR DSHTR outlet� Hi Hi� Hi

� Lo� Lo Lo

LP steam outlet temperature Steam temperature: upstream RHTR bypass tie in� Hi Hi� Hi

� Hi Hi� Hi

Steam temperature: HP DSHTR outlet cond. Steam temperature: downstream RHTR bypass tie in� Open� Close

� Hi Hi� Hi

HP SH2 drain line temperature Steam temperature: RHTR DSHTR outlet cond. trap� Open� Close

� Open� Close

14.3.1.2 Three-element control

A three-element control is a feedforward loop wherein the measured steam flow

(the feedforward component) is compared to the incoming feedwater flow and the

net difference is then adjusted/biased by the measured drum level. The resulting

biased flow then generates the required demand for the feedwater control valve.

Often during startup, the steam flow measurement may be unavailable, or perhaps at

the lowest loads, unreliable. In these modes of operation or configurations, a single-

element controller is used until a defined steam flow threshold (e.g., 30% of base load

flow) has been exceeded, after which time the three-element control is put in place. The

three-element controller typically will track the single-element controller to avoid

windup issues, where large errors may accumulate due to erroneous input, and to pro-

mote a smooth transfer (and vice versa when the system is under three-element control).

Due to the drum swell phenomenon (i.e., level in drum rises as a result of

increased specific volume of heated water), there will not be a demand for water

during the initial stages of startup. However, to accommodate the expected swell,

the drum level should be set to an appropriate level lower than “normal.” This

results in an error for the level controller (i.e., level not at set-point), which will

send a signal to the level control valve to open. To address this issue, a startup level

is often defined that serves as an initial set-point for the drum level until a defined

pressure or steam flow has been achieved. Once the threshold value has been

exceeded, the drum level set-point is transferred to the normal set-point via a rate

limited transfer (i.e., level returns to normal at a limited rate so to avoid fast swings

in valve position) (Fig. 14.1).

Figure 14.1 Drum level control.


14.3.2 Steam temperature control (attemperation/bypass)

As noted earlier in this chapter, ambient conditions can significantly affect the

process conditions of the HRSG (e.g., hot ambient creates hotter steam). Due to

the fact that off-design operation is unavoidable and most processes have a limited

range of acceptable final steam temperatures, almost all HRSGs will have some

level of main steam temperature control. This control can take the form of a final

stage attemperator but more often than not takes the form of an interstage desuper-

heater, necessitating the SHTR surface to be split. In some designs this control

may be a steam bypass system. Reheater systems, if applicable, are also subject to

final steam temperature control.

Attemperation is fundamentally addressed through the direct injection of a cooler

fluid into the hotter fluid. Although external heat exchangers could be employed,

they are typically not cost-effective solutions. In the example of HRSGs, cooler

feedwater is delivered to the desuperheating station where it is regulated and injected

into the live steam pipe, thus taking advantage of the latent heat of the water to min-

imize the amount of water being introduced into the system. Minimizing the amount

of desuperheater water utilized provides several advantages:

1. It promotes better steam chemistry as impurities brought into the system by the water are

minimized.

2. It minimizes the length of piping required for mixing and process measurement prior to

the next process component in the system (e.g., superheater, steam turbine, process).

3. It maximizes thermal performance due to proper allocation of the heating surface

(i.e., designing with low to zero desuperheating at the base operating case maximizes

steam production).

There are a number of general constraints that must be met prior to placing an

attemperator into service:

1. Sufficient superheat must be available in the main line steam to fully evaporate the

coolant that is introduced.

2. The velocity in the main steam line must be sufficient to entrain injected water droplets

and prevent pooling of coolant on the walls of the pipe.

3. To ensure adequate energy to evaporate the injected cooling water as well ensure suspen-

sion of the entrained coolant (i.e., water not falling to bottom of pipe), a certain quantity

of steam relative to introduced coolant quantity is to be maintained/observed. While the

specific design of the desuperheater can have great impact on the amount of water

that may be suitably injected, a good rule of thumb would be for no more than 20% of the

desuperheater outlet steam flow to come from water injection.

4. The minimum difference between the final desuperheater outlet temperature and saturation

required by the HRSG manufacturer’s design must be maintained.

14.3.2.1 Final stage attemperator

Understanding that the final steam temperature is ultimately what is being targeted

for control, one can readily understand the applicability of locating a desuperheater

in this location. A very simple feedback loop may be employed. However, as no

additional heat input will enter the system, one must employ relevant interlocks


to prevent water droplets resulting from incomplete evaporation from entering the

downstream process. Understanding that severe damage may result from water

ingestion in steam turbines or process equipment, final stage attemperators are gen-

erally supplied with an increased mixing length (i.e., longer straight run of pipe)

and may be restricted on the degree of desuperheating allowed (i.e., the margin

between the set-point temperature and the corresponding saturation temperature

may be larger). The ASME publication “Recommended Practices for the Prevention

of Water Damage to Steam Turbines Used for Electric Power Generation � Fossil

Fueled Plants,” ASME TDP-1 [2], while not clearly applicable for ASME Section 1

components, offers designer’s guidance on BoP, boiler external piping (BEP),

and non�boiler external piping (NBEP) piping for minimizing concerns over water

entrainment.

While final stage attemperation can be employed under the right conditions, final

stage attemperators, if supplied, are not typically used for normal operational

control of the main steam temperature but only to address the startup of the facility

as a whole. As discussed in Section 14.2.3, a CC facility will often suffer from a

disconnect between the desired steam temperature for bringing the steam turbine

online and the temperature of the steam being generated by the HRSG during

part load operation of the CT. The final stage attemperator is uniquely qualified

to address this gap between the process needs and the physics associated with

the boiler.

The HRSG supplier is often requested to supply this component, yet they are

not always familiar with the process demands for the downstream equipment espe-

cially during these highly transient conditions. Understanding that the final stage

attemperator provides a solution for warming/starting up BoP equipment, the supply

of this device is best addressed by the EPC or BoP designer, who will be more

familiar with the intended plant startup (e.g., will GT temperature matching be

employed? What is the design capacity of the condenser? How will auxiliary steam

be used during startup, if at all? What are the required hold points for the steam

turbine heatup?).

14.3.2.2 Interstage attemperator

While the base controls for the final stage attemperator are fundamentally simple,

this arrangement often does not provide the most cost-effective HRSG for normal

operating modes (i.e., not at startup). The superheater tubes must be designed

to accommodate the highest tube wall temperatures that will occur during the

operation of the HRSG. If the attemperation of the live steam occurs at the outlet,

then the superheater tubes will be subject to the highest temperatures associated

with part load operation, off-design ambient temperatures and burner operation,

if applicable, and will subsequently be thicker and/or made of a costlier material

(i.e., T91 vs T22). Thus, it is common practice to split the superheater surface

into multiple sections and introduce a desuperheating station between the different

coils. This will allow for the steam temperature to be tempered earlier in the

tube field, permitting lower-alloy materials to be supplied and thinner tubes to be


utilized. The actual split of this surface is balanced between material selection

and consideration of startup concerns most often addressed via the final stage

attemperator.

An interstage attemperator makes use of a cascading control loop, where the

error between the measured final steam temperature and the final steam temperature

set-point is scaled to determine the set-point temperature of the steam at the outlet

of the interstage desuperheater. The inner loop operates via a simple feedback loop.

Similar to the final stage attemperator, interlocks must be employed to prevent the

temperature at the outlet of the desuperheater from encroaching upon saturation

(Fig. 14.2).

14.3.2.3 Bypass

A bypass system for steam temperature control replaces the water introduced in

attemperation with steam, which is cooler than the HPSH or RHTR outlet steam

temperature. The inherent benefits of this arrangement are:

1. A bypass allows for a simple feedback loop to be employed for purposes of control.

2. It does not introduce additional chemicals/solids into the steam chemistry.

3. It eliminates concerns with water ingestion or quenching.

4. It improves overall performance by generating additional steam in lieu of excess

temperature.

Figure 14.2 Main steam temperature control.


14.3.3 Condensate detection/removal

As noted earlier in Section 14.2.3, the removal of condensate from the otherwise

“dry” coils (i.e., SHTRs, RHTRs) is very important for the long-term availability

and life of the HRSG. In fact, the damage potential and safety concern associ-

ated with the presence of condensate in these coils prompted the ASME to

include requirements (ASME Section 1, PHRSG-3/PHRSG-5) [3] that for

HRSGs with multiple pressure levels, the high-pressure SHTRs and RHTR coils

must include provisions for automatic condensate detection and removal. The

ASME actually went further in ASME Section 1, PHRSG-4, which requires

HRSG manufacturers to provide condensate traps with automatic detection/

removal immediately downstream of desuperheating devices whenever water

serves as the cooling medium.

There are several proven methods available for condensate detection and

removal. When sufficient superheat is available at the drain/trap during normal

operation, temperature measurement devices have been proven successful at serving

to open the drain(s) whenever the measured temperature encroaches upon saturation

(e.g., saturation1 15�F) and then closes the valve(s) once the measured temperature

exceeds a defined value (e.g., saturation1 40�F). This offers a low-cost and effec-

tive solution as thermocouples are particularly well suited for this high-temperature

service.

Without sufficient superheat to make use of temperature measurements, one may

employ level switches (i.e., mechanical/conductivity) or other less-intrusive methods

(i.e., ultrasound) to determine the presence of condensate. While employing these

devices is considerably more expensive when compared to temperature measurements

(i.e., thermocouples), they suitably fill the need of condensate detection.

One must be sure to incorporate the startup demands for the drains within

the condensate detection logic to ensure a comprehensive solution suitable for

addressing all modes of operation.

Specific to valve operation for condensate removal, a set of valves in series

is required per ASME code. To save the interior valve for tight shutoff, upon

detection of condensate, the interior valve is driven to the open position while the

exterior valve remains in the closed position. Once the interior valve is open,

the exterior valve is driven to the open position. This sequence allows the interior

valve to be isolated from the high differential pressure flow in low open positions

that can lead to valve seat damage. The valves are closed in the reverse order just

described (Fig. 14.3).

There are many drain configurations that, while employing two drains in series,

elect to have a single actuated valve, in lieu of both valves being actuated,

for purposes of cost effectiveness. This has been sufficient in many cases where

cycling is expected to be at a lower frequency or where operating pressures are

reduced. In higher-pressure systems or cycling units, the single actuated valve may

have a shorter operating life.


14.3.4 Feedwater preheater inlet temperature

As designers and owners strive to minimize heat rate (i.e., maximize efficiency) of

the overall process operation, thermodynamics allows one to either increase the

heat source (e.g., firing temperature in a CC plant) or minimize the heat sink (e.g.,

condensate coolant temperature). Materials play a role in both options. The higher

temperature option generally falls outside the HRSG (i.e., higher firing temperature

within the gas turbine) although the elevated exhaust temperature does enter the

HRSG and must be addressed in the design and controls, as addressed in separate

sections of this chapter and handbook.

The lower-temperature coolant, while beneficial for the overall plant perfor-

mance, does require special consideration in the HRSG. As the metal temperature

of the heat transfer surface is more strongly influenced by the tube side fluid tem-

perature, allowing low-temperature water to enter the earliest (i.e., coolest) coils of

the HRSG, can result in gas side acidic species condensing on the metal surfaces.

While generally a long-term concern when operating with natural gas, operation

with higher sulfur-laden fuels can result in damage much more quickly. Whether

natural gas or some other fuel, some means for ensuring that the boiler influent

remains above a determined temperature (e.g., 140�F/60�C for natural gas) is com-

monly employed.

Figure 14.3 Condensate detection.


14.3.4.1 Recirculation pumps (with bypass)

Recirculation pumps work to control the HRSG inlet water temperature by return-

ing hot water to the feedwater inlet to mix with the low-temperature condensate

prior to the mixture entering the coolest coil/heat transfer surface. While a variable

frequency drive may be used, a control valve is often located at the pump outlet

and utilizes the demand signal generated by the mixed temperature measurement to

determine a controlled position.

In some instances, recirculation alone is insufficient. In these scenarios, once the

recirculation control valve has been exhausted (i.e., opened past the point of con-

trol), a bypass control valve, which directs water around all (or a portion) of the

heat transfer surface, works to control the influent to the desired temperature. In

some rare instances, the required bypass flow may not be achievable via the pres-

sure drop of the heat transfer coil alone (i.e., as the coil is bypassed, the pressure

drop in the coil reduces as a square of the flow rate in the coil and there is insuffi-

cient back pressure to force required flow around the coil) and an additional control

valve must be located at the inlet of the heat transfer coil to artificially create the

necessary back pressure, either by using the same signal employed for the bypass

valve or working in series after the bypass valve has exceeded an effective open

position (Fig. 14.4).

While the use of a bypass results in depressed steam production (i.e., increases

approach into the associated steam drum), this mode of operation is typically

only encountered in off-design cases where the reduced steam production is not

of significant consequence.

14.3.4.2 Bypass valve

Should high-sulfur fuels be employed in the process, one may not be able to

efficiently recirculate water to adequately raise the inlet temperature to a level

(e.g., .240�F/115�C) that would prevent dew point corrosion associated with the

higher sulfur content fuel. One simple solution to protect the boiler from premature

corrosion is to fully bypass the problematic heating surface and introduce the influ-

ent directly into a steam drum. As noted previously, the cooler influent will impact

the generated steam production and in the case of a fully bypassed coil, the steam

drum pressure may be depressed to levels so low that they are either unsuitable for

process needs, or they may allow for intermittent, localized steam collapse in the

steam drum causing unacceptable fluctuations in level and pressure. To ensure that

the steam drum pressure does not drop to unacceptable levels, steam from a higher

operating pressure may be delivered to the drum via a regulating pressure control

valve. This method is commonly called “pegging steam.”

14.3.4.3 Heat exchanger

The use of external heat exchangers allows one to make use of the main plant

feedwater/condensate pumps in lieu of additional recirculation pumps, helping to

reduce costs and maintenance while helping to improve overall plant performance


Figure 14.4 (A) Preheater control with recirculation pumps and bypass. (B) Preheater

control with external heat exchanger.


(e.g., the slight increase in duty for the main plant water pumps will be more

efficient than operating additional recirculation pumps).

When using heat exchangers for inlet temperature control, the incoming water

passes through the cold side of the heat exchanger and is heated up to the desired

inlet temperature by hot water extracted from downstream sources or by typically

passing the full flow of the coil effluent through the hot side of the exchanger.

The use of heat exchangers for this application is described in greater detail in

Chapter 5, Economizers and feedwater heaters.

14.3.5 Startup vent/steam turbine bypass

As noted in Section 14.2.3, high stresses, which can be imposed by large temperature

gradients created during startup, particularly during a cold start, should be mini-

mized via a control scheme/startup philosophy that employs suitable venting/

bypassing of the generated steam until such time that the process can accept the

boiler effluent.

The state of the boiler/BoP equipment prior to startup plays a significant role in

defining the best approach to bring the system online. For example, a hot boiler

in which the temperature gradient across the largest and thickest components is at a

minimum can accommodate a much larger rate of increase in drum pressure than

a cold boiler, where the difference will be much greater (the inside drum wall will

be at the water/steam temperature whilst the outside drum wall will be much closer

to ambient temperature). A plant going through a hot startup will often have an online

condenser (i.e., a vacuum still exists) such that the generated steam may be directed

immediately to the condenser via a bypass system, which tempers the steam for

both pressure and temperature, allowing for the facility to minimize makeup water

demands. A cold plant will need to be able to controllably vent steam to atmosphere

until an alternate path is available (e.g., steam header, condenser, steam turbine).

Both motor-operated globe valves and traditional pneumatic actuated control

valves have been shown to be suitable options for controlling the rate of pressuriza-

tion of the steam system. Although a low-duty motor-operated valve can be utilized

to perform adequately for startup, a better solution is to ensure that appropriate

solid state controls are used in the motor and that an analog input/digital input

(AI/DI) converter is used at the motor to allow a typical PID controller output from

the DCS.

During the earliest stages of startup, the low-density/high-specific-volume steam

will generally cause the startup vent to be choked (flow is restricted by the sonic

velocity in the throat of the valve). As the upstream pressure increases, further

increasing the steam density, the startup vent will demonstrate greater and greater

levels of control.

As mentioned previously, the rate of pressurization is often a function of the

initial conditions, and the control scheme for the startup vent will likely have differ-

ent set-points to accommodate each type of startup. While pressurization is a direct

and easy-to-ascertain measurement (i.e., ASME code requires a drum pressure

transmitter), the rate of change of the metal temperature is of primary interest.


The rate of change of the drum metal temperature is often inferred from the rate

of change in drum water temperature, which is calculated using a function of

saturation pressure change in the drum. Of particular interest for startup is that the

slope of the steam/water saturation curve is steepest at low pressures. The HRSG

can thus accommodate a much larger increase in system pressure/temperature when

the system is at higher pressures. For example, the difference in saturation tempera-

ture between 1000 psig and 1500 psig is 50�F. If one were to limit the rate of

change for the drum water to 10�F/min, in 5 minutes the boiler could transition

from 1000 psig to 1500 psig. On the other hand, a cold boiler starting at 0 psig and

similarly limited to a 10�F/min ramp rate could only be at 22 psig after the same

5 minutes.

In any event, the sky vent, when used for HRSG pressurization, works to

increase pressure by throttling the flow. When the ramp rate is encroached upon or

exceeded, the sky vent will open to slightly reduce the back pressure. It is important

that prior to introducing any heat into the system a steam path must be established.

If no other path is suitable or available, the startup vents must be opened early

in the startup.

On a cold start, the startup vent is usually opened prior to CT ignition. Once the

startup vent is placed in automatic operation, the controller will drive the vent to its

minimum open position as it wants the water temperature to increase by a defined

value. As soon as the subcooled water begins to heat up, which will be uncon-

trolled, the demand signal to the startup vent will drive the valve open, generally to

the 100% position. Once the steam generation and the resulting pressure have

reached a level where the sky vent is effective and intended to operate, the vent

will work to control the ramp rate as defined.

On a warm/hot start, placing the startup vent in automatic mode will similarly

try to drive the valve closed at the initial stages of startup due to depressurization

that will occur when the valve is opened to create a steam path. A high select or

low limiter must be used to prevent the startup vent from closing during these

stages in order to maintain the required steam path.

Once a bypass to a condenser is available, it is desirable to transition the

startup vent/sky vent closed and make use of the steam bypass. The steam bypass

must be designed to control the rate of increase in the boiler steam systems just as

the sky vent would have. For units with RHTRs, the HP to RHTR bypass should

be used as early as possible to ensure cooling steam is available in the RHTR

coils prior to the introduction of elevated energy into the system from the heat

source. In these designs, the HP to RHTR bypass must again be capable of con-

trolling the rate of increase in the HP system. The pressurization of the RHTR

system must be at a rate that does not create excessive back pressure on the HP

system causing it to increase in pressure too quickly. The RHTR outlet is often

provided with a startup vent that is set to a predetermined position (e.g., 100% for

cold start) and the natural back pressure of the RHTR sky vent is the sole

basis for pressurization of the RHTR system. The IP system, which often feeds

into the cold reheat inlet piping, is provided with a back pressure valve on the

IP steam outlet and this valves serves to control the rate of pressure increase


for the IP drum. One should note that when the startup vents are 100% open,

the heat input must be limited to ensure that the ramp rates defined for HRSG

pressurization are not exceeded (Fig. 14.5).

14.3.6 Deaerator inlet temperature

To promote a long design life, the boiler water/steam chemistry must be maintained

within well-defined limits. Chapter 15, Developing the optimum cycle chemistry

provides the key to reliability for CC/HRSG plants, and numerous international

standards offer good technical direction on what to monitor, how to monitor, when

to monitor, and what to do if parameters are outside limits. Oxygen content in the

boiler feedwater is critical for ensuring that protective oxides develop to minimize

erosion and/or corrosion. However, the exact concentration must be carefully con-

trolled as various types of overall boiler chemistry programs dictate. A classical

mechanical device for reducing the oxygen content in the boiler feedwater is the

deaerator (DA). A deaerator may be a standalone device or can be incorporated

into the systems condenser.

In either case, the deaerator effectiveness is premised on two fundamental laws,

Henry’s law of partial pressures and the inverse solubility of a gas in a liquid with

temperature. Henry’s law basically states a diffusion principle, that if something

Figure 14.5 Startup vent/steam turbine bypass.


is concentrated at a level above the surrounding levels, the concentrated gas will

want to move in the direction of lower concentration. For a DA this is achieved by

surrounding the incoming water droplet, rich in oxygen, with an atmosphere high in

steam concentration thus leaching the oxygen from the water into the steam space

where it is vented from the system.

The HRSG controls must consider the inverse solubility of oxygen in the water

(i.e., as water temperature rises, oxygen will leave the water space) so that the

oxygen is released from the incoming water as it is heated to saturation conditions

in the DA vessel, where it may be evacuated through sky vents. The oxygen should

not be released in a location that could lead to high trapped oxygen concentrations

that may cause premature erosion during low load operating periods or offline

operation (Fig. 14.6).

DA manufacturers typically suggest an approach temperature (difference between

steam temperature and incoming feedwater temperature) into the DA tank in the

range of 20�25�F. Under part load operation, the temperature of DA influent

can encroach into this range thus risking premature release of O2 into the system.

A simple partial bypass around all or part of the feedwater preheater is commonly

employed to control the DA approach to the desired range.

Figure 14.6 Deaerator inlet temperature.


14.3.7 Drum blowdown/blowoff

Operation of the HRSG with inappropriate water chemistry will generally lead to

poor cycle performance and increased maintenance due to elevated corrosion rates.

Most drum type HRSGs are equipped with dedicated connections for assisting the

plant in maintaining the HRSG water chemistry within acceptable levels. These

connections are the continuous blowdown (CBD) and the intermittent blowoff

(IBO). While neither need be automated, as the plant may operate satisfactorily via

direct operator control, both connections may be automated. The blowdown connec-

tion is easier and more efficiently controlled than the blowoff connection.

14.3.7.1 Continuous blowdown

The CBD connection is provided for the removal of dissolved solids (Ca1, Mg1,Na1 , PO41 , Cl2 , etc.) from the steam drum that, while generally in concentra-

tion levels of ppm/ppb, can individually or in thermodynamically favorable

compounds precipitate out in the steam turbine, the condenser, or any other portion

of the steam/condensate cycle leading to reduced performance (i.e., reduced heat

transfer, increased pressure drop) and damaging mechanisms (e.g., stress corrosion

cracking, under deposit corrosion, caustic gouging, acid corrosion, etc.).

The boiling process concentrates the dissolved solids carried into the HRSG via

the boiler feedwater. The amount of CBD flow removed from the drum, which is

always in service when the HRSG is operating, and thus “continuous,” is a function

of the concentration in the feedwater entering the drum and the concentration

allowed in the steam effluent. The chemical/phase equilibrium of each chemistry

component (e.g., Na1), often termed the distribution ratio, defines the allowed con-

centration in the liquid phase relative to the steam phase. Via the measurement of

the feedwater flow rate and concentration of a representative element/compound

and the measurement of the drum concentration of the same compound, a required

CBD flow rate may be determined. The CBD valve is then adjusted to pass the

determined flow. Of note is the challenge in getting an accurate two-phase flow

measurement, which is the case with the CBD (i.e., the saturated water will flash as

it passes along the CBD piping).

14.3.7.2 Intermittent blowoff

The IBO is provided to allow a means of removing suspended solids from the

drum water. Unlike dissolved solids, which are ions of specific compounds,

suspended solids are typically organic material that is held in solution only as a

result of dynamic/static forces within the bulk fluid overcoming the gravitational

force otherwise imposed on the particulate. Typical boiler chemistry would

introduce an agent that creates the necessary flocculation and agglomeration of

the small particles into a larger chain of higher mass weight to the point that the

particle falls out of suspension. The IBO operation is used to purge the system of

these large compounds.


The frequency of the IBO operation is not as easy to define as the CBD.

A measurement of particulate matter may be collected from the steam drum and

compared to industry-recommended concentrations; however, these measurements

are generally grab samples and not easily carried out in situ. In practice, the

frequency of the IBO is determined over a period of time, allowing the system

to pickle, and often turns out to be on the order of once a day for fairly pure

condensate. Systems using less-pure water will require more frequent operation.

Typically, the IBO is opened and a certain portion of the drum water allowed to

be removed (e.g., 4 in. of drum level). The IBO is more often than not operated

manually by the operator although a series of timers may be employed to

automate the process.

14.3.8 Pressure control (automatic relief valve,control valve bypass)

When one talks about HRSG performance, production quantity and temperature at

a certain pressure are the key parameters used to describe the system. While mass

flow and final temperature are controlled or a function of the fundamental thermal

design, an unfired (i.e., no duct burner) HRSG does not, in and of itself, control

pressure beyond that described with a startup vent or bypass system. The steam

produced by the HRSG flows into a pipe network that delivers the steam to a final

consumer. The final user, or more correctly, the back pressure imposed by the

final user on the piping network, defines the pressure at the HRSG outlet.

NOTE: Some auxiliary systems (e.g., duct burners) may have pressure control

valves to regulate the fuel pressure being delivered to the burner system, and

the BoP may employ a scheme that employs a duct burner within the HRSG to

regulate a steam header pressure; however, these items are considered to be outside

the scope of the intended discussion of this chapter.

The next two sections intend to address two specific applications of pressure

control within the boiler proper: automatic relief valves and control valve bypasses.

14.3.8.1 Automatic relief valve(s)

In a certain sense, one can correctly state that the ASME required pressure safety

valves (PSVs) do in fact control the HRSG pressure. The misnomer here is the

word control. The PSVs limit or prohibit the pressure from exceeding a certain

maximum pressure but in the essence of this chapter, the PSV does not serve as an

automatic control. The operators cannot alter or adjust position or set-points while

running the system.

The lifting of a PSV is a traumatic event for the operating system, causing

significant process upsets beyond that already being encountered, which is causing

the PSVs to lift. Of immediate concern to the PSV itself is that when the plug

lifts off of the valve seat, there is potential for the high-pressure drop of the pass-

ing steam to cut and/or wear valve components resulting in leakage after the plug

resets. This leakage reduces plant efficiency and creates potential safety concerns.


In addition, the leakage will continue to erode the damaged area, further increas-

ing the negative impacts until the unit must be taken offline and the valve

repaired.

In an attempt to avoid the lifting of PSVs and avoid the consequences described

in the previous paragraph, some facilities employ an automatic relief valve system.

In order to open the vent valve or bypass valve with suitable speed so as to avoid

lifting the mechanical valve, the automatic relief valve system is fitted with

pneumatic actuators or in some rare instances hydraulic actuators. The intent is to

have the automatic vent system open at a lower pressure than the PSV set-point,

thus avoiding the previously described issues. It is important to note that the inclu-

sion of an automated system does not negate the requirement for ASME-designed

boilers to include the mechanical PSVs. Plant designers will often size the actuators

associated with a steam bypass system to allow the bypass system to function as a

pseudo automated relief system. A word of caution when being asked to supply

a system capable of preventing the PSVs from lifting after a steam turbine trip:

the pressure wave associated with the suddenly halted steam flow will move at the

speed of sound back through the piping network. As one does not typically have a

feedforward signal when the steam turbine will trip, it is very difficult to achieve

the requested goal (i.e., PSVs will almost always lift before the bypass system

can open to a suitable level) unless a very fast, high-pressure, expensive hydraulic

system is employed.

14.3.8.2 Control valve bypass

Depending on the requirements of the overall process, the main feedwater con-

trol valve may be located within the boiler proper piping downstream of some

of the heat transfer coils (i.e., downstream of economizer coil(s)). While the

placement of the control valve at this position fulfills a process need, there is a

potential undesirable effect. As the water side of the economizer coils may now

be isolated, a relief valve must be employed to ensure that design pressures are

not exceeded.

During startup, prior to the demand of feedwater to maintain drum level,

the feedwater control valve will be closed subsequently isolating the economizers

(i.e., check valve on inlet line and control valve between economizer and drum

closed). When heat is introduced into the system, the water within the isolated coils

will expand (specific volume increases with increasing temperature) and may result

in very high pressures within the coils due to the incompressibility of the water.

This is not encountered in every unit and has been shown to be strongly influenced

by the general BoP startup sequence. However, one is often not knowledgeable of

the final plant startup scheme during the design phase. In any sense, a small ball

valve may be placed in parallel to the feedwater control valve with a demand open

set-point at a pressure just below the set-point of the aforementioned economizer

relief valve. The actuated ball valve thus serves a similar role as that described

for the actuated relief valve only this time in a water service (Fig. 14.7).


References

[1] NFPA 85: Boiler and Combustion Systems Hazards Code, 2015.

[2] Recommended Practices for the Prevention of Water Damage to Steam Turbines Used

for Electric Power Generation - Fossil Fueled Plants, ASME TDP-1.

[3] ASME Section 1 � 2015 Boiler & Pressure Vessel Code.

Figure 14.7 Automatic pressure control/control valve bypass.



15Developing the optimum cycle

chemistry provides the key to

reliability for combined cycle/

HRSG plantsBarry Dooley

Structural Integrity Associates, Southport, United Kingdom

Chapter outline

Nomenclature 322


15.2 Optimum cycle chemistry treatments 32415.2.1 Condensate and feedwater cycle chemistry treatments 325

15.2.2 HRSG evaporator cycle chemistry treatments 327

15.3 Major cycle chemistry-influenced damage/failure in combined cycle/HRSG

plants 32815.3.1 Overview of cycle chemistry-influenced damage/failure mechanisms 328

15.4 Developing an understanding of cycle chemistry-influenced failure/damage

in fossil and combined cycle/HRSG plants using repeat cycle chemistry

situations 33915.4.1 Development of repeat cycle chemistry situations 339

15.4.2 Using RCCS to identify deficiencies in cycle chemistry control of combined cycle/HRSG

plants 341

15.5 Case studies 34215.5.1 Case studies 1 and 2: damage/failure in the PTZ of the steam turbine in combined cycle/HRSG

plants 343

15.5.2 Case study 3: under-deposit corrosion—hydrogen damage 345

15.5.3 Case study 4: understanding deposits in HRSG HP evaporators 345

15.6 Bringing everything together to develop the optimum cycle chemistry for

combined cycle/HRSG plants 34515.6.1 First address FAC 346

15.6.2 Transport of corrosion products (total iron) 346

15.6.3 Deposition of corrosion products in the HP evaporator 346

15.6.4 Ensure the combined cycle plant has the required instrumentation 347

15.6.5 Cycle chemistry guidelines and manual for the combined cycle plant 347

15.6.6 Do not allow repeat cycle chemistry situations 347



http://dx.doi.org/10.1016/B978-0-08-101940-5.00015-4

15.7 Summary and concluding remarks 349

15.8 Bibliography and references 350

References 352

Nomenclature

ACC Air-cooled condenser

AVT All-volatile treatment

AVT(O) All-volatile treatment (oxidizing)

AVT(R) All-volatile treatment (reducing)

CACE Conductivity after cation exchange

CPD Condensate pump discharge

CT Caustic treatment

DCACE Degassed CACE

EI Economizer Inlet

FAC Flow-accelerated corrosion

FFP Film forming product

FFA Film forming amine

FFAP Film forming amine product

HD Hydrogen damage

HTF HRSG tube failure

IAPWS International Association for the Properties of Water and Steam

OT Oxygenated treatment

PT Phosphate treatment

PTZ Phase transition zone

ppb part per billion (μg/kg)ppm part per million (mg/kg)

RCCS Repeat cycle chemistry situation

TGD (IAPWS) technical guidance document

TSP Trisodium phosphate

UDC Under-deposit corrosion

15.1 Introduction

The cycle chemistry treatments and control on combined cycle plants influence a

high percentage of the availability and reliability losses and safety issues experi-

enced on these plants worldwide. As this is a very large and important area this

chapter has four main parts. The first part briefly introduces the equipment and

materials of construction and how heat recovery steam generator (HRSG) reliability

depends on various protective oxides, the formation of which relates directly to the

cycle chemistry treatments that are used in the condensate, feedwater, evaporator

water, and steam. The second part delineates the main damage and failure mechan-

isms influenced by not operating with the optimum cycle chemistry treatments thus

allowing the protective oxides to break down. This will include the main damage

mechanisms of flow-accelerated corrosion (FAC), under-deposit corrosion (UDC),


and those that occur in the phase transition zone (PTZ) of the steam turbine. The

third part will describe the key analytical tools that have been developed to identify

whether failure and damage will occur in combined cycle/HRSG plants due to non-

optimum cycle chemistry treatments and control aspects. This involves identifying

the deficiencies in cycle chemistry control that are referred to as repeat cycle chem-

istry situations (RCCS). The final part describes the six sequential processes needed

to develop the optimum cycle chemistry for combined cycle/HRSG plants to avoid

the major failure and damage mechanisms.

Combined cycle/HRSG plants operate across a wide range of temperatures and

pressures. Multipressure drum-type HRSGs are coupled to high pressure (HP),

intermediate pressure (IP), and low pressure (LP) steam turbines, but there are also

a number of HRSGs with once-through HP or HP/IP circuits.

Mild and low-alloy carbon steels are used in the construction of the preheaters,

economizers, and evaporators of HRSGs with high alloy chromium containing

steels and austenitic stainless materials being used in superheaters, reheaters, and

steam turbines. It is very rare to find copper alloys in the HRSGs but these alloys

can be used in condensers and in older combined cycle plants that have external

feedwater heaters. Protection against corrosion is always provided by the protective

and passive oxides that grow on the surfaces of all this equipment and material.

In multipressure HRSGs the lower pressure and temperature circuits such as pre-

heaters, economizers, and IP/LP evaporators are the major sources of corrosion pro-

ducts, which can be transported into the HRSG HP evaporator and then deposited

on the heat transfer surfaces of the water/steam cycle. Corrosion is increased by the

presence of impurities in the condensate, feedwater, and cooling water. In combined

cycle/HRSG plants the major source of corrosion products is by single- and two-

phase FAC.

Corrosion of copper alloys, if present in combined cycle plants, can lead to the

transport of copper into the HRSG resulting in deposition on the HP evaporators

and on the high pressure turbine. Some early combined cycle/HRSG plants also had

feedwater heaters fed by extraction steam. The buildup of deposits in the steam

generating tubes of the HP evaporators, in combination with the presence of impuri-

ties, can lead to UDC during operation, and be the locations of pitting during non-

protected shutdowns.

The carryover of impurities into the steam from the HRSG drums can lead to

deposits in the steam turbine, and may lead to stress corrosion cracking and corro-

sion fatigue in the superheaters and steam turbines, and pitting during nonprotected

or inadequate shutdown conditions.

Leaks in water-cooled condensers are the most common source of impurities,

such as chloride and sulfate, entering the water/steam circuit, whereas air-cooled

condensers (ACCs) are subject to low temperature FAC and can be a major source

of high levels of corrosion products and air ingress.

One of the main purposes of good cycle chemistry is to provide protection

through oxide formation on the internal steam/water touched surfaces, and to pre-

vent and/or reduce corrosion and deposits in the steam/water circuit of these

power plants. A combination of chemical techniques has to be used to achieve this

323Developing the optimum cycle chemistry provides the key to reliability for combined cycle/HRSG plants

and chemical conditioning can be applied to the condensate, feedwater, and evapo-

rator water. Guidance limits have to be developed to control the corrosion processes

mentioned previously. Alternatively, allowing the cycle chemistry and its control

not to be optimum will lead to major availability and reliability problems as out-

lined previously, and can result in safety issues for plant staff.

15.2 Optimum cycle chemistry treatments

For the development of optimum cycle chemistry it is important to note that the

complete cycle of the combined cycle plant must be considered. Most often the

cause of the cycle chemistry-influenced failure and damage mechanisms in a partic-

ular section or circuit does not originate at that location. For instance corrosion pro-

ducts from the LP and IP circuits can be transported into the HP evaporator and

deposit. Also contaminants in the evaporator originating in the condensate can be

carried over into the steam turbine.

A quick “tour” of the cycle chemistry utilized for combined cycle plants follows.

This is an overview to provide an introduction of some key features required for the

cycle chemistry control of power plants, and the nomenclature will be used

throughout the chapter.

The first requirement is for high purity feedwater recycled from the condenser,

or added as makeup. The purity is monitored by measurement of the conductivity

after cation exchange (CACE) (which used to be called cation conductivity) of the

condensate, feedwater, evaporator water, and steam. These measurements include

contributions from impurities and corrosive species such as chloride, sulfate, carbon

dioxide, and organic anions. The higher the temperature and pressure of operation,

the higher the purity of water required to prevent corrosion and, thus, the lower the

CACE allowed.

The chemistry of the condensate and feedwater is critical to the overall reliability

of HRSG plants. Corrosion takes place in the feedwater of HRSG plants (preheaters

and economizers), and the resulting corrosion products flow into the HRSG eva-

porators, where they deposit on heat transfer areas. These deposits can act in the

HRSG evaporator as initiating centers for many of the tube failure mechanisms,

and in the steam turbine as a source of either efficiency losses or blade/disk fail-

ures. The choice of feedwater chemistry depends primarily on the materials of con-

struction and secondly on the feasibility of maintaining purity around the water/

steam cycle.

Most often a volatile alkalizing agent, usually ammonia, is added to the conden-

sate/feedwater to increase the pH. Alternatively a neutralizing amine can be added

in place of ammonia. A film forming product (FFP) can be added instead of the

ammonia or neutralizing amine. FFPs include film forming amines and film form-

ing compounds that do not contain an amine. These FFP are usually proprietary

compounds where the exact composition is not known by the user and most often

they are supplied as blends with a neutralizing amine and then referred to as a film


forming amine product. As of 2016, much work is being conducted internationally

to provide guidance on these FFPs.

15.2.1 Condensate and feedwater cycle chemistry treatments

There are three main established variations of volatile conditioning that can be

applied to the condensate and feedwater:

15.2.1.1 All-volatile treatment (reducing) [1]

All-volatile treatment (reducing) or AVT(R) involves the addition of ammonia or

an amine, FFP, blend of amines of lower volatility than ammonia and a reducing

agent (usually hydrazine or one of the acceptable substitutes such as carbohydra-

zide) to the condensate or feedwater of the plant. In combination with a relatively

low oxygen level (from air in-leakage) of about 10 ppb (μg/kg) or less in the con-

densate (usually measured at the condensate pump discharge [CPD]), the resulting

feedwater will have a reducing redox potential (usually measured as a negative

oxidation-reduction potential [ORP]). Higher levels of oxygen (.20 ppb [μg/kg])(due to high air in-leakage) will usually preclude generation of the reducing envi-

ronment, but are often incorrectly accompanied by excessive dosing of the reducing

agent. AVT(R) is most often used to provide protection to copper-based alloys in

mixed-metallurgy feedwater systems in fossil plants. In multipressure HRSG sys-

tems, AVT(R) should not be used in these cycles due to concerns for single-phase

FAC, and because the corrosion product levels in the feedwater would be most

likely to exceed 2 ppb (μg/kg). Reducing agents should not be used in combined

cycle/HRSG plants.

15.2.1.2 All-volatile treatment (oxidizing) [1]

All-volatile treatment (oxidizing), or AVT(O), has emerged since the 1990s as the

much preferred treatment for feedwater systems that only contain all-ferrous materi-

als (copper alloys can be present in the condenser). In these cases, a reducing agent

should not be used during any operating or shutdown/layup period. Ammonia or an

amine, FFP, blend of amines of lower volatility than ammonia is added at the CPD

or condensate polisher outlet (if a polisher is included within the cycle). This is the

treatment of choice for multipressure combined cycle/HRSG plants that have no

copper alloys in the feedwater. In combined cycle/HRSG plants with relatively

good control of air in-leakage (oxygen levels in the range 10�20 ppb (μg/kg)),the resulting feedwater will yield a mildly oxidizing positive ORP. Under optimum

conditions, a multiple pressure combined cycle plant should be able to operate

with corrosion product levels of total Fe, 2 ppb (μg/kg) in the feedwater and

,5 ppb (μg/kg) in the drums.


15.2.1.3 Oxygenated treatment

Application of oxygenated treatment (OT) [1] in combined cycle/HRSG plants is

much rarer than in conventional fossil plants, but often it is found that the use of

AVT(O) with low levels of oxygen (,10 ppb (μg/kg)) on these plants does not pro-

vide sufficient oxidizing power to passivate the very large internal surface areas

associated with preheaters; LP, IP, and HP economizers; and LP evaporators, espe-

cially if a deaerator is included in the LP circuit. In these cases, oxygen can be

added at the same level as for conventional recirculating cycles (30�50 ppb (μg/kg)).This is the feedwater of choice for conventional fossil units with all-ferrous feedwater

heaters and a condensate polisher and with an ability to maintain a CACE of

,0.15 μS/cm under all operating conditions. Under optimum conditions, a multiple

pressure combined cycle plant the total Fe should be ,1 ppb (μg/kg) in the feedwater

and ,5 ppb (μg/kg) in each of the drums.

15.2.1.4 Film forming products

The application and use of FFP in conventional fossil and combined cycle/HRSG

plants is increasing worldwide. They work in a different way than the conventional

treatments by being adsorbed onto metal oxide/deposit surfaces thus providing a

physical barrier (hydrophobic film) between the water/steam and the surface. There

are three main chemical substances that have been used historically: octadecyla-

mine (ODA), oleylamine (OLA), and oleylpropylendiamine (OLDA). As well as

these compounds the commercial products contain other substances, such as alkaliz-

ing amines, emulsifiers, reducing agents, and dispersants. There is currently much

confusion about their application for both normal operation and shutdown/layup,

and there is no international guidance on deciding whether to use an FFP or

whether it will provide a benefit to the plant. This situation will change in 2016

when the International Association for the Properties of Water and Steam (IAPWS)

publishes the first FFP guidance [2].

There are some basic international rules for the application of these condensate/

feedwater treatments. The all-volatile treatments (AVT(R), AVT(O), or OT) have

to be used for once-through boilers and are used without any further addition of

chemicals in the boiler or HRSG evaporators. AVT(R), AVT(O), or OT can also be

used for drum boilers of conventional fossil plants or combined cycle/HRSGs with-

out any further addition of chemicals to the boiler/HRSG drum. However, impuri-

ties can accumulate in the boiler water of drum-type HRSGs and it is necessary to

impose restrictive limits on these contaminants as a function of drum pressure both

to protect the boiler from corrosion and to limit the amount of impurities possibly

carried over into the steam [3], which could put at risk the superheaters, reheaters,

and steam turbines. It is recognized that AVT has essentially no capability to

neutralize or buffer feedwater/boiler water dissolved solids contamination.

Ammonia is a rather poor alkalizing agent at high temperatures, offering very

limited protection against corrosive impurities.


15.2.2 HRSG evaporator cycle chemistry treatments [4]

For some drum-type boilers, the addition of solid alkalizing agents to the boiler/

HRSG water may be necessary in order to improve the tolerance to impurities and

reduce the risk of corrosion. The alkalizing agents that can be used for this are tri-

sodium phosphate (TSP) (phosphate treatment (PT)) or sodium hydroxide (caustic

treatment (CT)) used alone. The two can also be used in combination. The amounts

of sodium hydroxide added have to be strictly limited to avoid excessively alkaline

conditions, which can result in a UDC mechanism (caustic gouging [CG]), which

destroys the protective oxide layer in the boiler or HRSG evaporator. The amounts

of both sodium hydroxide and TSP added to the cycle also have to be controlled to

avoid an increase of carryover of these conditioning chemicals into the steam, pos-

sibly putting the superheaters and turbines at risk [3].

Boiler and HRSG evaporator treatments are critical to the overall reliability of

conventional fossil and HRSG plants as they control and influence not only the

major tube failure mechanisms but also a number of damage mechanisms in the

steam turbine.

15.2.2.1 Phosphate treatment

Phosphates of various types have been the bases of the most common boiler/HRSG

evaporator treatments worldwide. However, historically there has been a multitude

of phosphate compounds and mixtures blended with other treatment philosophies,

which has resulted in a wide range of control limits for the key parameters (pH,

phosphate level, and sodium-to-phosphate molar ratio) and a number of reliability

issues. Some of the traditional PTs such as congruent phosphate treatment (CPT),

coordinated PT, and equilibrium phosphate treatment (EPT) have been used since

the 1960s across the fleet of conventional fossil boilers and HRSG evaporators,

sometimes successfully, sometimes resulting in tube failures and other problems.

For instance, the use of CPT, where mono- and/or disodium phosphate are used to

develop operating control ranges below sodium-to-phosphate molar ratios of 2.6:1,

has resulted in serious acid phosphate corrosion (APC) in many conventional fossil

boiler waterwalls and HRSG HP evaporators that have heavy deposits and have

experienced phosphate hideout.

More recently, since the 1990s, consolidated good operating experiences world-

wide have led to the recognition that TSP should be the only phosphate chemical

added to a boiler/HRSG, and that the operating range should be bounded by

sodium-to-phosphate molar ratios of 3:1 and TSP1 1 ppm (mg/kg) NaOH with a

pH above 9.0 and a minimum phosphate limit above 0.3 ppm (mg/kg). It should be

emphasized that the 0.3 ppm (mg/kg) level is regarded as a minimum and that bet-

ter protection will be afforded by operating at as high a level of phosphate as possi-

ble without experiencing hideout or exceeding the steam sodium limits.

PT can be used in a wide range of drum units up to high pressures (2800 psi,

19 MPa), so it is often the only alkali treatment available because CT is not sug-

gested for use above 2400 psi (16.5 MPa). However, it will be recognized that


phosphate hideout and phosphate hideout return become more prevalent with

increasing pressure. Phosphate hideout is the loss of phosphate from the boiler/

evaporator water on increasing drum pressure, and hideout return is the return of

the phosphate to solution on decreasing pressure. Hideout and hideout return are

therefore always associated with large swings of pH causing boiler/evaporator con-

trol problems, but if only TSP is used, then no harmful corrosion reactions can be

initiated as was experienced with CPT using sodium-to-phosphate molar ratios

below 2.6:1.

For multipressure HRSGs, PT can also be used in each of the pressure cycles,

but use of PT here is for different reasons depending on the pressure of the circuit.

At high pressure, the addition of TSP is basically to assist in addressing contamina-

tion in the same way as for conventional fossil plants. In the lower pressure circuits,

with temperatures below 480�F (250�C), PT is used to help control two-phase FAC

much as CT is used in these circuits. Of course neither solid alkali is used in the LP

evaporator in units where the LP drum feeds the IP and HP feedpumps and

attemperation.

15.2.2.2 Caustic treatment

Caustic treatment (CT) can be used in conventional fossil and HRSG drum-type

boilers to reduce the risk of UDC, and in HRSGs for controlling FAC in the lower-

pressure circuits, where all-volatile treatment has proved ineffective, or where PT

has been unsatisfactory due to hideout or has experienced difficulties of monitoring

and control.

The addition of sodium hydroxide to the boiler/evaporator water has to be care-

fully controlled to reduce the risk of CG in the HP evaporator and carryover into

the steam, which could lead to damage of steam circuits and turbine due to stress

corrosion cracking. Of primary risk are austenitic materials, stellite, and all steels

with residual stresses (e.g., welds without heat treatment) in superheaters, steam

piping and headers, turbine control and check valves, as well as components in the

steam turbine. CT is easy to monitor, and the absence of the complications due to

the presence of phosphate allows online conductivity and CACE measurements to

be used for control purposes.

15.3 Major cycle chemistry-influenced damage/failure incombined cycle/HRSG plants

15.3.1 Overview of cycle chemistry-influenced damage/failuremechanisms

It is not surprising that because the cycle chemistry “touches” all the parts of a gen-

erating plant that it controls the availability and reliability of these plants. It has

been suggested since the 1990s and early 2000s that the cycle chemistry influences

about 50% of all the failure and damage mechanisms in conventional fossil plants,


but because of the added complexity of combined cycle/HRSG plants with multiple

pressures this number may be as high as 70%. The statistics of cycle chemistry-

influenced failure and damage mechanisms in combined cycle/HRSG plants have

changed very little since at least the early 1990s. These can be categorized as follows:

� HRSG tube failures (HTF)

� FAC in LP and IP evaporators; LP, IP, and HP economizers (single- and two-phase)

(see detailed listing in Section 15.3.1.1)

� Corrosion fatigue in LP evaporators and economizers

� UDC in HP evaporators of both vertical and horizontal gas path HRSGs (mainly

hydrogen damage (HD) but APC and CG have also occurred) (see Section 15.3.1.3)

� Pitting (often evidenced as tubercles in pressure vessels (drums, deaerators))� FAC in ACCs (with main damage by two-phase FAC at ACC tube entries in upper ducts)

(see Section 15.3.1.1)� Steam turbine damage (see Section 15.3.1.2)

� Corrosion fatigue of blades and disks in the PTZ of the LP turbine

� Stress corrosion cracking (SCC) of blades and discs in the PTZ of the LP turbine

� Pitting on blade and disc surfaces

� FlOW-accelerated corrosion (FAC)

� Deposition of salts on the PTZ surfaces

One very important note is that although FAC and UDC mechanisms occur at

opposite ends of the HRSG, they are linked by the corrosion products generated by

the FAC mechanisms in the low pressure parts of the HSRG, which subsequently

transport to, and deposit in, the HP evaporator tubing where they form the basis of

the UDC damage mechanisms. This link forms the main focus of the cycle chemis-

try assessments in HRSGs, which identify the precursors or active processes, which

left unaddressed, will eventually lead to failure/damage by one or both mechanisms.

Acting proactively will remove the risk for both, and it is clear that avoiding FAC

and the associated increased corrosion in the LP circuits essentially ensures that

UDC will not occur. The mechanisms of FAC, UDC, and deposition are discussed

in three of the subsections following.

15.3.1.1 Flow-accelerated corrosion in combined cycle/HRSGplants

FAC occurs due to the accelerated dissolution of the protective oxide (magnetite)

on the surface of carbon steel components caused by flow. For combined cycle/

HRSG plants a detailed review of the FAC mechanism is available [5] and is illus-

trated in Fig. 15.1. The concentration in this chapter is to indicate that the overall

optimum cycle chemistry for these plants must first include the cycle chemistry

influences of single- and two-phase FAC as outlined in Section 15.6.

15.3.1.2 FAC in combined cycle/HRSGs

All the HRSG components within the temperature range 212�572�F (100�300�C)are susceptible to FAC, which involves both the single- and two-phase variants


predominantly in low temperature (LP, IP, and HP) economizers/preheaters and

evaporators (tubes, headers, risers, and drum components such as belly plates). The

same components can also be susceptible to FAC in HRSG designs where the nomi-

nal HP evaporator circuit operates for significant periods of time at temperatures

,572�F (300�C) (e.g., the HP evaporators in older dual-pressure HRSGs, HRSGs

where there is only one pressure stage, and high pressure evaporator circuits in

plants running for extended periods at low load with sliding pressure operation).

A quite comprehensive listing of locations of FAC in combined cycle/HRSGs is

provided in Table 15.1.

The appearances of single- and two-phase FAC are illustrated in Fig. 15.2.

The corrosion products released by the FAC mechanism in these circuits and by

corrosion of the nonpassivated lower-temperature/pressure circuits are transported

away from the corrosion site and can eventually reach the HP evaporator and

deposit on the internal tubing surfaces.

15.3.1.3 Flow-accelerated corrosion in air-cooled condensers

An increasing number of combined cycle/HRSG plants worldwide are equipped

with ACC. Operating units with ACCs at the lower regimes of pH provided in

IAPWS guidance documents will result in serious corrosion and FAC in the ACC

tubes, most predominantly at the entries to the cooling tubes [7]. The potential for

ACC to act as a major source of corrosion products needs to be considered in devel-

oping the optimum cycle chemistry control for an HRSG plant. Whether this is

occurring can easily be determined by monitoring the total iron at the condensate

pump discharge (CPD) [8]. To rectify the FAC situation, it will be necessary to

conduct a series of tests with gradually increasing levels of pH while monitoring

Figure 15.1 Schematic of FAC mechanism [5].


total iron. A condensate/feedwater pH of around 9.8 (as measured at 77�F, 25�C)will be needed to reduce the FAC to low enough levels to observe total iron values

at the CPD of around 5 ppb (μg/kg) or less [7]. If the total iron values cannot be

reduced to less than 5 ppb (μg/kg) by increasing the pH, then there may be a

requirement to include a 5 μm absolute condensate filter or a prefilter prior to a

condensate polisher if included in the cycle. Condensate polishing is not universal

on plants with ACC.

Table 15.1 Locations of FAC in combined cycle/HRSG plants(typical tube and header materials, and range of operatingtemperatures)

� LP economizer/preheater (feedwater) tubes at inlet headers (SA 178A, SA 192, and SA

210C tubing; SA 106B headers; 105�300�F, 40�150�C)� Economizer/preheater tube bends in regions where steaming takes place with particular

emphasis being given to the bends closest to the outlet header (SA 178A, SA 192, and SA

210C tubing; SA 106B headers, 105�300�F, 40�150�C) (Note: Steaming can easily be

identified in these areas by installation of thermocouples on the appropriate location)� IP/LP economizer outlet tubes (SA 178A, SA 192, SA 210C tubing; SA 106B headers;

260�300�F, 130�150�C)� HP economizer tube bends in regions where steaming takes place with particular

emphasis being given to the bends closest to the outlet (SA 210 A1 and C tubing;

B320�F, 160�C)� IP and HP economizer inlet headers (SA 106B; 140�210�F, 60�100�C)� LP evaporator inlet headers with a contortuous fluid entry path or with any orifices

installed (SA 106B; 260�340�F, 130�170�C)� LP outlet evaporator tubes at bends before the outlet header (SA 192, SA 178A, and SA

210C; 150�165�C, 300�330�F)� LP evaporator link pipes and risers (SA 106B, 300�330�F, 150�165�C)� Horizontal LP evaporator tubes on vertical gas path (VGP) units especially at tight hairpin

bends (SA 192; 300�300�F, 150�160�C)� LP and IP drum internals: behind the belly plates in line with riser entry fluid into the

drums� IP economizer outlet tubes with bends (SA 178A, SA 192, SA 210A1 and C) and headers

(SA 106B and C) (410�445�F, 210�230�C) if there is evidence of steaming� IP evaporator inlet headers (SA 106B) with a contortuous fluid entry path or with any

orifices installed (210�250�C, 410�482�F)� IP outlet evaporator tubes (SA 178A, SA 192, and SA 210C; 445�465�F, 230�240�C) on

triple-pressure units especially if frequently operated at reduced pressure� IP outlet link pipes and evaporator risers (SA 106B) to the IP drum (445�465�F,

230�240�C)� Piping around the boiler feed pump; includes SH and RH desuperheating supply piping� Reducers on either side of control valves� Turbine exhaust diffuser� ACC (see next sub-section)

Source: Adapted from R.B. Dooley, R.A. Anderson, Assessments of HRSGs � trends in cycle chemistry and thermaltransient performance, PowerPlant Chem. 11 (3) (2009) 132�151, [6].


Operating with elevated pH to control low temperature FAC in the ACC will

also assist in addressing two-phase FAC in the other areas of the HRSG. For plants

operating in the oxidizing mode, AVT(O) or OT, the customization can be useful to

improve the conditions in the two-phase regions but will be of little relevance for

the single-phase flow regions because, in the absence of contaminant anions, corro-

sion is suppressed to a very low level across the pH range 7�10.

The cycle chemistry-influenced damage in ACC can be best described through

an index for quantitatively defining the internal corrosion status of ACC. This is

known by the acronym DHACI (Dooley Howell ACC Corrosion Index) [7]. The

index separately describes the lower and upper sections of the ACC, as described in

the following paragraph.

The index provides a number (from 1 to 5) and a letter (from A to C) to

describe/rank an ACC following an inspection. For example, an index of 3C would

indicate mild corrosion at the tube entries, but extensive corrosion in the lower

(A) (B)

(C)(D)

1

Figure 15.2 Three examples of FAC in HRSG LP evaporator tubing. (A) Single-phase FAC

in a horizontal gas path (HGP) HRSG. (B) Example of two-phase FAC in a HGP HRSG. (C)

Two-phase FAC in a tight hairpin bend of a vertical gas path (VGP) HRSG. (D) Surface of

FAC damage on an HRSG LP evaporator taken with a scanning electron microscope

showing the typical scalloped appearance always seen of FAC [5 and 6].


ducts. An example for the upper ACC section (upper duct/header, ACC A-frame

tube entries) is shown in Fig. 15.3. An example for the lower ACC section (turbine

exhaust, lower distribution duct, risers) is shown in Fig. 15.4.

The DHACI can be used to describe the status of a particular ACC in terms of

its corrosion history and is a very useful means of tracking changes that occur as a

result of making changes in the cycle chemistry. A plant that has a relatively poor

rating for corrosion at a steam cycle pH of 8.5�8.8 (e.g., 4C) may increase the pH

to 9.4�9.6, and determine whether this change improves its rating (e.g., 3B).

A poor rating (e.g., 4B) indicates the need to consider options to reduce the corro-

sion rate especially in the tube entry areas.

Additionally, the index provides a convenient tool for comparison between dif-

ferent units. This can aid in determining whether some cycle chemistry factor in

effect at one station, e.g., use of an amine rather than ammonia, is yielding better

results.

15.3.1.4 Steam turbine phase transition zone failure/damage

Impurities in the steam from the HRSG may cause deposits and corrosion in steam

turbines and thus the steam purity controls most corrosion processes and is vital to

combined cycle plant reliability. These problems can usually be avoided by follow-

ing the guidance in the IAPWS Steam Purity Technical Guidance Document (TGD)

[9], which needs to be compatible with the condensate, feedwater, and evaporator

chemistries discussed in Sections 15.2.1 and 15.2.2.

Figure 15.3 Montage illustrating DHACI indices 1�5 for the upper ducts and tube entries.


The four most important corrosion-related failure/damage mechanisms in the

low pressure (LP) steam turbine are deposition, pitting, corrosion fatigue, and stress

corrosion cracking. The local steam environment determines whether these damage

mechanisms occur on blade and disk surfaces. The PTZ, where the expansion and

cooling of the steam leads to condensation, is particularly important. A number of

processes that take place in this zone, such as precipitation of chemical compounds

from superheated steam, as well as deposition, evaporation, and drying of liquid

films on hot surfaces, lead to the formation of potentially corrosive surface deposits.

Understanding the processes of transport, droplet nucleation, the formation of liquid

films on blade surfaces, and concentration of impurities is vital to understanding

how to avoid corrosion-related damage, and to improve unit efficiency/capacity [9].

The following two cycle chemistry operating regimes are identified as relevant

to steam turbine corrosion. Of course, adequate materials properties (composition,

structure, internal stresses, etc.) and design (temperature, stresses, crevices, etc.)

also play essential roles.

� The dynamic environment during turbine operation. These are the local conditions formed

by the condensation of steam as it expands through the PTZ of the turbine, and by the

deposition of salts, oxides, and other contaminants directly onto steam path surfaces.� The environment produced during shutdown. These are the conditions that occur during

unprotected shutdown when oxygenated moist/liquid films form on steam path surfaces as

a result of hygroscopic effects. These films are directly caused by inadequate shutdown

practices adopted by the turbine operator. They can lead to pitting, which is most often

the precursor to the corrosion mechanisms.

Figure 15.4 Montage illustrating DHACI indices (A)�(C) for the lower ducts from the

steam turbine to the vertical risers to the upper duct.


Thus, if adequate layup protection (dehumidified air (DHA)) is not provided,

serious corrosion damage may occur even with the best operating chemistry, mate-

rials, and design, and with only few major deposits. It is recognized that pitting can

possibly also initiate during operation in crevice areas such as blade attachments.

Impurities can enter the steam from the HRSG by the following processes:

� drum (LP, IP, HP) carryover of HRSG evaporator water� volatility in evaporating evaporator water� injection of feedwater into the superheater or reheater for attemperation

For a complete description of the chemistry in the PTZ of the LP steam turbine

the reader is referred to the IAPWS Steam Purity TGD [9]. This includes the details

on droplet nucleation, liquid film formation on turbine parts, deposition of oxides

and impurities on surfaces, and how inadequate shutdown practices results in pit-

ting. The major failures mechanisms of corrosion fatigue and stress corrosion crack-

ing are initiated at pits so this sequential process is most important.

15.3.1.5 Combined cycle/HRSG steam purity limits

For combined cycle/HRSG plant with condensing turbines operating with super-

heated steam the following guideline limits (Table 15.2) are suggested by IAPWS

[9]:

These limits are considered as the normal operating values during

stable operation to avoid the steam turbine damage mechanisms and are consistent

with long-term turbine reliability.

15.3.1.6 Steam purity for startup

In the case of a warm start, the values for normal operation (Table 15.2) should be

attained within 2 hours, and in the case of a cold start within 8 hours. During

startup, the impurity concentrations should show a decreasing trend.

Steam should not be sent to the turbine if the concentration of sodium exceeds

20 ppb (μg/kg). The immediate need at startup to ensure compliance with this limit

requires a sodium monitor for steam, as specified in the IAPWS Guidance on

Instrumentation for Cycle Chemistry [10].

Table 15.2 Steam purity for condensing turbines with superheatedsteam in combined cycle/HRSG plants, applicable for steamtemperature below 1112�F, 600�C

Parameter Unit Normal/target values

Conductivity after cation exchange @ 25�C μS/cm ,0.20

Sodium as Na ppb, μg/kg ,2

Silica as SiO2 ppb, μg/kg ,10

Source: IAPWS, Technical Guidance Document: Steam Purity for Turbine Operation (2013). Available from:,http://www.iapws.org..


http://www.iapws.org

Steam should not be sent to the turbine if the CACE exceeds 0.5 μS/cm.

Allowance may be given to possible contributions from carbon dioxide and for

sodium in units that only use TSP in the evaporator water. The actual contribution

of carbon dioxide must be measured and regularly verified for the specific plant.

Degassed CACE can help to estimate the contribution of carbon dioxide.

15.3.1.7 Unit shutdown limits

In addition to operating with a set of normal and action levels it is also necessary to

define a set of cycle chemistry conditions under which a unit must be shut down

because of severe contamination. Shutdown conditions usually involve defining a

steam CACE that indicates serious acidic contamination. Typically, a value of

1 μS/cm can be used under conditions that coincide with other upset conditions in

the steam/water cycle. Carbon dioxide from air in-leakage or certain conditioning

agents may warrant a less stringent CACE.

15.3.1.8 Failure/damage mechanisms in HRSGs: highlighting theunder-deposit corrosion mechanisms

The three UDC mechanisms in HRSGs, i.e., HD, APC, and CG, occur exclusively

in HP evaporator tubing [11�13], and all require relatively thick porous deposits

and a chemical (either a contaminant or nonoptimized treatment) concentration

mechanism within those deposits. UDC damage can occur early in the life of an

HRSG due to the inverse relationship between deposit loading/thickness and the

severity of the chemical excursion.

For HD, the concentrating corrodent species is most often chloride that enters

the cycle through condenser leakage (especially with seawater or brackish water

cooling) and via slippage into demineralized makeup water in water treatment

plants where ion exchange resins are regenerated with hydrochloric acid.

APC relates to a plant using phosphate blends that have sodium-to-phosphate

molar ratios below 2.6 and/or the use of CPT using either or both mono- or diso-

dium phosphate.

CG involves the concentration of NaOH used above the required control level

within caustic treatment, or with the use of coordinated phosphate with high levels

of free hydroxide, or the ingress of NaOH from improper regeneration of ion

exchange resins or condenser leakage (freshwater cooling).

15.3.1.9 Deposition in HRSG HP evaporators

Deposition and the UDC mechanisms can occur on both vertical and horizontal

HRSG HP evaporator tubing. On vertical tubing the deposition usually concentrates

on the internal surface (crown) of the tube facing the gas turbine (GT). It is nearly

always heaviest on the leading HP evaporator tube in the circuit as these are the

areas of maximum heat flux. Area of concentration can be the tube circuits adjacent

to the side walls or to the gaps between modules due to gas bypassing. The UDC

mechanisms usually occur in exactly the same areas. On horizontal tubing in VGP


HRSGs both deposition and the UDC mechanisms occur on the ID crown facing

toward or away from the GT. Damage occurs on the side facing away from the GT

when poor circulation rates, steaming, or steam blanketing lead to stratification of

water and steam and subsequent heavy deposition in a thin band along the top of

the tubing corresponding to the steam�water interface during service. When circu-

lation is adequate, the UDC mechanisms occur on the internal crown of the lower

tube surface facing the GT.

The UDC mechanisms of HD and CG have been well understood since the

1970s, and the acid phosphate mechanism since the early 1990s [14]. But until

about 2015 the understanding of how the initiating deposition takes place in HRSG

tubing has been less well understood as is the level of deposits necessary for these

mechanisms to initiate by concentration within thick deposits.

Until about 2015 there have not been any comprehensive studies to characterize

and quantify the critical level of deposits forming in HRSG HP evaporator tubes.

Initial published data from over 100 HRSGs worldwide has led to a new under-

standing on where to sample and how to analyze HRSG tubes for deposits and how

to determine if the HRSG needs to be chemically cleaned [15]. This is now pub-

lished in an IAPWS TGD [16] and the deposit map is shown in Fig. 15.5.

Examples of deposit loadings from over 100 HRSGs worldwide have been plot-

ted to develop the new deposit map shown in Fig. 15.5. Plants included cover a

Figure 15.5 IAPWS deposit map for HRSG HP evaporator tubes as a function of pressure

[16]. The deposit loadings (density) are in grams/ft2 (g/ft2) or mg/cm2. The rule of 2 and 5

refers to total iron corrosion product levels being less than 2 ppb (μg/kg) in the feedwater

and less than 5 ppb (μg/kg) in each drum [8].


very wide range of HRSGs from 17 HRSG manufacturers with HP drum pressures

spanning the range 1300�2200 psi (8.9�15.2 MPa) and with deposits up to

125 g/ft2 (136 mg/cm2). Full coverage of this is included in the IAPWS TGD [16].

Some general comments from the IAPWS document are made here about the

three colored cloud regions of Fig. 15.5:

� It should be first noted that the deposit map is only applicable to HRSG HP evaporator

pressures above about 1100 psi (7.6 MPa) relative to UDC mechanisms in HRSGs.� The green cloud represents deposit levels from HRSG plants operating with optimum

chemistries and generally meeting the total iron corrosion products levels. These generally

have deposit densities/loadings below B11 g/ft2 (12 mg/cm2). The color of the internal

surfaces under these optimum chemistry conditions is generally red/brown, indicative of

transported hematite from the lower-pressure circuits. Importantly, in no case was concen-

tration identified or were reaction products observed in the deposits near to the tube inter-

face. This suggests that concentration reactions of chemical species, such as chloride,

within the deposits cannot take place when the level of deposition is so low, and that the

risk therefore for UDC for the HRSG will be low.� The yellow cloud generally represents the deposits in the HP evaporator in plants not using

the optimum chemistry conditions such as by the use of reducing agents. This occurs even

for units with very low operating hours (,10,000 hours). The internal surfaces under these

chemistry conditions are generally much darker and in most cases black.� Toward the top of the yellow cloud and always in the red cloud there is evidence for con-

centration being identified or reaction products being observed in the deposits near to the

tube interface. The internal tube surfaces are most often black, indicative of transported

magnetite. Most significantly, no deposition data for any of these units has been measured

in the green cloud. Unfortunately very few of these plants sampled have accurate total

iron data to be able to see the elevation above the rule of 2 and 5 (total iron corrosion pro-

ducts less than 2 ppb (μg/kg) in the feedwater and less than 5 ppb (μg/kg) in each drum).� Clearly as HP evaporator deposits become thicker and exceed about 20�25 g/ft2 (25 mg/cm2)

(top of the yellow band and into the red band in Fig. 15.5) they become more porous and

thus become more susceptible to concentration mechanisms and corrosion reactions at the

base of the deposits next to the tube surface. These are the exact concentration processes that

initiate UDC and should be avoided. Thus if HP deposit analyses indicate levels within the

red cloud then the HRSG operator should consider chemical cleaning.� It must be noted that there are no solid lines between the clouds indicating that the bound-

aries are only for guidance.� The difference between deposit loadings in HRSGs using the optimum chemistry (accord-

ing to the IAPWS TGDs [1 and 4]) as compared to the deposit loadings with nonoptimum

chemistry is very clear. The difference between deposits that do not have concentration or

corrosion reaction products and those that do is also very clear with careful metallography

as described in the IAPWS TGD [16].

This new concept contained within the background of Fig. 15.5 of avoiding

deposits that are thick enough to allow concentration provides the first step of

avoiding UDC. The readers should be aware that the selection of the right cleaning

procedure is not always easy and simple, and that a certain caution and pretest is

advised. The results from the metallurgical analyses of the deposits can be used to

identify the chemicals (solvents) that should be used in a chemical cleaning process

if the analyses indicate that cleaning is needed.


15.4 Developing an understanding of cycle chemistry-influenced failure/damage in fossil and combinedcycle/HRSG plants using repeat cycle chemistrysituations

The understanding of the cycle chemistry-influenced failure and damage mechan-

isms in the steam/water circuits of conventional fossil and combined cycle/HRSGs

is very advanced, and has been known and documented since the 1980s. In spite of

this, chemistry-influenced damage and the associated availability losses due to defi-

cient chemistry practices are often enormous. Damage and component failure inci-

dents persist, in both conventional fossil and combined cycle units. It is thus very

clear that the approaches taken by organizations operating combined cycle/HRSG

plants to prevent such damage are frequently unsuccessful. Similarly, conventional

fossil industry usage of the response methodology by which chemistry-related dam-

age events are reacted to (identification of the mechanism, assessment of the root

cause, and implementation of actions to stop the mechanism) is often ineffective.

Analysis in 2008 [17] of past cycle chemistry assessments and damage/failure

reviews in over 100 organizations worldwide led to a very interesting new concept

to prevent damage/failure proactively. This involves identifying RCCS. These,

which can be regarded as the basics of cycle chemistry, are allowed to continue by

the chemistry or operating staff or are imposed on the plant/organization as a conse-

quence of inadequate management support for cycle chemistry.

The first subsection introduces the reader to RCCS while the second provides

information on the application of the RCCS analysis to 170 plants worldwide since

2008. This analysis in total from over 250 plants worldwide confirms that the pro-

cess can be used proactively to identify cycle chemistry deficiencies that if not

addressed will lead to future failure/damage of the types delineated in Section 15.3.

15.4.1 Development of repeat cycle chemistry situations

The analysis conducted in 2008 identified two key features that related to why and

how cycle chemistry influenced failure/damage occurred in conventional fossil and

combined cycle/HRSG plants. From the mechanism aspect the first shows that cycle

chemistry-influenced failure/damage involves the breakdown of the protective oxide

that grows on all fluid-touched surfaces. This could involve cracking, fluxing, dis-

solving, and solubilizing of the oxide layers as well as deposition of corrosion pro-

ducts (oxides) on the surfaces. From the viewpoint of organizational or

management aspects of the cycle chemistry and its control, it became clear that

every cycle chemistry failure/damage incident can be related backwards in time to

multiples of RCCS that were not recognized or properly addressed and allowed to

repeat or continue. In some cases the chemistry staff had not recognized the impor-

tance of the situation and allowed it to continue. In other cases the chemistry staff

recognized the importance, but was not successful in convincing the management

(either plant or executive) that action was required. In many cases the management


has delayed action or has not provided the necessary funds to resolve the situation.

In doing this type of retroactive analysis it very quickly became obvious that

plants/organizations can get away with having one or two RCCS, but once this

number increases then failure/damage was a certainty.

In 2008, ten RCCS were identified that were very commonly associated with

preventable cycle chemistry-related damage in conventional fossil and combined

cycle plants. After using the RCCS analysis at 177 plants worldwide since 2008,

the categories have remained the same but it has become clear that there are multi-

ple subcategories. To assist the readers in understanding the RCCS and whether

they exist in their plants, the following provides a few notes on some of the most

important categories. Some examples of a few case studies are provided later to fur-

ther illustrate this concept.

This RCCS analysis is very powerful in assisting with root cause analysis, in

identifying where cycle chemistry failure/damage will occur in the future, and

where improvements should be made. It has also been used internationally to iden-

tify where international research and guidance is necessary.

15.4.1.1 Corrosion products

Categories include the following: corrosion product levels are not known or moni-

tored, the levels are too high and above international guideline values [8], inade-

quate and/or not sufficient locations being monitored, sampling conducted at the

same time/shift each time, and using techniques with incorrect detection limit; a

most common feature is monitoring the soluble part only by not digesting the sam-

ple. A key easy-to-observe verification aspect of this RCCS is black deposits in the

steam and water sampling troughs for combined cycle/HRSG units on AVT(O), or

red deposits for units on AVT(R).

15.4.1.2 Conventional boiler/evaporator deposits [16]

Categories include the following: HRSG HP evaporator samples have not been

taken for analysis, there is no knowledge of deposits and deposition rate in HP eva-

porators, samples taken but not analyzed comprehensively according to the IAPWS

TGD [16], deposits excessive and exceed criteria to chemical clean, the HP evapo-

rator deposits are not linked with chemistry in the lower-pressure circuits or to the

levels of transported total iron [8], the HP evaporator has been sampled and needs

cleaning according to IAPWS criteria [16] but management delayed or canceled.

15.4.1.3 Drum carryover

Categories include the following: measurement of carryover [3] not conducted since

commissioning, not conducted even on units with PTZ problems, not aware of sim-

ple process to measure carryover [3], saturated steam samples not working or non-

existent, samples taken are not isokinetic.


15.4.1.4 Continuous online cycle chemistry instrumentation [10]

Categories include the following: installed and operating instrumentation is at a low

percentage compared to IAPWS (a normal level is between 58 and 65%); too many

out of service, not maintained or calibrated; instruments are not alarmed for opera-

tors and many are shared by multiple locations and not/never switched; plant relies

on grab samples to control plant (1�3 times per day/shift); the instrumentation

most often missing is CACE (cation conductivity) and sodium on main or HP steam

and conductivity (specific conductivity) on makeup line to condenser.

15.4.1.5 Challenging the status quo

Categories include the following: no change in chemistry since commissioning;

using incorrect or outdated guidelines; continuing to use reducing agents in com-

bined cycle/HRSGs and thus risking or experiencing single-phase FAC; continuing

to use the wrong phosphate treatment (usually not using only TSP); not having a

chemistry manual for the unit, plant or organization; incorrect addition point for

chemicals (most often reducing agent with AVT(R)); not questioning use of propri-

etary chemical additions (phosphate blends, amines, FFP) and therefore not know-

ing the composition of chemicals added to the unit/plant; not determining through

monitoring the optimum feedwater pH to prevent/control FAC.

15.4.1.6 Shutdown/layup protection

Categories include the following: unit/plant has no equipment for providing shut-

down protection (nitrogen blanketing, DHA), equipment present but not used or

inoperable/not maintained, poor/no operator procedures, only partial protection

applied (HRSG vs feedwater), no DHA provided for the steam turbine shutdowns.

15.4.1.7 Contaminant ingress

Categories include the following: no assessment of risk; inadequate instrumentation and

alarms (especially for seawater cooled plants); operators allow exceedances of control and

shutdown levels; chemists and/or operators compromise limits to plant ability (make high

readings acceptable), or make up (invent) normal and action levels which have no

technical relevance; no comprehensive procedures to deal with contaminant ingress.

15.4.2 Using RCCS to identify deficiencies in cycle chemistrycontrol of combined cycle/HRSG plants

Between 2008 and 2016 the RCCS analysis has been applied during 177 plant assess-

ments. Of these, 112 were at conventional fossil plants and 65 were combined cycle/

HRSG plants involving HRSGs from 17 manufacturers. The work involved a large range

of assessments that included HRSG tube failure (HTF) mechanism and root cause assess-

ments, fossil and combined cycle FAC and ACC assessments, cycle chemistry


assessments and chemistry optimization, cycle chemistry treatment conversions to OT and

PT, PTZ blade and disk failure/damage root cause analyses in combined cycle plants,

development of shutdown/layup and preservation procedures for all types of plants, and

combined cycle plants with desalination equipment interface problems.

Table 15.3 shows the data for these conventional fossil and combined cycle/

HRSG plants. The conventional fossil plant data is included to illustrate that the

same RCCS occur in those plants with approximately the same ranking order.

Table 15.3 clearly shows a ranking order of RCCS for combined cycle/HRSG

plants with monitoring corrosion products and online instrumentation being the

cycle chemistry processes that are most frequently not addressed properly. These

are followed by not challenging the status quo and measuring carryover. General

shutdown procedures for plants is relatively high on the list with the subcategory of

applying DHA in the steam turbine being most often missing. As of 2016, it is

expected that the application of FFP will over the next 5�10 years start to provide

this shutdown protection.

15.5 Case studies

This section provides four combined cycle/HRSG case studies as examples of

applying the RCCS methodology to make assessments on failure/damage and its

Table 15.3 Analysis of repeat cycle chemistry situations (RCCS) inconventional fossil and combined cycle/HRSG plants

RCCS categories In 112 conventional

fossil plants

In 65 combined cycle/

HRSG plants

Corrosion products 90 92

Conventional fossil waterwall/HRSG

evaporator deposition

45 62

Chemical cleaning 15 ,10

Contaminant ingress 16 ,10

Drum carryover 80 88

Air in-leakage 40 ,10

Shutdown protection 77 (& 92a) 65 (& 92a)

Online alarmed instrumentation 80 92

Not challenging the status quo 81 77

No action plans N/A N/A

The numbers in the table represent the percentage of plants where the RCCS was identified.aUse of dehumidified air (DHA) on steam turbine during shutdown.


use proactively to assist combined cycle/HRSG plants in determining if failure/

damage will occur in the future.

15.5.1 Case studies 1 and 2: damage/failure in the PTZ of thesteam turbine in combined cycle/HRSG plants

Protection of steam turbines from chemistry-influenced damage as indicated in

Section 15.3.1.3 has long been recognized as an integral key aspect of effective cycle

chemistry programs for combined cycle/HRSG plants. Equipment manufacturers and

research organizations have performed extensive investigations of damage mechanisms

and determined that most are related to the chemistry, both during operation and when

the unit is out of service. Experience has shown that many organizations continue to

experience contamination of the steam, leading to various consequences. In some

instances, a developing problem is identified during service through monitoring of car-

ryover but in most cases, the existence of steam purity issues only becomes apparent

when blade or disk cracking is observed during an inspection conducted as a scheduled

maintenance activity or as a consequence of a failure incident. This subsection includes

two combined cycle/HRSG case studies that illustrate a pattern observed worldwide in

conventional fossil and combined cycle plants. The first case was a failure incident

where the last stage blades were found cracked during a maintenance inspection. The

second was not a failure situation but part of a combined cycle/HRSG plant cycle

chemistry assessment where the analysis of the RCCS was almost identical to the first

case study, and so suggested proactively that future failure was a possibility.

15.5.1.1 Case study 1

This L-0 blade cracking occurred in a 700-MW 23 1 combined cycle/HRSG plant

after about 90,000 operating hours. The cracking emanated from pits on the blade

surface. The plant had two GTs and a steam turbine (HP/IP and LP), and triple-

pressure HRSGs with HP drum pressure of B10.3 MPa (1500 psi). The condenser

had titanium tubes that had experienced numerous condenser leaks of the brackish

cooling water. The cycle chemistry condensate/feedwater treatment included a pro-

prietary amine blend (ETA/MPA) and a reducing agent (carbohydrazide), and a pro-

prietary phosphate blend was added to all three drums.

During the root cause analysis the following seven RCCS were identified with

the last five being directly related to the PTZ cracking:

� Total iron corrosion products not measured at any location around the cycle.� No HP evaporator tubes had been removed to assess internal deposits.� Instrumentation at low level compared to international standards (IAPWS [10]). The level of

instrumentation (about 50%) was inadequate for identifying contamination quickly. There

was no sodium at the condensate pump discharge or in HP superheated steam (HPSH), pH

in feedwater, no CACE in steam, and no combination of CACE/pH in the HP drums.� Carryover had not been measured. Unknown levels of carryover into steam as the opera-

tors/chemists had failed to monitor carryover on a regular basis and during contamination


events exceeding the shutdown limit, suggesting that steam contamination levels had been

higher than the plant guideline limits on multiple occasions.� Shutdown protection had not been not applied. There was inadequate shutdown protection

for the plant and no DHA applied to the LP steam turbine despite frequent contamination

events that exceeded the plant shutdown limits.� Repetitive contaminant ingress. The operators continued to operate when contamination

exceeded the unit shutdown limits multiple times, and continued to operate attemperation

during these contaminant periods.� Not challenging the status quo. Plant continued to operate with inadequate and out-of-date

chemistry guidance, and kept changing (increasing) the shutdown limit to allow the plant

to keep operating, but the operators continued to ignore the shutdown limits and action

levels that they had developed, and continued to use a reducing agent despite the clear

guidance for combined cycle/HRSG plants that this chemical should not be used [1].

It can easily be seen that this represents a “full house” of RCCS. Singly, each

RCCS would (probably) not have caused failure/damage, or be viewed as the plant

operating out of control. But together, these are commonly the basis of PTZ failures

and damage worldwide. The other important observation is that operating with

seven RCCS in total is rare but is a clear indicator that some other failure/damage

mechanism, such as HD, will occur in the future.

15.5.1.2 Case study 2

The unit in this assessment was a 650-MW 23 1 combined cycle plant with about

93,000 operating hours. The plant had two GTs and a steam turbine (HP and IP/

LP), and triple-pressure HRSGs with HP drum pressure of B10.3 MPa (1500 psi).

The condenser had SeaCure tubes that had experienced condenser leaks of the cool-

ing water (B200 ppb Cl and B400 ppb SO4). The cycle chemistry condensate/

feedwater treatment included a proprietary amine blend (ETA/MPA). The reducing

agent (hydroquinone) had been eliminated a few years before the assessment.

A proprietary phosphate blend was added to the HP drums.

During the cycle chemistry/FAC assessment for this plant the following seven

RCCSs were identified:

� Total iron corrosion products not measured.� No HP evaporator tubes removed to assess deposits.� Instrumentation at low level compared to international standards. The plant had no opera-

tional online continuous instrumentation and was “controlled” by grab samples.� Carryover had never been measured.� Shutdown protection not applied to HRSGs and there was no DHA for the steam turbine.� Air in-leakage was a continuing problem.� Status quo. Plant guidance had not been updated for 6 years.

By comparing this listing with that from the first case study, the similarities will

be noted, and the risks for PTZ cracking and UDC were assessed to be high, illus-

trating the powerfulness of the RCCS methodology.


15.5.2 Case study 3: under-deposit corrosion—hydrogendamage

Although an understanding of the causes of HD was developed in the 1960s, HD is

still prolific in combined cycle/HRSG plants worldwide. The author continues to

conduct metallurgical analyses and root cause investigations multiple times each

year and continues to identify the same suite of RCCSs in the plants that experience

this UDC mechanism. In brief, these include:

� Excessive feedwater corrosion products.� Nonmonitored feedwater corrosion products.� Measuring only soluble corrosion products (no digestion).� No HP evaporator tubes taken for deposit analysis.� Excessive deposits on HRSG HP evaporator tube ID surfaces.� Delayed/postponed chemical cleaning.� Repetitive contamination above action or unit shutdown levels.� Contaminant ingress above shutdown limit.� No operational or managerial support to shutdown with low pH.� Inadequate online instrumentation below the IAPWS international standard [10].� High level of air in-leakage.� Not challenging the cycle chemistry status quo including the following categories: the feed-

water and boiler water treatments and control limits were not optimal; the specification of

chemical treatments and guidance were largely determined by a chemical supplier, and thus

plant personnel were not fully aware of the active chemical composition of the products

they were feeding to the HRSG. No cycle chemistry manual is available for the unit/plant.� No action plans to address any of the previously listed repeat situations. This is because

very often the plant staff had accepted these situations as “normal and allowable” under

the culture but in other cases ignored for various reasons.

15.5.3 Case study 4: understanding deposits in HRSG HPevaporators

Deposition in HRSG HP evaporators was discussed in Section 15.3.1.1 and

Table 15.3 illustrates that not having a comprehensive understanding of these

deposits and the deposition rate is key to a number of HRSG failure mechanisms.

Also it provides an indirect indicator of FAC in other parts of the HRSG.

15.6 Bringing everything together to develop theoptimum cycle chemistry for combined cycle/HRSGplants

Previous sections have discussed failure/damage in the combined cycle/HRSG plant

and the cycle chemistry aspects that influence and address these mechanisms

locally. This section brings everything together to provide the six-step sequential


process that is needed to develop the optimum cycle chemistry control for com-

bined cycle/HRSG plants that will avoid each of the damage mechanisms.

15.6.1 First address FAC

From Section 15.3 it is clear which cycle chemistry activities need to be addressed

as early in the operating life as possible to ensure that FAC (single- and two-phase)

will not occur in the HRSG. As FAC remains the leading cause of failure/damage

in HRSGs, the following aspects should be taken to control it in the lower-pressure

circuits of combined cycle/HRSG plants:

1. Use of only oxidizing treatments in the feedwater/condensate to control single-phase

FAC. No reducing agents should be used at any time [1] unless the combined cycle/

HRSG is relatively old (1970s) and the cycle contains copper-based feedwater heaters.

The oxygen levels need to be high enough to provide surface passivation for the single-

phase flow locations.

2. Use of an elevated pH in the lower-pressure circuits of the HRSG to control two-phase

FAC [1]. This can be accomplished by increasing condensate and feedwater ammonia or

an amine so that the pH elevates above 9.6, or by adding TSP or NaOH to the LP and/or

IP drums if allowed by the HRSG design, attemperation sources, and any interpressure

connection arrangements. Elevated pH (9.8) operation is particularly important in units

with ACC [1 and 7].

3. Depending on whether contaminants are, or could be, prevalent in the cycle, add nothing

to the HP drum or a minimum amount of only TSP or NaOH [4].

4. Monitor total iron around the cycle with a suggestion that operating within the rule of 2

and 5 (,2 ppb (μg/kg) in the feedwater and ,5 ppb (μg/kg) in each of the drums) will

provide some indication of minimum risk for both FAC and UDC [8].

15.6.2 Transport of corrosion products (total iron)

It will be noticed that both avoiding HRSG tube failures (HTF), particularly FAC

and UDC, and developing the optimized cycle chemistry for HRSGs are intimately

related to understanding the corrosion processes around the HRSG cycle, monitor-

ing corrosion products [8] and the formation of deposits in HP evaporators. Thus

each combined cycle/HRSG plant should have a comprehensive monitoring pro-

gram for total iron with the continuing need to ensure that the total iron levels meet

the rule of 2 and 5 [1] using the approved monitoring processes [8].

15.6.3 Deposition of corrosion products in the HP evaporator

Controlling UDC involves the following cycle chemistry features: (1) controlling

corrosion and FAC in the lower temperature sections, (2) minimizing the trans-

port of iron corrosion products to the HP evaporator, (3) removing HP evaporator

tube samples on a regular basis to determine the deposition rate, (4) maintaining

a low level of deposits within the HP evaporator tubes, (5) chemical cleaning if

required, (6) controlling contaminant ingress and adding the correct control


chemicals, and (7) having a fundamental level of instrumentation alarmed in the

control room. The measurement of HP evaporator deposits is the key to ensuring

that a plant does not experience UDC. This is the focus of a new IAPWS TGD

[16] because insufficient tubes are sampled worldwide mainly because of the

uncertainty as to where to sample and often the difficulty of removing the sam-

ples because of the tightly packed HRSG steam circuits directly in front of the

HP evaporator.

15.6.4 Ensure the combined cycle plant has the requiredinstrumentation

As illustrated by the ranking of RCCS (Table 15.3) too many combined cycle/

HRSG plants do not have an adequate suite of continuous online instruments, but

instead rely on grab samples. Table 15.4 provides an indication of the key instru-

ments needed for each combined cycle/HRSG plant.

15.6.5 Cycle chemistry guidelines and manual for the combinedcycle plant

Section 15.4 has illustrated the importance of combined cycle/HRSG plants oper-

ating with the latest cycle chemistry treatments and guidance, and how failure/

damage can take place by not challenging the status quo. An important aspect

of this is for the staff of a combined cycle plant to develop and frequently

update (yearly) a chemistry manual for the plant that contains a compilation of

the important aspect of cycle chemistry control for the plant. A typical example

of manual content is illustrated in Table 15.5. Section 11 of this manual should

include the latest international guidance for the plant, an example of which is

shown in Table 15.6. Examples for PT and CT can be found in the IAPWS

TGD [4].

15.6.6 Do not allow repeat cycle chemistry situations

As discussed in Section 15.4, it has been found that by themselves, individual

RCCS are not usually a concern in terms of plant availability, but when multiples

are allowed to continue then failure/damage has either occurred or is going to hap-

pen in the future. The case studies in Section 15.5 clearly illustrate how multiple

RCCS linked together can eventually result in failure/damage. Thus the identifica-

tion of RCCS is vital, and that these are critical to a plant’s continued reliability.

RCCS are the cycle chemistry equivalents to root cause for other noncycle

chemistry-influenced damage mechanisms. It is suggested that action plans are

required for each with elimination within a 12-month period (or less), which is criti-

cal to the overall management aspects.


Table 15.4 Summary of minimum key instrumentation requirements

Sampling location Minimum key

instrumentation

Caveat

Condensate

pump discharge

(CPD)

Conductivity after

cation exchange

Dissolved oxygen

Sodium (key on

seawater-cooled

plants)

DCACE (Frequently

started and fast-start

units)

Na—Not plants

with air-cooled

condensers

Feedwater

(drum and

once-through

evaporator

circuits)

Condensate

polisher

outlet (CPO)

(rare on

HRSG plants)

Conductivity after

cation exchange

Sodium (key instrument

if CPP is operated in

ammonia form)

Main feed pump Conductivity

Conductivity after

cation exchange

pH

Dissolved oxygen

HRSG drums Plants on AVT

and CT

Conductivity

Conductivity after

cation exchange

pH

Plants on OT Conductivity

Conductivity after

cation exchange

pH

Dissolved oxygen

(Sample should be

from downcomer)

Plants on PT Conductivity

Conductivity after

cation exchange

pH

Phosphate (plants that

prove vulnerable to

hideout or to other

issues with phosphate

concentration control)

(Continued)


15.7 Summary and concluding remarks

The optimum cycle chemistry control of combined cycle/HRSG plants is of par-

amount importance in achieving and maintaining the desired availability,

reliability, and performance. There are a number of key basic features that need

to be adopted and addressed to achieve this highest level of operational perfor-

mance. These involve primarily ensuring that the cycle chemistry drivers for

the main damage mechanisms are comprehensively understood and addressed in

developing and monitoring the cycle chemistry for combined cycle/HRSG plants.

In addition it has been unambiguously shown that cycle chemistry-influenced

Table 15.4 (Continued)

Sampling location Minimum key

instrumentation

Caveat

Steam Saturated Conductivity after

cation exchange

Sodium

Isokinetic sampling

is necessary

Superheated/

reheated

Conductivity after

cation exchange

Sodium

Silica

DCACE (Frequently

started and fast-start

HRSG units)

For plants that have

consistently

demonstrated a

low risk of

elevated silica

concentrations in

steam, the

continuous

monitoring may

be considered

inessential

Makeup water to

condenser

Conductivity

Conductivity after

cation exchange

Silica

Total organic carbon

Plants with storage

tank exposed to

atmosphere

Plants where there

is a risk of

nonreactive silica

or organic

contamination of

raw water

Source: Adapted from Table 1 in IAPWS, Technical Guidance Document: Instrumentation for Monitoring andControl of Cycle Chemistry for the Steam-Water Circuits of Fossil Fired and Combined Cycle Power Plants(Original 2009; Revision 2015). Available from: ,http://www.iapws.org. [10].



failure/damage is directly related to an increasing number of RCCS. A number

of examples have been included in this chapter to illustrate how to address and

ultimately prevent the major cycle chemistry-influenced mechanisms. Guidance

has been provided for condensate, feedwater, evaporator water, and steam.

Specific programs should be developed to ensure that RCCS are not allowed to

occur or continue.

15.8 Bibliography and references

For the reader, there are a plethora of international guidelines and guidance avail-

able for the cycle chemistry control of combined cycle/HRSG plants in many coun-

tries of the world: IAPWS (international), EPRI (United States), VGB (Germany),

JIS (Japan), Russian, Chinese, manufacturers of major fossil and combined cycle/

HRSG equipment (international), chemical supply companies (international). In this

Table 15.5 Typical content of combined cycle plant chemistry manual

Section Subject

1.0 Introduction

2.0 Purpose

3.0 Objectives

4.0 Program roles and responsibilities

5.0 Program benchmarking

6.0 Repeat cycle chemistry situations (RCCS)

7.0 Continuous online instrumentation (IAPWS guidance)

8.0 Cycle chemistry treatment chemicals (IAPWS guidance)

9.0 Feedwater treatment (IAPWS guidance for AVT(O))

10.0 Drum/evaporator water treatment (IAPWS PT/CT guidance)

11.0 Cycle chemistry guidance (normal targets and action levels)

12.0 Shutdown protection of steam/water cycle components

13.0 Drum carryover testing (IAPWS guidance)

14.0 Grab sample and total iron analysis procedures (IAPWS guidance)

15.0 Makeup system

16.0 Equipment inspections

17.0 References and source documents


Table 15.6 Example of guidance for AVT and OT for a multipres-sure combined cycle/HRSG drum unit, no copper alloys, inde-pendently fed low pressure (LP), intermediate pressure (IP),and high pressure (HP) circuits, no condensate polisher for AVT(O), no reducing agent added to the cycle, and not cooled by sea-water or brackish water

Locations/parameters Normal/target values

AVT (O) OT

Condensate pump discharge (CPD)

Conductivity after cation

exchange, μS/cm,0.3 ,0.3

Dissolved oxygen, ppb (μg/kg) ,10 ,10

Sodium, ppb (μg/kg) ,3 ,3

Economizer inlet (EI), preheater inlet, or feed pump discharge

Conductivity, μS/cm Consistent with pH Consistent with pH



pH 9.2�9.8 9.0�9.8

Dissolved oxygen, ppb (μg/kg) 5�10 Per recirculation ratio

LP drum (0.5 MPa, 70 psi) blowdown (LPBD)/downcomer (LPDC)



exchange, μS/cm,25 ,25

pH 9.0�9.8 9.0�9.8

Dissolved oxygen (for OT), ppb (μg/kg) not applicable ,10

IP drum (2.4 MPa, 350 psi) blowdown (IPBD)/downcomer (IPDC)



exchange, μS/cm,25 ,25

pH 9.0�9.8 9.0�9.8


HP drum (14 MPa, 2000 psi) blowdown (HPBD)/downcomer (HPDC)


(Continued)


chapter the main emphasis has been on the Technical Guidance Documents (TGD)

of the International Association for the Properties of Water and Steam (IAPWS) as

these are freely downloadable on the IAPWS website (www.IAPWS.org). These

have been used as the main reference materials throughout this chapter and full

attribution is given to IAPWS in relation to the TGD in Refs. [1�4, 8�10, and

[16]. These TGDs also provide extensive further references for each topic area.

References

[1] IAPWS, Technical Guidance Document: Volatile Treatments for the Steam-Water

Circuits of Fossil and Combined Cycle/HSRG Power Plants (Original 2010; Revision

2015). Available from: ,http://www.iapws.org..

[2] IAPWS, Technical Guidance Document: Application of Film Forming Amines in Fossil,

Combined Cycle and Biomass Plants (To be published September 2016). Will be

Available from: ,http://www.iapws.org..

[3] IAPWS, Technical Guidance Document: Procedures for the Measurement of Carryover

of Boiler Water into Steam (2008). Available from: ,http://www.iapws.org..

[4] IAPWS, Technical Guidance Document: Phosphate and NaOH Treatments for the

Steam � Water Circuits of Drum Boilers in Fossil and Combined Cycle/HRSG Power

Plants (Original 2011; Revision 2015). Available from: ,http://www.iapws.org..

Table 15.6 (Continued)

Locations/parameters Normal/target values

AVT (O) OT



pH (unit shutdown limit if pH is falling) 9.0�9.8 (8) 9.0�9.8 (8)


Saturated steam on LP, IP, and HP drums

Sodium on LP, IP, HP drums, ppb (μg/kg) ,2 ,2

HP steam/RH steam



Sodium, ppb (μg/kg) ,2 ,2

Makeup (MU)

Conductivity, μS/cm ,0.1 ,0.1

The drum pressures for the plant are considered to be LP 70 psi (0.5 MPa), IP 350 psi (2.4 MPa), and HP 2000 psi (14 MPa).

Source: Adapted from IAPWS, Technical Guidance Document: Volatile Treatments for the Steam-Water Circuits of Fossil and Combined Cycle/

HSRG Power Plants (Original 2010; Revision 2015). Available from:,http://www.iapws.org..


http://www.IAPWS.org








[5] R.B. Dooley, Flow-accelerated corrosion in fossil and combined cycle/HRSG plants,

PowerPlant Chem. 10 (2) (2008) 68�89.

[6] R.B. Dooley, R.A. Anderson, Assessments of HRSGs � trends in cycle chemistry and

thermal transient performance, PowerPlant Chem. 11 (3) (2009) 132�151.

[7] R.B. Dooley, A.G. Aspden, A.G. Howell, F. du Preez, Assessing and controlling corro-

sion in air-cooled condensers, PowerPlant Chem. 11 (5) (2009) 264�274.

[8] IAPWS, Technical Guidance Document: Corrosion Product Sampling and Analysis for

Fossil and Combined Cycle Plants (2014). Available from: ,http://www.iapws.org..

[9] IAPWS, Technical Guidance Document: Steam Purity for Turbine Operation (2013).

Available from: ,http://www.iapws.org..

[10] IAPWS, Technical Guidance Document: Instrumentation for Monitoring and Control of

Cycle Chemistry for the Steam-Water Circuits of Fossil Fired and Combined Cycle

Power Plants (Original 2009; Revision 2015). Available from: ,http://www.iapws.org..

[11] R.B. Dooley, A. Bursik, Hydrogen damage, PowerPlant Chem. 12 (2) (2010) 122�127.

[12] R.B. Dooley, A. Bursik, Acid phosphate corrosion, PowerPlant Chem. 12 (6) (2010)

368�372.

[13] R.B. Dooley, A. Bursik, Caustic gouging, PowerPlant Chem. 12 (3) (2010) 188�192.

[14] R.B. Dooley, S.R. Paterson, Phosphate Treatment: Boiler Tube Failures Lead to

Optimum Treatment, 55th International Water Conference, Pittsburgh, October 31/

November 2, 1994, IWC Paper IWC-94�50.

[15] R.B. Dooley, W. Weiss, The criticality of HRSG HP evaporator deposition: moving

towards an initial understanding of the process, PowerPlant Chem. 12 (4) (2010)

196�202.

[16] IAPWS, Technical Guidance Document: HRSG High Pressure Evaporator Sampling

for Internal Deposit Identification and Determining the Need to Chemical Clean

(2014). (To be published September 2016). Will be Available from: ,http://www.

iapws.org..

[17] R.B. Dooley, K.J. Shields, S.J. Shulder, How repeat situations lead to chemistry-related

damage in conventional fossil and combined cycle plants, PowerPlant Chem. 10 (10)

(2008) 564�574.

































16HRSG inspection, maintenance

and repairPaul D. Gremaud


Chapter outline


16.2 Inspection and maintenance 35516.2.1 Hot inspection 356

16.2.2 Daily walkdown of equipment 361

16.2.3 Cold inspection and maintenance 361

16.3 Repair 37516.3.1 Flow-accelerated corrosion 376

16.3.2 Thermal fatigue 376

16.3.3 Under-deposit corrosion 377

16.3.4 Casing or liner failures 377

References 377

16.1 Introduction

A heat recovery steam generator (HRSG) is a large, complex piece of equipment

and, as such, requires regular inspection and maintenance and occasional repairs to

keep it functioning in a safe, efficient, and reliable manner. Although many people

in the boiler industry think of inspection, maintenance, and repair occurring at the

annual shutdown of the facility, a well-run plant will also utilize daily “walkdowns”

of the equipment to proactively search for potential problems. They also take

advantage of scheduled and unscheduled shutdowns for additional inspection and

maintenance to keep all systems functioning properly.

16.2 Inspection and maintenance

HRSG inspection and the maintenance associated with it can be divided into two

categories: hot inspection and cold inspection. Hot inspections are performed on the

outside of the unit when the HRSG is either operating or has been recently shut down



http://dx.doi.org/10.1016/B978-0-08-101940-5.00016-6

and is still hot. Hot inspections should be performed at regular intervals with the daily

walkdown considered an abbreviated hot inspection. Cold inspections take place when

the HRSG is shut down and has cooled off so that it is possible to enter the HRSG.

There are various types of maintenance programs that have been studied and

developed in the recent past: preventative maintenance, predictive maintenance,

reliability centered maintenance, etc. This chapter will cover a practical approach

that can easily be used by HRSG maintenance personnel to take a proactive

approach to maintenance and understand the important aspects of maintaining a

reliable HRSG.

Each component of the HRSG should be listed and a maintenance plan for each

of these components should be developed so that maintenance will be routinely and

consistently performed at the appropriate time. The Operating and Maintenance

Manual provided with the HRSG is a useful document to use when developing this

document. The HRSG supplier should also be able to help.

A list of and inventory of critical spare parts is also necessary for an effective

maintenance program and to minimize the impact of unplanned outages. The

operating and maintenance manual and HRSG supplier are helpful in developing

this list. The list should include at a minimum:

� two sections of tubing (including bends) for every coil and material in the HRSG� two tube plugs for each configuration of tubing� spare liner pins� two spare desuperheater nozzles� two manway gaskets for each drum

The most common mechanisms for HRSG component failures are flow-

accelerated corrosion (FAC), thermal fatigue in superheaters and reheaters, and

under-deposit corrosion in HP evaporator tubing as described very well in Ref. [1].

Inspection and maintenance should therefore place special emphasis on these areas.

16.2.1 Hot inspection

A regularly scheduled (yearly or more often) hot inspection is an inexpensive,

proactive task that can help avoid more costly repairs in the future. The inspection

should include the use of a thermal camera. The hot inspection will incorporate

some of the tasks that are part of the daily walkdown, namely listening

to the sounds near the inlet duct, viewing the casing penetration seals in the high-

temperature region, and observing the duct burner flame pattern. A thorough hot

inspection will take approximately half a day for the typical HRSG. Performing a

hot inspection 2�3 months before a scheduled cold inspection can be very useful in

preparing for the cold inspection and maintenance.

16.2.1.1 Inlet expansion joint

Begin the inspection at the connection between the combustion turbine diffuser and

the HRSG inlet duct. This will be the region that is most susceptible to damage


and other issues related to the high velocity and turbulence in the combustion tur-

bine exhaust. The fabric expansion joint, which is the interface between the com-

bustion turbine and the HRSG, should be viewed in its entirety. A thermal camera

should be used to ensure that the fabric temperatures are below the design tempera-

ture of the outer layer material. Any type of material on the external face of the belt

will increase the belt temperature; the belt will fail rather quickly if its temperature

exceeds 350�F. If a local area is hot, the issue may be as easy as exhaust leakage

due to a loose backing bar at the outside of the expansion joint. The seam where

the fabric expansion joint is field bonded is a typical location of failure, so this area

should always be closely inspected.

16.2.1.2 Inlet duct

The inlet duct region of the HRSG is the key location for using the “watch and

listen” approach. The loads on the liner system due to the high velocity and

turbulence in the turbine exhaust can cause pulsation of the casing and liner

systems. This movement of the casing will ultimately cause fatigue failure of the

liner support system resulting in a potential forced outage. Liner system failures

will not only cause high casing temperatures and personnel safety issues, but will

also permit the liberation of insulation, which will coat all heating surfaces and

equipment downstream. The concern for a forced outage comes into play if there

is a CO or SCR system. The loose insulation will block the open spaces/channels

in the CO or SCR blocks, cause a large increase in differential pressure across

the equipment, and can even cause failure of the support system. Pumpable

insulation, which can be installed through a hole in the casing, can be an

effective temporary fix for a hot spot until a permanent repair can be made

during an outage.

16.2.1.3 Duct burner

A duct burner is frequently incorporated into a HRSG to increase output. The

efficiency and flexibility provided by the duct burner and the additional steam

production that can be delivered have made it common for the duct burner to be

cycled multiple times daily. Review of duct burner operation is an item that

should be included in a daily walkdown schedule. Burner viewports are typically

provided with the duct burner system, however, a sufficient number to easily

view the flame pattern are often not available. Viewports should allow for

viewing all burner runners in their entirety and allow for the viewing of flame

impingement on the face of the coil immediately downstream of the burner.

Fig. 16.1 shows a typical duct burner flame pattern as viewed through a

viewport.

Issues arising from improper duct burner operation or design are unfortunately a

common occurrence. Damage to liner systems, vibration supports, heating surface,

and burner runners occur frequently. Although this damage often does not directly

cause a forced outage, significant damage could be avoided by viewing the duct

357HRSG inspection, maintenance and repair

burner flame patterns during the daily walkdown. If the duct burner is operated at

various combustion turbine loads, the flame pattern should be viewed on a more

frequent basis.

16.2.1.4 Casing

Inspection of the casing is much like inspection of the inlet duct; however, gas

velocities and turbulence are lower in this area. Hot casing is not an uncommon

occurrence in HRSGs. However, the typical scenario is a very local hot spot,

usually around a penetration seal, test port, or at structural members. The

HRSG casing should be viewed for regions with discolored paint or distorted

sections. The important areas to view are the casing sections nearest the

combustion turbine, i.e., the inlet duct through the reheater/HP superheater

coils (Fig. 16.2).

16.2.1.5 Casing penetration seals

Penetration seals in the hot region of the HRSG must perform in a severe environ-

ment. They are utilized where an inlet nozzle, outlet nozzle, or drain line for a

header must pass through the casing. They can be required to seal 1700�F exhaust

Figure 16.1 Typical duct burner flames when viewed through a viewport.


and allow for large vertical movements of the component within the penetration.

The lateral design movement of the penetration seals can also be difficult.

Casing penetration seal design has improved tremendously in the past ten years.

This is especially true for fabric penetration seals that are used with high-

temperature components such as HP superheaters, reheaters, and HP evaporators.

Although there are several companies that provide excellent products, thorough

viewing of the high-temperature penetration seals during a hot inspection is neces-

sary. A thermal camera should be used to measure the temperature of the outer fab-

ric. The penetration seal supplier should provide the appropriate temperature. It is

important that the exterior of the fabric seal be free of insulation so it is cooled by

the ambient air. The inspection should include a check for gas leakage. Caution

must be taken due to the high exhaust temperature. It is critical to identify and

replace damaged or leaking penetration seals as the hot exhaust can cause injury,

failure of adjacent seals, or damage to other equipment. These penetration seals

should thus be viewed during a daily walkdown (Fig. 16.3).

Figure 16.2 Casing hot spots.


16.2.1.6 High-energy piping and support system

The high-energy piping is an area prone to issues due to high operating pressure

and temperatures and the corresponding large thermal expansions. The support

system combined with proper fabrication and installation of the system is critical to

long-term reliability. Damage due to creep and fatigue can occur and is exacerbated

if materials were not fabricated and heat treated with great care.

The typical hot inspection of high-energy piping would entail visual inspection

of the piping system with special care taken to view all the supports. The support

condition should be compared to the pipe support drawing from the original

designer. It is critical that the support functions as designed and that the pipe line is

not overly restrained by the support. Spring supports should be viewed to confirm

that the position indicator is in the proper “hot” location (Fig. 16.4).

Figure 16.3 Penetration seals with proper piping insulation arrangement.

Figure 16.4 Spring can with indicator in proper location.


Several engineering and consulting companies have developed inspection plans

for high-energy piping. These inspection programs are typically performed during

an outage and include nondestructive examination and other material testing that is

not appropriate for a hot inspection.

16.2.2 Daily walkdown of equipment

If there is one aspect of an inspection program that is underutilized, it is the daily

walkdown of the HRSG by plant personnel. This is very unfortunate, as the

daily viewing of plant equipment is an important, proactive task that can signifi-

cantly reduce maintenance spending and capital costs over the life of the HRSG.

The daily walkdown also allows personnel to understand operational norms so they

can better identify when something is amiss.

The daily walkdown is an abbreviated version of the hot inspection described

above but it should not be performed in haste or carelessly. Notes should be taken

during this daily exercise. A standard document can be created to make this an

efficient process. The notes can be an important reference when issues arise.

Thermal scans can be performed for areas of interest such as the high-temperature

casing penetrations in the reheater and HP superheater sections on a regular (not

daily) schedule. These scans can be compared to previous scans to help identify

gradual degradation of equipment where repairs or replacements can be planned

before failures occur. Any steam/water leakage should be noted and corrected at a

subsequent outage.

Drain line temperature downstream of stop valves should be checked in order to

determine if drain valves are leaking. Leaking drain valves are a common problem and

operators must understand that these valves are not to be used as blowdown valves.

16.2.3 Cold inspection and maintenance

The cold inspection is the best method to verify the current condition of the heating

surfaces of a HRSG. The cold inspection is also the only way to effectively inspect

several other components, such as the liner systems, distribution grid, duct burner,

and the catalyst systems.

There are several acceptable options regarding the inspection of your HRSG.

The inspection can be performed by plant personnel experienced in the maintenance

of HRSGs. Plant personnel can be effectively trained by the HRSG supplier and

provided with a basic inspection program including critical inspection items. Most

HRSG suppliers also have competent personnel to perform the inspection service.

To prepare for the cold inspection, the HRSG must be isolated from all steam

headers and feedwater sources. All gas duct access doors should be removed and

the stack damper should be placed in the open position. Access door surfaces

should be cleaned so new gasket materials can be used when the doors are closed.

Once the unit has cooled and all plant safety requirements have been completed,

the HRSG can be safely entered.


Use of conventional terminology is useful for effective communication when

working in and around a HRSG. The upstream end of the HRSG is at the end where

the gas turbine is, i.e., downstream is near the stack. Right and left sides are deter-

mined when standing at the upstream end and looking downstream.

The following tools are necessary for a detailed inspection:

� bright flashlights� notebook� camera� wire brush� inspection mirror� soap stone or paint pen

16.2.3.1 Inlet duct

Standard practice is to begin the HRSG gas path at the interface between the com-

bustion turbine diffuser and the inlet duct. The expansion joint at this location is

particularly susceptible to failure due to the extremely high velocities and turbu-

lence in this area. The inlet duct, especially the floor liner system, should be viewed

in great detail, looking for damaged or missing liner plates, pins or clips, guide

vanes or deflectors and insulation. Areas often in need of maintenance are field

seams, corner angles, and access doors. Exposed insulation at the liner system

should always be replaced and covered to minimize the amount of foreign material

in the HRSG gas flow and provide adequate insulation for the casing (Fig. 16.5).

Each liner pin should be viewed for structural integrity. Any liner pins where the

connection to the casing has failed should be repaired. Also, gaps at liner pins

should be repaired if the gap is greater than 1/8v. A shim should be added to

minimize deflection of the liner system, and potential failures during operation. The

shim can be a slotted plate, slightly larger than the washer, that is slipped between

the liner and washer and welded to the existing pin and washer. The shim must not

be welded to the liner plate.

Repairs of the liner system damage are important to the reliability of the HRSG

especially if there is CO or SCR equipment as discussed previously.

16.2.3.2 Distribution grid

A distribution grid, if present, should be inspected due to the extremely difficult

operating conditions in the inlet duct of a HRSG. The typical distribution grid has

several components that should be inspected. Many different restraint systems have

been utilized over the years. The recommendations below are specific to a grid that

is designed to rest on the floor of the inlet duct with a fixed restraint at the center

line. This distribution grid is designed to expand vertically from the floor and also

expand horizontally from the centerline of the gas path toward each sidewall of the

HRSG inlet duct.


A common place to start is with the grid restraints on the floor of the inlet duct.

The most important floor restraint will be the fixed support at the center of the duct

(Fig. 16.6). Inspection of the condition of the weld at the fixed support is key. If the

grid is not fixed and is allowed to move freely perpendicular to the exhaust gas at

this point, binding at other restraints and subsequent failures can be expected. The

floor guides to the sides of the fixed restraint (Fig. 16.7) should also be inspected to

ensure that they allow the grid to move perpendicular to the exhaust gas yet provide

support in the direction of the exhaust flow.

Next, the sidewall restraints (Fig. 16.8) should be inspected. The lowest sidewall

restraints can be viewed from the floor of the duct or from a ladder. There are a

couple different styles, such as a pin and retainer lug, or a horizontal bumper. It is

important that these restraints provide support in the gas flow direction, but also

allow the distribution grid to grow vertically and horizontally several inches in the

direction perpendicular to the gas flow. The lower sidewall restraints typically

withstand the highest loads and are most prone to failure. If damage is found on a

component of the support system, it would be prudent to then closely inspect the

adjacent supports. Any support damage must be repaired. Failure of one support

can very easily propagate to others and cause failure of the grid section.

Figure 16.5 Exposed insulation at liner system.


The distribution grid perforated plate and frame sections should also be

inspected at each outage. Deformation of the perforated plate can be common but is

not cause for great concern. It is appropriate to document the distortion and

continue to monitor at each subsequent outage. Cracks in the ligaments of the

perforated plate should be repaired to ensure that sections of the grid do not fail

and cause collateral damage. Repeated cracking in a specific area will require

Figure 16.6 Distribution grid fixed support.

Figure 16.7 Distribution grid floor guide.


strengthening of the grid in that area. Grid designs using perforated plate thicknesses

less than half an inch in the lower sections historically have not been very reliable.

16.2.3.3 Duct burner

The duct burner, a critical component in the HRSG, is subjected to very high

temperatures and should be inspected carefully during the cold inspection. The

ignitor, flame scanner, burner runners, and baffles should be viewed carefully.

Viewports should be inspected and cleaned, gaskets under the glass should be

replaced, and seams should be sealed with high-temperature sealant.

Close attention to the burner spuds or holes in the runner is important as cracks

can be common in the runners at the holes. Coking and other buildup on the runners

is also a frequent issue that typically stems from incomplete combustion due to lack

of oxygen. Viewing the flames during operation can help assist with possible

solutions to this problem.

Another common occurrence is severe distortion of the lowest runner, or lowest

two runners (Fig. 16.9). This distortion is a classic result of quenching of the runner

with condensate when the gas valve is opened to begin duct burner operation.

Figure 16.8 Distribution grid sidewall restraints.


During operation of the combustion turbine, before the duct burner is ignited,

condensate is created in the external burner piping due to hot exhaust gas flowing

into the burner runner and subsequently migrating into the external piping. When

the exhaust hits the cold external piping, condensate is formed and fills the external

gas piping. This cold condensate is forced into the lowest runners once the gas

valve is opened. A distorted runner should be viewed to see if it is still supported

adequately and whether it will expand and contract as required.

In addition to inspecting the burner, the surrounding equipment should be

viewed to see if the heat released from the burner is causing collateral issues.

The sidewall, roof, and floor liner panels should be viewed for distortion or discol-

oration, which would signify an overheating condition (Figs. 16.10 and 16.11)

and the vibration supports on the coil immediately downstream of the burner

Figure 16.9 Distorted lower burner runners.

Figure 16.10 Damaged liner system due to overheating.


should also be viewed. If the duct burner flame impinges on a vibration support,

overheating can occur (Fig. 16.12).

16.2.3.4 Heating surfaces/HRSG coils

The heat transfer coils are the backbone of the HRSG and are the most expensive

components; thus a thorough inspection is warranted. There should be particular

focus on the tube-to-header joints and drain connections to look for damage due

to thermal stress. Special attention should be paid to superheaters and reheaters

upstream of the HP evaporator and the coldest row of the feedwater preheater.

A thorough inspection will include a hydraulic test of the coils under pressure to

look for leaks. In the event a leak is detected, it must be repaired before bringing

the unit back online and a root cause analysis should be performed. The root

Figure 16.11 Liner damage from flame impingement.

Figure 16.12 Damaged vibration supports due to overheating.


cause analysis should, at a minimum, focus on normal operation, upsets, and

excursions of the HRSG, auxiliary equipment, chemical treatment equipment,

conditions during previous lay-up, and outages and previous repair work in the

vicinity of the leak.

All coils should be inspected in their entirety from the floor of the HRSG. If a

scaffold is in place or access doors are open on the roof, these should be used to

view the coils in more detail. In addition to looking for leaks, the coil inspection

should include the general condition of the tubes, the tube-to-header joints, and the

drain piping. Drain lines passing through casing penetrations often corrode due to

trapped moisture in the area and should therefore be inspected carefully.

Nonpressure parts such as the finning, lower coil restraint system, vibration

supports, lower gas baffles, and acoustic baffles should also be viewed. It is

common to see lower gas baffles out of position or damaged, especially in the front

section of the HRSG. These baffles should be repositioned and fixed at the bottom

of the tube fins to minimize gas bypass.

It is convenient to divide the coils into categories: HP superheaters and reheaters,

the HP evaporators, and the lower temperature coils back through the preheaters for

the sake of discussion.

16.2.3.5 HP superheater and reheater coils

Tube-to-header joints at the bottom of the HP superheater and reheater coils

should be inspected closely. These coils will be subjected to very large tube

temperature changes between startup and normal operation. With a change in

temperature of 1000�F or greater, the tubes can expand up to 12v if the coils are

made from stainless steel. This amount of expansion can cause failure in very

little time if the expansion is restricted. Look for tube bulging or damage to the

oxide layer on the tubes at the connection to the lower headers. This damage will

be a sign that there are high stress conditions that will ultimately lead to failures.

If the coils are top supported, as is the most common scenario, the lower header

gas flow restraints should be inspected closely. Restraints should permit vertical

movement of the headers while restricting horizontal movement. Improper

restraint or restraint failure can cause significant damage. If damage is found,

some type of nondestructive examination of the affected joints should be

performed to see if there are indications or cracks that should be repaired. A root

cause evaluation should also be conducted.

If there are questions as to whether header restraints are functioning properly, it

would be advisable to contact the original equipment manufacturer.

Photographs of the front and back of each coil should be taken at each outage to

document the general condition for future comparison. Any bowing or distortion of

tubes (Fig. 16.13) should be noted and a simplified root cause evaluation performed

to help the plant personnel understand if repairs or operational modification should

be implemented. The HRSG supplier should be able to provide drawings (if you do

not already have them) with nozzle and drain locations that will quickly help you

identify the potential cause to the majority of the damage that will be encountered.


Similar to the situation where tube-to-header damage is identified, if bowed tubes

are located, some type of nondestructive examination of the affected joints should

be performed to see if there are indications or cracks that should be repaired.

If there is no distribution grid in the inlet duct, the first HP superheater or reheater

coil can be subjected to high loads due to exposure to the high-velocity and

extremely turbulent gas flow. Damage to the tube fins at the vibration supports and

bowing or movement of the coils is possible. Additional vibration supports can be

installed if necessary.

It is common to have issues with casing penetration seals in this area where

temperatures are very hot and the coils expand a considerable amount. Each seal

should be inspected carefully, looking for uncovered and missing insulation.

Missing insulation should be replaced and liner plates should be repositioned or

replaced to ensure that the seal will not overheat upon restart of the unit. This is

also a good time to repack any packing glands that are present.

16.2.3.6 Evaporator coils

Evaporator coils operate at lower and more uniform temperatures than the HP

superheaters and reheaters, therefore there is much less issue with tube-to-header

failures. Even though many rows of evaporator tubes may be connected into the

same upper and lower headers, the row-to-row temperature differentials are very

small so issues with thermal stress-induced failures are very rare.

The HP evaporator can be susceptible to under-deposit corrosion. If this occurs,

it will present itself in the higher heat flux rows near the front of the evaporator.

Under-deposit corrosion is very uncommon in the first 10 years or so of operation.

Figure 16.13 Bowed/distorted tubes.


However, there are some factors that can make under-deposit corrosion appear

much sooner in the life of the HRSG. If the coils were not chemically cleaned prop-

erly, so that a proper magnetite protective layer is formed, or if there is a high level

of iron in the water, which can deposit in the high heat flux tubes, then the occur-

rence of under-deposit corrosion is much more likely. The iron in the water could

be a result of FAC issues in the LP system or from somewhere else in the steam/

water cycle of the facility. If there is concern about under-deposit corrosion, the

deposit weight density in a HP evaporator tube should be tested to determine if

chemical cleaning of the evaporator is recommended (see Ref. [2]).

Section 15.3.1.3 contains additional information related to under-deposit corrosion.

16.2.3.7 Emissions control equipment

There are often several pieces of equipment that are related to emissions control

located in the HRSG that should be viewed during the cold inspection. If there are

any issues with this very specialized equipment the most prudent course of action is

typically to contact the original supplier for the best recommendation.

The CO catalyst should be viewed to ensure that the face is clean and there is no

foreign material, such as insulation, blocking the flow channels. Also the seals

around the edges of the catalyst support frame should be viewed to ensure gas

bypass is not occurring. See Section 9.5.4 for additional information related to

cleaning CO catalysts.

The ammonia injection grid lances upstream of the SCR catalyst should be

viewed at each internal inspection. Each lance will have many small diameter holes

that can be prone to blockage. If the lowest runners are viewed and there is no

blockage, then most likely the entire system is in good condition. If holes are

plugged the lances should be inspected with a borescope to determine if they all

should be cleaned.

The SCR catalyst should also be checked during the cold inspection. Similar to

the CO catalyst, it is wise to view the front face of the blocks to ensure there is no

(or minimal) foreign material such as insulation blocking the cells. Checking the

seals at the frame for any damage or area where flow may bypass is important, as is

viewing the insulation pieces that are typically placed between each catalyst section

and along the edges where the catalyst is fastened to the frame. After several years

in operation it is relatively common for insulation pieces to be missing. A photo or

two sent to the SCR supplier will help them assess whether repair is required. See

Section 8.4.4 for additional information related to maintenance of SCR catalyst

systems.

If either the CO or SCR catalyst is underperforming, catalyst samples can be

removed and evaluated by the catalyst supplier.

16.2.3.8 Coils in the low-temperature region of the HRSG

Even though the operating temperatures in the back end of the HRSG are low (usually

,400�F), the coils should be inspected during a cold inspection. Major concerns are


FAC in the tubes, headers, and risers of LP evaporators, and in the tubes and headers

of low-temperature economizers and feedwater heaters; thermal stress-induced dam-

age in the preheater/economizer coils from the introduction of cold condensate during

warm or hot starts; and fouling of the finned tubes in this area. FAC occurs in areas

where the velocity of the water or steam/water mixture is high such as bends in tubes

(Fig. 16.14) or risers or tube-to-header joints.

The tube-to-header connections at the inlet headers in the economizers should be

viewed for distortion or oxide layer damage, which is a sign of high stresses.

Viewing the tube field on the water inlet side is also important. A distorted tube

can be a sign of a high thermal stress at some period of operation.

External buildup of debris or fouling of the finned tubes is very common in most

HRSGs that have operated for more than 5 years. The temperature of the back end

exhaust gas and the prevalence of impurities can lead to the precipitation of these

impurities.

A modest buildup of rust on the finned surfaces is common. It can be a concern

if it is excessive as it can reduce the efficiency of the heat transfer in the fouled

coil. Additionally, the rust will cause higher exhaust side pressure, which can

reduce the efficiency of the combustion turbine.

Sulfur (Fig. 16.15), ammonia salts (Fig. 16.16), and other contaminants can also

precipitate out on the coils in the back end of the HRSG. These contaminants when

wet can be transformed into acids that can attack the tubes and cause tube failures.

These deposits can be removed by water washing or more effectively and with less

collateral damage by blasting with dry ice pellets. An experienced cleaning contrac-

tor should be used for removal of ammonia salts.

16.2.3.9 Internal steam drum inspection

The internals of all steam drums should be inspected at each outage. Both manways

should be opened and a fan placed at one end to provide a draft and help cool the

Figure 16.14 Flow-accelerated corrosion in the upper tube bend of an LP evaporator.


drum for quicker access. The HP steam drum, due to shell thicknesses that can be as

much as 7 in., may take several days to cool to a reasonable temperature for access.

While the drums are cooling, the external areas can be inspected as follows:

� Check that all valves and trim are supported and sealed properly.� Service and calibrate safety valves every 2 years at a minimum.� Check for signs of leaking flanges/covers on the manways and replace gaskets.� Check the general condition of the level control equipment, cleaning the water column

gage glass and probes and replacing gaskets.� View the saddle support and ensure the slide packs are in the proper position and grease

any fittings present.� View the shear bars at the drum’s support.

Figure 16.16 Ammonia salt buildup on finned tubes.

Figure 16.15 Sulfur buildup on finned tubes.


When the drum is being entered care should be taken to avoid dropping inspec-

tion tools or flashlights as they may enter pump suction or downcomer lines located

on the bottom of the drum shell near the drum manway that are not covered.

Once inside the drum, look for corrosion, erosion, deposits, or mechanical issues.

The following items should be carefully inspected:

� the drum manway forging and cover gasket surfaces� the downcomer-to-shell connection� the belly pan and the connections to the drum shell� the feedwater nozzle connections and internal pipe� the secondary steam separation boxes, including the mesh pads� the internal color of the drum

Depending on the pressure level of the drum there are different concerns.

The major concerns for each drum are:

LP Steam Drum

The major concern for the LP steam drum is the possibility of FAC. The primary sepa-

ration devices such as the belly pan or cyclones should be viewed for signs of FAC. This

may appear as shiny metal where the magnetite layer has been removed or actual erosion

of the material. FAC damage can also be present at the downcomer nozzles. Viewing the

general color of the inside of the LP drum is also important due to FAC concerns.

The inside of the drum should be “ruggedly red” due to the presence of an oxidizing

environment (hematite). If the inside of the LP drum is not red in color, the plant chemis-

try program should be reviewed by an expert as soon as possible.

If ports are available in the lower baffle of the drum (belly pan), looking down into

the riser nozzles and beyond into the LP evaporator with a borescope for signs of FAC is

recommended.

If there are feedwater headers present in the LP steam drum, the spring-loaded spray

nozzles should be checked to ensure the springs are still functioning properly. It should be

possible to open the nozzle by hand.

IP Steam Drum

Generally, there is much less concern for issues in the IP steam drum than in the HP

or LP steam drums. Inspection of the final separator and associated mesh pad is important

to ensure IP steam purity. Viewing the manway forging and manway cover gasket

surfaces and the separation equipment is recommended. Additionally, depending on the

pressure of the IP system, there could be the potential for FAC at the downcomer or

primary separators so they should be viewed as they were in the LP steam drum.

Inspection for the general cleanliness or any buildup of loose material at the ends of the

IP steam drum is also prudent. This may be a sign of improper blowdown or water quality

concerns.

HP Steam Drum

The HP steam drum has several areas that should be inspected closely. The gasket sur-

faces on the manway forging and the cover should be viewed at each outage. Gouges,

scratches, or imperfections that lie across the surface (perpendicular to the edge) are most

important. Any damage that is 1/32v deep or greater should be repaired.

Another very important inspection location in the HP steam drum is the downcomer-

to-shell connection, especially if the downcomer forging projects inside the shell inside

diameter. Units that were originally designed for baseload service can experience cracking

in this area if now started and stopped frequently.


Due to the higher operating temperatures, and subsequently greater thermal stresses

between the thin-walled internal components and the thick-walled shell than the IP and

LP steam drums, the primary and secondary steam separators in the HP steam drum

should be inspected closely. The locations where the separator plates are welded to the

drum shell can be prone to small cracks. If small cracks are found they can be monitored

yearly to determine if repair is necessary. However, if there is concern that the crack may

propagate into the shell base material, then it should be repaired as soon as possible.

The mesh pads should also be checked to ensure they are free of debris and

cover the entire surface of the separator vanes as in Fig. 16.17. Bypass of the mesh

pads as in Fig. 16.18 has the potential to affect the overall steam quality.

16.2.3.10 Stack

Inspection of the stack should complete the internal inspection of the HRSG. The

stack floor and lowest shell can should be viewed for general corrosion. Checking

that the floor drain is not blocked by rust or other debris is important to help mini-

mize corrosion that may occur due to the presence of condensate in the stack.

The silencer and stack damper should also be viewed from the floor of the stack.

If there is concern about the integrity of the silencers, closer inspection is

warranted. If it appears that the damper blades are not sealing completely, the

movement of the blades should be checked during the outage.

16.2.3.11 Severe service valves

Attemperators (desuperheaters) and pressure-reducing valves between the HP

superheater and reheater are severe service valves and should be inspected and

maintained annually.

Figure 16.17 Secondary separator with mesh pads.


Nonreturn valves in the HP steam outlet piping are subjected to very difficult

operating conditions. These are very large, thick-walled castings or forgings with

hardened seats. Thermal stresses at startups and shutdowns can cause cracking and

failures in the seating surfaces. Plants that typically operate in a cyclic mode should

plan to inspect these valves after 5 years of service.

16.3 Repair

Most modern HRSGs are well designed and manufactured to very high standards.

As a result, major repairs are usually not required. However, unforeseen situations

can arise when operating a complex power plant and components can be damaged.

Operating conditions and needs of a plant can also change so that the HRSG may

require modifications. The cyclic service, with frequent startups and shutdowns,

that is demanded of many power plants in today’s environment is also hard on a

HRSG that is not designed for this service. A few of the most common repair

situations will therefore be reviewed. Detailed repair procedures are beyond the

scope of this book. When making repairs such as these, the services of a contractor

who is experienced and certified to repair boilers are required, and this contractor

should be involved in developing procedures that are appropriate for both the repair

and the staff performing the work.

After a HRSG is constructed and stamped in accordance with ASME rules and

procedures, any subsequent repair falls under the jurisdiction of the National Board

Inspection Code (NBIC). Repairs and alterations are to be approved by a local

authorized inspector.

Figure 16.18 Secondary separator needing mesh pad replacement.


16.3.1 Flow-accelerated corrosion

FAC occurs predominantly in the tubes, headers, and risers of low-pressure

evaporators and in the tubes and headers of economizers and feedwater preheaters

operating in the 200�500�F temperature range. It occurs in areas where the velocity

of the water or water/steam mixture is high such as bends in tubes or risers or tube-

to-header joints. Repair involves replacement of the damaged portion of the compo-

nent and requires the services of very capable tube welders who are certified to the

boiler code in use. Accessibility of the area where the repair is needed can be an

issue as the finned tubes in a HRSG are spaced very close together. If the

components being replaced are carbon steel, consideration should be given to the

use of low-alloy chrome steel for the replacement as it is more resistant to FAC.

The water treatment program should also be reviewed as FAC occurs as a result of

both inappropriate water treatment and high velocities. See Chapter 15, Developing

the optimum cycle chemistry provides the key to reliability for combined cycle/

HRSG plants, for water treatment solutions.

16.3.2 Thermal fatigue

Thermal fatigue or operational stress occurs primarily at the hot end of the HRSG

where thermal growth of components is greatest. It can be the result of improper

restraint of an expanding tube or more commonly the result of inadequate drainage

of superheater and reheater tubes during startup. Water entering the coil from any

source can cause significant damage. Malfunction or improper operation of attem-

perator valves is especially troublesome. Nonuniform distribution of attemperator

spray into a superheater or reheater will fatigue tubes easily. Fig. 16.19 shows

tube-to-header joints that failed as a result of operational stress. Repair involves

Figure 16.19 Sheared tube-to-header joints resulting from operational stress.


replacement of the damaged components, much as with FAC. Tube welders must

again be very capable and certified—even more so than for the previous FAC

example as the high-alloy tubes in a superheater or reheater are more difficult to

weld. Heat treatment of the welds may also be required. If thermal fatigue occurs, a

root cause analysis should be performed to prevent reoccurrence of the problem.

Chapter 10, Mechanical design and Chapter 11, Fast-start and transient operation,

discuss reasons for and solutions to thermal fatigue problems.

16.3.3 Under-deposit corrosion

Under-deposit corrosion occurs in tubes at the hot end of a high-pressure evaporator

where a contaminant concentrates under a deposit on the inner surface of the tube

and corrodes the tube. Repair entails replacement of the failed tubes by certified

welders and access can also be an issue. A root cause analysis of the failure should

be performed and chemical cleaning of the evaporator may be required to remove

deposits from tubes that have not failed. Water treatment is an issue when under-

deposit corrosion occurs. See Chapter 15, Developing the optimum cycle chemistry

provides the key to reliability for combined cycle/HRSG plants, for solutions.

16.3.4 Casing or liner failures

Casing and liner failures are common in HRSGs due to the high velocities and

turbulence in the exhaust from modern combustion turbines but can be greatly

minimized by a good inspection and maintenance program. Repair usually involves

replacing insulation and making sure that the liner covers it securely. If the damage

is near a casing penetration as it often is, the expansion joint or packing gland most

likely will need service also. When repairing liners, care must be taken to ensure

that the liner and those surrounding it remain free to expand. The repairs are usually

performed from the inside of the HRSG but can be performed from the outside

when access from the inside is difficult. Qualified welders are required but they do

not have to be certified to the boiler code.

References

[1] B. Dooley, B. Anderson, Assessment of HRSGs—trends in cycle chemistry and thermal

transient performance, PowerPlant Chem. 11 (3) (2009) 132�151.

[2] IAPWS Document TGD7�16, HRSG high pressure evaporator sampling for internal

deposit identification and determining the need to chemical clean, 2016.






17Other/unique HRSGsVernon L. Eriksen1 and Joseph E. Schroeder2

1Nooter/Eriksen, Inc., Fenton, MO, United States, 2J.E. Schroeder Consulting LLC,

Union, MO, United States

Chapter outline

17.1 Vertical gas flow HRSGS 37917.1.1 Forced circulation 379

17.1.2 Natural and assisted circulation 381

17.1.3 Comparison to a horizontal HRSG 381

17.2 Once-through HRSG 38417.2.1 Serpentine coil OTSG 385

17.2.2 Benson HRSG 386

17.2.3 Supercritical 389

17.3 Enhanced oil recovery HRSGs 39017.3.1 Process design 391

17.3.2 Mechanical design 393

17.3.3 Controls 395

17.4 Very high fired HRSGs 395

References 396

17.1 Vertical gas flow HRSGS

The vertical gas flow, horizontal tube, forced circulation HRSG was used in the

early days of combined cycle development and was very common in Europe, Japan,

and the Middle East into the 1990s. This design evolved first as an assisted circula-

tion and then as a natural circulation design in order to eliminate circulating pumps

and the power consumption and maintenance associated with them. It is now used

primarily in the Middle East, Northern Africa, and parts of Asia. It is also possible

to use vertical gas flow, horizontal tube technology for once-through water/steam

flow. This once-through design will be discussed in Section 17.2.

17.1.1 Forced circulation

A typical vertical gas flow, horizontal tube, forced circulation HRSG with two levels

of steam pressure is shown schematically in Fig. 17.1. Gas that exits the gas turbine



http://dx.doi.org/10.1016/B978-0-08-101940-5.00017-8

horizontally from the left turns upward in the turning duct, flows across the horizon-

tal tubes and exits to the atmosphere from the stack at the top of the unit. Water for

the high-pressure portion of the system enters the first high-pressure economizer at

the top of the unit and flows horizontally through the tubes row by row gradually

progressing downward. This water flows from the exit of the first high-pressure

economizer to the entrance of the second high-pressure economizer and flows

through this economizer in the same way it progressed through the first economizer.

From the outlet of the second economizer the water flows to the high-pressure steam

drum. Circulating pumps deliver water from the steam drum to the inlet at the

bottom of the high-pressure evaporator. Water enters the bottom of the high-pressure

evaporator and flows through the horizontal tubes in much the way it did in the

economizers, only now it flows from bottom to top. The water evaporates as it

FW preheater

LP evaporator

LP superheater

HP economizer

HP evaporator

HP superheater

LP steamdrum

HP steamdrum

Circulationpumps

Figure 17.1 Schematic drawing of a vertical gas flow, horizontal tube forced circulation HRSG.


moves upward, creating a steam/water mixture of increasing quality as it progresses

to the outlet. Note that the water/steam mixture flows through several rows of tubes

in parallel in the evaporator to minimize flow velocities, erosion, and pressure

drop. From the outlet of the high-pressure evaporator the water/steam mixture is

piped to the steam drum where the water and steam are separated. The separated

water mixes with water from the economizer and returns to the evaporator inlet. The

separated dry steam flows to the high-pressure superheater, where it flows through

the superheater in much the same way that water flowed through the economizers.

The low-pressure economizer, evaporator, and superheater function in much the

same way as their high-pressure counterparts, only as a separate system. Each low-

pressure component is located at the proper place in the HRSG to optimize steam

production for both systems.

The horizTontal tubes are supported by vertical tubesheets that are in turn sup-

ported by beams at the top of the HRSG. The tubesheets grow downward as they

heat up during startup of the HRSG. The tubes must slide within the tubesheets to

accommodate longitudinal growth of the tubes as they also expand during startup.

A feedwater preheater, third pressure level, and reheater could be included but

have been omitted to simplify the explanation above.

17.1.2 Natural and assisted circulation

A vertical gas flow, horizontal tube, natural or assisted circulation HRSG is shown

schematically in Fig. 17.2. It looks very much like the forced circulation HRSG

mentioned previously, with the primary difference being the elevation of the steam

drums. Gas flows through the HRSG in the same way as above. Water flows

through the economizers the same way and steam flows through the superheaters

the same way. The water/steam mixture flows through the evaporators in much the

same way as previously mentioned only it now relies on the buoyant forces present

due to the difference in elevation between the steam drum and the evaporator to

generate flow in the evaporators. Since the static liquid head is small, there are usu-

ally more parallel circuits in these evaporators than in a forced circulation unit and

the piping to and from the steam drums is usually larger to minimize pressure drop.

An assisted circulation unit would have pumps to help overcome the pressure drop

on the steam/water side of the evaporator, especially during startup. A true natural

circulation unit would not have these pumps.

Support of the tubes and tubesheets would be the same as for the forced circula-

tion unit.

A feedwater preheater, third pressure level, and reheater could again be included

but have been omitted to simplify the explanation.

17.1.3 Comparison to a horizontal HRSG

17.1.3.1 Thermal performance

Since both the vertical and horizontal HRSG can be custom designed, the steam

flows, superheater and reheater outlet temperatures, fluid side pressure drops, and

381Other/unique HRSGs

FW preheater

LP evaporator

LP superheater

HP economizer

HP evaporator

HP superheater

HP steamdrum

LP steamdrum

Figure 17.2 Schematic drawing of a vertical gas flow, horizontal tube natural (or assisted)

circulation HRSG.


gas side pressure drop can be identical. The only difference in overall performance

would be the power consumed by the circulation pumps if they are present.

The water/steam flow mixture in the horizontal tube evaporator is subject to

stratification if the proper flow regimes are not maintained, which is sometimes a

difficult task when only a small pressure drop is available to drive the flow. It is

also difficult to completely drain the horizontal tubes as they tend to sag between

tube supports. The condensed moisture in horizontal superheater and reheater tubes

can be especially troublesome during startup.

Since the head available to drive the flow in the horizontal tubes in the natural

circulation unit is small, the circulation ratio (ratio of the total flow of water and

steam to the steam flow) will be lower than in a vertical tube unit. The circulation

ratio in the forced circulation unit is also usually lower than it is in the vertical tube

unit in order to reduce power consumption of the circulating pumps.

The circulating pumps in a forced or assisted circulation, horizontal tube unit

can be used to establish circulation quicker than for a natural circulation, horizontal

tube HRSG. Establishment of circulation in a vertical tube HRSG is not an issue,

however, as buoyant forces exist within the tubes, and flow automatically starts as

the tubes are heated.

Vertical tube HRSGs are tolerant of maldistribution in both flow and tempera-

ture in the exhaust gas. Buoyant forces are greatest in vertical tubes where the heat

flux due to maldistribution is highest and compensate for the increased pressure

drop in these tubes. In horizontal tube units, most of the head due to pumps or

drum elevation is outside of the tubes and thus cannot compensate for maldistribu-

tion within the tube bank. In fact, the increased steam generated in circuits with

higher gas flow or temperature increases the pressure drop in these circuits and

decreases the fluid flow. Supplemental firing is therefore more prevalent in horizon-

tal gas flow HRSGs than it is in vertical gas flow HRSGs, especially when firing

temperatures are high.

The water in a vertical tube economizer flows upward at the hot end of the econ-

omizer so any steam bubbles generated there will easily flow upward to the steam

drum. The water flow in the horizontal tube economizer progresses downward as it

flows through the horizontal tubes. Any steam bubbles generated will try to rise

and resist exiting the economizer.

17.1.3.2 Support and flexibility

The vertical tubes in horizontal gas flow HRSGs are supported either from headers

or return bends at their top and are free to grow downward as much as required.

Intermediate supports are light and flexible as they only have to hold tubes in posi-

tion to prevent flow-induced vibration. The horizontal tubes in vertical gas flow

HRSGs must slide within the large vertical tubesheets mentioned in Section 17.1.1

as the tubes heat up. This issue is of most importance in superheaters and reheaters

where tube temperatures are highest and expansion of the tubes is greatest.

The mass of the tube bank in a vertical gas flow HRSG is located higher than

that in a horizontal gas flow HRSG due to the gas turning duct below the vertical


unit. Wind and seismic loads and thus the external structure and foundations for the

vertical gas flow unit are larger than for the horizontal unit.

Horizontal gas flow HRSGs utilize a cold casing as described in Section 3.2.1.

Vertical gas flow HRSGs have either a hot or cold casing depending on the manu-

facturer. The cold casing is far more forgiving during startup and shutdown of the

HRSG as the casing in a hot casing design is in direct contact with the gas flow and

will expand and contract very quickly and oftentimes nonuniformly during these

transient conditions.

Emission reduction catalysts are very large in face area and thin in the direction

of flow. They are much easier to support in a horizontal gas flow HRSG than in a

vertical gas flow HRSG.

17.1.3.3 Space requirements

If the performance of the horizontal HRSG and the vertical HRSG are identical, the

basic bank of tubes, catalysts, etc. is a rectangle of about the same size for both

units. The horizontal gas flow HRSG might be a bit narrower, shorter in height, and

longer in its gas flow direction than the vertical gas flow HRSG but not by much for

large units. In the past when HRSGs were much smaller, the vertical HRSG could

have a somewhat smaller footprint and greater height than the horizontal HRSG. If a

job site has space restrictions that need to be considered, the designer of either type

of unit can usually accommodate them.

17.1.3.4 Installation

Installation of either a large horizontal gas flow or vertical gas flow HRSG is a major

undertaking and many factors must be considered. Comparison of the two is highly

dependent on many factors specific to the site under consideration and it is difficult to

make general conclusions. That said, there are a couple of obvious differences. The

horizontal gas flow HRSG is usually installed by using a large crane to lift the vertical

tube bundles in to the structure and casing assembly. The order of installation of the

bundles is not important. The vertical gas flow HRSG is usually installed by trans-

porting the horizontal tube bundles under the structure, connecting the tubesheets to

the ones above them and jacking the bundles up. A large crane is not required but

bundle installation is dependent on the sequence in which they are delivered to the

site. The vertical unit tends to have heavier structural steel and larger foundations due

to the height of the unit. Whether one method has an advantage over the other is

highly dependent on the site.

17.2 Once-through HRSG

A once-through steam generator or (OTSG) is very similar to a conventional HRSG

except that at least the HP evaporator is designed such that there is no water recir-

culation. Water enters the evaporator section and flows continuously through the


evaporator exiting as superheated steam. Other evaporators such as the IP or LP

evaporators may or may not be once-through designs. Since there is no way to con-

trol steam purity within an OTSG, the feedwater entering the OTSG must be of

equivalent purity necessary to match that of the final steam requirements. The feed-

water in this case will require condensate polishing.

Cycling of OTSGs can be advantageous because of the elimination of thick wall

drums; however, the OTSG does not have the benefit of a reserve of stored water

volume that can be utilized in the event of a boiler feed pump problem. This stored

water allows time for corrective action. An OTSG would have to trip offline in the

event of a pump problem. OTSGs also may not be able to retain pressure during

shutdown so the number of full range pressure cycles increases. Superheaters and

reheaters in OTSGs are similar to those in conventional HRSGs.

There are two main commercial versions of OTSGs for producing steam for a

steam turbine: the serpentine coil design and the Siemens Benson design.

17.2.1 Serpentine coil OTSG

A serpentine coil OTSG is typically a vertical gas flow design where water/steam

flow is countercurrent to the gas turbine exhaust flow as shown schematically in

Fig. 17.3 and in more detail in Fig. 17.4. This design can be a one- or two-pressure

design and has typically been applied to smaller gas turbines (,100 MW). The

design utilizes 800 or 825 series Incoloy tubes such that it can be started up without

flow through the tubes. Incoloy is good for high temperatures and for resistance to

flow-accelerated corrosion. Specific material type varies due to concerns in differ-

ent areas for stress corrosion cracking and other types of corrosion. Run dry opera-

tion will impact the casing design and fin material choice through the entire OTSG

and may not even be possible if NOx catalyst systems are required.

Terminal headers are low-alloy steel and therefore there are dissimilar metal

welds between the tubes and headers. Tubes are supported by support plates. Tube-

to-tube flexibility is good as tubes can move within the support plates. Sagging of

tubes between supports can lead to pooling of water or condensate. As this water

evaporates, dissolved solids can be left behind, creating tube deposits.

Control of a serpentine coil design OTSG is simple once operating in that the

water flow is adjusted to achieve a desired outlet superheat temperature. Control

logic is a feedforward system that must predict the intended feedwater flow. Water

flow distribution is also important so that there is uniformity in temperature of the

flow from each tube flow circuit. To achieve uniform distribution and for flow sta-

bility, each tube circuit may have an inlet orifice. During shutdown, if steam in the

coil can condense, care must be taken to ensure that the condensate is not allowed

to flow into hot steam headers. Chang (Ref. [2]) describes a typical single-pressure

OTSG startup that takes approximately 27 minutes. Gradual introduction of water is

important to prevent hot tubing from thermal quenching, which can result in warped

and bowed tubes. LP system starts would lag the HP system starts. Chang mentions

various failures associated with corrosion, thermal quenching, and plugging of tube

inlet orifices.


17.2.2 Benson HRSG

The Siemens Benson OTSG technology is the most common technology used for

larger gas turbines (.100 MW). Most Benson OTSGs are horizontal gas flow

design although more recently, this has been applied to vertical gas flow configura-

tions. Horizontal coils in vertical gas flow configurations could have greater diffi-

culty achieving flow distribution and stability.

HP water

LP water

LP steam

HP steam

Figure 17.3 Schematic drawing of a small, vertical gas flow once-through HRSG.


The horizontal gas flow Benson technology was first used in the Cottam com-

bined cycle power plant (United Kingdom) in 1999 (Ref. [3]). The horizontal gas

flow Benson concept is shown in cross section in Fig. 17.5 and utilizes a two-pass

evaporator. Water from the economizers enters the bottom of the evaporator first

pass. This water entering the evaporator must be subcooled to avoid any flow issues

related to a steaming economizer. Water in the first pass distributes to all tubes in

the pass and flows upward. Tubes with higher heat input will naturally get more

water flow similar to natural circulation designed evaporators. The quality (mass

flow of steam per unit of total mass flow) of the flow leaving this first pass is

approximately 50%. This two-phase flow is collected by headers and manifolds at

the top of the evaporator section and led by downcomers to the entrance to distribu-

tors located at the bottom of the evaporator. The distributors are designed to dis-

charge a uniform constant quality flow to pipes that lead from the distributor to the

inlet of the second evaporator tube pass. The flow through the second pass flows

upward and ends up exiting somewhat superheated. There will be a row-to-row var-

iation in the superheat temperature due to the decreasing gas temperature as it flows

over each row of tubes. The target combined outlet superheat level must be high

enough to assure superheat conditions leaving each tube row.

At startup, excess water flows through the evaporator until boiling is established.

A two-phase flow separator and surge vessel is located at the outlet of the evaporator.

The unit is initially operated by controlling the feedwater flow (flow control mode)

but once the heat input reaches an adequate level, the control system switches to

superheat temperature control. The horizontal gas flow Benson evaporator configura-

tion is illustrated in Fig. 17.6. A picture of the evaporator lower header and piping

configuration is shown in Fig. 17.7. Tube bends are included at the inlet of the sec-

ond evaporator pass to accommodate tube-to-tube differences in expansion.

Figure 17.4 Small once-through HRSG (Ref. [1]).


The Benson design does not have a thick wall drum but does have separator and

surge vessels. These vessels are smaller in diameter than conventional steam drums

and thus somewhat thinner but still of substantial thickness.

CO

cat

alys

tA

IG g

rid

SC

R c

atal

yst

IP s

uper

heat

er

IP e

vapo

rato

r

LP

sup

erhe

ater

LP

eva

pora

tor

FW

pre

heat

er

IP steamdrum

LP steamdrum

Silencer

Damper

HP steamseparator

Reh

eate

r #

2

HP

sup

erhe

ater

#2

HP

sup

erhe

ater

#1

Reh

eate

r #

1

HP

eva

pora

tor

#2

HP

eva

pora

tor

#1

HP

/IP

eco

nom

izer

#1

HP

eco

nom

izer

#2

Figure 17.5 Schematic drawing of a horizontal gas flow, vertical tube Benson HRSG.

Figure 17.6 Schematic diagram of a Benson high-pressure evaporator (Ref. [4]).


The Benson OTSG control logic is a complex feedforward control system with

various provisions and limitations for the different coil sections and surge vessel.

A completed and operational horizontal gas flow Benson OTSG is shown in

Fig. 17.8.

17.2.3 Supercritical

The critical pressure of water is 3206 psia. Boilers in conventional power plants

have utilized once-through supercritical steam cycles since the mid-1950s. Once-

through designs are more appropriate for supercritical operation because there is no

phase change from water to steam and natural circulation will not occur. The com-

pressed liquid or dense fluid is sensibly heated from the boiler inlet to outlet. Once-

through systems therefore are more conducive to supercritical operation.

Today, large modern gas turbines have enough flow at high temperature to make

a supercritical HRSG design practical. Supercritical steam cycles have a higher effi-

ciency than subcritical cycles. Supercritical steam turbines are very large so multi-

ple large HRSGs would be required to produce enough steam for the smallest

available supercritical steam turbine. A supercritical design must start up and oper-

ate under subcritical conditions. Flow distribution and flow instabilities must also

be considered under all operating conditions. Flow distribution and/or flow instabil-

ity must be analyzed in detail to avoid tube-to-tube temperature differences that

would affect the mechanical integrity of the coils and the design temperature limits

Figure 17.7 Photograph of the lower headers and piping in a Benson high-pressure

evaporator.

Source: Photo courtesy of Nooter/Eriksen, Inc.


of the evaporator. With the exception of the HP evaporator, the balance of coils in

an HRSG would be essentially the same. Lower pressure level evaporator sections

could still be natural circulation design. Since a supercritical design is an OTSG,

there is no need for a steam drum. Some startup separator vessel may be required if

a minimum startup water flow is necessary.

Siemens Benson HRSG Reference List (Ref. [5]) indicates that the highest steam

pressure installation is 175 bara or 2538 psia. Supercritical Benson technology has

been used in numerous conventional boilers. The advantage of using Siemens

Benson technology for supercritical OTSG design would be that the basic Benson

configuration is known to function properly at supercritical conditions.

17.3 Enhanced oil recovery HRSGs

There are a number of techniques available to increase the production of crude oil

over that which can be achieved by primary production methods. These techniques

Figure 17.8 Horizontal gas flow Benson once-through HRSG.

Source: Photo Courtesy of Nooter/Eriksen, Inc.


are generally referred to as enhanced oil recovery (EOR). One of the methods that

is widely used, steam flooding or thermal EOR, involves the injection of a steam/

water mixture into the reservoir.

Steam/water injection increases the recovery of viscous crude oils by heating the

oil and reducing its viscosity, increasing the pressure in the well to force more oil

out, and displacing crude oil with condensate as the steam condenses.

The water that is pumped from a well with the crude oil, referred to as produced

water, is separated from the crude oil, treated, and used as feedwater for the HRSG

in most EOR steam injection projects. Since the produced water may be cycled

through the formation multiple times in an EOR steam injection project, the pro-

duced water builds up a heavy concentration of total dissolved solids (TDS) as it

continues to leach solids out of the formation in each pass through the formation.

HRSGs for EOR cogeneration projects normally operate on produced feedwater

containing TDS ranging from 1500 to 8500 PPM.

To avoid or minimize the deposition of solids on the inner walls of the tubes, it is

necessary to use a steam/water mixture of the appropriate quality in the tubes. The

solids remain in suspension in the water portion of the mixture as the steam portion is

formed, and thus flow through the boilers or HRSG. Operating experience has shown

that it is possible to utilize up to 80�85% quality steam without excessive deposition

of solid material on the tube surfaces. Steam quality of 80% is widely used. In appli-

cations where the level of solids is especially high, lower qualities are used.

The generation of 80% quality steam from feedwater containing high TDS

requires both a proven HRSG design and proper pretreatment of the produced

feedwater.

Even when feedwater quality is maintained in the range listed above, scaling on

the inside of the evaporator tubes can develop over a period of time. This scale is

then removed by using compressed air to force a cleaning device through the tubes

during a shutdown. This cleaning process is referred to as “pigging.” In some

instances chemical cleaning is used. Intervals between shutdowns for cleaning can be

as short as 6 months or as long as 2 years, depending on the condition of the feed-

water, the design of the EOR HRSG, and the way in which the unit is operated.

17.3.1 Process design

EOR HRSGs usually contain a cocurrent flow evaporator followed by a counterflow

economizer as shown schematically in Fig. 17.9. Use of cocurrent flow in the evapo-

rator serves two main purposes. First, the liquid loading in the tubes is highest where

the gas temperature is highest. Second, since the saturation temperature of the

steam/water mixture will drop a few degrees from inlet to outlet, the gas and steam

temperatures at the evaporator outlet will be lower and the steam production will be

higher for the same pinch temperature difference than if counterflow was used. The

first couple of rows of tubes in the evaporator often serve as economizer surface as

the water entering them has not reached saturation. Subcooled boiling may even

take place in them.


Proven HRSG designs ensure that the liquid and vapor are maintained in inti-

mate contact throughout the HRSG evaporator coil, and that phase separation is

avoided. The HRSG evaporator coils must also be designed to maintain the steam/

water mixture in the proper flow regime as described in a later section of this paper.

By proper pretreatment of the feedwater and correct HRSG coil design, HRSGs

have operated for many years without experiencing significant coil fouling or

corrosion.

Since the consequences (tube overheating and failure) of a buildup of scale on

the inner surface of a tube are disastrous, good fluid side flow distribution is a

must. If the flow distribution is poor, some tubes will have quality higher than 85%

and the buildup of scale will occur. Several complementary techniques can be used

to ensure that the fluid side flow distribution is good.

First, the fluid flow is split into a number of parallel circuits that are not inter-

rupted throughout the entire HRSG (both economizer and evaporator). The outlet of

each circuit contains the same fluid and mass flow that entered the circuit at the

inlet. The only difference is the quality of the mixture: water at the inlet of the cir-

cuit and a steam/water mixture of the desired quality at the outlet. There are no

headers or other devices between the inlet and outlet where the flows from adjacent

circuits could intermingle and then not separate uniformly.

Second, a very high fluid side pressure drop is utilized to assist the control

valves in maintaining uniform flow to each circuit and to promote high, uniform

EconomizerEvaporator

Steam/wateroutlet

Waterinlet

Gas

inle

t

Gas

outl

et

Figure 17.9 Schematic drawing of a typical evaporator and economizer arrangement for

EOR HRSG (plan view).


heat transfer from the tubes to the two phase mixture in the evaporator. Total pres-

sure drop across the HRSG is often 200 psi or greater. A substantial portion of this

pressure drop (B50 psi) should take place in the economizer.

Several other factors influence the tube wall temperature (and thus the potential

for overheating and failure):

First, strong fluid velocities are required inside the tubes to provide good cooling of the

tube walls. Since the density of the fluid changes so much from the inlet to the outlet of

the unit, it is often necessary to change the diameter of the tubes somewhere in the unit.

Second, it is preferred that the flow inside the evaporator tubes be maintained in a flow

regime that will provide adequate, uniform cooling around the periphery of the tube.

Third, the heat flux must be kept to a level such that either the tube will not dry out at the

top or that the impact of a small amount of dryout will be minimized.

From the standpoint of heat transfer and pressure drop selection, there are two

major flow regimes: gravity-controlled flow and shear-controlled flow. Various flow

patterns can be grouped into one of these two major regimes as shown in Fig. 17.10.

Charts such as the Taitel & Dunkler chart, the Baker diagram (Refs. [6,7]) or the

Heat Transfer Research, Inc. (HTRI) generalized flow regime map (Ref. [8]), for

those who have access to HTRI documents, can be used to determine the flow

regime and flow pattern at any point in a tube.

It is necessary to maintain the steam/water flow in the shear-controlled flow

regime in as much of the HRSG as possible, especially in areas where strong cool-

ing of the tubes is required.

Special care must be taken in the design of the evaporator at the gas inlet, espe-

cially if a duct burner is used. If the water temperature has not reached saturation

yet, fluid velocities are low, subcooled boiling is probably occurring and even when

saturation is reached, the fluid flow will be in the gravity-controlled regime.

Reduction of the heat flux to levels appropriate for the flow regime in this area will

minimize the chances of tube burnout. It is also necessary to account for radiation

in this area as radiation can increase the heat flux substantially.

17.3.2 Mechanical design

The mechanical design of an EOR HRSG is not much different from that of a hori-

zontal tube superheater or economizer used in a power boiler, HRSG, or waste heat

boiler.

Both conventional fired EOR units and EOR HRSGs have traditionally used

schedule pipe rather than boiler tubing. This is due to several factors, mostly related

to the availability of replacement pipe and return bends in remote locations.

The use of standard return bends is a substantial benefit to the end user.

The horizontal tubes are supported by tubesheets. Tubesheet spacing is

determined to maintain reasonable tube deflection and prevent tube vibration,

much as for a conventional HRSG. Tubesheet material is selected based on gas

temperature.


At high gas temperatures, water-cooled tube supports are used. These tubesheets

maintain the structural integrity required and minimize differential thermal expan-

sion between the tube coils and tubesheets.

Since gas temperatures are similar to those used in a conventional HRSG, a cold

casing design is used.

Bubbly flow

Annular flow

Annular flow with mist

Slug flow

Wavy flow

Stratified flow

Plug flow

Figure 17.10 Two phase flow patterns in horizontal flow.


17.3.3 Controls

Each circuit of the EOR HRSG should have a control valve at the economizer inlet.

Quality of the steam/water mixture can then be measured at the outlet of each circuit

and the control valve can be modulated to maintain the desired steam quality.

17.4 Very high fired HRSGs

When more steam than the exhaust gas from the gas turbine can supply is required,

burners are included within the HRSG to increase its output. The temperature leav-

ing the burner is usually limited to approximately 1650�F to avoid damage to the

interior walls of the HRSG. Occasionally, far more output is required and, in these

instances, water-cooled walls are provided around the combustion chamber with the

first few rows of tubes as bare tubes to form a furnace. As for conventional HRSGs

with supplemental firing, combustion is very efficient as the combustion air is pre-

heated. The limit for output of the boiler is the amount of firing that the oxygen

present in the turbine exhaust will support.

Due to the relatively high combustion temperature (high at least for a HRSG) and

steam flow, the economizer recovers a substantial amount of heat and additional pres-

sure levels are not justified. The HRSGs are usually only single pressure level systems.

Fig. 17.11 shows a HRSG with a water cooled furnace at its inlet. Exhaust from

the small gas turbine enters the burner windbox and flows through the throat of the

Radiantevaporator

Steam drum

Steam out

Convectiveevaporator

Economizer

Figure 17.11 Schematic drawing of a small very high fired HRSG.


register-type burner. A small amount of exhaust bypasses the burner as it is not

needed for combustion.

It may be possible to use a modified package boiler design for these applications.

In larger applications a traditional fired boiler design can be used. In fact, many of

these applications resemble a conventional boiler that utilizes a small gas turbine as

a combined forced draft fan and air preheater. When this technique is applied to an

existing boiler, it is often referred to as hot windbox repowering.

References

[1] Landon Tessmer, Once through steam generators design, operation, and maintenance

considerations, McIlvaine Company Hot Topic Hour, March 7, 2013, http://www.mcil-

vainecompany.com/Universal_Power/Subscriber/PowerDescriptionLinks/Landon%

20Tessmer,%20Innovative%20Steam%20Technologies%20(IST)%20-%203-7-13.pdf.

[2] W.K. Chang, Once-through steam generator high nickel alloy tube damage experiences,

in: EPRI Boiler Tube Failure Conference, Baltimore, MD, April, 2010.

[3] A.G. Siemens, BENSON once-through heat recovery steam generator, 2006.

[4] J. Bruchner, G. Schlund, Pego experience confirms Benson as proven HRSG technology,

Mod. Power Syst. (June 2011) 21�24.

[5] Siemens, Benson HRSG Boilers, http://www.energy.siemens.com/us/pool/hq/power-

generation/power-plants/steam-power-plant-solutions/benson%20boiler/BENSON_HRSG_

Reference_List_20160614.pdf.

[6] J.R. Thome, Two phase flow patterns, Chapter 12, Engineering Data Book III,

Wolverine Tube, Inc., Decatur, AL, 2007.

[7] G. Hewitt, Annular Two Phase Flow, Elsevier, 2013.

[8] HTRI Design Manual B6.2, Flow Regimes, April 2008, p. B6.2-3.


http://www.mcilvainecompany.com/Universal_Power/Subscriber/PowerDescriptionLinks/Landon%20Tessmer,%20Innovative%20Steam%20Technologies%20






http://www.energy.siemens.com/us/pool/hq/power-generation/power-plants/steam-power-plant-solutions/benson%20boiler/BENSON_HRSG_Reference_List_20160614.pdf





Index

Note: Page numbers followed by “f ” and “t” refer to figures and tables, respectively.

A

Acid phosphate corrosion (APC), 325, 334

Acoustic resonance, 63

Acoustics, 258�260

attenuation methods, 259�260

casing radiated noise, 259

stack radiated noise, 259

Air heating, 117

Air pollution, 145

Air Pollution Control Act, 147�148

Air-cooled condensers (ACCs), 321

flow-accelerated corrosion in, 328�331

Alarms, 301, 302t

All-volatile treatment

oxidizing, 323

reducing, 323

Ambient air firing, 124�125

Ambient temperature, 289�290

American Boiler Manufacturers Association

(ABMA), 248�249

American Institute of Steel Construction

(AISC), 200

American Society for Testing and Materials

(ASTM), 226

American Society of Civil Engineering

(ASCE), 200

American Society of Mechanical Engineers

(ASME), 200

ASME code, 295�296, 298

Ammonia injection grid (AIG), 157, 368

Ammonia oxidation, 158

Ammonia salt buildup on finned tubes, 370f

Ancillary equipment, 253

equipment access, 261

external access, 261

internal access, 261

exhaust gas path components, 253�260

acoustics. See Acoustics

combustion turbine exhaust

characteristics, 253�254, 254f

exhaust flow conditioning, 255�256

exhaust flow control dampers and

diverters. See Exhaust flow control

dampers and diverters

inlet duct configuration and mechanical

design requirements, 254

outlet duct and stack configuration and

mechanical design requirements,

256�257

water/steam side components, 260�261

deaerator, 260�261

feedwater pumps, 260

ANSI B31.1 and B31.3, 144

Atomic absorption (AA), 194t

Attenuation methods, 259�260

Augmenting air, 123f, 125�126

Automatic pressure control/control valve

bypass, 317�318, 318f

Automatic recirculation (ARC) valve, 260

Automatic relief valve(s), 317

Automatic startup, general comments for, 299

Auxiliary equipment, 215

Auxiliary heat input, 290�291

Auxiliary systems, 285

B

Baffle type separator, 73

Baker diagram, 391

Base load, 291�292

vs fast startup and/or high cycling,

109�110

Benson HRSG, 11, 13f, 384�387

Biofuels, use of, 196

Bowed/distorted tubes, 367f

Brayton cycle and Rankine cycle,

combining, 18�21

Bundle support types, 104

Buoyant forces, 381

Bypass system, 306, 317

Bypass valve, 309�311

C

Carbon monoxide, 134�135

Carbon monoxide catalyst systems, 285

Carbon monoxide oxidizers, 173

catalyst, 167, 368

design, 183�188

choosing the catalyst, 184�186

defining the problem, 183�184

determining the catalyst volume,

186�187

system considerations, 187�188

future trends, 196

operation and maintenance, 188�196

catalyst characterization, 194�195

catalyst deactivation mechanisms,

191�193

data analysis, 189�191

initial commissioning, 188

reclaim, 195�196

stable operation, 188�189

oxidation catalyst, 179�182

active material, 179�180

carrier, 180�181

putting it all together, 182

substrate, 181�182

oxidation catalyst fundamentals, 174�179

activity and selectivity, 174�176

catalytic reaction pathway, 176�177

effect of the rate limiting step,

177�179

Carbon monoxide�volatile organics

oxidation (CO/VOC) catalyst, 157

Carbon steel grade SA-516 Gr. 70, 78

Carnot cycle, 29, 30f

heat transfer in, 29

Casing, 356, 357f, 375

Casing radiated noise, 259

Catalyst and tunnel analogy, 175f

Catalyst characterization tools, 194t

Catalyst design, 182�183

Catalyst materials and construction,

150�153

Catalyst poisoning, 192, 192f

Caustic treatment (CT), 326

Ceramic catalyst, 194

C-frame modularization, 273�274, 273f,

274f

Challenging the status quo, 339

Circulating boiler, use of, 6

Circulating pumps, 377�379, 381

Circulation ratio, 68

Clean Air Act Amendments of 1990

(CAAA), 149

Clean Air Act in 1963, 147

Clean Air Act of 1970, 147

CO catalyst. See Carbon monoxide oxidizers

Coal-fired power plants, 40

Cogeneration, 35�38, 116

Coil bundle modularization, 266�276


274f

goalpost-style modularization, 272�273

harp construction, 266�268

modular or bundle construction, 268�271

O-frame (shop modular) construction,

275, 275f

super modules and offsite erection,

275�276

Coil flexibility, 210�213

comparisons, 211f

Coil modules, 268�272

Coils in the low-temperature region of the

HRSG, 368�369

Cold casing construction, 61�62, 62f

Cold inspection and maintenance,

359�373

coils in the low-temperature region of the

HRSG, 368�369

distribution grid, 360�363

duct burner, 363�365

emissions control equipment, 368

evaporator coils, 367�368

heating surfaces/HRSG coils, 365�366

HP superheater and reheater coils,

366�367

inlet duct, 360

internal steam drum inspection, 369�372

HP steam drum, 371�372

IP steam drum, 371

LP steam drum, 371

severe service valves, 372�373

stack, 372

Combined cycle (CC), 117, 299

design, HRSGs in, 22�34

decisions affecting heat recovery,

31�34

pressure levels, 23�29, 26f

reheat, 28f, 29�31

398 Index

Combined cycle cogeneration plant, 35�36

with a reheat HRSG, 38f

with three pressure HRSG and condensing

steam turbine, 37f

with two pressure HRSG and

backpressure steam turbine, 37f

Combined cycle plants, 1, 3f, 22f

Combustion air and turbine exhaust gas,

122�127

ambient air firing, 124�125

augmenting air, 125�126

equipment configuration and TEG/

combustion airflow straightening,

126�127

temperature and composition, 122

turbine power augmentation, 122�123

velocity and distribution, 123�124

Combustion air blower inlet preheaters,

117

Combustion chamber, 174, 187

Combustion turbine (CT), 287�288

CT fuel, 291

CT load, 290

CT ramp rate, 293�294

Combustion turbine exhaust characteristics,

253�254, 254f

Computational fluid dynamic (CFD)

modeling, 127�131, 256

wing geometry, 128�131

basic flame holder, 129

flame holders, 128�129

low-emissions design, 129�131

Condensate and feedwater cycle chemistry

treatments, 323�324

all-volatile treatment

oxidizing, 323

reducing, 323

film forming products (FFP), 324

oxygenated treatment (OT), 324

Condensate detection, 308f

Condensate detection/removal,

307�308

Condensate management, 215

Condensate pump discharge (CPD),

328�329

Conductivity after cation exchange (CACE),

322

Congruent phosphate treatment (CPT),

325

Construction, of HRSG, 263, 265f

auxiliary systems, 285

coil bundle modularization, 266�276

C-frame modularization, 273�274,

273f, 274f

goalpost-style modularization,

272�273


modular or bundle construction,

268�271


275, 275f


275�276

construction considerations for valves and

instrumentation, 284�285

details, 243

direct labor, 263�264

exhaust stacks, 281�282

future trends, 285�286

indirect labor, 264

inlet ducts, 278�281

modularization, 277t

levels of, 264�265

piping systems, 282�283

platforms and secondary structures, 284

structural frame, 276�278

Consumption of energy, 17

Contaminant ingress, 339

Continuous blowdown (CBD), 314�316

and intermittent blowoff systems, 76

Continuous emission monitoring (CEM),

153, 256

Continuous online cycle chemistry

instrumentation, 339

Controls, 301�318

condensate detection/removal, 307�308

deaerator inlet temperature, 314, 315f

drum blowdown/blowoff, 314�316

continuous blowdown, 315�316

intermittent blowoff (IBO), 316

drum level control, 301�303

single-element control (SEC), 301�302

three-element control, 303

feedwater preheater inlet temperature,

308�311

bypass valve, 309�311

heat exchanger, 311

recirculation pumps, 309

399Index

Controls (Continued)

pressure control, 316�318

automatic relief valve(s), 317

control valve bypass, 317�318, 318f

startup vent/steam turbine bypass,

311�313, 313f

steam temperature control, 304�306

bypass system, 306

final stage attemperator, 305�306

interstage attemperator, 306

Coordinated PT, 325

Corrosion, 244, 244f

fatigue, 88

products, 338

Creep, 244�245

strength, 208

Custom design, 81�83

full circuit, 82

half circuit, 83

Custom designed economizer, 81

full-circuit arrangement, 82f

half-circuit arrangement, 83f

Cycle chemistry-influenced damage/failure

mechanisms, 326�336

allowing repeat cycle chemistry situations,

345

combined cycle/HRSG steam purity

limits, 333

cycle chemistry guidelines and manual for

the combined cycle plant, 345

deposition of corrosion products in the HP

evaporator, 344

ensure the combined cycle plant has the

required instrumentation, 345

failure/damage mechanisms in HRSGs,

334

first address FAC, 343�344

flow-accelerated corrosion

in air-cooled condensers, 328�331

in combined cycle/HRSG plants,

327

in combined cycle/HRSGs, 327�328

HRSG HP evaporators, deposition in,

334�336

steam purity for startup, 333�334

steam turbine phase transition zone

failure/damage, 331�333

transport of corrosion products, 344

unit shutdown limits, 334

Cycling, 250�252, 300

draining of condensate, 250�251

scope items for, 249

stress monitors, 251

valve wear, 251�252

water chemistry, 251

Cyclone type separator, 73

D

Daily walkdown of equipment, 359

Damaged liner system due to overheating,

364f

Damper actuation, 258

Damper seal air systems, 258

Dead loads, 215�216

Deaerators, 78�79, 260�261

inlet temperature, 314, 315f

integral floating pressure deaerator, 79

remote deaerator, 79

Density wave instability, 60�61

Deposition in HRSG HP evaporators,

334�336

Deposits in conventional boilers/evaporators,

338

Design code, 200, 202, 217, 228�229

Desuperheater, spraywater, 106�107

Dew point monitoring, 93�94

DHACI (Dooley Howell ACC Corrosion

Index), 330�331, 331f, 332f

Diesel particulate filter (DPF), 151

Direct labor, 263�264

Distributed control system (DCS), 292

Distribution grid, 360�363

Distribution grid fixed support, 362f

Distribution grid floor guide, 362f

Distribution grid sidewall restraints,

363f

Diverter damper, 257

Drainability and automation, 110

Drum blowdown/blowoff, 314�316

continuous blowdown, 315�316

intermittent blowoff (IBO), 316

Drum carryover, 338

Drum internals, 73�75

primary separator, 73

secondary separator, 74�75

Drum level control, 301�303, 304f

single-element control (SEC), 301�302


400 Index

Drum thickness, 243

Drum water levels and volumes, 72�73

high high water level (HHWL), 72

high water level (HWL), 72

low low water level (LLWL) trip, 72�73

low water level (LWL), 72

normal water level (NWL), 72

Duct burners, 115, 285, 355�356, 356f,

363�365

applications, 116�118

air heating, 117

cogeneration, 116

combined cycle, 117

fume incineration, 118

stack gas reheat, 118

combustion air and turbine exhaust gas,

122�127

ambient air firing, 124�125

augmenting air, 125�126

equipment configuration and TEG/

combustion airflow straightening,

126�127

temperature and composition, 122

turbine power augmentation, 122�123

velocity and distribution, 123�124

design guidelines and codes, 143�144

ANSI B31.1 and B31.3, 144

Factory Mutual, 143

NFPA 8506, 143

Underwriters’ Laboratories,

143�144

distorted lower burner runners, 364f

drilled pipe duct burner, 130f

emissions, 131�138

CO, UBHC, SOx, and particulates,

134�138

NOx and NO versus NO2, 132�134

visible plumes, 132

fuels, 121�122

natural gas, 121�122

grid configuration, 118�121

in-duct or inline configuration, 118

maintenance, 138�142

accessories, 138�142

burner management system, 138�139

fuel train, 139�142, 139f, 140f

physical modeling, 127�131, 128f

CFD modeling, 127�131

Duct firing. See Supplementary firing

E

Economizers, 32, 48, 81

custom design, 81�83

full circuit, 82

half circuit, 83

feedwater heaters, 89�94

arrangements, 89�93

concerns, 89

dew point monitoring, 93�94

flow distribution, 84�86

mechanical details, 86�88

corrosion fatigue, 88

steaming, 87�88

tube orientation, 86�87

venting, 87

standard design, 83�84

full circuit, 83�84

half circuit, 84

Elastic/plastic behavior, 206�207

Electron microprobe analysis (EPMA), 194t

Emission reduction catalysts, 382

Emission regulations, 149

Emissions, 2, 131�138

carbon monoxide, 134�135

NOx and NO versus NO2, 132�134

particulate matter, 136�138

sulfur dioxide, 136

unburned hydrocarbons (UHCs), 135�136

visible plumes, 132

Emissions control equipment, 368

EN 12952�3 method, 243

Energy balance, 46�47

Engineering, procurement, and construction

(EPC) contractor, 201, 299

Engineering, procurement, and construction

(EPC) firm, 264�265

Enhanced oil recovery HRSGs, 388�393

controls, 393

design, 11�12

mechanical design, 391�392

process design, 389�391

Environmental Protection Agency (EPA),

147�148

Environmental regulations, 174

Equilibrium phosphate treatment (EPT), 325

Equipment access, 261

external access, 261

internal access, 261

Evaporator coils, 367�368

401Index

Evaporator designs, 59, 66�71

flow accelerated corrosion (FAC), 68�71

heat transfer/heat flux, 66�67

natural circulation and circulation ratio,

68

Exhaust flow conditioning, 255�256

Exhaust flow control dampers and diverters,

257�258

damper actuation, 258

damper seal air systems, 258

flow diverter dampers, 257�258

isolation dampers, 257

Exhaust gas path components, 253�260

acoustics, 258�260

attenuation methods, 259�260

casing radiated noise, 259

stack radiated noise, 259

exhaust flow control dampers and

diverters, 257�258

damper actuation, 258

damper seal air systems, 258

flow diverter dampers, 257�258

isolation dampers, 257

HRSG inlet duct design and combustion

turbine exhaust flow conditioning,

253�256

combustion turbine exhaust

characteristics, 253�254, 254f

exhaust flow conditioning, 255�256

inlet duct configuration and mechanical

design requirements, 254

outlet duct and stack configuration and


256�257

Exhaust stacks, 281�282

Exposed insulation at liner system, 360, 361f

External access, of equipment, 261

External heat exchanger, 90�91

F

Fabrication, 228�229

Factory Mutual (FM), 143

Failure/damage mechanisms in HRSGs, 334

Fast start cycles, multiple drum designs for,

78

Fast-start and transient operation, 231

change in temperature, 234�240

components most affected, 233

construction details, 243

corrosion, 244, 244f

creep, 244�245

effect of pressure, 233�234

HRSG operation, 245�248

layup, 248

load changes, 247�248

shutdown and trips, 247

startup, 246�247

life assessments, 248�249

fast start, 249

methods, 248�249

responsibilities, 249

scope items for cycling, 249

materials, 241�242

miscellaneous cycling considerations,

250�252

draining of condensate, 250�251

stress monitors, 251

valve wear, 251�252

water chemistry, 251

National Fire Protection Association

(NFPA), 250

Feedwater control valve, 87�88

Feedwater flow distribution, 85

Feedwater heaters, 89�94


alternative external heat exchanger, 92f

basic feedwater heater, 89, 90f

benefits, 91

external heat exchanger, 90�91

high-efficiency feedwater heater,

92�93, 93f

water recirculation, 89�90

concerns, 89

dew point monitoring, 93�94

Feedwater preheater inlet temperature,

308�311

bypass valve, 309�311

heat exchanger, 311

recirculation pumps (with bypass), 309

Feedwater pumps, 260

Feedwater recirculation, 215

Feedwater velocities, 83�84

Field erection and constructability, 228

Film forming amine product, 322�323

Film forming product (FFP), 322�324

Fin material selection, 112�113

Final stage attemperator, 305�306

Finned tubes, 54�55, 55f

402 Index

ammonia salt buildup on, 370f

sulfur buildup on, 370f

Firetube heat recovery boiler, 4

Flame impingement, liner damage from,

365f

Flow arrangements, 99f

Flow distribution, 84�86, 110�112

gas side, 111�112

steam side, 110�111

Flow diverter dampers, 257�258

Flow velocity (turbulence), 70

Flow-accelerated corrosion (FAC), 68�71,

85, 320�321, 328f, 369f, 374

in air-cooled condensers, 328�331

in combined cycle/HRSG plants, 327

in combined cycle/HRSGs, 327�328

Fluid temperature, 70

Fluidized bed boilers, 117

Fluidized bed startup duct burner, 117f

Forced circulation, 7�8, 377�379

Fossil fuels, 116

Fuel-bound nitrogen NOx, 133

Full load exhaust gas temperatures,

evolution of, 24f

Fume incineration, 118

G

Gas firing, 118�119

Gas flow HRSGs

horizontal. See Horizontal gas flow

HRSGs

vertical. See Vertical gas flow HRSGS

Gas fuel train, 140f

Gas ports, 138

Gas turbine combined cycle systems

(GTCCs), 150�152, 164

Gas turbine exhaust, 246�247

Gas turbine�based power plants, 1�4

advantages, 1�2

history, 2�3

outlook, 3�4

Goalpost-style modularization,

272�273

Grid burners, 120f, 123�124

H

Harp construction, 266�268

Hazardous air pollutant (HAP), 184

Headers, 200

Heat exchanger design, 54�61

evaporation and circulation, 58�59

finned tubing, 54�55

instability, 59�61

pressure drop, 54

tube arrangement, 55

two-phase flow, 55�58

Heat recovery boiler, 4

Heat recovery steam generator (HRSG),

1�14

characteristics, 5�6

in power plant, 4�5

types, 6�14

Benson design, 11, 13f

enhanced oil recovery design, 11�12

horizontal gas flow, vertical tube,

natural circulation design, 7, 7f

large once-through design, 11, 12f

small once-through design, 10�11, 10f

vertical gas flow, horizontal tube,

forced circulation design, 7�8, 8f

vertical gas flow, horizontal tube,

natural circulation design, 8�10, 9f

very high fired design, 12�14, 14f

Heat Transfer Research, Inc. (HTRI), 391

Heat transfer/heat flux, 66�67

Heating surfaces/HRSG coils, 365�366

Henry’s law of partial pressures, 79,

260�261, 314

High-energy piping and support system,

358�359

High-pressure superheaters and reheaters,

97, 112�113

Homogeneous flow, 57

Honeycombs, 181

Hooke’s law, 206�207

Horizontal gas flow HRSGs, 382

Horizontal tube economizers, 86�87

Hot inspection, of HRSG, 354�359

casing, 356, 357f

casing penetration seals, 356�357, 358f

duct burner, 355�356, 356f

high-energy piping and support system,

358�359

inlet duct, 355

inlet expansion joint, 354�355


HP superheater and reheater coils, 32,

366�367

403Index

Hybrid power augmentation (PAG) cycle,

39�40, 40f

I

Independent power producers (IPPs), 2�3

Indirect labor, 264

Inductively coupled plasma electron

spectrometry (ICP), 194t

Inlet chillers/foggers, 291

Inlet duct, 278�281, 355, 360

burner in, 103

configuration, 254

Inlet expansion joint, 354�355

Inline burner, 118, 119f

Insertion type desuperheater, 106f

Inspection and maintenance, of HRSG,

353�373

cold inspection and maintenance,

359�373

coils in the low-temperature region of

the HRSG, 368�369

distribution grid, 360�363

duct burner, 356f, 363�365

emissions control equipment, 368

evaporator coils, 367�368

heating surfaces/HRSG coils, 365�366

HP superheater and reheater coils,

366�367

inlet duct, 360

internal steam drum inspection,

369�372

severe service valves, 372�373

stack, 372

daily walkdown of equipment, 359

hot inspection, 354�359

casing, 356, 357f

casing penetration seals, 356�357, 358f

duct burner, 355�356, 356f

high-energy piping and support system,

358�359

inlet duct, 355

inlet expansion joint, 354�355

Integral drum style evaporator, 69f

Integral floating pressure deaerator, 79

Integrated gasification combined cycle

(IGCC), 34�35, 40�41, 41f

Interconnecting piping, 211, 212f

Intermittent blowoff (IBO), 76, 314, 316

Internal access, of equipment, 261

Internal steam drum inspection, 369�372


IP steam drum, 371

LP steam drum, 371

International Association for the Properties

of Water and Steam (IAPWS), 324,

335f, 348

Interstage attemperator, 306

Interstage spraywater desuperheater,

106�107

IP steam drum, 371

Isolation dampers, 257

J

Jobsites, 265, 269�270, 278

K

Kyoto Protocol of 1998, 147

L

Larson�Miller curve, 244�245, 245f

Lateral force-resisting system, 222�224,

223f

Layup, of HRSG, 248

Lead/lag unit, 297�299

Ledinegg instability, 59�60

Life assessments, 232, 248�249

cycling, scope items for, 249

fast start, 249

methods, 248�249

responsibilities, 249

Ligament reduction factor variables, 206f

Linear burner elements, 118�121, 120f

Linear burners, 116, 118�121, 120f

Liner failures, 375

Liner system, 280�281, 355

damaged liner system due to overheating,

364f

exposed insulation at, 360, 361f

Liquid firing, 119�121

Liquid fuels, 118�122

Live loads, 216

Load changes, of HRSG, 247�248

Logistics, 265

Long-chain hydrocarbons, 135

Longitudinal force-resisting system, 221,

224

Louver dampers, 257

Low-cycle fatigue, 210�213, 232

404 Index

Lower heating value (LHV), 23

Low-pressure economizer, 34

Low-pressure evaporator, 79

Low-pressure steam drum, 371

Low-pressure steam turbine, 332

M

Main oil fuel train, 141f, 142f

Main steam temperature control, 304, 307f

Materials, 241�242

alumina materials, 180

carbon steel material, 70�71

catalyst materials, 150�153, 158�159,

164, 179�180

fin material, 112�113

higher-strength materials, 78

selection, 202�203, 226

transitions, 213�214

tubesheet material, 391

Mechanical design, of HRSG, 61�63, 199

allowable design stress, 206�209

code of design

mechanical, 200�201

structural, 201

fabrication, 228�229

field erection and constructability, 228

general information, 204

internal “hoop” stress, 204�205

nonpressure parts, 61�62

owner’s specifications and regulatory

body/organizational review,

201�202

piping and support solutions, 226�227

pressure parts, 62, 202�204

design methods, 202

design parameters, 202

material selection, 202�203

mechanical component geometries and


pressure parts design flexibility, 209�215

auxiliary equipment, 215

coil flexibility, 210�213

condensate management, 215

feedwater recirculation, 215

general information, 209�210

material transitions, 213�214

preventing quenching, 214

reinforced openings, 205�206

requirements, 254

structural components, 215�221

dead loads, 215�216

live loads, 216

operating loads, 221

seismic loads, 217�221

wind loads, 216�217

structural solutions, 221�226

anchorage, 224�226

design philosophy, 221, 222f

lateral force-resisting system, 222�224,

223f

longitudinal force-resisting system, 224

material selection, 226

tube vibration and acoustic resonance,

62�63

Mechanical details, 86�88

corrosion fatigue, 88

steaming, 87�88

tube orientation, 86�87

venting, 87

Medium-pressure (MP) process steam

header, 36, 38

Mesh pads, 74�75, 372, 373f

secondary separator with, 372f

Metal composition, 70�71

Modular or bundle construction, 268�271

Modularization, coil bundle, 266�276


274f

goalpost-style modularization, 272�273


modular or bundle construction,

268�271


275, 275f


275�276

Modularization, levels of, 264�265

Multiple drum evaporator designs for fast

start cycles, 78

Multiple pressure systems, 53

N

National Ambient Air Quality Standards

(NAAQS), 149, 184

National Board Inspection Code (NBIC),

373

National Emissions Standards for Hazardous

Air Pollutants (NESHAP), 184

405Index

National Fire Protection Association

(NFPA), 250

Natural and assisted circulation, 379

Natural circulation and circulation ratio, 68

Natural circulation design, 377, 387�388

Natural circulation evaporator designs,

65�66

Natural circulation HRSGs, 58

Natural gas (NG), 121�122, 155�156

liquid fuels, 122

low heating value, 121�122

refinery/chemical plant fuels, 121

NFPA 8506, 143

Nitric oxide

ammonia oxidation to, 158

Nitrogen oxides

formation mechanisms in gas turbines,

152�153

reaction chemistry, 147f

reduction of, 145�146

NO to NO2 conversion, 186

Nonpressure parts, 61�62, 366

Nonreheat steam turbine configurations, 27f

O

Octadecylamine (ODA), 324

O-frame (shop modular) construction, 275,

275f

Oklahoma Gas & Electric’s Belle Isle

Station, 22

Oleylamine (OLA), 324

Oleylpropylendiamine (OLDA), 324

Once-through steam generator (OTSG),

382�388, 385f

Benson HRSG, 384�387

serpentine coil OTSG, 383

supercritical, 387�388

Open cycle gas turbine generator, 19f

Operating loads, 221

Operation, of HRSG, 245�248, 288�301

alarms, 301, 302t

base load, 291�292

cycling, 300

layup, 248

load changes, 247�248

part load/shut down, 299�300

plant influences, 288�291

ambient temperature, 289�290

auxiliary heat input, 290�291

balance of plant operating pressure, 290

combustion turbine load, 290

CT fuel (natural gas or fuel oil), 291

inlet chillers/foggers, 291

shutdown and trips, 247

startup, 246�247, 293�299


general comments for automatic startup,

299

lead/lag, 297�299

startup type, 294�295

steam temperature (interstage/final),

296�297

superheater/reheater drain(s),

295�296

Operator-defined power load, 292

Optimum cycle chemistry, developing, 319

case studies, 340�343

damage/failure in PTZ of steam turbine

in combined cycle/HRSG plants,

341�342

under-deposit corrosion—hydrogen

damage, 342�343

understanding deposits in HRSG HP

evaporators, 343

for combined cycle/HRSG plants,

343�345

allowing repeat cycle chemistry

situations, 345

cycle chemistry guidelines and manual

for combined cycle plant, 345

deposition of corrosion products in the

HP evaporator, 344

ensuring the combined cycle plant has

the required instrumentation, 345

first address FAC, 343�344

transport of corrosion products, 344

condensate and feedwater cycle chemistry


all-volatile treatment (oxidizing), 323

all-volatile treatment (reducing), 323

film forming products (FFP), 324

oxygenated treatment (OT), 324

cycle chemistry-influenced damage/failure

mechanisms, 326�336

combined cycle/HRSG steam purity

limits, 333

failure/damage mechanisms in HRSGs,

334

406 Index

flow-accelerated corrosion in air-cooled

condensers, 328�331

flow-accelerated corrosion in combined

cycle/HRSG plants, 327

flow-accelerated corrosion in combined

cycle/HRSGs, 327�328

HRSG HP evaporators, deposition in,

334�336

steam purity for startup, 333�334

steam turbine phase transition zone

failure/damage, 331�333

unit shutdown limits, 334

HRSG evaporator cycle chemistry


caustic treatment (CT), 326

phosphate treatment, 325�326

repeat cycle chemistry situations (RCCS),

development of, 337�340

challenging the status quo, 339

contaminant ingress, 339

continuous online cycle chemistry


conventional boiler/evaporator deposits,

338

corrosion products, 338

drum carryover, 338

shutdown/layup protection, 339

Oscillating pressures, 62�63

Outlet duct and stack configuration and


256�257

Overhead, 264

Overheating

damaged liner system due to, 364f

damaged vibration supports due to,

365f

Overstrength factors, 220

Oxidation catalyst, 174�182, 188�189,

191

active material, 179�180

activity and selectivity, 174�176

carrier, 180�181

catalytic reaction pathway, 176�177

effect of the rate limiting step, 177�179

putting it all together, 182

representative performance of, 185f

substrate, 181�182

Oxygenated treatment (OT), 324

Ozone, 147�148, 147f

P

PACE (Power at Combined Efficiency), 2

Part load/shut down, 299�300

Partial water side bypass, 88, 88f

Particulate matter (PM), 136�138

Pegging steam, 79, 291, 309�311

Penetration seals, casing, 356�357, 358f

Phase transition zone (PTZ), 320�321, 332

Phosphate treatment, 325�326

Photovoltaic (PV) power, 41�42

Pigging, 389

Pilot gas train, 140f, 141f

Pilot oil train, 142f, 143f

Pinch point, 46�47

Piping, 204, 282�283

high-energy piping, 358�359

interconnecting, 211, 212f

less-than-desirable pipe routings,

226�227

steam piping, 227

and support solutions, 226�227

Platforms and secondary structures, 284

Platinum and chromium (III) oxide based

catalysts, 150

Power cycle variations that use HRSGs,

34�43

cogeneration, 35�38

integrated gasification combined cycle,

40�41

solar hybrid, 41�43

steam power augmentation, 38�40

Preoperational acid cleaning, 67

Pressure

balance of plant operating pressure, 290

effect of, 233�234

high-pressure evaporator, 104

high-pressure superheater, 108�109,

112�113

integral floating pressure deaerator, 79

intermediate-pressure superheaters, 109

levels, 23�29

multiple pressure systems, 53

nonpressure parts, 61�62

reheater pressure loss, 100�101

single pressure level, 26

sliding/floating pressure operation, 102

steam pressures, 11

three-pressure nonreheat cycle, 27�29

two-pressure nonreheat cycle, 27

407Index

Pressure control, 316�318

automatic relief valve(s), 317

control valve bypass, 317�318, 318f

Pressure drop, 54

Pressure parts, 62, 202�204

design flexibility, 209�215

auxiliary equipment, 215

coil flexibility, 210�213

condensate management, 215

feedwater recirculation, 215

general information, 209�210

material transitions, 213�214

preventing quenching, 214

design methods, 202

design parameters, 202

material selection, 202�203

mechanical component geometries and


headers, 200

piping, 204

steam drums, 204

tubes, 203

Pressure safety valves (PSVs), 317

Process steam, 96�97

Proportional integral derivative (PID)

controller, 301, 312

Public Utility Regulatory Policies Act

(PURPA), 2�3, 35

Pumpable insulation, 355

Q

Qualifying facility (QF), 35

Quenching, preventing, 214

R

Ramp rates, 235, 294�295

Rankine cycle, 20�21

combining Brayton cycle and, 21

T-S diagram, 20f

Reciprocating engines, 116

Recirculation pumps (with bypass),

309

Redundancy, 220�221

Refinery/chemical plant fuels, 121

Remote deaerator, 79

Remote drum style evaporator, 69f

Repair, of HRSG, 373�375

casing or liner failures, 375

flow-accelerated corrosion (FAC), 374

thermal fatigue, 374�375

under-deposit corrosion, 375

Repeat cycle chemistry situations (RCCS),

320�321, 339�340, 340t

development of, 337�339

challenging the status quo, 339

contaminant ingress, 339

continuous online cycle chemistry


conventional boiler/evaporator deposits,

338

corrosion products, 338

drum carryover, 338

shutdown/layup protection, 339

Retention time, 73

Ring type desuperheater, 106f

Roof beams, 271�273, 271f, 276�277

S

Saturation temperature, 47�48, 246�247,

294, 296

Scanning electron microscopy (SEM), 194t

Seismic loads, 217�221

Selective catalytic reduction (SCR)

technology, 145, 174, 285

catalyst materials and construction,

150�153

catalyst performance vs temperature

graph, 155f

catalyst seal, 162f

drivers and advances in, 165�170

advancements in multifunction catalyst,

167�170

enhanced reliability and lower pressure

loss, 165�166

transient response, 167

future outlook for, 170�171

history, 146

impact on HRSG design and performance,

153�164

performance impacts, 162�164

SCR configuration, 157�158

SCR location within the HRSG,

153�156

SCR support structure, 158�161

regulatory drivers, 147�150

SCR catalyst, 368

Separated (or slip) flow, 66

Separated flow condition, 57

408 Index

Serpentine coil OTSG, 383

Severe service valves, 372�373

Shipping bundle versus individual coil, 98f

Shutdown and trips, of HRSG, 247

Shutdown/layup protection, 339

Side-fired oil gun, 119�121, 120f

Siemens Benson OTSG technology, 384

Silica-based carriers, 180

Single-element control (SEC), 76�77,

301�302

Single-row harp isometric, 267f

Sintering, 191

Sliding/floating pressure operation, 102

Sodium hydroxide, 325

Solar hybrid, 41�43

Solar hybrid cycle, 34�35

Specialty steam drums, 77�79

deaerators, 78�79

fast start cycles, multiple drum designs

for, 78

Split superheater, 52, 52f, 103

Spraywater desuperheater, 106�107

interstage, 107

water source vs steam purity, 107

Spring can with indicator in proper location,

358f

Stack, 372

exhaust stacks, 281�282

Stack gas reheat, 118

Stack radiated noise, 259

Stack temperature, 33�34

STAG plant, 2

Standard design, 83�84, 87

full circuit, 83�84, 84f

half circuit, 84, 85f

Starting up a power/process plant, 293�299

automatic startup, general comments for,

299


lead/lag, 297�299

startup type, 294�295

steam temperature (interstage/final),

296�297

superheater/reheater drain(s), 295�296

Startup, of HRSG, 246�247

Startup drum level, 77

Startup vent/steam turbine bypass, 311�313,

313f

Steam bypass attemperator, 108�109, 252

Steam drum design, 71�75, 71f

drum internals, 73�75

primary separator, 73

secondary separator, 74�75

drum water levels and volumes, 72�73

high high water level (HHWL), 72

high water level (HWL), 72

low low water level (LLWL) trip,

72�73

low water level (LWL), 72

normal water level (NWL), 72

Steam drum inspection, 369�372


IP steam drum, 371

LP steam drum, 371

Steam drum operation, 75�77

continuous blowdown and intermittent

blowoff systems, 76


single-element control, 76�77


startup drum level, 77

Steam drums, 204

Steam injection. See Steam power

augmentation

Steam power augmentation, 38�40

Steam purity

combined cycle/HRSG limits, 333

for startup, 333�334

vs various applications, 97

water source vs, 107

Steam side flow distribution, 110�111

Steam temperature, 52, 296�297

Steam temperature control, 304�306

bypass system, 306

final stage attemperator, 305�306

interstage attemperator, 306

Steam turbine phase transition zone failure/

damage, 331�333

Steam/water injection, 389

Steaming in economizer, 87�88

Stress due to change in temperature,

234�240

Stress monitors, 251

Stress�strain curve for a metal, 207f

Structural frame, 276�278

Sulfur, 193

Sulfur buildup on finned tubes, 370f

Sulfur dioxide, 136

409Index

Sulfur oxides, 155�156, 163

Sulfuric acid, 156

Super modules and offsite erection,

275�276

Supercritical steam cycles, 387�388

Superheater, 49�50

Superheater and reheater, 95

base load vs fast startup and/or high

cycling, 109�110

design types and considerations, 97�105

bundle support types, 104

circuitry, 100�101, 101f

countercurrent/cocurrent/crossflow,

98�99

headers/jumpers vs upper returns,

99�100

sliding/floating pressure operation, 102

staggered/inline, 98

tube-to-header connections, 105

unfired/supplemental fired, 103�104

drainability and automation, 110

flow distribution, 110�112

gas side, 111�112

steam side, 110�111

general description of superheaters,

96�97

power plant steam turbine, 97

process steam, 96�97

steam purity vs various applications,

97

materials, 112�113

outlet temperature control, 105�109

mixing requirements for each, 109

spraywater desuperheater, 106�107

steam bypass attemperator, 108�109

Superheater/reheater drain(s), 295�296

Supplemental firing, 50�51, 51f, 52f,

103�104

burner in inlet duct, 103

at combustion gas turbine part load, 104

impact downstream of the high-pressure

evaporator, 104

screen evaporator, 103�104

split superheater/reheater, 103

Supplementary firing, 32�33, 116

Surface area sequencing, 32

Surface of the superheaters (SHTR), 289

Sweetwater condenser desuperheater, 107

Swell/shrink volume, 73

T

Taitel & Dunkler chart, 391

Technical Guidance Document (TGD),

331

Terminal point spraywater desuperheater,

106�107

Thermal deactivation of catalyst, 191, 192f

Thermal design, 46�61

economizer, 48

energy balance, 46�47

heat exchanger design, 54�61

evaporation and circulation, 58�59

finned tubing, 54�55

instability, 59�61

pressure drop, 54

tube arrangement, 55

two-phase flow, 55�58

multiple pressure systems, 53

split superheater, 52

superheater, 49�50

supplemental firing, 50�51

Thermal fatigue, 374�375

Thermal NOx, 133

Thermogravimetric analysis (TGA/DTA),

194t

Three-element control, 66, 303

Titania-based carriers, 180

Top-supported modular style bundle, 271f

Total dissolved solids (TDS), 389

Tripping a power plant/process plant, 288

Trisodium phosphate (TSP), 325

TSP (total suspended particulate), 136

Tube orientation, 86�87

Tubes, 203

Tube-to-header connections, 213�214, 243,

243f, 250, 369

Tube-to-header joints, 366, 374f

Turbine exhaust gas (TEG), 116, 118�119,

122, 125�126

Turbine exhaust gas distribution, 111�112

Turbine power augmentation, 122�123

Turbine sound power, 259

Two-phase density, 57

Two-phase flow heat transfer, 66

U

Ultimate tensile strength, 208

Ultra low sulfur diesel (ULSD), 155�156

Unburned hydrocarbons (UHCs), 135�136

410 Index

Under-deposit corrosion (UDC), 320�321,

367�368, 375

Underwriters’ Laboratories (UL), 143�144

Unit shutdown limits, 334

Uprighting device, 270f

US Energy Information Administration

projects, 3�4

V

Valve wear, 251�252

Venting, 87

Vertical gas flow HRSGS, 377�382, 378f,

380f

forced circulation, 377�379

horizontal HRSG, comparison to,

379�382

installation, 382

space requirements, 382

support and flexibility, 381�382

thermal performance, 379�381

natural and assisted circulation, 379

Vertical tube economizer, 87, 381

Vertical tube HRSGs, 381

Vertical tube natural circulation evaporators,

65

evaporator design fundamentals, 66�71

flow accelerated corrosion (FAC),

68�71

heat transfer/heat flux, 66�67

natural circulation and circulation ratio,

68

specialty steam drums, 77�79

deaerators, 78�79

fast start cycles, multiple drum designs

for, 78

steam drum design, 71�75

drum internals, 73�75

drum water levels and volumes,

72�73

steam drum operation, 75�77

continuous blowdown and intermittent

blowoff systems, 76


startup drum level, 77

Very high fired HRSGs, 393�394, 393f

Void fraction, 57, 58f

Volatile organic compound (VOC), 131,

174, 183

W

Waste heat boilers, 4

Water chemistry, 70, 251, 322

Water/steam flow mixture, 381

Water/steam side components, 260�261

deaerator, 260�261

feedwater pumps, 260

Watertube heat recovery boilers, 4

Welding, 277�278

Whirling instability, 62�63

Wind loads, 216�217

X

X-ray diffraction (XRD), 194t

X-ray fluorescence (XRF), 194t

X-ray photoelectron spectroscopy (XPS),

194t

Y

Yield strength, 207

411Index

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