Site Inspection Guidelines and Protocol

AJ2

Synergy Engineers

CFB Boiler Assessment

Site Inspection Guidelines & Protocol

Compiled and Edited

By

José Agustín González

AJ2

PROJECT MANAGEMENT

QUALITY SYSTEMS ENGINEERING

Synergy Engineers

JOSÉ AGUSTÍN GONZÁLEZ II

SUMMARY OF DOCUMENT REVISIONS

Rev. Date Revised Section Revised

Revision Description

00 21/12/2016 N/A Internal issue of document

00A 30/12/2016 N/A Issued for Internal Review and Edition

00 03/01/2017 N/A Issued with new file name - FROM: Inspection.XC-1306.86-M8.CFB.Peru.Rev.00 – TO: Site.Inspection.XC-1306.86-M8.CFB.Peru.Rev.00

01 05/01/2017 4 & 5 Include missing internal inspection sections and transfer sections previously included in section 5 onto 4

01A 09/01/2017 N/A Document´s Properties

02 16/01/2017 6 Section 6 Safety added to the document thus improving the site inspection guidelines

DOCUMENT´S PROPERTIES

Prepared by José Agustín González Engineering & Systems Integration

Reviewed by Alberto Balarezo Construction and Commissioning

Approved by Joel González Morante Planning & Control

Date of Creation Monday, January 16, 2017

Saved Date Wednesday, January 18, 2017

Number of Words 22913 Words

File Name Site.Inspection.XC-1306.86-M8.CFB.Peru.Rev.02

File Size 5882 Kilobytes 6 Megabytes

AJ2

PROJECT MANAGEMENT


Synergy Engineers

JOSÉ AGUSTÍN GONZÁLEZ III

TABLE OF CONTENT

1 BOILERS INSPECTION ................................................................................................................................... 7

2 CIRCULATING FLUIDIZED BED BOILERS ..................................................................................................... 8

2.1 CFB BOILER GENERAL ARRANGEMENT.............................................................................................. 9

2.1.1 FLUE GAS STREAM .............................................................................................................................. 11

2.1.2 SOLID STREAM ..................................................................................................................................... 11

2.1.3 WATER – STEAM CIRCUIT ................................................................................................................... 12

2.1.4 ECONOMIZER ....................................................................................................................................... 12

2.1.5 EVAPORATORS .................................................................................................................................... 13

2.1.6 SUPER-HEATERS AND RE-HEATERS ................................................................................................. 13

2.2 TYPES OF CFB BOILERS ..................................................................................................................... 14

2.2.1 BOILERS WITHOUT BUBBLING BED HEAT EXCHANGERS ............................................................... 15

2.2.2 BOILERS WITH BUBBLING FLUIDIZED BED HEAT EXCHANGER ..................................................... 16

2.2.3 BOILERS WITH INERTIAL OR IMPACT SEPARATORS ....................................................................... 16

2.2.4 BOILERS WITH VERTICAL, NONCIRCULAR CYCLONES ................................................................... 17

2.2.5 OTHER TYPES ...................................................................................................................................... 17

3 BOILER DEGRADATION MECHANISMS ...................................................................................................... 18

3.1 CORROSION .......................................................................................................................................... 18

3.2 EROSION ............................................................................................................................................... 18

3.3 FATIGUE ................................................................................................................................................ 18

3.4 OVER-HEATING .................................................................................................................................... 19

3.5 HYDROGEN DAMAGE .......................................................................................................................... 19

3.6 VIBRATION ............................................................................................................................................ 19

4 CONDITION ASSESSMENT EXAMINATION METHODS.............................................................................. 20

4.1 NON-DESTRUCTIVE EXAMINATIONS ................................................................................................. 22

4.1.1 VISUAL ................................................................................................................................................... 22

4.1.2 MAGNETIC PARTICLES ........................................................................................................................ 22

4.1.3 LIQUID PENETRANT ............................................................................................................................. 22

4.1.4 ULTRASONIC ......................................................................................................................................... 23

4.1.4.1 ULTRASONIC THICKNESS TESTING ............................................................................................... 23

4.1.4.2 ULTRASONIC OXIDE MEASUREMENT ............................................................................................ 23

4.1.4.3 ULTRASONIC MEASUREMENT OF INTERNAL TUBE DAMAGE .................................................... 25

4.1.4.4 IMMERSION ULTRASONIC TESTING............................................................................................... 25

4.1.4.5 SHEER WAVE ULTRASONIC TESTING ........................................................................................... 25

4.1.4.6 TIME OF FLIGHT DEFRACTION (TOFD) .......................................................................................... 26

4.1.5 EDDY CURRENT ................................................................................................................................... 26

4.1.6 RADIOGRAPHY ..................................................................................................................................... 26

4.1.7 NUCLEAR FLUORESCENCE ................................................................................................................ 27

4.1.8 ELECTROMAGNETIC ACOUSTICS ...................................................................................................... 27

AJ2

PROJECT MANAGEMENT


Synergy Engineers

JOSÉ AGUSTÍN GONZÁLEZ IV

4.1.9 ACOUSTICS ........................................................................................................................................... 29

4.1.10 ACOUSTIC EMISSIONS .................................................................................................................... 30

4.1.11 METALLOGRAPHIC REPLICATION .................................................................................................. 30

4.1.12 STRAIN MEASUREMENT .................................................................................................................. 30

4.1.13 TEMPERATURE MEASUREMENT .................................................................................................... 30

4.2 DESTRUCTIVE EXAMINATIONS .......................................................................................................... 31

4.2.1 TUBE SAMPLES .................................................................................................................................... 31

4.2.2 BOAT SAMPLES .................................................................................................................................... 31

4.3 ADVANCES IN NON-DESTRUCTIVE EXAMINATIONS ........................................................................ 31

5 SITE INSPECTION OF BOILER COMPONENTS AND AUXILIARIES .......................................................... 32

5.1 EXTERNAL BOILER INSPECTION ........................................................................................................ 32

5.1.1 LADDERS, STAIRWAYS AND PLATFORMS ........................................................................................ 32

5.1.1.1 CRACKS ............................................................................................................................................. 32

5.1.1.2 TIGHTNESS OF BOLTS ..................................................................................................................... 33

5.1.1.3 CONDITION OF PAINT OR GALVANIZED MATERIAL ..................................................................... 33

5.1.1.4 WEAR ON LADDER RUNGS AND STAIR TREADS. ......................................................................... 33

5.1.1.5 SECURITY OF HANDRAILS .............................................................................................................. 33

5.1.1.6 THE CONDITION OF FLOORING ...................................................................................................... 33

5.1.2 FANS ...................................................................................................................................................... 33

5.1.3 AIR DUCTS AND FLUE GAS DUCTS .................................................................................................... 33

5.1.4 SUPPORT STRUCTURE AND BOILER CASING .................................................................................. 33

5.1.5 STACK .................................................................................................................................................... 34

5.1.6 BOILER PIPING ..................................................................................................................................... 35

5.1.7 INSTRUMENTATION ............................................................................................................................. 35

5.1.8 PAINT AND INSULATION ...................................................................................................................... 35

5.2 INTERNAL BOILER INSPECTION ......................................................................................................... 35

5.2.1 SAFE ENTRY ......................................................................................................................................... 36

5.2.2 REFRACTORY ....................................................................................................................................... 36

5.2.3 STEAM DRUM ........................................................................................................................................ 37

5.2.4 BOILER TUBING .................................................................................................................................... 37

5.2.4.1 STEAM-COOLED ............................................................................................................................... 37

5.2.4.2 WATER-COOLED............................................................................................................................... 38

5.2.5 RISERS .................................................................................................................................................. 38

5.2.6 HEADERS .............................................................................................................................................. 38

5.2.6.1 HIGH TEMPERATURE ....................................................................................................................... 38

5.2.6.2 LOW TEMPERATURE........................................................................................................................ 41

5.2.7 ATTEMPERATORS ................................................................................................................................ 41

5.2.8 HIGH TEMPERATURE PIPING .............................................................................................................. 43

5.2.8.1 DAMAGE MECHANISMS ................................................................................................................... 43

5.2.8.2 OVERALL EVALUATION PROGRAM ................................................................................................ 43

AJ2

PROJECT MANAGEMENT


Synergy Engineers

JOSÉ AGUSTÍN GONZÁLEZ V

5.2.9 DETAILED EVALUATION PROGRAM ................................................................................................... 43

5.2.9.1 Phase I................................................................................................................................................ 43

5.2.9.2 Phase II ............................................................................................................................................... 44

5.2.10 TYPICAL FAILURES .......................................................................................................................... 45

5.2.11 LOW TEMPERATURE PIPING .......................................................................................................... 45

5.2.11.1 TYPICAL FAILURES ...................................................................................................................... 45

5.2.12 TUBULAR AIR HEATERS .................................................................................................................. 46

5.3 BOILER SETTINGS ................................................................................................................................ 46

5.3.1 DESIGN REQUIREMENTS .................................................................................................................... 47

5.3.2 TUBE WALL ENCLOSURES .................................................................................................................. 48

5.3.2.1 MEMBRANE TUBES .......................................................................................................................... 48

5.3.2.2 MEMBRANE TUBES WITH REFRACTORY LINING.......................................................................... 49

5.3.2.3 FLAT STUD TUBE WALLS ................................................................................................................. 49

5.3.2.4 TANGENT TUBE WALL ..................................................................................................................... 51

5.3.2.5 FLAT STUD AND TANGENT TUBE WALL UPGRADES ................................................................... 52

5.3.3 CASING ENCLOSURES ........................................................................................................................ 52

5.3.3.1 HOPPER ............................................................................................................................................. 52

5.3.3.2 WIND-BOX ......................................................................................................................................... 53

5.3.3.3 TEMPERING GAS PLENUM .............................................................................................................. 53

5.3.3.4 PENTHOUSE ..................................................................................................................................... 53

6 SAFETY.......................................................................................................................................................... 54

6.1 EXPLOSIONS ......................................................................................................................................... 54

6.2 IMPLOSIONS ......................................................................................................................................... 55

7 INSPECTION FORM TEMPLATE .................................................................................................................. 56

7.1 EXTERNAL BOILER INSPECTION ........................................................................................................ 58

7.2 INTERNAL BOILER INSPECTION ......................................................................................................... 83

8 RELIABLE INFORMATION IS KEY TO A RELIABLE ASSESSMENT ........................................................... 99

9 CFB Boilers – Reheat and Non-reheat ......................................................................................................... 100

AJ2

PROJECT MANAGEMENT


Synergy Engineers

JOSÉ AGUSTÍN GONZÁLEZ VI

TABLE OF FIGURES

Figure 1 – Non-reheat Circulating fluidized bed boiler major components ............................................................... 8

Figure 2 – General arrangement of a typical circulating fluidized bed boiler ............................................................ 9

Figure 3 – Air and feed circuit of a CFB boiler with an external heat exchanger .................................................... 10

Figure 4 – Water and Steam circuit of a CFB boiler without an external heat exchanger ....................................... 12

Figure 5 – Arrangement of a CFB boiler with impact separators ............................................................................ 14

Figure 6 – CFB boiler with a vertical non-circular cyclone ...................................................................................... 15

Figure 7 – Application of steel, refractory, and expansion joints to a CFB boiler .................................................... 16

Figure 8 – A novel design of CFB boiler with central multi-entry cyclone ............................................................... 17

Figure 9 – Three phase (levels) of boiler damage assessment .............................................................................. 21

Figure 10 – Steam side oxide scale on ID surface ................................................................................................. 24

Figure 11 – Typical ultrasonic signal response ....................................................................................................... 24

Figure 12 - Sheer wave technique for detecting hydrogen damage ....................................................................... 26

Figure 13 – Basic principles of EMAT operation ..................................................................................................... 28

Figure 14 – B&W´s Fast-Scanning Thickness Gage (FST-GAGE®) ....................................................................... 28

Figure 15 - header locations susceptible of cracking .............................................................................................. 39

Figure 16 - Steam temperature variation in a header ............................................................................................. 40

Figure 17 - Super-heater tube leg temperatures vary with load .............................................................................. 40

Figure 18 - Large ligament cracks on header ID. ................................................................................................... 41

Figure 19 - Typical attemperator assembly ............................................................................................................ 42

Figure 20 - Failed attemperator spray head ........................................................................................................... 42

Figure 21 - Acoustic Ranger® schematic ................................................................................................................ 46

Figure 22 – Membrane wall construction ................................................................................................................ 48

Figure 23 – Fully studded membrane wall .............................................................................................................. 49

Figure 24 – Flat stud tube wall construction with inner casing shown .................................................................... 50

Figure 25 – Tangent tube wall construction with outer casing shown ..................................................................... 51

Figure 26 – Casing attachment to membrane wall ................................................................................................. 51

Figure 27 – Tangent tubes with closure rods .......................................................................................................... 52

Figure 28 – Widely spaced tubes with flat studs and closure bars ......................................................................... 52

Figure 29 – Tie bar and buck-stay arrangement at corner of furnace ..................................................................... 55

Figure 30 – CFB Boilers Reheat and Non-reheat ................................................................................................. 100

AJ2

PROJECT MANAGEMENT


Synergy Engineers

JOSÉ AGUSTÍN GONZÁLEZ Page 7 de 100

1 BOILERS INSPECTION

Inspections are done to determine the amount of maintenance required to have the equipment operate

properly, until the next turnaround. Boilers should be inspected at least every two years. Inspection

intervals are based on service and experience.

Inspection is not an exact science and requires the use of judgment and experience as well as science.

Records should be reviewed before an inspection, to become thoroughly familiar with the equipment. This

review should result in identifying expected problems and planning areas of emphasis for the planned

inspection. The following records that should be checked are as follows:

1. Original Design Drawings

2. Piping and Instrumentation Diagrams (P&IDs)

3. E & I Single Line Diagrams

4. DCS (Distributed Control System)

5. Boiler Log

6. Maintenance Records

7. Safety Instruction Sheets (SIS)

8. Hydrostatic Test Diagram

9. Previous hydrostatic test results

The original design drawings and the P&IDs provide information on the pressure and temperature of the

original design. The original design drawings indicate inspection points, with notes on inspection

procedures. These drawings also contain notes on how to access equipment. The P&IDs should also

show all pipe sizes, materials of construction, vent and drain locations, and blind. They also provide

material specifications and original thickness of equipment.

The boiler log provides a record of each inspection, maintenance check, and notes on the equipment.

These notes are necessary to prepare for inspection. The maintenance records indicate conditions found

in a previous inspection that required maintenance. The Safety Instruction Sheets (SIS) provides operating

pressure and temperature information, and pressure test targets. It also contains the retirement thickness

on critical piping. The hydraulic test diagram is a line drawing showing blinds, piping layout, and location

of pressure test connections. The test diagram will specify the relief valve size, set pressure, and location.

Previous hydraulic test results indicate problem areas from previous inspections.

AJ2

PROJECT MANAGEMENT


Synergy Engineers


2 CIRCULATING FLUIDIZED BED BOILERS

The circulating fluidized bed (CFB) boiler is a member of the fluidized bed boiler family. It has gained

popularity, especially in the electric power-generation market, for its several practical advantages (Figure

1 – Non-reheat Circulating fluidized bed boiler major components), such as efficient operation and

minimum effect on the environment. Although it entered the market only in the 1980s, CFB technology is

well beyond its initial stage of development. The technology has matured through successful operation in

hundreds of units of capacities ranging from 1 MWe to 340 MWe (until 2005). The problems of the first

generation have been solved and CFB is now considered to be a mature technology for atmospheric-

pressure units. Its design methodology, however, is not as well-established as that of pulverized coal-fired

boilers. Many aspects of its design are still based on rules of thumb. The present chapter describes

different aspects of the circulating fluidized bed boiler including a brief outline of a design approach.

Figure 1 – Non-reheat Circulating fluidized bed boiler major components

AJ2

PROJECT MANAGEMENT


Synergy Engineers


2.1 CFB BOILER GENERAL ARRANGEMENT

A CFB boiler (See Figure 1 – Non-reheat Circulating fluidized bed boiler major components) may be

divided into two sections:

1. The CFB loop and the convective or back-pass section of the boiler (Figure 2 – General arrangement

of a typical circulating fluidized bed boiler). The CFB loop consists of the following items making up

the external solid recirculation system.

1. Furnace or CFB riser

2. Gas–solid separation (cyclone)

3. Solid recycle system (loop-seal)

4. External heat exchanger (optional)

Figure 2 – General arrangement of a typical circulating fluidized bed boiler

Whereas Figure 2 – General arrangement of a typical circulating fluidized bed boiler shows the general

arrangement of a typical CFB boiler without the external heat exchanger; Figure 3 – Air and feed circuit of

a CFB boiler with an external heat exchanger shows the same for one with the heat exchanger.

2. The back-pass is comprised of:

1. Super-heater

2. Re-heater

3. Economizer

4. Air heater

AJ2

PROJECT MANAGEMENT


Synergy Engineers


Figure 3 – Air and feed circuit of a CFB boiler with an external heat exchanger

The following section describes the working of the boiler, tracing the path of air, gas, solids and water

through it.

The primary air fan delivers air at high pressure (10 to 20 kPa). This air is preheated in the air preheater

of the boiler and then enters the furnace through the air distributor grate at the bottom of the furnace.

The secondary air fan delivers air, also preheated in the air preheater, at a relatively low pressure (5 to

15 kPa). It is then injected into the bed through a series of ports located around the periphery of the

furnace and at a height above the lower tapered section of the bed. In some boilers, the secondary air

provides air to the start-up burner as well as to the tertiary air at a still higher level, if needed. The

secondary air fan may also provide air to the fuel feeder to facilitate the smooth flow of fuel into the furnace.

Loop-seal blowers deliver the smallest quantity of air but at the highest pressure. This air directly enters

the loop-seals through air distribution grids. Unlike primary and secondary air, the loop-seal air is not

heated.

AJ2

PROJECT MANAGEMENT


Synergy Engineers


2.1.1 FLUE GAS STREAM

Generally, only one suction fan is used to handle the flue gas in a CFB boiler. This fan, called induced

draft (ID) fan, creates suction in the system to draw flue gas from the boiler and through the dust control

or any other gas emission-control equipment. The suction head of the ID fan is designed to have a

balanced draft in the air/flue gas system with zero (or atmospheric) pressure at the mid or the top section

of the furnace. This helps keep the boiler-house clean and at the same time optimizes the power

consumption by the ID fan.

2.1.2 SOLID STREAM

Fuel from the bunker drops on to a belt or some other type of feeder, which then feeds measured quantities

of fuel into the fuel chute. In most large CFB boilers, the fuel chute feeds the fuel into the loop-seal’s

inclined pipe (Figure 3 – Air and feed circuit of a CFB boiler with an external heat exchanger). Here, the

fuel mixes with hot solids recirculating around the CFB loop, and therefore enters the bed better dispersed.

Other boilers either take the fuel directly into the lower section of the bed through the front wall or use

another conveyor to take it around the furnace for sidewall feeding.

The sorbent is generally finer than the fuel, so it is carried by conveying air and injected into the bed

through several feed injection points. As sorbents react very slowly, the location of their feed points is not

as critical as that for the fast-burning fuel.

The ash or spent sorbent is drained from the boiler through the following points:

1. Bed drain

2. Fly ash collection hopper under the fabric filter or electrostatic precipitator

3. Economizer or back-pass hopper

In some cases, ash is also drained partially from the external heat exchanger. In the case of a coarse bed

drain, the ash is cooled by air or water before it is disposed of. The fly ash, being relatively cold, can be

disposed of without cooling. Its particles are generally smaller than 100 mm with a mean size of 30 mm

and are, therefore, easily carried pneumatically into a fly ash silo, where they are hauled away by truck or

rail wagon as necessary.

The mixture of fuel, ash, and sorbents circulate around the CFB loop. Particles, coarser than the cyclone

cut-off size, are captured in the cyclone and recycled near the base of the furnace. Finer solid residues

like ash or spent sorbents, generated during combustion and desulfurization, escape through the

cyclones. These are collected by the fabric filter or electrostatic precipitator located further downstream.

AJ2

PROJECT MANAGEMENT


Synergy Engineers


2.1.3 WATER – STEAM CIRCUIT

Figure 4 – Water and Steam circuit of a CFB boiler without an external heat exchanger

Figure 4 – Water and Steam circuit of a CFB boiler without an external heat exchanger shows the water–

steam flow circuit through a typical CFB boiler. Here, one can detect the following heat transfer surfaces

in the boiler:

1. Economizer in the back-pass

2. Evaporator in the furnace wall

3. Super-heaters in both the back-pass and furnace

4. Re-heaters in both the back-pass and furnace

A CFB boiler could locate parts of the super-heater and re-heater in an external heat exchanger as shown

in Figure 3 – Air and feed circuit of a CFB boiler with an external heat exchanger.

2.1.4 ECONOMIZER

The boiler feed pump feeds the water into the economizer located in the back-pass or convective section

of the boiler (Figure 4 – Water and Steam circuit of a CFB boiler without an external heat exchanger). The

economizer is a conventional shell-tube heat exchanger that uses the waste heat of the flue gas to preheat

water. The water is forced through the economizer to flow directly to the drum. Water enters the cooler

section and leaves from the hotter upper section of the economizer making it a counter-flow heat

AJ2

PROJECT MANAGEMENT


Synergy Engineers


exchanger. The temperature of the water leaving the economizer is generally kept at least 288C below

the saturation temperature of the water to ensure good circulation. Some high-performance boilers allow

steam formation, but considering the possibility of non-uniform flow distribution between tubes, flow

instabilities and other factors the rise in enthalpy in the economizer should be guided by the following

equation (Stultz and Kitto, 1992):

Equation 1

𝐻2 − 𝐻1 = 2

3(𝐻𝑓 − 𝐻1)

Where H1, H2, and Hf are enthalpies of water entering the economizer, leaving the economizer and at

saturated condition at the economizer outlet pressure, respectively.

The water velocity through the economizer is typically in the range of 600 to 800 kg/m2s and gas velocity

is in the range of 7 to 15 m/s.

2.1.5 EVAPORATORS

In a typical subcritical boiler, the water flows down large-diameter unheated pipes (known as down-

comers) into distributing manifolds called headers. The header distributes water amongst vertical tubes

rising along the walls of the furnace. Water rises through these tubes and hence they are called riser, or

water wall tubes. To make an airtight enclosure around the furnace, these tubes are generally welded

together by means of fins between them in the form of panels.

As the water rises up the tubes it absorbs heat from the furnace, converting part of it into steam. Hot water,

carrying steam bubbles, leaves the top of the water wall panels and is collected in headers, which in turn

carry it to the steam drum. Steam is separated from the water in the drum, which mixes with fresh water

from the economizer and flows down through the down-comer and into the riser for heating again.

Sometimes four walls of the furnace cannot provide sufficient surface area to carry the entire evaporative

load of the boiler. Additional surfaces are provided in the form of wing walls in the furnace (Figure 4 –

Water and Steam circuit of a CFB boiler without an external heat exchanger) or in the form of bank tubes

downstream of the furnace to take this load.

2.1.6 SUPER-HEATERS AND RE-HEATERS

Figure 4 – Water and Steam circuit of a CFB boiler without an external heat exchanger shows the

arrangement of re-heaters and super-heaters in a typical CFB boiler. Saturated steam from the drum flows

through a set of tube panels forming the walls of the back-pass. Then it goes to the omega super-heater

panels inside the furnace. These tubes are formed from a special steel section that, when joined, gives a

flat vertical surface to minimize the erosion potential. The partially-heated steam then rises up through

wing wall tubes as shown (Figure 4 – Water and Steam circuit of a CFB boiler without an external heat

exchanger) and passes through the final super-heater located in the back pass. Such a complex back-

and-forth tube arrangement helps minimize the cost of tubes while minimizing any risk of tube overheating.

Steam temperature can be controlled by spraying water into the steam at appropriate locations.

AJ2

PROJECT MANAGEMENT


Synergy Engineers


Low pressure steam enters the re-heater section immediately upstream of the economizer (Figure 4 –

Water and Steam circuit of a CFB boiler without an external heat exchanger). It then passes through the

final re-heater section upstream of the final super-heater. One may use a bypass valve between the entry

and exit of the re-heater section to control the steam temperature.

2.2 TYPES OF CFB BOILERS

Numerous designs of CFB boilers are available in the market, some of which are more common than

others. The following are four major types of CFB boiler designs:

1. Boilers with vertical, hot cyclones with or without in-furnace heating surfaces (Figure 2 – General

arrangement of a typical circulating fluidized bed boiler)

2. Boilers as above, with bubbling fluidized bed heat exchanger parallel in the CFB loop (Figure 3 – Air

and feed circuit of a CFB boiler with an external heat exchanger)

3. Boilers with impact or inertial-type separators (Figure 5 – Arrangement of a CFB boiler with impact

separators)

4. Boilers with vertical, noncircular, cooled cyclones (Figure 6 – CFB boiler with a vertical non-circular

cyclone)

Figure 5 – Arrangement of a CFB boiler with impact separators

AJ2

PROJECT MANAGEMENT


Synergy Engineers


Figure 6 – CFB boiler with a vertical non-circular cyclone

2.2.1 BOILERS WITHOUT BUBBLING BED HEAT EXCHANGERS

This is the most popular type and belongs to the first generation CFB boilers that entered the market in

the 1980s. The furnace is connected by way of an expansion joint to a thick, refractory-lined, vertical, hot

cyclone, which feeds the collected solids to a loop-seal. The loop-seal returns the solids to the furnace.

Several expansion joints are used at different sections to compensate for the differential expansion

between the cooled furnace and uncooled cyclone-loop-seal circuit as shown by Figure 7 – Application of

steel, refractory, and expansion joints to a CFB boiler. Following types of in-furnace surfaces are used if

needed to meet the demand for required furnace heat absorption:

1. Wing wall (also called platen) (Figure 2 – General arrangement of a typical circulating fluidized bed

boiler)

2. Omega tube panel (Figure 3 – Air and feed circuit of a CFB boiler with an external heat exchanger)

3. Division wall

AJ2

PROJECT MANAGEMENT


Synergy Engineers


Figure 7 – Application of steel, refractory, and expansion joints to a CFB boiler

2.2.2 BOILERS WITH BUBBLING FLUIDIZED BED HEAT EXCHANGER

The flue gas needs to be cooled down to the required temperature (800º to 900º C) before it leaves the

CFB loop. In large boilers (.100 MWe) the furnace walls alone cannot absorb this heat, so additional

surfaces like wing walls are required. Such surfaces do not give the flexibility of control of heat absorption,

which may be required for partial load operation or for burning alternative types of fuel. For this reason, a

bubbling fluidized bed heat exchanger as shown in Figure 3 – Air and feed circuit of a CFB boiler with an

external heat exchanger is used in the CFB loop in this type of boiler. It is placed in parallel to the solid

recycle line between the loop-seal and furnace. A part of the solid stream from the loop-seal is diverted

through the bubbling fluidized bed heat exchanger. Boiler heat-absorbing tubes are located in the fluidized

bed to absorb heat from the hot solids circulating through it. By regulating the amount of solids diverted

through it, solid flow through the heat exchanger is easily controlled. Two type bubbling fluidized beds are

used:

1. External heat exchanger located outside the furnace (Figure 3 – Air and feed circuit of a CFB boiler

with an external heat exchanger)

2. Internal heat exchanger located in the furnace.

2.2.3 BOILERS WITH INERTIAL OR IMPACT SEPARATORS

In order to avoid the high cost of hot cyclones an alternative type of gas–solid separator is used by this

type of CFB boiler as shown in Figure 5 – Arrangement of a CFB boiler with impact separators. Here, the

solids are separated through impact against a row of U-shaped flow barriers. Such separators are located

AJ2

PROJECT MANAGEMENT


Synergy Engineers


partially in the furnace and partially outside it. They are not as efficient as centrifugal-type cyclones, so an

additional multi-clone or other type of gas–solid separator is required downstream of the back-pass. Solids

from these separators are also recycled to the furnace. Compactness is a major feature of such boilers.

2.2.4 BOILERS WITH VERTICAL, NONCIRCULAR CYCLONES

This type of boiler is also known as compact design. Here, a geometric-shaped (square or octagonal)

separator chamber is formed by boiler tubes covered with a thin refractory (Figure 6 – CFB boiler with a

vertical non-circular cyclone). Circular gas exits are located on the roof of these chambers. Gas–solid

suspension from the furnace is made to enter the separator chamber through tangential entry points. Such

entries create horizontal vortices, which separate the solids in the chamber and allow the gas to leave

from the top.

2.2.5 OTHER TYPES

In addition to the above, many of other types of CFB boilers are available in the market and are generally

used in smaller-sized units. An important type is the innovative Cymicq design shown in Figure 8 – A novel

design of CFB boiler with central multi-entry cyclone. Here the gas–solid separator and the standpipe are

located in the center of the furnace, with risers around it. Gas–solid suspension enters the central cyclone

through a number of tangential vanes, forming a vortex. The solids drop into the central standpipe while

gas leaves from the top. The collected solids move to the riser through openings at the bottom of the

standpipe as shown in Figure 8 – A novel design of CFB boiler with central multi-entry cyclone. This design

is very compact and needs less refractory because it makes greatest use of heating surfaces. Large

boilers can be built with multiple central tubes in a rectangular riser chamber.

Figure 8 – A novel design of CFB boiler with central multi-entry cyclone

AJ2

PROJECT MANAGEMENT


Synergy Engineers


3 BOILER DEGRADATION MECHANISMS

3.1 CORROSION

Corrosion occurs inside and outside the tubes, pipes, drums and headers of these lower temperature

components. Internal corrosion is usually associated with the boiler water, contaminants in the water, and

improper chemical cleaning or poor storage procedures. External corrosion can be caused by corrosive

combustion products, a reducing atmosphere in the furnace, moisture between insulation and a

component, and acid formed on components in the colder flue gas zones when the temperature reaches

the acid dew point. Corrosion results in wall metal loss. This wall thinning raises the local stresses of the

component and can lead to leaks or component failure.

Corrosion may also be accelerated by the thermal fatigue stresses associated with startup and shutdown

cycles. Furnace wall tubes, in areas of high structural restraint or high heat flux, often contain internal

longitudinal or external circumferential or longitudinal corrosion fatigue cracks in cycled units.

Corrosion fatigue can occur in the steam drum around rolled tube joints. The residual stresses from the

tube rolling process are additive to the welding and operating pressure stresses. Corrosion from chemical

cleaning and water chemistry upsets acts on this highly stressed area to produce cracking around the seal

weld or the tube hole. Extensive cracking can require drum replacement.

3.2 EROSION

Erosion of boiler components is a function of the percent ash in the fuel, ash composition, and local gas

velocity or soot-blower activity. Changing fuels to a high-ash western United States (U.S.) fuel may lead

to more erosion, slagging and fouling problems.

Changing fuels might also require a change in the lower temperature convection pass elements to

accommodate higher fouling and erosion. The tube wall loss associated with erosion weakens the

component and makes it more likely to fail under normal thermal and pressure stresses. Erosion is

common near soot-blowers; on the leading edges of economizers, super-heaters and re-heaters; and

where there are vortices or around eddies in the flue gas at changes in gas velocity or direction.

Such changes are caused by closely spaced tube surfaces, slag deposits, or other obstructions including

extended surfaces and staggered tube arrangements.

3.3 FATIGUE

The thermal stresses from temperature differentials that develop between components during boiler

startup and shutdown can lead to fatigue cracks. These cracks can develop at tube or pipe bends; at tube-

to-header, pipe-to-drum, fitting-to-tube, and support attachment welds; and at other areas of stress

concentration. Smaller, lower temperature boilers are less prone to fatigue failures because the thermal

differentials are lower and operate over small distances in these units. As unit size and steam temperature

increase, the potential for thermal stresses and the resulting fatigue cracking also rises.

AJ2

PROJECT MANAGEMENT


Synergy Engineers


3.4 OVER-HEATING

Overheating is generally a problem that occurs early in the life of the plant and can often result in tube

ruptures. These problems may go undetected until a tube failure occurs. Overheating attributable to

operation is generally resolved during the early stages of boiler life. Other problems regarding overheating

may be difficult to ascertain, and specialized boiler performance testing is generally required to identify

the source and determine corrective actions.

In spite of these aging mechanisms, low temperature components are normally expected to be replaced

after more than two decades without major overhauls unless the unit burns a corrosive fuel, burns fuel in

a reducing atmosphere, or is improperly operated. When erosion, corrosion, fatigue, or overheating lead

to frequent leaking, failures, or the threat of a major safety related failure, then component repair, redesign,

or replacement is appropriate.

3.5 HYDROGEN DAMAGE

Boilers operating at pressures above 1200 psi (8274 kPa) and 900º F (482º C) final steam temperature

suffer from more complicated aging mechanisms than lower temperature units. These boilers are

generally larger than the low pressure, low temperature units and this increases the likelihood of thermal

fatigue from boiler cycling. The higher pressures and associated higher furnace wall temperatures make

these units more susceptible to water-side corrosion. The high temperatures in combination with any

furnace wall internal deposits may promote hydrogen damage of the furnace tubing in areas of high

corrosion or heavy internal deposits. Severe cases of furnace wall hydrogen damage have forced the

retirement of older units.

3.6 VIBRATION

Excessive vibration can cause failures of the tubes, insulation, casing and supports. These vibrations can

be produced by external rotating equipment, furnace pulsations from the uneven combustion of the fuel,

or turbulence in the flowing streams of air or gas in flues, ducts and tube banks.

Tube walls, flues and ducts are designed to limit vibration during normal operating conditions. In regard

to wall tube vibrations, buck-stays are typically spaced to ensure that the natural frequency of the wall

tubes is greater than or equal to 6 hertz. The moment of inertia of a buckstay must be chosen to ensure

that the buckstay natural frequency is greater than or equal to 3 hertz, based on a simply loaded uniform

beam. Flues, ducts and casings are similarly stiffened by bars or structural shapes to limit vibration. This

stiffening is particularly necessary in sections of flues and ducts where the flow is highly turbulent, as in

the fan discharge connecting piece. Every effort should be made to eliminate the sources of severe

vibration, such as unbalanced rotating equipment, poor combustion and highly turbulent or unbalanced

air or gas flow.

Vibration ties or tube guides are required on some end-supported tube sections. These ties may be

needed if the natural frequencies within the boiler load range are in or near resonance with the vortex

shedding frequency. Stringer tubes are also subject to vibration. This vibration is magnified by long

unsupported stringer tube lengths near the large cavity below the convection pass roof.

AJ2

PROJECT MANAGEMENT


Synergy Engineers


4 CONDITION ASSESSMENT EXAMINATION METHODS

The assessment of accumulated damage, or condition assessment, has a long history in the boiler

industry. Whenever a component was found to contain damage or had failed, engineers asked what

caused the damage and whether other components would fail. These questions typically pertained to

tubing and headers, which caused the majority of downtime. As boiler cycling became more common, the

need for more routine condition assessment increased to avoid component failure and unscheduled

outages.

Condition assessment includes the use of tools or methods in the evaluation of specific components and

then the interpretation of the results to identify:

1. The component’s remaining life and

2. Areas requiring immediate attention.

A boiler component’s damage assessment, typically compared to its design life, is based on accumulated

damage, and can be performed in three phases.

1. PHASE 1

In Phase 1 of the assessment, design and overall operating records are reviewed and interviews are

held with operating personnel.

2. PHASE 2

In Phase 2, nondestructive examinations, stress analysis, verification of dimensions, and operating

parameters are undertaken.

3. PHASE 3

If required, the more complex Phase 3 includes finite element analysis, operational testing and

evaluation, and material properties measurement. (Figure 9 – Three phase (levels) of boiler damage

assessment).

The major boiler components must be examined by nondestructive and destructive tests (See Figure 1 –

Non-reheat Circulating fluidized bed boiler major components).

AJ2

PROJECT MANAGEMENT


Synergy Engineers


Figure 9 – Three phase (levels) of boiler damage assessment

(Courtesy of the Electric Power Research Institute).

RL: Remaining life of component predicted by

evaluation

DL: Desired life of component (derived by unit

objective)

Assemble Historical Records

¿Is key information

Missing?

¿Is RL >= DL?Establish

Re-Evaluation Period

YES

NO

Additional Information(Generally Inspection

Results)

¿Is RL >= DL?Establish

Re-Inspection Period

YES

¿Economically Justified?

NO

Cost Evaluation

Level III

LEVEL III

Additional Information(Sampling, Analysis,

Inspection)

YES

Level II MethodscalculateRL and DL

LEVEL II

Level IIICalculateRL and DL

¿Is RL >= DL?

LEVEL III

NO

Establish Re-Inspection

Period

¿Establish Re-Evaluation &

Re-Inspection Period?

YES

Establish Re-Evaluation / Re-Inspection

Period

YES

Establish Re-Evaluation

Period

¿Establish Re-Inspection

Period?NO

NO

YES

Root Cause Analysis NO

Understand Root Cause of Damage

Mitigation of Driving Force

Choice of Repair/Replace

Refurbish Components

Level IMethods

NO

Yes

AJ2

PROJECT MANAGEMENT


Synergy Engineers


4.1 NON-DESTRUCTIVE EXAMINATIONS

Most nondestructive examination (NDE) methods for fossil fuel-fired plants have been in use for many

years, although new methods are being developed for major components. Nondestructive testing does

not damage the component.

The NDE methods used in evaluating electric utility power stations and industrial process plants include:

1. Visual,

2. Magnetic particle,

3. Liquid penetrant,

4. Ultrasonic,

5. Eddy current,

6. Radiography,

7. Nuclear fluorescence,

8. Electromagnetic acoustics,

9. Acoustic emissions,

10. Metallographic replication,

11. Strain measurement, and

12. Temperature measurement.

4.1.1 VISUAL

Whether the inspected component is subject to mechanical wear, chemical attack, or damage from

thermal stress, visual examination can detect and identify some of the damage. Visual inspection is

enhanced by lighting, magnification, mirrors, and optical equipment such as borescopes, fiberscopes and

binoculars.

4.1.2 MAGNETIC PARTICLES

Magnetic particle testing (MT) and wet fluorescent magnetic particle testing (WFMT) detect surface and

near surface flaws. Because a magnetic field must be imparted to the test piece, these tests are only

applicable to ferromagnetic materials. The choice between these techniques generally depends on the

geometry of the component and the required sensitivity. For typical power plant applications, one of two

methods is used:

1. The component is indirectly magnetized using an electromagnetic yoke with alternating current (AC)

2. The part is directly magnetized by prods driven by AC or direct current (DC).

In magnetic particle testing, any discontinuity disrupts the lines of magnetic force passing through the test

area creating a leakage field. Iron particles applied to the area accumulate along the lines of magnetic

force. Any leakage field created by a discontinuity is easily identified by the pattern of the iron particles.

Dry magnetic particle testing is performed using a dry medium composed of colored iron particles that are

dusted onto the magnetized area. In areas where a dry medium is ineffective, such as in testing overhead

components or the inside surfaces of pressure vessels, the wet fluorescent method is more effective. With

this method, fluorescent ferromagnetic particles are suspended in a liquid medium such as kerosene. The

liquid-borne particles adhere to the test area. Because the particles are fluorescent, they are highly visible

when viewed under an ultraviolet light.

4.1.3 LIQUID PENETRANT

Liquid penetrant testing (PT) detects surface cracking in a component. PT is not dependent on the

magnetic properties of the material and is less dependent on component geometry. It is used by The

AJ2

PROJECT MANAGEMENT


Synergy Engineers


Babcock & Wilcox Company (B&W) in limited access areas such as tube stub welds on high temperature

headers which are generally closely spaced. PT detects surface flaws by capillary action of the liquid dye

penetrant and is only effective where the discontinuity is open to the component surface. Following proper

surface cleaning the liquid dye is applied. The penetrant is left on the test area for about ten minutes to

allow it to penetrate the discontinuity. A cleaner is used to remove excess penetrant and the area is

allowed to dry. A developer is then sprayed onto the surface. Any dye that has been drawn into the surface

at a crack bleeds into the developer by reverse capillary action and becomes highly visible.

4.1.4 ULTRASONIC

Ultrasonic testing (UT) is the fastest developing technology for nondestructive testing of pressure

components. Numerous specialized UT methods have been developed. A piezoelectric transducer is

placed in contact with the test material, causing disturbances in the interatomic spacings and inducing an

elastic sound wave that moves through the material. The ultrasonic wave is reflected by any discontinuity

it encounters as it passes through the material. The reflected wave is received back at the transducer and

is displayed on an oscilloscope.

4.1.4.1 ULTRASONIC THICKNESS TESTING

Ultrasonic thickness testing (UTT) is the most basic ultrasonic technology. A common cause of pressure

part failure is the loss of material due to oxidation, corrosion or erosion. UTT is relatively fast and is used

extensively for measuring wall thicknesses of tubes or piping. The surface of the component must first be

thoroughly cleaned. Because ultrasonic waves do not pass through air, a couplant such as glycerine, a

water soluble gel, is brushed onto the surface. The transducer is then positioned onto the component

surface within the couplant. A high frequency (2 to 5 MHz) signal is transmitted by the transducer and

passes through the metal. UTT is performed using a longitudinal wave which travels perpendicular to the

contacted surface. Because the travel time for the reflected wave varies with distance, the metal thickness

is determined by the signal displacement, as shown on the oscilloscope screen (Figure 10 – Steam side

oxide scale on ID surface).

4.1.4.2 ULTRASONIC OXIDE MEASUREMENT

In the mid-1980s, B&W developed an ultrasonic technique specifically to evaluate high temperature tubing

found in super-heaters and re-heaters. This NDE method, called the Nondestructive Oxide Thickness

Inspection Service (NOTIS®), measures the oxide layer on the internal surfaces of high temperature tubes.

The test is generally applicable to low alloy steels because these materials are commonly used in outlet

sections of the super-heater and re-heater.

Low alloy steels grow an oxide layer on their internal surfaces when exposed to high temperatures for

long time periods (Figure 11 – Typical ultrasonic signal response). The NOTIS test is not applicable to

stainless steels because they do not develop a measurable oxide layer.

AJ2

PROJECT MANAGEMENT


Synergy Engineers


Figure 10 – Steam side oxide scale on ID surface

Figure 11 – Typical ultrasonic signal response

The technique used for NOTIS testing is similar to UTT; the major difference between the two is the

frequency range of the ultrasonic signal. A much higher frequency is necessary to differentiate the

interface between the oxide layer and inside diameter (ID) surface of the tube. Using data obtained from

this NOTIS testing, tube remaining creep life can also be calculated as discussed later in Analysis

techniques. NOTIS and UTT are methods in which the transducer is placed in contact with the tube using

a couplant gel. Because of the high sensitivity of the NOTIS method, it is less tolerant of rough tube

surfaces or poor surface preparation.

AJ2

PROJECT MANAGEMENT


Synergy Engineers


4.1.4.3 ULTRASONIC MEASUREMENT OF INTERNAL TUBE DAMAGE

Several ultrasonic methods have been investigated for detecting damage within boiler tubes. All

techniques use contact UT where a transducer is placed on the outside diameter (OD) or tube surface

using a couplant, and an ultrasonic signal is transmitted through the material. The techniques can be

categorized by type of signal evaluation: backscatter, the evaluation of UT wave scatter when reflected

by damaged material; attenuation, the evaluation of UT signal loss associated with transmission through

damaged material; and velocity, the measurement and comparison of UT wave velocity through the tube

material.

When a longitudinal wave passes through a tube, part of the signal is not reflected to the receiver if it

encounters damaged material. The damaged areas reflect part of the wave at various angles,

backscattering the reflected signal. The loss of wave amplitude that is received back at the transducer is

then used to evaluate the degree of damage.

Damage in the tube can also be assessed by evaluating the loss of signal amplitude (attenuation) as a

shear wave is transmitted through the tube wall. The technique uses a fixture with two transducers

mounted at angles to each other. One unit transmits a shear wave into the tube and the second transducer,

the receiver, picks up the signal as the wave is reflected from the tube ID. A drop in signal amplitude

indicates damage in the tube wall.

This technology is the basis of the B&W patented Furnace wall Hydrogen damage Nondestructive

Examination Service (FHyNES®) test method (Figure 12 - Sheer wave technique for detecting hydrogen

damage). The velocity test method uses either longitudinal or shear ultrasonic waves. As a wave passes

through a chordal section of tube with hydrogen damage, there is a measurable decrease in velocity.

Because the signal is not reflected from the tube inside surface, ultrasonic velocity measurement is not

affected by damage to the inside of the tube and therefore specifically detects hydrogen damage.

4.1.4.4 IMMERSION ULTRASONIC TESTING

In immersion ultrasonic testing, the part is placed in a water bath which acts as the couplant. B&W uses

a form of immersion UT for tube wall thickness measurements. In two-drum industrial power boilers,

process recovery boilers and some utility power generation boilers, most of the tubes in the convective

bank between the drums are inaccessible for conventional contact UTT measurements. For these

applications, an ultrasonic test probe was developed which is inserted into the tubes from the steam drum;

it measures the wall thickness from inside the tubes. As the probe is withdrawn in measured increments,

the transducers measure the tube wall thicknesses. A limitation of this technique is that the ID surface of

the tubes must be relatively clean.

4.1.4.5 SHEER WAVE ULTRASONIC TESTING

This is a contact ultrasonic technique in which a shear wave is directed at an angle into the test material.

Angles of 45º and 60º (deg) (0.79 and 1.05 rad) are typically used for defect detection and weld

assessment. The entire weld must be inspected for a quality examination.

AJ2

PROJECT MANAGEMENT


Synergy Engineers


Figure 12 - Sheer wave technique for detecting hydrogen damage

4.1.4.6 TIME OF FLIGHT DEFRACTION (TOFD)

TOFD is an ultrasonic technique that relies on the diffraction of ultrasonic energies from defects in the

component being tested. The primary application is weld inspection on piping, pressure vessels, and

tanks. TOFD is an automated inspection that uses a pitch-catch arrangement with two probes, one on

each side of the weld. The weld material is saturated with angled longitudinal waves to inspect for

discontinuities. Because the time separation of the diffracted waves is directly related to flaw size (height),

TOFD can detect both the flaw and allow estimation of the flaw size.

4.1.5 EDDY CURRENT

Measuring the effects of induced eddy currents on the primary or driving electromagnetic field is the basis

of eddy current testing. The electromagnetic induction needed for eddy current testing is created by using

an alternating current. This develops the electromagnetic field necessary to produce eddy currents in a

test piece.

Eddy current testing is applicable to any materials that conduct electricity and can be performed on

magnetic and nonmagnetic materials. The test is therefore applicable to all metals encountered in power

station condition assessment work.

Parameters affecting eddy current testing include the resistivity, conductivity, and magnetic permeability

of the test material; the frequency of the current producing the eddy currents; and the geometry and

thickness of the component being tested.

4.1.6 RADIOGRAPHY

Radiography testing (RT) is the most common NDE method used during field erection of a boiler.

Radiography is also valuable in condition assessments of piping. As x-rays and gamma rays pass through

AJ2

PROJECT MANAGEMENT


Synergy Engineers


a material, some of the rays are absorbed. Absorption depends upon material thickness and density.

When the rays passing through an object are exposed to a special film, an image of the object is produced

due to the partial absorption of the rays.

In practical terms, a radioactive source is placed on one side of a component such as a pipe, at a weld,

and a film is placed on the opposite side. If x-rays are directed through the weld and there is a void within

the weld, more rays pass through this void and reach the film, producing a darker image at that point. By

examining the radiographic films, the weld integrity can be determined. During the field erection of a boiler

and power station, thousands of tube and pipe welds are made and radiographed.

The major disadvantage of radiography is the harmful effect of excessive exposure to the radioactive rays.

RT is also limited in its ability to provide the orientation and depth of an indication.

4.1.7 NUCLEAR FLUORESCENCE

The primary use of this testing in condition assessment is the verification of alloy materials in high

temperature piping systems. When certain elements are exposed to an external source of x-rays they

fluoresce (emit) additional x-rays that vary in energy level. This fluorescence is characteristic of the key

alloys common to high temperature piping and headers. Chromium and molybdenum are the key elements

measured. The nuclear alloy analyzer is a portable instrument that contains a low level source of x-rays.

A point on the surface of the pipe is exposed to x-rays emitted from the analyzer. As the source x-rays

interact with the atoms of the metal, the alloys emit x-rays back to the analyzer. Within the detector system

of the analyzer, the fluoresced x-rays are separated into discrete energy regions. By measuring the x-ray

intensity in each energy region, the elemental composition is also determined.

4.1.8 ELECTROMAGNETIC ACOUSTICS

Electromagnetic acoustics combine two nondestructive testing sciences, ultrasonics (UT) and

electromagnetic induction. This technology uses an electromagnetic acoustic transducer (EMAT) to

generate high frequency sound waves in materials, similar to conventional ultrasonics. Conventional UT

transducers used for field testing convert electrical impulses to mechanical pulses by use of piezoelectric

crystals. These crystals must be coupled to the test piece through a fluid couplant. For electrically

conductive materials, ultrasonic waves can be produced by electromagnetic acoustic wave generation. 5

In contrast to conventional contact UT where a mechanical pulse is coupled to the material, the acoustic

wave is produced by the interaction of two magnetic sources. The first magnetic source modulates a time-

dependent magnetic field by electromagnetic induction as in eddy current testing. A second constant

magnetic field provided by an AC or DC driven electromagnet or a permanent magnet is positioned near

the first field. The interaction of these two fields generates a force, called the Lorentz force, in the direction

perpendicular to the two other fields. This Lorentz force interacts with the material to produce a shock

wave analogous to an ultrasonic pulse, eliminating the need for a couplant.

Figure 13 – Basic principles of EMAT operation; shows the basic principles of EMAT operation. A strong

magnetic field (B) is produced at the surface of the test piece by either a permanent magnet or

electromagnet. Eddy currents (J) are induced in the test material surface. An alternating eddy flow in the

presence of the magnetic field generates a Lorentz force (F) that produces an ultrasonic wave in the

AJ2

PROJECT MANAGEMENT


Synergy Engineers


material. For boiler tubes that are electromagnetically conductive (including alloys such as SA-213T22),

the EMAT technology is ideal.

Figure 13 – Basic principles of EMAT operation

B&W, working with the Electric Power Research Institute (EPRI), developed a nondestructive rapid scan

system to inspect boiler tubes using EMAT technology. This EMAT based system is known as the Fast-

Scanning Thickness Gage (FST-

a continuous measurement of tube wall thickness. (Figure 14 – B&W´s Fast-Scanning Thickness Gage

(FST-GAGE®)). The system conducts tests at exceptional speeds, allowing scanning of thousands of feet

(m) of boiler tubing in a single shift. To perform an inspection, the FST-GAGE system is manually scanned

along individual boiler tubes. System sampling rates greater than 65 samples per second supports rapid

scanning of tubes. During a scan, the system provides an immediate display of both tube wall thickness

and signal amplitude. At the conclusion of each tube scan, a complete record of the inspection is

electronically stored and is traceable to each boiler tube and position.

Figure 14 – B&W´s Fast-Scanning Thickness Gage (FST-GAGE®)

EMAT based system can provide continuous measurement of tube wall thickness.

AJ2

PROJECT MANAGEMENT


Synergy Engineers


As with conventional UT, the FST-GAGE system can assess internal tube damage by evaluating the loss

of signal amplitude (attenuation) as a shear wave is transmitted through the tube wall. By monitoring and

indicating signal amplitude, the system can also be used to detect tube damage such as hydrogen

damage, similar to B&W’s patented FHyNES technique. The FST-GAGE has also demonstrated the ability

to detect internal tube pitting, caustic gouging, and under-deposit corrosion.

As with any NDE method, surface preparation is important for effective testing with EMATs. However,

EMAT is not as sensitive to scale as conventional UT since it produces the ultrasonic wave within the

material. Some scales, such as magnetite oxide of uniform thickness, have no detrimental effect on the

signal generation of the EMAT probe. When the plant burns a clean fuel such as natural gas, testing may

be conducted without any special surface cleaning. To protect the coil from damage, surface preparation

will normally be required for boilers firing oil or solid fuels. Some gas-fired units may require surface

cleaning if external buildup or corrosion is present. Grit blasting or water blasting are effective methods of

cleaning larger areas. Smooth metal is the preferred surface to ensure rapid testing.

EMAT technology continues to be applied where its unique properties have advantages over conventional

UT techniques. B&W and EPRI are developing a system for the detection of cracking in boiler tubes

associated with corrosion fatigue. Waterside corrosion fatigue is a serious boiler tube failure mechanism.

The failures usually occur close to attachments such as buckstay welds, wind-box attachment welds, or

membrane welds. The combination of thermal fatigue stresses and corrosion leads to ID-initiated cracking

that is oriented along the tube axis. The EMAT system under development for corrosion fatigue has unique

characteristics that enhance its ability to scan past welds and attachments and scan the full circumference

of the boiler tube. The EMAT equipment uses a tone burst EMAT signal allowing the use of horizontally

polarized shear wave (SH waves) to detect cracking adjacent to external tube attachment welds.

B&W has developed an EMAT application to inspect horizontal banks (i.e., economizer, re-heater) of

tubing within the boiler. Horizontal bank tubing may experience tube failures caused by out of service

corrosion pitting forming aligned voids in the tube ID. The purpose of this EMAT test is to detect the internal

aligned pitting at the lower portion of the horizontal tube internal surface. The test is accomplished by

scanning along the outside of the horizontal tube at either the 3 or 9 o’clock positions with an EMAT

transducer generating a Lamb wave (ultrasonic waves that travel at right angles to the tube surface) which

is focused at the 6 o’clock position on the tube.

B&W has also developed a surface wave EMAT application to show surface indications including axially

oriented cracks in boiler tubes. Conventional surface nondestructive test methods were unsatisfactory

because they lacked adequate sensitivity and had slow production rates for testing on large areas. A tone

burst EMAT technique was developed that uses a bidirectional focused surface wave EMAT that follows

the tube surface circumferentially until the signal is reflected back from a longitudinally orientated OD

crack.

4.1.9 ACOUSTICS

Acoustics refers to the use of transmitted sound waves for nondestructive testing. It is differentiated from

ultrasonics and electromagnetic acoustics in that it features low frequency, audible sound. B&W uses

acoustic technology in testing tubular air heaters. Because the sound waves are low frequency, they can

AJ2

PROJECT MANAGEMENT


Synergy Engineers


only be transmitted through air. A pulse of sound is sent into the air heater tube. As the wave travels along

the tube, it is reflected by holes, blockage or partial obstructions. By evaluating the reflected wave on an

oscilloscope, the type of flaw and its location along the tube can be determined.

4.1.10 ACOUSTIC EMISSIONS

Acoustic emissions (AE) detect subsurface crack growth in pressure vessels. When a structure such as a

pipe is pressurized and heated, the metal experiences mechanical and thermal stresses. Due to the stress

concentration at a defect such as a crack, a small overall stress in the pipe can produce localized yield

and fracture stresses resulting in plastic deformation. These localized yields release bursts of energy or

stress wave emissions that are commonly called acoustic emissions. AE testing uses acoustic transducers

that are positioned along the vessel being monitored. AE signals are received at various transducers on

the vessel. By measuring the time required for the signal to reach each of the transducers, the data can

be interpreted to identify the location of the defect.

4.1.11 METALLOGRAPHIC REPLICATION

Metallographic replication is an in situ test method that enables an image of the metal grain structure to

be nondestructively lifted from a component. Replication is important in evaluating high temperature

headers and piping because it allows the structure to be examined for creep damage. Prior to the use of

replication techniques, it was necessary to remove samples of the material for laboratory analysis. The

replication process involves three steps: grinding, polishing and etching, and replicating. In the first step,

the surface is rough ground then flapper wheel ground with finer grit paper. In the second step, the surface

is polished using increasingly finer grades of diamond paste while intermittently applying a mixture of nitric

acid and methanol in solution. The acid solution preferentially attacks the grain boundaries of the metal.

In the final step, the replica, which is a plastic tape, is prepared by coating one face of the tape with

acetone for softening. The tape is then firmly pressed onto the prepared surface. Following a suitable

drying time, the tape is removed and mounted onto a glass slide for microscopic examination.

4.1.12 STRAIN MEASUREMENT

Strain measurements are obtained nondestructively by using strain gauges. Gauges used for piping

measurements are characterized by an electrical resistance that varies as a function of the applied

mechanical strain. For high temperature components, the gauge is made of an alloy, such as platinum-

tungsten, which can be used at temperatures up to 1200º F (649º C). The gauge is welded to the surface

of the pipe and the strain is measured as the pipe ramps through a temperature-pressure cycle to

operating temperature. Strain gauges used for lower temperature applications such as for analysis of

hanger support rods are made of conventional copper-nickel alloy (constantan). These low temperature

gauges are made of thin foil bonded to a flexible backing and are attached to the test surface by a special

adhesive.

4.1.13 TEMPERATURE MEASUREMENT

Most temperature measurements can be obtained with sheathed thermocouples (TC). In special

applications where temperature gradients are needed such as detailed stress analysis of header

AJ2

PROJECT MANAGEMENT


Synergy Engineers


ligaments, special embedded TCs are used. The embedded unit is constructed by drilling a small hole into

the header. A sheathed TC wire is then inserted and peened in place.

4.2 DESTRUCTIVE EXAMINATIONS

B&W tries to minimize the use of sample analysis because it is generally more expensive to perform

destructive testing. However, for certain components, complete evaluation can only be done by removing

and analyzing test samples. Destructive testing is described for two types of specimens, tube samples

and boat samples.

4.2.1 TUBE SAMPLES

Tubes are the most common destructively tested components. Tube samples are generally removed from

water- and steam-cooled circuits. A relatively large number of samples may be removed for visual

inspections, from which a smaller number are selected for complete laboratory analysis. A tube analysis

usually includes the following:

1. As-received sample photo documentation,

2. Complete visual inspection under magnification,

3. Dimensional evaluation of a ring section removed from the sample,

4. Material verification by spectrographic analysis,

5. Optical metallography, and

6. Material hardness measurement.

On water-wall tubes removed from the boiler furnace, the analysis includes a measurement of the internal

deposit loading [g/ft2 (g/m2)] and elemental composition of the deposit. On steam-cooled super-heater and

re-heater tubes, the thickness of the high temperature oxide layer is also provided. Specialized tests are

performed as required to provide more in-depth information. Failure analysis is a common example. When

failures occur in which the root cause is not readily known from standard tests, fractography is performed.

Fractography involves examination of the fracture surface using a scanning electron microscope.

4.2.2 BOAT SAMPLES

Boat samples are wedge shaped slices removed from larger components such as headers, piping and

drums. The shape of the cut allows the material to be replaced by welding. Because the repairs usually

require post weld heat treating, the use of boat samples is expensive. In most instances, replication is

adequate for metallographic examination of these components and boat sample removal is not required.

4.3 ADVANCES IN NON-DESTRUCTIVE EXAMINATIONS

Innovative techniques are being developed to replace or enhance existing NDE methods. Some are

becoming viable due to advancements in microprocessor technology. Others are relatively new and may

replace current methods. Advanced techniques include:

1. Infrared scanning.

2. Automated Phased Array UT.

3. Pipe and wall scanners which automatically cover large areas.

AJ2

PROJECT MANAGEMENT


Synergy Engineers


4. Through-insulation radiography.

EMAT technology is being refined and studied for further applications in the NDE field.

5 SITE INSPECTION OF BOILER COMPONENTS AND AUXILIARIES

In Phase 1 of a condition assessment program, interviews of plant personnel and review of historical

maintenance records help identify problem components. These components are targeted for a closer

onsite examination during Phase 2 of the program. Nondestructive and destructive examination methods

can then be used to evaluate the remaining life of the boiler components and its major auxiliaries.

5.1 EXTERNAL BOILER INSPECTION

The external boiler inspection may be conducted when the boiler is operating or shutdown. If possible, an

external inspection should begin before shutdown in order to detect hot spots, leaks, etc. during operation.

An external inspection determines the amount of deterioration and is used to evaluate whether the boiler

is operating safely. The external boiler inspection may be conducted at any time and should include the

following:

1. Ladders, stairways and platforms

2. Air and flue gas ducts

3. Boiler support structure

4. Stack

5. Support structure & boiler casing

6. Boiler piping

7. Instrumentation

8. Safety relief valves

9. Paint and insulation

10. Boiler circulating pumps

11. Vents and drains

5.1.1 LADDERS, STAIRWAYS AND PLATFORMS

This inspection will insure that you can move around the equipment. The primary means of inspection is

visual. Hammering and scraping to remove oxide scales and other corrosion products may also be

necessary. Inspect for the following:

5.1.1.1 CRACKS

Inspect welds and structural steel for cracks. Remove floor plates to inspect supporting structure. Inspect

crevices by picking them with a pointed scraper. Determine if a crack warrants repair or further inspection

via ultrasonic measurements.

AJ2

PROJECT MANAGEMENT


Synergy Engineers


5.1.1.2 TIGHTNESS OF BOLTS

Bolt tightness can be determined by tapping with an inspector’s hammer or by trying the nuts with a

wrench. Note any loose bolts on the inspection sheet. Note any thread wear. Bolts that continue to loosen

up between inspections may indicate a structural fault.

5.1.1.3 CONDITION OF PAINT OR GALVANIZED MATERIAL

5.1.1.4 WEAR ON LADDER RUNGS AND STAIR TREADS.

Inspect depressions carefully because water lying in depressions can cause corrosion. Find loose or

broken parts by tapping with an inspectors hammer

5.1.1.5 SECURITY OF HANDRAILS

Inspect for broken braces, supports, or signs of movement. Inspect anchor points for deterioration.

5.1.1.6 THE CONDITION OF FLOORING

Check for any unsafe conditions. Check for worn flooring that could become slippery. Be especially

observant of any overhangs in and around platforms and ladders that may project into path during use.

5.1.2 FANS

Both forced and induced draft fans should be inspected when a boiler is shutdown. The inspection should

include:

1. Removal and inspection of motor including bearings and lubricant

2. Rotor and rotor blade inspection for loose blades. Examination of coupling and alignment of all parts

3. Inspection of induced draft fans for corrosion

4. Inspection of all dampers for operability and corrosion

5.1.3 AIR DUCTS AND FLUE GAS DUCTS

Inspect ducts for any signs of oxidation and the condition of the painted surfaces while the unit is in

operation. Some breeching and ducts are protected internally by refractory. Discoloration or destruction

of painted surfaces may indicate leakage through the refractory. Inspect the seams and joints for any

indications of cracking and leakage. Hammer testing can indicate thin area in ducting and breeching. Thin

areas may indicate internal corrosion. Check alignment of ducts that may indicate failure of supports or

shifting of equipment. Inspect expansion joints to ascertain their general condition and the presence of

cracks in the thinner, flexible joint material.

5.1.4 SUPPORT STRUCTURE AND BOILER CASING

The support structure includes all beams, columns, and girders that support the boiler as well as

foundations.

Inspect all load carrying structural steel for bending which may indicate weakening due to overloading,

lateral forces, corrosion or overheating due to leaks in the refractory. Inspect structural steel for corrosion.

AJ2

PROJECT MANAGEMENT


Synergy Engineers


Inspect all connections between columns, beams and girders. Visually inspect walls and wall alignment

for any signs of bulging or movement. Inspect walls for signs of hot spots or discoloration that would

indicate refractory problems. (See section 5.3 on page 46).

Foundations are steel reinforced concrete. Inspect the foundation for calcining, settling, cracks, and/or

spalling. One of the main causes of deterioration of the foundation is high temperature. High temperature

may cause calcining and/or cracks. Calcining is the drying out of concrete so that it has very little cohesion.

Locate calcining by chipping at the suspected area with a hammer.

Cracks in concrete may be caused by high temperature, poor design, and/or improper installation

(materials, curing). Cracks provide an entrance for water to corrode the reinforcing steel. When the steel

corrodes, it expands making cracks wider, which results to more corrosion. Spalling can result from

internal corrosion of reinforcing steel and/or overheating.

All foundations settle to some extent. Little or no trouble may be experienced if the settling is small and

evenly distributed. When settlement is noted, examine all pipe connections to the boiler. Inspect all anchor

points for the support structure for indications of excessive stress. Check various points with a bubble

level to find settlement. Spalling is a form of concrete deterioration caused by heat, corrosion of steel or

insufficient thickness of concrete over reinforcement. Major cracks or spalling may indicate the necessity

to removal of a core for testing.

Note all deficiencies on the inspection sheets.

5.1.5 STACK

Stacks have been known to collapse when allowed to deteriorate.

Deposits that accumulate in the stack can be explosive.

Deposits should be removed occasionally.

Inspect brick, concrete, and steel stacks for conditions that may weaken these structures. Use field

glasses to inspect high stacks from the ground. Use infrared temperature measurements to look for hot

spots that would indicate internal refractory problems.

Conduct a thorough hammer testing of the steel stacks. Pay particular attention to the seams, stiffening

rings, lugs, and nozzles. Acids in the flue gas that may condense may attack the upper cool portion of a

stack.

Inspect bolts at the base and at elevated sections for loosening and breakage. Check a loose bolt for

abrasion from movement of the structure. Inspect guy lines for corrosion. Inspect lightning rods and

grounding cables to see that they are securely grounded and not corroded. Guy line connections to the

dead-man at the bottom, and at the top are especially subject to corrosion due to moisture settling retained

around these connections. Guy wires should be replaced at safe intervals, since inspection is impractical

between the dead-man and the top. The electrical resistance of the ground should be less than 25 ohms.

AJ2

PROJECT MANAGEMENT


Synergy Engineers


5.1.6 BOILER PIPING

A leak or failure in a piping system may be a major problem or a minor inconvenience, depending on the

location and service. Study historical records to determine which sections may be approaching retirement

thickness. Inspect all lines including vents, drains, fuel supply lines, steam atomizing lines and fuel

smothering steam piping.

Inspect piping supports, and spring hangers for external corrosion, distortion, damage, settlement or

movement of the foundation.

Inspect for internal corrosion, using ultrasonic testing. X-ray and/or inspect internally when the lines are

opened. Ultrasonic inspection may not detect pitting, which is why internal visual inspection is important.

5.1.7 INSTRUMENTATION

Inspect all lines to instrumentation for leakage. Inspect all control valves for leakage. Verify if any safety

devices or alarms are bypassed. Alarm and shutdown settings should be verified when possible.

Inspect water glasses, since these are extremely important in operating the boiler. Make sure they are

well lit. Have the operator blow down the water gage in a normal manner and observe how the level

returns. A sluggish response may indicate an obstruction in the pipe connections to the boiler.

Check pressure gages in the field against those in the control room. Test the pressure with a test gage.

5.1.8 PAINT AND INSULATION

Visually inspect the condition of the protective coating and/or insulation. Any cracks or openings should

be repaired. Any rust spots and or bulging may indicate corrosion underneath thus, further inspection may

be required. Scrapping paint away from blisters or rust spots often reveals pits in the vessel walls. Measure

the depth of pitting with a pit gage. The most likely spots for paint failure are in crevices, in constantly

moist areas, and at welded seams.

5.2 INTERNAL BOILER INSPECTION

Internal boiler inspection can only be done when the boiler has been shut-down, properly blanked, and

purged. Internal inspection of the boiler may require removal of much of the casing and

insulation/refractory. Boilers should not be entered until entry can be done safely.

Internal boiler inspections are conducted whenever a boiler is shutdown. It is opened to determine the

amount of deterioration, and evaluated if the deterioration affects the safe use of the boiler. The main

types of deterioration are as follows: corrosion, erosion, metallurgical and physical changes, and

mechanical forces. Metallurgical changes include cracking and micro structural changes such as

graphitization, carbide precipitation, inter-granular corrosion, and embrittlement. Mechanical forces

include thermal shock, cyclic temperature changes, vibration, excessive pressure surges, and external

loads.

AJ2

PROJECT MANAGEMENT


Synergy Engineers


5.2.1 SAFE ENTRY

Entry into a boiler is not safe until the following have been done:

1. All fuel supply lines have been blocked in and blinded.

2. The boiler has been purged and tested to be free of fuel and flue gases.

3. Pumps are shut-down and tagged.

4. All feed valves have been blocked, tagged, padlocked and blinded, if necessary. Boiler has been

rained of all liquids. All drain lines and vents are open.

5. Manhole and hand-hole plates have been removed.

6. Boiler has cooled sufficiently for safe entry.

7. An entry permit has been issued.

5.2.2 REFRACTORY

The firebox refractory should be visually inspected for breakage, crumbling, spalling, and open joints.

Leakage of hot gases through the joints when the edges have crumbled, or when the tile or insulating

concrete has fallen out, may expose supporting steel to high metal temperatures, rapid oxidation, and

corrosion.

Fly-ash corrosion may occur, when fly ash and refractory are in contact. Fluxing occurs and produces a

slag that may be fluid at heater operating conditions. Slagging may cause rapid deterioration of hardware,

such as tube hangers. Metal oxides found in fuel oil are the fluxing agents that cause slagging. Spalling

can be caused by overheating, or heating up too fast after a turnaround or after repairs to refractory.

Sagging of refractory would indicate problems with the refractory supports. Overheating or corrosion of

supports usually causes support problems.

External deposits may indicate the need for external water washing. The water washing procedure may

include sealing the refractory with bitumen sealer to prevent water damage of the refractory, and the use

of 0.5% soda ash solution to minimize stress cracking of austenitic steels such as stainless steels. Under

no circumstances should raw water or salt water be used for water washing boilers. The bitumen sealer

will be burned off during normal operation.

Inspect all baffles for condition of baffle and refractory protecting baffles. Inspect the linings of all stacks

and ducts for cracks, wear, and structural soundness. Use ultrasonic measurements to check wall

thickness.

Field experience has demonstrated that corrosive slag in any form should be kept away from the tubes by

a refractory coating. Experience on operating units has proven that the most durable refractories are ram-

type high density formulations. The specific refractory selection may be contingent upon the specific plant

fuel.

Key overall issues to achieve the best potential chance for increased refractory life include:

1. Ensure proper maintenance/application of studs (along with maximizing stud density).

2. Choose the proper refractory for the application (proven positive experience).

3. Use refractory that has not exceeded its shelf life.

AJ2

PROJECT MANAGEMENT


Synergy Engineers


4. Follow proper refractory installation and curing procedures.

5. Follow good Cyclone startup/operation procedures.

Any one of these items done incorrectly can cause early loss of refractory.

5.2.3 STEAM DRUM

The steam drum is the most expensive boiler component and must be included in any comprehensive

condition assessment program. There are two types of steam drums, the all-welded design used

predominantly in electric utilities where the operating pressures exceed 1800 psi (12.4 MPa), and drums

with rolled tubes. The steam drum operates at saturation temperature [less than 700º F (371º C)]. Because

of this relatively low operating temperature, the drum is made of carbon steel and is not subject to

significant creep. Creep is defined as increasing strain at a constant stress over time.

Regardless of drum type, damage is primarily due to internal metal loss. The causes of metal loss include:

corrosion and oxidation, which can occur during extended outages; acid attack; oxygen pitting; and chelant

attack. Damage can also occur from mechanical and thermal stresses on the drum that concentrate at

nozzle and attachment welds. These stresses, most often associated with boilers that are on/off cycled,

can result in crack development. Cyclic operation can lead to drum distortion (humping) and can result in

concentrated stresses at the major support welds, seam welds, and girth welds. The feed-water

penetration area has the greatest thermal differential because incoming feed-water can be several

hundred degrees below drum temperature.

A problem unique to steam drums with rolled tube seats is tube seat wee-page (slight seeping of water

through the rolled joint). If the leak is not stopped, the joint, with its high residual stresses from the tube

rolling operation, can experience caustic embrittlement. In addition, the act of eliminating the tube seat

leak by repeated tube rolling can overstress the drum shell between tube seats and lead to ligament

cracking.

Condition assessment of the steam drum can include visual and fiber optic scope examination, MT, PT,

WFMT, UT and replication.

5.2.4 BOILER TUBING

5.2.4.1 STEAM-COOLED

Steam-cooled tubing is found in the super-heater and reheat super-heater. Both components have tubes

subjected to the effects of metal creep. Creep is a function of temperature, stress and operating time. The

creep life of the super-heater tubes is reduced by higher than expected operating temperature, thermal

cycling, and by other damage mechanisms, such as erosion and corrosion, causing tube wall thinning and

increased stresses. Excessive stresses associated with thermal expansion and mechanical loading can

also occur, leading to tube cracks and leaks independent of the predicted creep life.

Super-heater tubing can also experience erosion, corrosion, and interacting combinations of both.

Condition assessment of the super-heater tubes includes visual inspection, NOTIS, UTT and tube sample

analysis. Problems due to erosion, corrosion, expansion, or excessive temperature can generally be

located by visual examination.

AJ2

PROJECT MANAGEMENT


Synergy Engineers


5.2.4.2 WATER-COOLED

Water-cooled tubes include those of the economizer, boiler (generating) bank and furnace. The convection

pass side wall and screen tubes may also be water-cooled. These tubes operate at or below saturation

temperature and are not subject to significant creep. Modern boilers in electric utilities and many industrial

plants operate at high pressures. Because these boilers are not tolerant of waterside deposits, they must

be chemically cleaned periodically, which results in some tube material loss. Proper water chemistry

control will limit tube inside surface material loss due to ongoing operations and cleaning.

With the exception of creep deformation, the factors that reduce steam-cooled tube life can also act upon

water-cooled tubes. Erosion is most likely to occur on tube outside surfaces in the boiler or economizer

bank from soot-blowing or ash particle impingement. Corrosion of the water-cooled tubes is most common

on internal tube surfaces and results from excessive waterside deposits. Deposit accumulations promote

corrosion, caustic gouging or hydrogen damage.

5.2.5 RISERS

The riser tubes are generally found in the penthouse or over the roof of the boiler. They carry the saturated

steam-water mixture exiting the upper water-wall headers to the steam drum. Condition assessment

includes UTT measurements on non-drainable sections and on the extrados (outside surface) of bends.

When access is available it is advantageous to perform internal visual inspection with a fiber optic or video

probe.

5.2.6 HEADERS

Headers and their associated problems can be grouped according to operating temperature. High

temperature steam-carrying headers are a major concern because they have a finite creep life and their

replacement cost is high. Lower temperature water and steam-cooled headers are not susceptible to creep

but may be damaged by corrosion, erosion, or severe thermal stresses.

5.2.6.1 HIGH TEMPERATURE

The high temperature headers are the super-heater and re-heater outlets that operate at a bulk

temperature of 900º F (482º C) or higher. Headers operating at high temperature experience creep under

normal conditions. The mechanics of creep crack initiation and crack growth are further discussed in the

data analysis section of this chapter. Figure 15 - header locations susceptible of cracking; illustrates the

locations where cracking is most likely to occur on high temperature headers. In addition to material

degradation resulting from creep, high temperature headers can experience thermal and mechanical

fatigue. Creep stresses in combination with thermal fatigue stress lead to failure much sooner than those

resulting from creep alone.

There are three factors influencing creep fatigue in super-heater high temperature headers: combustion,

steam flow and boiler load. Heat distribution within the boiler is not uniform: burner inputs can vary, air

distribution is not uniform, and slagging and fouling can occur. The net effect of these combustion

parameters is variations in heat input to individual super-heater and re-heater tubes. When combined with

steam flow differences between tubes within a bank, significant variations in steam temperature entering

AJ2

PROJECT MANAGEMENT


Synergy Engineers


the header can occur. See Figure 16 - Steam temperature variation in a header. Changes in boiler load

further aggravate the temperature difference between the individual tube legs and the bulk header. As

boiler load increases, the firing rate must increase to maintain pressure. During this transient, the boiler is

temporarily over fired to compensate for the increasing steam flow and decreasing pressure. During load

decreases, the firing rate decreases slightly faster than steam flow in the super-heater with a resulting

decrease in tube outlet temperature relative to that of the bulk header Figure 17 - Super-heater tube leg

temperatures vary with load. As a consequence of these temperature gradients, the header experiences

localized stresses much greater than those associated with steam pressure and can result in large

ligament cracks as shown in Figure 18 - Large ligament cracks on header ID. In addition to the effects of

temperature variations, the external stresses associated with header expansion and piping loads must be

evaluated. Header expansion can cause damage on cycling units resulting in fatigue cracks at support

attachments, torque plates, and tube stub to header welds. Steam piping flexibility can cause excessive

loads to be transmitted to the header outlet nozzle. These stresses result in externally initiated cracks at

the outlet nozzle to header saddle weld.

Figure 15 - header locations susceptible of cracking

Condition assessment of high temperature headers should include a combination of NDE techniques that

are targeted at the welds where cracks are most likely to develop. Creep of the header causes it to swell;

the diameter should be measured at several locations on the header and the outlet nozzle. All major

header welds, including the outlet nozzle, torque plates, support lugs, support plates and circumferential

girth welds, should be examined by MT or PT. A percentage of the stub to header welds should be

examined by PT. Each section of the header should be examined by eddy current or acid etching to locate

the seam if it is not readily apparent. The seam weld is examined for surface indications by MT or PT, and

ultrasonic shear wave testing is performed to locate subsurface flaws. To examine the header for creep

damage, metallographic replication is performed. The last test that should be performed on any high

temperature header is internal examination of at least two tube bore holes. This test is considered the

most effective. Ideally, the evaluation should correspond to the hottest location along the header.

AJ2

PROJECT MANAGEMENT


Synergy Engineers


Figure 16 - Steam temperature variation in a header

Figure 17 - Super-heater tube leg temperatures vary with load

AJ2

PROJECT MANAGEMENT


Synergy Engineers


Figure 18 - Large ligament cracks on header ID.

5.2.6.2 LOW TEMPERATURE

The low temperature headers are those operating at temperatures below which creep is a consideration.

These include water-wall headers, economizer inlet and outlet headers, and super-heater inlet and

intermediate headers. Any damage to the low temperature headers is generally caused by corrosion or

erosion. Water-wall headers, found in most electric utility and industrial power generation boilers, are

generally located outside the hostile environment of the combustion zone. One exception is the

economizer inlet header; this may be in the gas stream and is subject to unique problems associated with

cycling. Boilers that are held overnight in a hot standby condition without firing can experience severe

damage to the economizer inlet header in a very short time. This damage is typically caused by thermal

shock.

The magnitude of the thermal shock is a function of the temperature differential between the feed-water

and the inlet header. It is also a function of water flow, which is usually large because the feed-water

piping/ valve train is sized for rated boiler capacity. The thermal shock is worst near the header feed-water

inlet and rapidly decreases as flow passes into the header and tubes. The primary concern with other low

temperature headers is internal and external corrosion during out of service periods. Lower water-wall

headers on stoker-fired boilers that burn coal or refuse may experience erosion along the side walls

adjacent to the stoker grates.

5.2.7 ATTEMPERATORS

The attemperator, or desuperheater, is located in the piping of the super-heater and is used for steam

temperature control. The spray attemperator is the most common type used. (See Figure 19 - Typical

attemperator assembly) In the spray unit, high quality water is sprayed directly into the superheated steam

AJ2

PROJECT MANAGEMENT


Synergy Engineers


flow where it vaporizes to cool the steam. The attemperator is typically located in the piping between the

primary super-heater outlet header and the secondary super-heater inlet header. Steam exiting the

primary header at temperatures of 800º to 900º F (427º to 482º C) enters the attemperator, where relatively

cool water [approximately 300º F (149º C)] is sprayed into the steam and reduces the temperature to the

inlet of the secondary super- eater. Because of the large temperature difference between the steam and

spray water, parts of the attemperator experience thermal shock each time it is used. Over a period of

years this can lead to thermal fatigue and eventual failure (Figure 20 - Failed attemperator spray head).

Figure 19 - Typical attemperator assembly

Figure 20 - Failed attemperator spray head

Condition assessment of the attemperator requires removal of the spray nozzle assembly. The thermal

stresses occurring in the attemperator are most damaging at welds, which act as stress concentrators.

The spray head and welds on the nozzle assembly are examined visually and by PT to ensure there are

no cracks. With the spray head removed, the liner can be examined with a video or fiber optic probe. For

larger attemperators, it may be necessary to remove radiograph plugs before and after the attemperator

to better view the critical liner welds.

AJ2

PROJECT MANAGEMENT


Synergy Engineers


5.2.8 HIGH TEMPERATURE PIPING

5.2.8.1 DAMAGE MECHANISMS

Damage to high temperature piping systems operating at more than 800º F (427º C) arises from creep,

cycle fatigue, creep fatigue, and erosion-corrosion.

Most modern high temperature piping systems are designed for temperatures ranging from 950º to 1050º

F (510º to 566º C), or higher. The American Society of Mechanical Engineers (ASME) allowable material

stresses at these temperatures may produce creep rupture in approximately 30 to 40 years. Systems

designed from 1950 through 1965, that used 1-1/4 Cr- 1/2 Mo alloy steel, may be under-designed by

today’s standards because the ASME Code has evolved, lowering the allowable high temperature stress

for this material.

Fatigue damage to a piping system is caused by repeated cyclic loading, which can be the result of

mechanical loads, thermal expansion and contraction, and vibration. Most piping systems are designed

with some degree of fatigue resistance. This built-in flexibility comes from hangers and supports.

Creep and fatigue can occur together and interact to cause more damage than each mechanism by itself;

it is not fully understood which mechanism is the primary cause. This combination of conditions is by far

the most prominent because most power piping systems are highly dynamic.

Erosion-corrosion is not as prominent as the creep fatigue failure mechanisms. It is defined as wall thinning

that is flow induced and occurs on the fluid side of the piping system. Factors that contribute to erosion-

corrosion include bulk fluid velocity, material composition and fluid percent moisture.

5.2.8.2 OVERALL EVALUATION PROGRAM

When evaluating high temperature piping, condition assessment is usually necessary if the following

conditions exist: piping operates above 1000º F (538º C); was manufactured of SA335-P11 or P22

material, or manufactured of long seam welded material; has had hanger problems; was manufactured

with specific weld joint types; has a history of steam leaks; or operates above design conditions. Once a

priority list is developed, the evaluation can begin. This evaluation program should be as complete as

economically possible.

5.2.9 DETAILED EVALUATION PROGRAM

5.2.9.1 Phase I

To determine where physical testing is required, the following preliminary steps are part of a Phase I

evaluation: plant personnel interviews, plant history review, walk-downs, stress analysis, and life fraction

analysis.

Plant personnel interviews are conducted to gather information that is not readily available from plant

records. Significant history may only be found in recollections of experienced personnel.

Operating history reviews complement personnel interviews. They can provide problem histories and

design or operating solutions.

AJ2

PROJECT MANAGEMENT


Synergy Engineers


Piping system walk-downs serve three major functions: to evaluate pipe supports and hangers, to find

major bending or warpage, and to verify changes.

Pipe hangers and supports should be carefully examined. This can be done by creating a baseline

inspection record of all supports.

While the data are being taken on the piping walk-down, the general appearance should also be noted. In

particular, inspections may reveal the following damages: necked-down rods or yokes, spring coil

fractures, deterioration of the hanger can, and deterioration of tiebacks into building steel.

Many times a walk-down reveals that a modification was performed. If the entire system was not reviewed

during the modification, other problems may result.

Stress analysis of the piping system can now be performed. Typically, a computer program is used to

perform the stress calculations based on design and any abnormal conditions found during the walk-down.

Once a piping system is modeled, the analysis allows the engineer to pinpoint high stress locations. The

objective is to limit the nondestructive examination work to these high stress areas.

Life fraction analysis (LFA) of a pipe is done if the primary failure mode is creep due to operating

temperatures above 900º F (482º C). The LFA is based on the unit’s operating history and stress levels

are calculated using design conditions and minimum wall thicknesses. This analysis is discussed at length

later.

5.2.9.2 Phase II

Phase II of the evaluation includes all physical testing of the piping system. The majority of the testing

should be nondestructive; however, some destructive testing may be required. The results from Phase I

testing provide test location priority. Specific test recommendations are shown in Table 1 – Typical Piping

System Tests.

The test data generated from the inspections must be evaluated to determine the remaining component

life. This is known as the Phase III evaluation and is covered under Analysis techniques.

Table 1 – Typical Piping System Tests

TEST AREA TEST TYPE OPTIONAL*

Circumferential welds A, B, D, E, F, G, H C, I, J

Longitudinal welds A, B, D, E, F, G, H C, I, J

Wye blocks A, B, E, F, G, H C, D, I, J

Hanger sheer lugs A, B C, F, G, J

Hanger bracket and supports A, B C, F, G, J

Branch connections A, B, D, E, F, G, H C, I, J

RT plugs A, B C, F, G, I

Miscellaneous taps and drains A, B C, I

Elbows / bends A. E, F B, C, G

* Optional tests should be used to gather more detailed information

AJ2

PROJECT MANAGEMENT


Synergy Engineers


A Visual F Replication

B Magnetic particle G Material ID

C Liquid penetrant H Dimensional

D Ultrasonic sheet I Radiography

E Ultrasonic thickness J Metallography

5.2.10 TYPICAL FAILURES

The most typical steam pipe failure is cracking of attachment welds (support welds or shear lugs). These

cracks are caused by thermal fatigue, improper support, or improper welding.

Radiograph plugs often have cracked seal welds. Although the plug threads are the pressure bearing

surfaces, they can become disengaged over time due to corrosion, creep swelling or oxidation.

Steam pipe warping is another serious problem. If the pipe has deformed, it has undoubtedly gone through

a severe thermal shock. The high strain between the upper and lower sections of pipe can cause

permanent deformation.

Two final common failure areas are the boiler outlet headers and turbine stop (throttle) valves. These

areas should always be considered in any piping evaluation.

5.2.11 LOW TEMPERATURE PIPING

Low temperature piping operating at less than 800º F (427º C) is not damaged by creep. These systems

typically fail due to fatigue, erosion or corrosion. The evaluation methods are the same as those for high

temperature piping; however, a finite life is not predicted. Low temperature pipes, if maintained, last much

longer than their high temperature counterparts. Typical systems are reheat inlet steam lines, extraction

lines, feed-water lines and general service water lines.

5.2.11.1 TYPICAL FAILURES

Many high temperature failure modes occur in low temperature pipes. Cold reheat lines experience

thermal shock because the reheat temperature control is typically an in-line attemperator. The

attemperator spray can shock the line if the liner is damaged or the nozzle is broken. Economizer

discharge lines that run from the economizer outlet header to the boiler drum can be damaged during

startup sequences. If the economizer is steaming and flow is initiated as a water slug, the line can

experience severe shocks. This can cause line distortion and cracking at the end connections and support

brackets. Other low temperature piping can be damaged by oxygen pitting caused by inadequate water

treatment. Erosion due to flow cavitation around intrusion points can cause severe wall thinning. If solid

particles are entrained in the fluid, erosion of pipe elbows results. General corrosion of the inside pipe

surface can be caused by extended outage periods. Proper line draining is recommended unless

protective materials are in place.

AJ2

PROJECT MANAGEMENT


Synergy Engineers


5.2.12 TUBULAR AIR HEATERS

Tubular air heaters are large heat exchangers that transfer heat from the boiler flue gas to the incoming

combustion air. On large utility boilers, tubular air heaters can contain up to 90,000 tubes with lengths of

50 ft. (15.2 m) each. These 2 in. (50.8 mm) OD tubes are densely grouped with spacings of 3 to 6 in. (76.2

to 152.4 mm) centers in two directions. Flue gas flow direction is typically opposite that of the combustion

air to maximize thermal efficiency. Unfortunately, this promotes corrosion on the gas side cold end.

Condensate formation promotes acid corrosion from the flue gas which causes wall thinning. If left

unchecked for several years the tubes eventually corrode through, causing air leakage from the air to gas

side.

Because access to air heater tubes is limited, eddy current and acoustic technologies are used to test for

blockage, holes and wall thinning. Eddy current technology is used to measure wall thicknesses of thin [<

0.065 in. (< 1.65 mm)] nonferrous heat exchanger tubing. Holes and partial and complete blockage are

located using acoustic technology. When an audible sound is introduced into a tube it travels the length

of the tube and exits the open end. If a hole exists in the tube, however, it changes the signal pitch in the

same manner as a flutist changes a note pitch. In a like manner, partial or total tube blockage yields a

pitch change. B&W uses The Acoustic Ranger® inspection probe for this test. (See Figure 21 - Acoustic

Ranger® schematic)

Figure 21 - Acoustic Ranger® schematic

5.3 BOILER SETTINGS

The boiler components that are not part of the steam-water pressure boundary are general maintenance

items that do not have a significant impact on remaining life of the unit. The non-pressure components

include the penthouse, boiler casing, brickwork and refractories, and flues and ducts. Deterioration of

these components results from mechanical and thermal fatigue, overheat, erosion and corrosion. In all

cases, condition assessment is done by performing a detailed visual inspection. For flues, ducts and

casing, it is of value to inspect the in-service boiler to detect hot spots, air leaks and flue gas leaks that

can indicate a failed seal.

AJ2

PROJECT MANAGEMENT


Synergy Engineers


The structural members of the boiler must be reviewed during a condition assessment inspection.

Normally these members, along with the support rods above the boiler and auxiliaries, last the life of the

boiler. However, because non-uniform expansion can lead to boiler load movement, the support system

should be examined during the boiler outage inspections. Particular attention should be given to header

and drum supports that could be damaged if the vessel is distorted.

The term boiler setting originally applied to the brick walls enclosing the furnace and heat transfer surfaces

of the boiler. Today, boiler setting comprises all the water-cooled walls, casing, insulation, outer covering

and reinforcement steel that form the outside envelope of the boiler and furnace enclosure. The term

enclosure may refer to either the entire setting or to a part of it.

As larger capacity steam generating units were demanded, boiler settings underwent a long evolution

from uncooled brick surfaces to today’s water-cooled walls. Water-cooled walls began as widely spaced

tubes exposed to the furnace and covered with insulating block. These progressed to tangent tubes

covered with refractory. They gradually evolved to the present day construction of membrane tubes.

5.3.1 DESIGN REQUIREMENTS

The boiler settings must safely contain high temperature pressurized gases and air. Leakage, heat loss

and maintenance must be reduced to acceptable values. The following factors must be considered in the

setting design:

1. Enclosures must withstand the effects of temperatures up to 3500º F (1927º C).

2. The effects of ash and slag, or molten ash, must be considered because:

a. Destructive chemical reactions between slag and metal or refractory can occur under certain

conditions,

b. Accumulation of ash on the water-walls can significantly reduce heat absorption,

c. Ash accumulations can fall causing injury to personnel or damage to the boiler, and

d. High velocity ash particles can erode the pressure parts and refractory.

3. Provisions must be made for the thermal expansion of the enclosure and for differential expansion of

attached components.

4. The buckstay system must accommodate the effects of thermal expansion, temperature and pressure

stresses, as well as wind and earthquake loading appropriate to the plant site.

5. The effect of explosions and implosions must be considered to lessen the risk of injury to personnel

and damage to equipment.

6. Vibrations caused by combustion pulsations and the flow characteristics of flue gas and air must be

limited to acceptable values.

7. Insulation of the enclosures should limit the heat loss to an economical minimum.

8. Neither the exterior surface temperature nor the ambient air temperature should cause discomfort or

hazard to operating personnel.

9. Enclosures must be gas-tight to minimize leakage into or out of the setting.

10. Settings of outdoor and indoor units that require periodic wash-down must be weatherproof.

11. Settings must be designed for economic fabrication, erection and service life.

12. Serviceability, including access for inspection and maintenance, is essential.

AJ2

PROJECT MANAGEMENT


Synergy Engineers


13. Good appearance, in conjunction with cost and maintenance requirements, is desirable.

5.3.2 TUBE WALL ENCLOSURES

In today’s units, water- or steam-cooled tubes, or both, are used as the basic structure of the enclosure in

high temperature areas of the setting. Important types of water-cooled enclosures are membrane tubes,

membrane tubes with refractory lining, flat stud tubes and tangent tubes.

5.3.2.1 MEMBRANE TUBES

Figure 22 – Membrane wall construction; illustrates a typical furnace wall with membrane construction.

These walls are water-cooled and constructed of bare tubes joined by thin membrane bars. The walls are

gas-tight and do not require an exterior casing to contain the products of combustion. Insulation is placed

on the outside of the wall and sheet metal or lagging is installed over the insulation to protect it.

One of the advantages of membrane walls compared to cased walls is that they eliminate flue gas

corrosion on the cold face of the enclosure walls. Most flue gases contain sulfur; therefore, metal parts of

the setting must either be kept above the dew point of the gases or out of contact with the gases. The dew

point generally ranges between 150º and 250º F (66º and 12lº C) and is dependent on the fuel, its sulfur

content and the firing method.

Figure 22 – Membrane wall construction

Flues carrying low temperature spent gases should be insulated on the outside to inhibit corrosion. This

is particularly necessary on outdoor units. Water-cooled doors and slag tap coils require water

temperatures above 150º F (66º C) to keep the cooling coils above the dew point of the gases.

When casing is located outside of insulation or refractory, it is still subject to the action of the flue gases.

When this type of casing is subjected to a temperature below the dew point, an asphalt mastic or other

type of coating is needed to protect it from corrosion on the inside. This problem requires special attention

AJ2

PROJECT MANAGEMENT


Synergy Engineers


in the design of outdoor installations where temperatures may, at times, be below flue gas dew point

temperatures.

With the use of externally insulated casing, corrosion problems are greatly reduced because the flue gases

are completely contained by a metal skin, which is well above the dew point temperature. However, even

with the inner casing, seals and expansion joints must be insulated properly to avoid cold spots and

consequent corrosion.

5.3.2.2 MEMBRANE TUBES WITH REFRACTORY LINING

There are several locations in selected types of boilers that require refractory lining on the furnace side of

the tubes to protect the tubes from either erosion or corrosion from the products of combustion. Some of

the most common applications are:

1. Cyclone-fired units: lower furnace and cyclone burner walls.

2. Circulating fluidized-bed boilers: lower furnace.

3. Refuse boilers: lower furnace.

4. Pulverized coal-fired boilers: burner throats.

Cylindrical pin studs, welded on the hot side of the tubes at close intervals, hold the refractory in place

Figure 23 – Fully studded membrane wall. Lining the wall with refractory can also increase furnace

temperature by reducing heat absorption where this is desired. The increase in temperature helps to

maintain the coal, peat, or lignite ash in a liquid state, thereby preventing large ash buildup and allowing

better removal of slag. However, because of maintenance problems it is usually desirable to avoid

refractory where technically acceptable.

Figure 23 – Fully studded membrane wall

5.3.2.3 FLAT STUD TUBE WALLS

These walls consist of tubes with small, flat bar studs welded at the sides Figure 24 – Flat stud tube wall

construction with inner casing shown. These walls are typically backed by one of two construction methods

which are usually found in the convection pass enclosure.

AJ2

PROJECT MANAGEMENT


Synergy Engineers


Figure 24 – Flat stud tube wall construction with inner casing shown

In the current method, the flat studded tubes are backed with refractory covered with a welded inner hot

casing that is insulated and covered with metal lagging for protection. The casing is supported from

channel tie bars welded to the tubes at each buckstay row. The walls are reinforced with buck-stays and

the inner casing is reinforced with stiffeners. Stiffener spacing and size are set by the design pressure of

the walls between buck-stays. This system provides a better gas-tight enclosure than the former method.

In former practice, as shown in Figure 25 – Tangent tube wall construction with outer casing shown, the

tubes are backed with refractory, followed by a dense insulation and an outer cold casing. The casing is

supported from the buck-stays with expansion folds at the attachments. These folds minimize stresses in

the casing caused by differential expansions between the hot tube wall and cold casing. This method is

now obsolete, but found on many old boilers that are still in service.

AJ2

PROJECT MANAGEMENT


Synergy Engineers


Figure 25 – Tangent tube wall construction with outer casing shown

While the construction of the casings described in the preceding paragraphs applies to areas of horizontal

buckstay reinforcement, some industrial boiler designs require a vertical casing that is welded vertically to

a bar located between two tubes Figure 26 – Casing attachment to membrane wall.

Figure 26 – Casing attachment to membrane wall

5.3.2.4 TANGENT TUBE WALL

These walls are constructed of bare tubes placed next to each other with a typical gap of 0.03125 in.

(0.7937 mm). The refractory backup, casing and insulation system design, similar to that described for flat

stud tube walls, has also been used with tangent tube walls. These walls are typically found in the furnace

area of older boiler designs Figure 25 – Tangent tube wall construction with outer casing shown.

AJ2

PROJECT MANAGEMENT


Synergy Engineers


5.3.2.5 FLAT STUD AND TANGENT TUBE WALL UPGRADES

Figure 27 – Tangent tubes with closure rods

In recent years, two methods have been used to provide a better enclosure seal on units with either inner

(hot) or outer (cold) casing as the gas seal. In one method, on boiler enclosure areas with tangent tubes,

a round bar is seal welded between each tube for the full length Figure 27 – Tangent tubes with closure

rods. In the other method, where boiler enclosure areas have widely spaced tubes with flat studs, a flat

bar is seal welded between the tubes just behind the flat studs over the full length Figure 28 – Widely

spaced tubes with flat studs and closure bars.

Figure 28 – Widely spaced tubes with flat studs and closure bars

These methods have been effective on many boilers, providing an improved gas seal with considerably

less maintenance and longer life than the casing seal they replaced. Their biggest drawback is high

installation costs because the entire boiler must be stripped of its existing casing and insulation, then a

new insulation and lagging system must be installed.

5.3.3 CASING ENCLOSURES

The casing is the sheet or plate attached to pressure parts for supporting, insulating, or forming a gastight

enclosure.

A boiler unit contains many cased enclosures that are not water-cooled. These enclosures must be

designed to withstand relatively high temperatures while having external walls that minimize heat loss and

protect operating personnel.

Casings are constructed of sheet or plate reinforced with stiffeners to withstand the design pressures and

temperatures. When the casing is directly attached to the furnace walls, expansion elements are added

to allow for differential thermal expansion of the tubes and casing.

5.3.3.1 HOPPER

Hopper enclosures are used in various areas of the boiler setting that may include the economizer hopper,

furnace hopper enclosure and the wash hopper for dry bottom units.

AJ2

PROJECT MANAGEMENT


Synergy Engineers


The enclosure provided by the hopper casing may also serve as a plenum for the recirculating gas which

leaves the economizer hopper through ports and enters the furnace through openings between tubes in

the furnace hopper

5.3.3.2 WIND-BOX

The wind-box is a reinforced, metal-cased enclosure that attaches to the furnace wall, houses the burners,

and distributes the combustion air. It may be located on one furnace wall, on two opposite furnace walls,

or on all furnace walls using a wraparound configuration. The attachments to the furnace walls must be

gas-tight and permit differential thermal expansion between the tubes and casing.

For large capacity boilers, the wind-box may be compartmented and placed only on the front and rear

furnace walls. The wind-boxes are compartmented (internally separated with horizontal division plates)

for better combustion air control.

5.3.3.3 TEMPERING GAS PLENUM

This enclosure, located above the wind-box, provides for the distribution and injection of flue gas which is

used to temper the furnace gases and control the ash fouling of heating surfaces. It is constructed similarly

to the wind-box, but is normally protected on the inside by a combination of refractory and stainless steel

shields opposite the gas ports

5.3.3.4 PENTHOUSE

The penthouse casing forms the enclosure for all miscellaneous pressure parts located above the furnace

and convection pass roofs. It is a series of reinforced flat plate panels welded together and to the top

perimeter of the furnace pressure parts. Various seals are used at the penetrations through the penthouse

walls, roof and roof tubes. Some examples are cylindrical bellows or flexible cans sealing the suspension

hangers, large fold (pagoda) seals around the steam piping and refractory or casing seals around heating

surface tube penetrations through the roof tubes. On many utility and some industrial boilers a gas-tight

roof casing is used on top of the roof tubes as the primary gas seal (pressure boundary). Penthouses may

or may not be designed as pressure-tight enclosures with seal air. It depends upon whether the boiler is

a pressure fired or a balanced draft unit and whether the roof seals are seal welded gas-tight or are of the

refractory type.

AJ2

PROJECT MANAGEMENT


Synergy Engineers


6 SAFETY

6.1 EXPLOSIONS

In the design of settings, the effect of possible explosions must be considered to minimize the possibilities

of personnel injury and serious equipment damage. It is imperative that all types of boilers be designed to

minimize the risk and effect of explosion. This requires that all new boilers and boilers undergoing major

alterations be designed and evaluated so that they are in compliance with the National Fire Protection

Association (NFPA) 85 Standard, Boiler Combustion Systems Hazards Code. On units with fluid or

fluidized fuels, care must be taken to avoid puffs that can occur from improper fuel and air mixture during

startup. A better understanding of the technical problems and the development of adequate design and

operating codes have eliminated most explosions.

The enclosure is designed to withstand common puffs and large transient gas-side pressure excursions.

A design can be provided that results in the failure of studs, stud attachments and welds rather than failure

of tube walls in the event of a major furnace explosion.

This minimizes the risk of release of large quantities of high pressure steam. Unfortunately, this design

may also result in extremely hot gases being directed at platforms and steel in areas that were not

designed to accommodate high temperature gases. Explosion doors were once used on small furnaces

to relieve excessive internal furnace pressure. These doors are no longer used because the rapid internal

pressure increase from a fuel explosion is not significantly relieved by opening one or more doors.

Explosion doors may also be more of a hazard than a safety margin because, in the event of a puff, they

may discharge hot gases that would otherwise be completely contained within the setting.

The forces from normal operating negative or positive furnace gas-side pressures and from transient

negative or positive furnace gas-side pressures, as defined by NFPA 85, are contained by rectangular

bars called tie bars and/or channel tie bars attached to wall tubes to form continuous bands around the

setting. Cold beams (buck-stays), which are attached to the tie bars with slip connections, accommodate

the gas side pressure loadings and limit the inward and outward deflection of the wall tubes.

Because the buck-stays are outside of the insulation, special corner connections are required that allow

the walls to expand Figure 29 – Tie bar and buck-stay arrangement at corner of furnace. Forces generated

by furnace gas-side pressures concentrate at the corner connections. These connections must be tight

during startup when the walls have not fully expanded and during the normal operating fully expanded

position.

AJ2

PROJECT MANAGEMENT


Synergy Engineers


Figure 29 – Tie bar and buck-stay arrangement at corner of furnace

The vertical tubes that span between the buck-stays act as a beam to resist the internal furnace pressure.

The larger the tube diameter and the heavier the tube wall, the farther apart the buck-stays may be spaced,

provided that allowable wall tube vibration limits are not exceeded. Permissible deflections and/or

combinations of the positive or negative pressure loadings with wind or seismic loadings determine the

size of the buck-stay beam.

6.2 IMPLOSIONS

Implosions are usually caused by an extremely rapid decay of furnace pressure due to sudden loss of fuel

supply or by the improper operation of dampers on units with high static pressure induced draft fans.

The risk of furnace implosions exists whenever a fan is located between the furnace and the stack. This

risk exists even if the furnace is not normally being operated at a negative pressure since the rapid furnace

temperature decay occurring on a Master Fuel Trip (MFT) results in the furnace being exposed to the

maximum head capacity of the fan on a transient basis during the fuel trip. This risk is also increased

where axial flow forced draft (FD) fans are used since they can go into stall on the negative transient,

blocking air flow into the furnace which is needed to restore the furnace pressure. The rules for determining

minimum continuous and transient design pressures for the furnace enclosures can be found in the NFPA

85 Standard. In addition, induced draft fan controls are specified in NFPA 85 to minimize possible

operating or control errors and to reduce the degree of furnace draft excursion following a fuel trip.

AJ2

PROJECT MANAGEMENT

QUALITY SYSTEMS ENGINEERING Synergy Engineers

A HEALTH & SAFETY ISSUE B MINOR FINDING C MAJOR FINDING SQ SUPPLEMENTARY QUESTION Page 56 of 100

7 INSPECTION FORM TEMPLATE

Circulating Fluidized Bed Boiler CFB

Major Components

Site Inspection

INSPECTION FORM TEMPLATE

150 MW utility re-heat internal re-circulation circulating fluidized bed CFB (IR-CFB) boiler

AJ2

PROJECT MANAGEMENT



TYPICAL CIRCULATING BED BOILER SCHEMATIC CFB PRIMARY PARTICLE COLLECTION SYSTEM

AJ2

PROJECT MANAGEMENT



7.1 EXTERNAL BOILER INSPECTION

ITEM INSPECTION REQUIREMENT

FINDINGS

DESCRIPTION AND LOCATION OF FINDING NO YES

SQ A B C

1. EXTERNAL BOILER INSPECTION

1.1. LADDERS

Refer to 5.1.1 Page 32

1.1.1. Deformations & Cracks

1.1.2. Tightness of bolts

1.1.3. Corrosion & Condition of paints (Go to page 18; section 3.1)

1.1.4. Wear on ladder rungs

1.1.5. Security of handrails

1.1.6. Condition of galvanized surfaces

AJ2

PROJECT MANAGEMENT




FINDINGS


SQ A B C


1.2. STAIRWAYS





1.2.4. Wear on stairway treads


1.2.6. Condition of galvanized surfaces

AJ2

PROJECT MANAGEMENT




FINDINGS


SQ A B C


1.3. PLATFORMS


1.3.1. Condition of flooring

1.3.2. Deformations

1.3.3. Cracks




AJ2

PROJECT MANAGEMENT




FINDINGS


SQ A B C


1.4. STRUCTURAL MEMBERS


1.4.1. COLUMNS

1.4.1.1. Deformations & Cracks

1.4.1.2. Tightness of bolts

1.4.1.3. Condition of paint

1.4.1.4. Corrosion (Go to page 18; section 3.1)

1.4.1.5. Welded joints

AJ2

PROJECT MANAGEMENT




FINDINGS


SQ A B C


1.4.2. BEAMS

1.4.2.1. Deformations & Cracks


1.4.2.3. Condition of paint


1.4.2.5. Welded joints

AJ2

PROJECT MANAGEMENT




FINDINGS


SQ A B C


1.4.3. GIRDERS



1.4.6. Condition of paint

1.4.7. Corrosion (Go to page 18; section 3.1)

1.4.8. Welded joints

AJ2

PROJECT MANAGEMENT




FINDINGS


SQ A B C


1.4.9. STRUCTURE REINFORCING ELEMENTS






AJ2

PROJECT MANAGEMENT




FINDINGS


SQ A B C


1.4.15. SUPPORTS






AJ2

PROJECT MANAGEMENT




FINDINGS


SQ A B C


1.5. FANS


1.5.1.

Fans require frequent inspection to detect and correct irregularities that might cause problems. This can be assured by proper lubrication and cooling of fan shafts, couplings and bearings.

1.5.2.

A fan should be properly balanced, both statically and dynamically, to assure smooth and long-term service. This balance should be checked after each maintenance shutdown by running the fan at full speed, first with no air flow and second with full air flow.

1.5.3.

Fans handling gases with entrained abrasive dust particles are subject to erosion. Abrasion resistant materials and liners can be used to reduce such wear. In some cases, beads of weld metal are applied to build up eroded surfaces.

1.5.4.

Inlet sound levels from forced draft and primary air fans are most commonly controlled by the installation of an absorption-type silencer. Fan casing noise can usually be effectively controlled by the use of mineral wool insulation and acoustic lagging.

1.5.5.

Fan discharge noise, however, requires a more detailed evaluation to determine the most cost-effective method of control. For forced draft and primary air fans, insulating the outlet ducts or installing an absorption-type discharge silencer can be effective. For induced draft fans, installation of thermal insulation and lagging on the outlet flues will generally be sufficient.

AJ2

PROJECT MANAGEMENT




FINDINGS


SQ A B C


1.6. AIR DUCTS


1.6.1. PRIMARY AIR DUCTS


1.6.1.2. Expansion joints

1.6.1.3. Vibration (Go to page 19; section 3.6)

1.6.1.4. Supports


1.6.1.6. Reinforcing elements

AJ2

PROJECT MANAGEMENT




FINDINGS


SQ A B C


1.6.2. SECONDARY AIR DUCTS


1.6.2.2. Expansion joints

1.6.2.3. Vibration (Go to page 19; section 3.6)

1.6.2.4. Supports



AJ2

PROJECT MANAGEMENT




FINDINGS


SQ A B C


1.6.3. AIR DUCT TO FLUID BED COOLER

1.6.3.1.1. Corrosion (Go to page 18; section 3.1)

1.6.3.1.2. Tightness of bolts

1.6.3.1.3. Vibration (Go to page 19; section 3.6)

1.6.3.1.4. Deformations

1.6.3.1.5. Galvanized surfaces

1.6.3.1.6. Corrosion (Go to page 18; section 3.1)

AJ2

PROJECT MANAGEMENT




FINDINGS


SQ A B C


1.7. FLUE GAS DUCTS




1.7.1.3. Vibration dampeners

1.7.1.4. Insulation protection

1.7.1.5. Insulation material condition

1.7.1.6. Deformations

AJ2

PROJECT MANAGEMENT




FINDINGS


SQ A B C


1.8. FUEL BUNKER

Refer to Page

1.8.1. Integrity of the sub-system

1.8.2. Deposits

1.8.3. Cracks


1.8.5. Welding

AJ2

PROJECT MANAGEMENT




FINDINGS


SQ A B C


1.9. GRAVIMETRIC FEEDER

Refer to Page

1.9.1. Integrity of the Sub-system

1.9.2. Deformations

1.9.3. Deposits

1.9.4. Joints

1.9.5. Cracks

AJ2

PROJECT MANAGEMENT




FINDINGS


SQ A B C


1.10. FUEL CHUTE

Refer to Page

1.10.1. Integrity of the sub-system

1.10.2. Deposits

1.10.3. Joints

1.10.4. Cracks


1.10.6. Welding

AJ2

PROJECT MANAGEMENT




FINDINGS


SQ A B C


1.11. REFRACTORY LINE


1.11.1. The firebox refractory should be visually inspected for breakage, crumbling, spalling, and open joints.

1.11.2.

Fly-ash corrosion may occur, when fly ash and refractory are in contact. Fluxing occurs and produces a slag that may be fluid at heater operating conditions.

1.11.3.

Sagging of refractory would indicate problems with the refractory supports. Overheating or corrosion of supports usually causes support problems.

1.11.4. External deposits may indicate the need for external water washing.

1.11.5.

Inspect all baffles for condition of baffle and refractory protecting baffles. Inspect the linings of all stacks and ducts for cracks, wear, and structural soundness. Use ultrasonic measurements to check wall thickness

AJ2

PROJECT MANAGEMENT




FINDINGS


SQ A B C


1.12. FLUID BED COOLER

Refer to Page

1.12.1.

Corrosion (Go to page 18; section 3.1)

Corrosion results in wall metal loss. This wall thinning raises the local stresses of the component and can lead to leaks or component failure.

1.12.2.

Erosion (Go to page 18; section 3.2)

Erosion is common near soot-blowers; on the leading edges of economizers, super-heaters and re-heaters; and where there are vortices or around eddies in the flue gas at changes in gas velocity or direction.

1.12.3.

Fatigue (Go to page 18; section 3.3)

Temperature differentials that develop between components during boiler startup and shutdown can lead to fatigue cracks. Cracks can develop at tube or pipe bends; tube-to-header, pipe-to-drum, fitting-to-tube, support attachment welds.

1.12.4.

Over-heating (Go to page 19; section 3.5)

Overheating is a problem that occurs early in the life of the plant and can often result in tube ruptures. These problems may go undetected until a tube failure occurs.

1.12.5.

Hydrogen damage (Go to page 19; section 3.5)

High temperatures in combination with any furnace wall internal deposits may promote hydrogen damage of the furnace tubing in areas of high corrosion or heavy internal deposits.

AJ2

PROJECT MANAGEMENT




FINDINGS


SQ A B C


1.13. STEAM COIL AIR HEATER


1.13.1.



1.13.2.



1.13.3.

Fatigue (Go to page 3.318; section 3.3)


1.13.4.



1.13.5.

Vibration (Go to page 19; section 3.6)

Excessive vibration can cause failures of the tubes, insulation, casing and supports. These vibrations can be produced by external rotating equipment, furnace pulsations from the uneven combustion of the fuel, or turbulence in the flowing streams of air or gas in flues, ducts and tube banks.

AJ2

PROJECT MANAGEMENT




FINDINGS


SQ A B C


1.14. AIR HEATER


1.14.1.



1.14.2.



1.14.3.



1.14.4.



1.14.5.

Vibration (Go to page 19; section 3.6) Excessive vibration can cause failures of the tubes, insulation, casing and supports. These vibrations can be produced by external rotating equipment, furnace pulsations from the uneven combustion of the fuel, or turbulence in the flowing streams of air or gas in flues, ducts and tube banks.

AJ2

PROJECT MANAGEMENT




FINDINGS


SQ A B C


1.15. MULTI-CYCLONE DUST COLLECTOR

Refer to Page

1.15.1.



1.15.2.



1.15.3.



1.15.4.



1.15.5.


AJ2

PROJECT MANAGEMENT




FINDINGS


SQ A B C


1.16. STACK


1.16.1.



1.16.2.



1.16.3.



1.16.4.



1.16.5.


AJ2

PROJECT MANAGEMENT




FINDINGS


SQ A B C


1.17. BOILER PIPING


1.17.1.



1.17.2.



1.17.3.



1.17.4.



1.17.5.


AJ2

PROJECT MANAGEMENT




FINDINGS


SQ A B C


1.18. INSTRUMENTATION


1.18.1.

Inspect all lines to instrumentation for leakage.

Inspect all control valves for leakage.

1.18.2. Verify if any safety devices or alarms are bypassed.

1.18.3.

Inspect water glasses, since these are extremely important in operating the boiler. Make sure they are well lit. Have the operator blow down the water gage in a normal manner and observe how the level returns.

1.18.4. Check pressure gages in the field against those in the control room.

1.18.5. Test the pressure with a test gage.

AJ2

PROJECT MANAGEMENT




FINDINGS


SQ A B C


1.19. PAINT AND INSULATION


1.19.1. Visually inspect the condition of the protective coating and/or insulation.

1.19.2.

Any cracks or openings should be repaired.

If not repaired immediately, logged to the next paint maintenance cycle.

1.19.3. Any rust spots and or bulging may indicate corrosion underneath thus, further inspection may be required

1.19.4.

Scrapping paint away from blisters or rust spots often reveals pits in the vessel walls.

Measure the depth of pitting with a pit gage.

1.19.5. The most likely spots for paint failure are in crevices, in constantly moist areas, and at welded seams.

AJ2

PROJECT MANAGEMENT



7.2 INTERNAL BOILER INSPECTION


FINDINGS


SQ A B C

2. INTERNAL BOILER INSPECTION

2.1. STEAM DRUM


2.1.1.

Corrosion (Go to page 18; Section 3.1) Corrosion results in wall metal loss. This wall thinning raises the local stresses of the component and can lead to leaks or component failure.

2.1.2.

Erosion (Go to page 18; section 18) Erosion is common near soot-blowers; on the leading edges of economizers, super-heaters and re-heaters; and where there are vortices or around eddies in the flue gas at changes in gas velocity or direction.

2.1.3.

Fatigue (Go to page 18; section 3.3) Temperature differentials that develop between components during boiler startup and shutdown can lead to fatigue cracks. Cracks can develop at tube or pipe bends; tube-to-header, pipe-to-drum, fitting-to-tube, support attachment welds.

2.1.4.

Over-heating (Go to page 19; section 3.4) Overheating is a problem that occurs early in the life of the plant and can often result in tube ruptures. These problems may go undetected until a tube failure occurs.

2.1.5.


AJ2

PROJECT MANAGEMENT




FINDINGS


SQ A B C


2.2. RISERS


2.2.1.


Corrosion results in wall metal loss. This wall thinning raises the local stresses of the component and can lead to leaks or component failure

2.2.2.



2.2.3.



2.2.4.



2.2.5.



AJ2

PROJECT MANAGEMENT




FINDINGS


SQ A B C


2.3. DOWN-COMERS

Refer to Page

2.3.1.



2.3.2.



2.3.3.



2.3.4.



2.3.5.



AJ2

PROJECT MANAGEMENT




FINDINGS


SQ A B C


2.4. HEADERS – HIGH TEMPERATURE

Refer to 5.2.6.1 Page 38

2.4.1.



2.4.2.



2.4.3.



2.4.4.



2.4.5.

Hydrogen Damage (Go to page 19; section 3.5)


AJ2

PROJECT MANAGEMENT




FINDINGS


SQ A B C


2.5. HEADERS – LOW TEMPERATURE


2.5.1.



2.5.2.



2.5.3.



2.5.4.



2.5.5.



AJ2

PROJECT MANAGEMENT




FINDINGS


SQ A B C


2.6. INTERNAL EVAPORATIVE CIRCUIT


2.6.1.



2.6.2.



2.6.3.



2.6.4.



2.6.5.



AJ2

PROJECT MANAGEMENT




FINDINGS


SQ A B C


2.7. ECONOMIZER


2.7.1.



2.7.2.



2.7.3.



2.7.4.



2.7.5.



AJ2

PROJECT MANAGEMENT




FINDINGS


SQ A B C


2.8. FEED-WATER TO DRUM


2.8.1.



2.8.2.



2.8.3.



2.8.4.



2.8.5.



AJ2

PROJECT MANAGEMENT




FINDINGS


SQ A B C


2.9. SUPER-HEATERS


2.9.1. SUPER-HEATER WING-WALLS

2.9.1.1.



2.9.1.2.



2.9.1.3.



2.9.1.4.



2.9.1.5.



AJ2

PROJECT MANAGEMENT




FINDINGS


SQ A B C


2.9.2. SECONDARY SUPER-HEATERS

2.9.2.1.



2.9.2.2.



2.9.2.3.



2.9.2.4.



2.9.2.5.



AJ2

PROJECT MANAGEMENT




FINDINGS


SQ A B C


2.10. ATTEMPERATORS


2.10.1.1.



2.10.1.2.



2.10.1.3.



2.10.1.4.



2.10.1.5.



AJ2

PROJECT MANAGEMENT




FINDINGS


SQ A B C


2.11. RE-HEATERS


2.11.1. COLD RE-HEATER

2.11.1.1.



2.11.1.2.



2.11.1.3.



2.11.1.4.



2.11.1.5.



AJ2

PROJECT MANAGEMENT




FINDINGS


SQ A B C


2.11.2. HOT RE-HEATER

2.11.2.1.



2.11.2.2.



2.11.2.3.



2.11.2.4.



2.11.2.5.



AJ2

PROJECT MANAGEMENT




FINDINGS


SQ A B C


2.12. U-BEAMS


2.12.1. IN-FURNACE U-BEAMS

2.12.1.1.



2.12.1.2.



2.12.1.3.



2.12.1.4.



2.12.1.5.



AJ2

PROJECT MANAGEMENT




FINDINGS


SQ A B C


2.12.2. U-BEAMS

2.12.2.1.



2.12.2.2.



2.12.2.3.



2.12.2.4.



2.12.2.5.

Hydrogen damage (Go to page 19; section 3.5)


AJ2

PROJECT MANAGEMENT




FINDINGS


SQ A B C


2.13. HIGH TEMPERATURE PIPING


2.13.1.1.



2.13.1.2.



2.13.1.3.



2.13.1.4.



2.13.1.5.



AJ2

PROJECT MANAGEMENT


Synergy Engineers


8 RELIABLE INFORMATION IS KEY TO A RELIABLE ASSESSMENT

Inspection is not an exact science and requires the use of judgment and experience as well as engineering

knowledge.

Records should be reviewed before an inspection, to become thoroughly familiar with the equipment. This

review should result in identifying expected problems and planning areas of emphasis for the planned

inspection. The following records that should be checked are as follows:

1. Original Design Drawings

2. Piping and Instrumentation Diagrams

(P&IDs)

3. E & I Single Line Diagrams

4. DCS (Distributed Control System)

5. Boiler Log

6. Maintenance Records

7. Safety Instruction Sheets (SIS)

8. Hydrostatic Test Diagram

9. Previous hydrostatic test results

AJ2

PROJECT MANAGEMENT


Synergy Engineers


9 CFB Boilers – Reheat and Non-reheat

Figure 30 – CFB Boilers Reheat and Non-reheat