

II

PTC 101

Outage Inspections

Introduction

This document will contain a series of sections, each pertaining to equipment and/or systems commonly found in power plants that may be evaluated during an internal

inspection while the unit is out of service. Each section can be used independently, and

includes recommendations on what to look for during the inspection of each specific piece of equipment. Inspections covered in this document are intended to take place

when the equipment is in out of service. For additional information on inspections which

can be done when the unit is on-line please consult ASME PTC-102 – OperatingWalkdowns.

1.0 Object and Scope

1.1 Object

These guidelines for equipment inspections are designed to ultimately improvethe thermal performance or efficiency of the power plant. Many issues identified, upon

resolution, will also improve the reliability of the plant.

1.2 Scope

This document provides guidelines for equipment inspections of power plantsusing fossil fuels during shutdown or outage periods. Some portions of this document

may be applicable to other types of power plants.

1.3 Uncertainty

As a guideline, the information provided herein is qualitative, and there are noexpectations of uncertainty other than that provided in each section.

2.0 Definitions / Acronyms

ACET Average Cold End Temperature

AH Air Heater CSP Confined Space Permit

CT Combustion Turbine (see also Gas Turbine)

DP Differential PressureEPA Environmental Protection Agency

ESP Electrostatic Precipitator

FEGT Furnace Exit Gas Temperature

GR Gas RecirculationGT Gas Turbine (see also Combustion Turbine)

HP High Pressure



III

HRSG Heat Recovery Steam Generator

IP Intermediate PressureLOTO Lock Out Tag Out

LP Low Pressure

OEM Original Equipment Manufacturer

OFA Over-Fire Air OSHA Occupational Safety and Hazard Act

P&ID Process and Instrumentation Diagram

PPE Personal Protective EquipmentSCR Selective Catalytic Reduction system

SNCR Selective Non-Catalytic Reduction system

ST Steam Turbine

3.0 Guiding Principles

Equipment reliability and performance have parallels. Indications of poor

performance are closely tied to those of reduced reliability. Abnormal wear patterns, poor cleanliness, increased corrosion and/or erosion, and mechanical failures, no matter

how small have effects on both unit reliability and unit performance. Identifying thesources and root cause(s) are the first steps in improving the overall performance of a

piece of equipment and the power generating unit of which it is a part. While these

inspection guidelines are written to ultimately enhance the plant’s performance, allobservations should be noted and acted upon.

The following sections provide details on activities to be completed prior to

starting an outage inspection.

3.1 Safety considerations

Prior to inspecting or entering any piece equipment, it is important to identify all

potential hazards that may be encountered. All energy sources must be removed from

service or isolated to ensure without failure that no energy can be released into the area or

component inspected. Nearby equipment supporting sister units may remain in service.In sites with multiple units ensure one is inspecting the correct piece of equipment.

Maintain a safe distance from rotating equipment and moving parts which are

encountered near the inspection area.In addition to the general safety considerations included here, additional safety

considerations are included within each section for application on the specific equipment

being inspected.(a) Personal Protective Equipment (PPE) may be required for some of the

procedures recommended in this guideline. Your site safety manual should be

referenced and the proper PPE acquired prior to starting any walkdown whileequipment is in operation.

(b) Proper Lock-Out-Tag-Out (LOTO) procedures should be used where

necessary. This guideline addresses inspections when equipment has been

removed from normal operation and LOTO is required for safe entries. Refer toyour site safety manual or safety representative if any questions arise.



IV

(c) Biological Hazards may be present, especially around wet areas such as

cooling towers. Visually inspect the areas for cleanliness; if any areas appear dirty with distinct odors present, assume biological contamination and use the

proper PPE. In some cases a respirator may be necessary.

(d) Confined space entry permits should be used in compliance with the site’s

safety procedures.(e) The control room and/or operation supervisor should be notified prior to

initiating an inspection of any piece of equipment. The location, purpose, and

expected timing of the inspection should be communicated to the proper personnel in case an emergency situation arises.

3.2 Pre-inspection activities

Prior to any inspection, the following documents and information should be

gathered and reviewed:

(a) The last inspection report

(b) Recent operating data from control system historian and other available

archivesc) Recent operating history as recalled by current plant operations staff

(d) Actual versus expected performance for the component(s) of interest(e) As-built P&ID’s and design specifications of the system(s) of interest

3.3 Inspection Plan

A plan or checklist for the inspection should be developed prior to starting the

actual inspection, covering the objective of the inspection; whether this is a routine

inspection or the specific details if a performance deficit has initiated the need for anextra inspection.

The plan should include a list of the equipment to be inspected as well as methodsof accessing equipment where special PPE or confined spaces may be involved.

The plan for the inspection should be covered with plant operations staff for

additional information on operating history prior to starting the inspection.

Equipment needed for the inspection should be organized prior to starting theinspection, such as cameras, flashlights, infrared temperature guns and writing

equipment. If necessary, arrangements should be made for temporary scaffolding or

ladders.

3.4 Inspection activities

During the inspection, the following activities are recommended:

(a) Inspect the unit or piece of equipment in a structured direction, either fromtop to bottom, bottom to top, front to back, etc. This will help to provide

complete coverage while minimizing time spent moving from one area to another.

(b) Record all information as observed; do not rely on mental notes. This iscritical to ensure all findings will be included on the inspection report.

(c) Obey all site safety rules.

3.5 Post-inspection activities

The following items should be completed immediately following the inspection:



V

(a) Report the significant findings from the inspections to the responsible

plant contacts.(b) Report any safety issues found to correct and remove the hazards.

(c) Ensure all tools and materials taken on the inspection are returned to their

proper storage locations and that nothing was left out in the field.

(d) Sign out on the appropriate forms, as needed (such as LOTO or confined space permits).

(e) Document all findings in a report that is retrievable in the future.

(f) Summarize all recommended actions and alert appropriate personnel asneeded for implementation.

(g) Plan for a re-inspection if recommended actions require it.

4.0 Specific Equipment Considerations

Additional documentation on specific equipment considerations are provided in

the appendices.

5.0 Instruments and Methods of MeasurementA list of some of the instrumentation available to support equipment inspections is

as follows:(a) Digital / photographic camera – Note: be sure to take notes with each

picture: instrument ID, location, time, etc.

(b) Ultrasonic depth meters for determining wall thickness of metal pieces(c) Rulers and tape measures

(d) Magnifying glasses

6.0 Report of Results

When reporting the results of an outage inspection, the following informationshould be included:

a) Site information

b) Date and time of the inspection

c) Names, positions and affiliations of persons involved in the inspectiond) Equipment included in the inspection

e) Purpose of the inspection

f) Instrumentation used during the inspectiong) Analytical methods used, if applicable

h) Findings from inspection

i) Conclusions and/or recommendations j) Uncertainty considerations – may be applicable to extrapolations of future

expectations

k) Appendices for data collected in support of the inspection, including:i) raw data and measurements

ii) photos

iii) drawings or sketches

iv) P&ID’s of selected systems, as appropriate



VI

Appendix 1

Air Heater (tubular)

TABLE OF CONTENTS ........................................ERROR! BOOKMARK NOT DEFINED.

GENERAL TUBULAR AIR HEATER INSPECTION GUIDELINES ........................ VII

SAFETY ................................................................................................................................... VIII 1. GENERAL AREA ................................................................................................................. IX

1.1 GENERAL .............................................................................................................................. IX

2. INITIAL INSPECTION – BEFORE CLEANING .......................................................... IX 3. SECOND INSPECTION – AFTER CLEANING ............................................................ IX

3.1 TUBESHEETS .......................................................................................................................... X 3.2 TUBES .................................................................................................................................... X

3.3 SEALS..................................................................................................................................... X

3.4 I NSTRUMENTATION................................................................................................................ X 3.5 SOOTBLOWERS .................................................................................................................... XI

3.6 PENETRATIONS ..................................................................................................................... XI

4. AIR SIDE INSPECTION ..................................................................................................... XI 4.1 TUBES ................................................................................................................................... XI 4.2 TUBESUPPORT SHEETS ........................................................................................................ XI

4.3 SEALS.................................................................................................................................... XI

4.4 I NSTRUMENTATION............................................................................................................... XI 4.5 PENETRATIONS ..................................................................................................................... XI



VII

General Tubular Air Heater Inspection Guidelines

This is a general inspection procedure, not all areas or items will pertain to every air heater.

Equipment reliability and performance have parallels. Indications of poor performance

are closely tied to those of reduced reliability. Abnormal wear patterns, poor cleanliness,increased corrosion, and mechanical failures, no matter how small have effects on both

unit reliability and unit performance. Identifying the root cause is the first step in

improving the overall performance of a piece of equipment and the power generating unitit is a part of. While these inspections guidelines are written to ultimately enhance the

plant’s performance, all observations should be noted and acted upon.

Prior to the outage:

-review the last inspection report.

-review recent operating history

-air inleakage-pressure drops, both air and flue gas sides

-efficiency and x-factor -tube leak history and map

-abnormal operating events

-contact plant operations for additional information on operating history-Obtain the following drawings of the air heater prior to inspection to aide in the

inspection and report/documentation.

Elevation

PenetrationsInstrumentation

Layout

-it is recommended to use thermography to locate hot or cold spots on the external casingof the air heater. Any spot varying more than 10 F from the general area should be

documented, as it may be caused by air inleakage or loss of insulation.

-make a plan or checklist on the items and areas of interest that should be inspected.Know which doors (manways) you plan to use to enter and exit the air heater.

-make a safety plan and conduct a briefing prior to entering the air heater. Ensure all

participants are aware of their responsibilities, including looking out for each other,obeying the outside safety watch person, and evacuation plans.

-gather personal safety equipment

-gather cameras, flashlights, and writing equipment, and ensure sufficient lanyards areavailable for all equipment brought into the air heater.

-if necessary, arrange for temporary scaffolding or ladders.

During the Inspection:



VIII

-Record all information as observed; do not rely on mental notes. This is critical to

ensure all findings will be included on the inspection report.-obey all instructions from the outside safety watch person.

After the inspection:

-Report the significant findings from the inspections immediately to the responsible plant

contacts.

-Safety issues require immediate reporting and correction to remove the hazards.-ensure all material brought into the air heater as part of the inspection leaves with you

-sign out on the appropriate forms

-document all findings in a report that is retrievable in the future-summarize all recommended actions

-plan for a re-inspection if recommended actions require it

Safety

The following safety equipment and procedures are required prior to performing aninspection.

Steel Toed Boots, Hard Hat, Safety Glasses or goggles, Coveralls

Gloves, Primary and backup Flashlights, Dust Mask or respirator with HEPA filter for

ceramic fibersLife line Harness

Cell phone or radio

Confined space gas monitor

Confined space training must be completed.Complete the confined space testing procedure prior to entering the confined space.

Restrict access until the confined spaces of the unit are below 100

0

FSafety person for watch for permit required confined spaces.

Equipment taken out of service and sign on the clearances for that equipment.

All energy sources, steam, soot blowers, fuels and chemical injection equipment such asammonia must be removed from service.

Consider double block & bleed valve isolation for inspections if any connections exist to

operating units.

If other boiler back-pass maintenance activities (eg economizer cleaning or replacement)

will be conducted during the outage, this inspection should be scheduled to avoid those

times when work will be occurring directly overhead. Mechanical parts and tools areheavy and if dropped may present a serious threat to safety. If the ash hopper beneath the

air heater has been removed, the open areas should be covered to prevent unanticipated

ingress of tools and personnel.

Inspecting an air heater involves heights, close spaces, hard metal, sharp edges and fly

ash. Inspectors should be physically fit and able to climb. They should not be bothered by feelings of claustrophobia.



Appendix 2

Blowdown Tank Inspection Guidelines


1 General Area

1.1 General

A tubular air heater inspection should be undertaken as a team effort. It is

recommended that a minimum of three individuals participate. Utilizing Inspection team

members from maintenance, engineering, and operations will broaden the view and improve

the findings. One may rotate as the outside safety watch or all three may enter simultaneouslyif the safety-watch function can be performed by another. It is recommended that one person

serve as scribe and another carry the camera or video recording device. The notes / records

may be recorded in writing or via sound recording to be transcribed immediately thereafter.Upon exiting the air heater all notes, records, and photographs should be duplicated and stored

separately to ensure preservation of this information.

This is a multi-part inspection, first prior to any cleaning, then after cleaning, and evenlater if needed, tube leak check. The air side should not require cleaning, therefore one

internal inspection of that portion of the air heater is sufficient.

Many tubular air heaters are designed and built to contain 2 separate banks of tubes,

located in series with respect to flue gas flow. Two separate banks of tubes, means double of

nearly everything, from tube sheets to instrumentation. Ensure all notes and recordings areaccurately labeled to ensure future reference to the correct bank of tubes, eg upper or lower.

2 Initial Inspection – before cleaning

The first inspection should be conducted prior to any cleaning activities in the air

heater.

Check the insulation on the interior of the casing walls; ensure it is all in placeand none has fallen. Check the interior casing walls for indications of air inleakage.

These may be manifested by discoloration or distinctive fouling.

Photograph or sketch the locations of any debris. Piles of ash may be significant,record their size and location. Look for wear patterns from soot blowers and look for

cleaning patterns to identify any area missed. These are evidenced by shiny spots or defined fouling patterns.

Note any signs of debris, foreign material, and corrosion products. Material and tools may

have been inadvertently dropped from work in the duct work above the air heater. Identifyingthe source of the foreign material will assist in preventing its recurrence. Large pieces of

material may block the flow through a large number of tubes, degrading the heat transfer

capability of the air heater. A localized concentration of corrosion products are typically theindication of a problem. A further investigation is warranted to determine the root cause and

potentially prevent recurrence.

Check to ensure instruments and their connections are not buried, covered, or insulated by mounds of ash or other debris.

3 Second Inspection – after cleaning

A second inspection should be conducted after the air heater is cleaned. Thisinspection will enable those entering the air heater to observe the actual mechanical

condition of the components.

Again, look for wear patterns from soot blowers and look for cleaning patterns to

identify any area missed. These are evidenced by shiny spots or areas with accelerated wear.



X

Note any signs of debris, foreign material, and corrosion products. Material and tools

may have been inadvertently dropped from work in the duct work above the air heater.Identifying the source of the foreign material will assist in preventing its recurrence. A

localized concentration of corrosion products are typically the indication of a problem. A

further investigation is warranted to determine the root cause and potentially prevent

recurrence.

3.1 Tubesheets

The tube to tube sheet seal should be inspected to ensure no leakage is occurring.Look for erosion or shiny wear spots. The tube sheet should be flat and not warped or

uneven. If necessary an ultra-sonic depth gage can be used to determine any metal loss

from the tube sheet. There should not be signs of any flow between the edges of the tubesheet and the sides of the air heater.

3.2 Tubes

The tubes should first be visually examined for damage, or the existence of foreign material, fouling, or scaling. This visual inspection may continue deeper into the

tubes through the use of a video probe. If the tubes are not clean or clear, the source of the fouling or foreign material should be identified and the tubes should be cleaned or

performance will suffer and tube leaks may occur in the future.

The tube surfaces should be clean, free from debris, and unscarred. If a coatingexists, a sample should be taken to later determine its content, source, and effect. Debris

and foreign material should be gathered and removed, or arrangements should be made to

ensure its removal. If a scar is noticed on a tube or tubes, it should be inspected closelyto determine if it is through the wall or may potentially progress eventually

compromising the tube’s integrity prior to the next planned outage.If tube leaks have occurred in the past, the map of plugged tubes should be used

to ensure all plugs are intact. Ensure all plugs are secured and matched, that is each one

on the inlet side is accompanied by one underneath, plugging the same tube. Quantitative

tube wall thickness measurements can be done with eddy current testing.There are several methods to determine which, if any tubes are leaking. The most

commonly used method is to “pressurize” the air side of this heat exchanger by starting a

forced draft (FD) fan. Leaking tubes may then be identified by the air flow exiting them.That air flow rate is typically very low and difficult to sense. Using a very light weight

and thin piece of paper or plastic sheet, cover a small number of tubes. If the sheet rises,

a leak is present. Other methods include the use of sonic listening devices and theintroduction of visible smoke.

3.3 Seals

If visible, check the seals between the tube sheets and the sides of the air heater.

3.4 Instrumentation

Examine the oxygen probes. Ensure they are undamaged and not heavily fouled

with ash. If extractive, ensure the sampling holes are open and unobstructed. Verify the

probes are fully inserted into the duct.



XI

Ensure all thermowells are in place. These are commonly used as a step and

subject to erosion and other damage. Ensure they are undamaged and not heavily fouled with ash.

Check the penetrations used for pressure measurements and ensure they are open

and unobstructed.

3.5 Soot BlowersThe soot blowers should be checked for alignment. Their supports should be secure.

The spray holes at the ends of the lances should be open and free from debris. Inspect the tube

sheet and air heater internals directly in the path of the soot blower media for erosive damage.

3.6 Penetrations

Examine the penetrations through the ductwork casing for signs of fatigue cracks,

erosion, corrosion, or obstructions and pluggage. In advance of the inspection, inspectorsshould familiarize themselves with the location and purpose of these penetrations as

identified on design drawings.

Check the gasket material and seals on the manways and other penetrations for

potential air inleakage sources.

4 Air Side InspectionThe air side should be relatively clean. The existence of flyash there is the sign of a leak

and its source should be determined. Note any signs of debris, foreign material, and corrosion products. Identifying the source of the foreign material will assist in preventing

its recurrence. A localized concentration of corrosion products are typically the

indication of a problem. A further investigation is warranted to determine the root causeand potentially prevent recurrence.

4.1 Tubes

Look between the tubes to both identify any foreign material that may be caught therein.If a scar is noticed on a tube or tubes, it should be inspected closely to determine if it is

through the wall or may potentially progress eventually compromising the tube’sintegrity prior to the next planned outage.

4.2 Tube Support Sheets

Examine all tube support sheets for structural soundness. These are installed to

secure the tubes and prevent tube damage due to vibration and to promote better heattransfer by routing the air across the tubes. The tube support sheets should be free of

holes and firmly in place.

4.3 Seals

If visible, check the seals between the tube sheets and the sides of the air heater.

4.4 Instrumentation

Ensure all thermowells are in place. These are commonly used as a step and subject to physical damage.

Check the penetrations used for pressure measurements and ensure they are open

and unobstructed.

4.5 Penetrations

Examine the penetrations through the ductwork casing for signs of fatigue cracks,

erosion, corrosion, or obstructions. In advance of the inspection, inspectors should

familiarize themselves with the location and purpose of these penetrations as identified on design drawings.



XII

Check the gasket material and seals on the manways and other penetrations for

potential air leakage.



XIII

Appendix 2

Blowdown Tank

Table of Contents

TABLE OF CONTENTS ....................................................................................................... XIII GENERAL BLOWDOWN TANK INSPECTION GUIDELINES................................ XIV

SAFETY .................................................................................................................................... XV

1. GENERAL AREA .............................................................................................................. XVI 1.1 GENERAL ............................................................................................................................ XVI

2. INTERNALS ....................................................................................................................... XVI 2.1 CLEANLINESS / DEBRIS / CORROSION ................................................................................ XVI

2.2 PENETRATIONS ................................................................................................................... XVI

2.3 WALLTHICKNESS .............................................................................................................. XVI



XIV

General Blowdown Tank Inspection Guidelines

This is a general inspection procedure, not all areas or items will pertain to every blowdown tank.









-feedwater chemistry

-blowdown flow rates-steam turbine fouling

-steam turbine damage due to solid particle erosion

-contact plant operations for additional information on operating history

-Obtain the drawings and specifications of the blowdown tank prior to inspection to aidein the inspection and report/documentation.

-make a plan or checklist on the items and areas of interest that should be inspected. The

action plan should be justified and based on historic performance and maintenance-make a safety plan and conduct a briefing prior to the inspection

-gather personal safety equipment-gather cameras, flashlights, and writing equipment, and ensure sufficient lanyards are

available for all equipment that enters the feedwater heater



-Inspect the vessel systematically, from top to bottom or left to right, to ensure all internal

areas receive adequate attention-Record all information as observed; do not rely on mental notes. This is critical to

ensure all findings will be included on the inspection report.



contacts.-Safety issues require immediate reporting and correction to remove the hazards.

-Ensure all material brought into the blowdown tank as part of the inspection is

withdrawn

-document all findings in a report that is retrievable in the future-summarize all recommended actions




XV

Safety



Gloves, Primary and backup Flashlights, Dust Mask or respirator with HEPA filter for ceramic fibers

Cell phone or radio

Confined space gas monitor Confined space training must be completed.

Complete the confined space testing procedure prior to entering the confined space.

Restrict access until the confined spaces of the unit are below xxx0F

Safety person for watch for permit required confined spaces.


All energy sources, steam, feed water or recirculation pumps, lay-up and chemical

injection equipment such as those supplying a nitrogen blanket must be removed fromservice.

Consider double block & bleed valve isolation for inspections if any connectionsexist to operating units.

Inspecting a blowdown tank usually involves entering it through a man-way with

your head or upper body. It still presents many of the same hazards as those spaces inwhich your entire body enters the confined space.



Appendix 3

Condenser Steam Space Inspection Guidelines


1 General Area

1.1 General

A blowdown tank inspection should be justified and planned in advance. The

frequency of inspection is dependent upon the history of chemistry related problems on the

steam side and feedwater portion of the plant. Scheduling when the tank will be open during

an outage should incorporate any contingencies to ensure time exists to complete any required repairs. If wall thickness data or weld NDT is desired, arrangements should be made to ensure

personnel with those capabilities and the related instruments are available. The notes / records

may be recorded in writing or via sound recording to be transcribed immediately thereafter.Upon completing the inspection of each blowdown tank all notes, records, and photographs

should be duplicated and stored separately to ensure preservation of this information.

2 Internals

A visual inspection of the inside of a blowdown tank can be conducted with a video

probe through an instrument connection. While it is not normal practice to conduct an internal

inspection of the blowdown tank during each planned outage, occasional inspections can help

identify the causes of chemistry problems and potential solutions. There is not a lot of space,

though and prior planning and very careful movements will help one conduct a safe internalinspection.

2.1 Cleanliness / Debris / Corrosion

Note any signs of debris, foreign material, and corrosion products. Identifying the

source of the foreign material will assist in preventing its recurrence. The foreign material

should be removed prior to closing the vessel.The site glasses, if installed, should be verified to be clean and clear, permitting a

reasonable visual indication of level when the tank is in service.

2.2 Penetrations

Examine all penetrations for structural soundness. In addition to a visual

inspection, the welds may be checked via non-destructive testing (NDT) methods.

2.3 Wall Thickness

The wall thickness should be examined directly across from each high energy

penetration. Those have the potential to cause erosion of the opposite wall byimpingement. The wall thickness of elbows on any lines transporting wet steam can be

checked using NDT from the outside of the pipe.



XVII

Appendix 3

Condenser Steam Side

Table of Contents

TABLE OF CONTENTS ..................................................................................................... XVII GENERAL CONDENSER STEAM SPACE INSPECTION GUIDELINES ........... XVIII

SAFETY .................................................................................................................................... XX 1. GENERAL AREA ...............................................ERROR! BOOKMARK NOT DEFINED.

1.1 GENERAL ..................................................................... ERROR! BOOKMARK NOT DEFINED.

1.2 CLEANLINESS / DEBRIS / CORROSION ......................... ERROR! BOOKMARK NOT DEFINED. 2. INTERNAL PIPING ...........................................ERROR! BOOKMARK NOT DEFINED.

3. SUPPORTS ...........................................................ERROR! BOOKMARK NOT DEFINED.

4. INSTRUMENTATION ......................................ERROR! BOOKMARK NOT DEFINED.5. BAFFLE PLATES ...............................................ERROR! BOOKMARK NOT DEFINED.

6. SPARGERS ..........................................................ERROR! BOOKMARK NOT DEFINED.

7. TUBES ...................................................................ERROR! BOOKMARK NOT DEFINED.8. HOTWELL ...........................................................ERROR! BOOKMARK NOT DEFINED.9. FEEDWATER HEATERS AND EXTRACTION PIPINGERROR! BOOKMARK

NOT DEFINED.

10. PENETRATIONS ..............................................ERROR! BOOKMARK NOT DEFINED.11. TURBINE-CONDENSER FLANGE (BOOT SEAL)ERROR! BOOKMARK NOT

DEFINED.



XVIII

General Condenser Steam Space Inspection Guidelines

This is a general inspection procedure, not all areas or items will pertain to every steamcondenser.








-review recent operating history-air inleakage / off gas flow rates

-dissolved oxygen in the condensate-actual versus expected backpressure

-tube leak history and map

-abnormal operating events


-Obtain the following drawings of the condenser prior to inspection to aide in the


Elevation

Penetrations

PipingLayout

-it is recommended to use thermography to locate hot or cold spots on the external casingof the LP turbine and condenser shell. Any spot varying more than 20 F from the norm

should be documented.

-check the off-gas flow and dissolved oxygen in the hotwell to determine if air inleakageis higher than desired.

-make a plan or checklist on the items and areas of interest that should be inspected.

Know which doors (manways) you plan to use to enter and exit the condenser.-make a safety plan and conduct a briefing prior to entering the steam space. Ensure all

participants are aware of their responsibilities, including looking out for each other,

obeying the outside safety watch person, and evacuation plans.




XIX

-gather cameras, flashlights, and writing equipment, and ensure sufficient lanyards are

available for all equipment brought into the condenser.-if necessary, arrange for temporary scaffolding or ladders.


-Inspect unit from top to bottom or vice-versa, as components are typically common

across each horizontal plane.

-Record all information as observed; do not rely on mental notes. This is critical toensure all findings will be included on the inspection report.

-obey all instructions from the outside safety watch person.

-avoid walking on the tubes, utilize the tops of the support plates where ever possible.



contacts.-Safety issues require immediate reporting and correction to remove the hazards.

-ensure all material brought into the condenser as part of the inspection leaves with you-sign out on the appropriate forms

-document all findings in a report that is retrievable in the future

-summarize all recommended actions-plan for a re-inspection if recommended actions require it



XX

Safety




Life line Harness

Cell phone or radioConfined space gas monitor

Confined space training must be completed.

Complete the confined space testing procedure prior to entering the confined space.Restrict access until the confined spaces of the unit are below xxx

0F



All energy sources, steam, feed water or recirculation pumps, fuels and chemicalinjection equipment such as the ammonia must be removed from service.

Consider double block & bleed valve isolation for inspections if any connections exist tooperating units.

If LP turbine maintenance will be conducted during the outage, this inspection

should be scheduled to avoid those times when work will be occurring directly overhead.Turbine parts and tools are heavy and if dropped may present a serious threat to safety. If

the turbine casing has been removed, the open areas should be covered to prevent

unanticipated ingress of tools and personnel.

Inspecting a condenser steam space involves heights, close spaces, hard metal,and sharp edges. Inspectors should be physically fit and able to climb. They should not

be bothered by feelings of claustrophobia.



Appendix 4

Condenser Waterbox and Tube-side Inspection Guidelines


Table of Contents

TABLE OF CONTENTS ....................................................................................................... XXI

GENERAL CONDENSER STEAM SPACE INSPECTION GUIDELINES ............ XXII

SAFETY ................................................................................................................................ XXIII

1. GENERAL AREA .................................................................................................... XXXVIII 2. CLEANLINESS, CORROSION, AND CLEANING ......................................... XXXVIII

3. EXPANSION JOINTS ......................................................................................................... XL

4. INSTRUMENTATION ....................................................................................................... XL 5. PENETRATIONS ................................................................................................................. XL

6. VALVES ................................................................................................................................. XL



XXII

General Condenser Steam Space Inspection Guidelines

This is a general inspection procedure, not all areas or items will pertain to every steamcondenser.









-actual versus expected cooling water temperature rise-actual versus expected backpressure

-tube leak history and map-abnormal operating events

-contact plant operations for additional information on operating history-Obtain the water box elevation drawings and tube map prior to inspection to aide in the


-make a plan or checklist on the items and areas of interest that should be inspected.Know which doors (manways) you plan to use to enter and exit each waterbox.

-make a safety plan and conduct a briefing prior to entering the steam space. Ensure all participants are aware of their responsibilities, including looking out for each other,



-gather cameras, flashlights, and writing equipment, and ensure sufficient lanyards areavailable for all equipment brought into the condenser.



-Inspect waterbox from top to bottom or vice-versa. Also at each level consistently movein the same direction horizontally to ensure full coverage.

-Record all information as observed; do not rely on mental notes. This is critical to

ensure all findings will be included on the inspection report.-obey all instructions from the outside safety watch person.



contacts.



XXIII

-Safety issues require immediate reporting and correction to remove the hazards.

-ensure all material brought into the waterbox as part of the inspection leaves with you-sign out on the appropriate forms


-summarize all recommended actions


Safety

The following safety equipment and procedures are required prior to performing an

inspection.



Life line HarnessCell phone or radio

Confined space gas monitor Confined space training must be completed.

Complete the confined space testing procedure prior to entering the confined space.

Restrict access until these confined spaces are below 1200F


Prior to entry into the condenser, the following should be addressed:

1. Hazards should be identified and resolved thus eliminating potential accidents

2. Verify the need for Confined Space permitting and complete appropriate trainingand record keeping

3. An Air Quality test should be performed

4. Proper lighting adequate to inspect the water boxes and associated piping

5. Floor openings should be noted and proper coverings should be installed to allowfor safe maneuverability throughout both waterboxes

6. Verification of plant Lock Out/ Tag out procedures and the implementation of

those procedures7. Valves should be inspected to verify full shut-off capability


The cooling water pumps shall be out of service. The cooling water system shall beisolated; all inlet and outlet valves shall be shut and verified to be closed and not leaking.

Water box drains should be inspected to assure they are in proper working

condition and no obstructions exist. Obstructions should be removed and/or plant personnel notified to ensure that water will drain. Once that is verified, grating or

plywood should be installed over the drains to prevent damage to the drain and for the

safety of the crews.



XXIV

All energy or fluid sources, eg, chemical injection, spongy ball injection

equipment must be removed from service.Inspecting condenser water boxes may involve heights, close spaces, hard metal,

and sharp edges. Inspectors should be physically fit and able to climb. They should not

be bothered by feelings of claustrophobia.

Prior to any inspection or cleaning process, it should be determined if scaffoldingis required to reach all areas of the tubesheet.



XXV

APPENDIX 5

COOLING TOWER OUTAGE INSPECTION GUIDELINES

Contents

SAFETY XXVIGENERAL GUIDELINES XXVI

INPSECTION GUIDLINES XXVIII

FANS ................................................................................................................................................. XXVIII

Blades ............................................................................................................................... xxviii

Gear-Driven ..................................................................................................................... xxviiiBelt Drive ........................................................................................................................... xxix

Drive shaft .......................................................................................................................... xxix

WATER DISTRIBUTION ....................................................................................................................... XXIX Headers .............................................................................................................................. xxix

Distribution Nozzels .......................................................................................................... xxix

Strainers ............................................................................................................................. xxixTower Decks ....................................................................................................................... xxx

FILL...................................................................................................................................................... XXX

BASIN.................................................................................................................................................. XXXI

LOUVERS ........................................................................................................................................... XXXII PLENUM ............................................................................................................................................. XXXII

CHEMICAL I NJECTION........................................................................................................................ XXXII

Inhibitor Feed .................................................................................................................... xxxiiAcid Feed .......................................................................................................................... xxxii

Bleach Feed ....................................................................................................................... xxxiiPIPING AND VALVING........................................................................................................................ XXXII

Blowdown ......................................................................................................................... xxxiiMakeup ............................................................................................................................ xxxiiiRisers................................................................................................................................ xxxiii

SUPPORT STRUCTURE....................................................................................................................... XXXIII

Wood ................................................................................................................................ xxxiii

Chemical Attack ............................................................................................................. xxxiii

Biological Surface Attack .............................................................................................. xxxiv

Biological Internal Attack .............................................................................................. xxxiv

Iron Rot .......................................................................................................................... xxxiv

Galvanized ....................................................................................................................... xxxiv

Structural Inspection ........................................................................................................ xxxiv

How to inspect ................................................................................................................ xxxv

LADDERS AND WALKWAYS .............................................................................................................. XXXV



XXVI

Safety

Safety should be paramount in any undertaking performed.

• Identify all hazards that may be encountered during the inspection

• Lock-out/Tag-out

o Ensure all energy sources are isolated o Ensure all fans are de-energized

o Ensure all circ water pumps are de-energized

• Moving parts

o Be aware of all moving parts that will be inspected or are in the inspection

area

• PPE

o Hardhat

o Safety Glasses or Goggles

o Gloves

o Flashlight

o Fall Protection if mandated

o Common sense

• Biological hazards

o Due to the nature of the operation, cooling towers are prone to biological

contamination

o This can be hazardous to personnel health

o Visually inspect tower for cleanliness

If tower appears dirty and there is a distinct odor, assume

biological contamination, and gear up appropriately May require respirator

General Guidelines

• Understand the tower operation and construction, as they will influence the

inspection process. Some examples include:

o Natural Draft, Forced Draft, Cross Flow, etc.

o Know the materials of construction

o Fill type- High Efficiency, Splash, etc.

• Plant operations can greatly affect the cooling tower integrity. For instance, if the

plant yearly capacity is 30%, then we can assume the tower is sitting idle for

extended periods of time.

o Therefore, it is important to understand the consequences of this type of

operation.

o An example would be an increase in biological activity or an increase in

corrosion rates. Both of which affect the integrity of the piping and fill.

• P+ID’s/drawings will improve the quality of the inspection by:



XXVII

o Improving the ability to communicate inspection findings, as well as any

corrective actions that need to take place.

o Helping to determine the root cause of any failures identified during the

inspection.

For instance, if iron fouling is found in the fill, understanding the

entire system may help determine where the origin of the iron

fouling, as well as how to prevent the reoccurrence.

o Identifying heat exchangers supplied by the cooling tower for subsequent

inspections.

o If P+ID’s are not available, hand sketches will do.

• Makeup water source:

o Understanding the chemistry of the makeup source can also help guide the

inspection.

For example, if a particular makeup source is high in silica, there

may be an increased potential for amorphous silica. Therefore, cooling tower fill would be an extremely critical portion

of the inspection.

o Understanding if the makeup source varies will also help to understand

any failures identified during the inspection.

• Review of operating chemistry:

o Upsets in tower chemistry can lead to many problems seen during the

inspection.

o A good understanding of the operating chemistry, and all upsets

experienced, can improve the ability to identify root causes during the

inspection.

• Photos are critical for any inspection:

o It is one thing to describe what was seen, it is another to show what was

seen.

o Photos help when sharing ideas with, as well as asking for assistance from,

others.

o Photos also help to determine year over year conditions, and allow for

determination of improvement or worsening of any existing conditions

• Analyses are critical in understanding what may be causing a particular issue.

They can help indentify root causes, as opposed to chasing down symptoms.Examples of pertinent analyses are:

o Water analyses-

Particularly makeup source

Tower water if still some available

o Biological analyses-

Any biofilms or sludges collected during the inspection



XXVIII

Particularly fill slime or basin sludge

o Deposit analyses-

Any scaling seen in the fill

Fill fouling

Strainer fouling

• When inspecting equipment, ensure that all measurements or recordings are in

accordance with manufacturers’ specifications.

o For instance, belt tension, oil levels, blade pitch, and many others, need to

all be within manufacturers’ specifications.

o Some may change set points in accordance with their previous experience

with similar, although not the same, types of equipment. This rarely ends

up a positive change for the plant operations.

Inpsection Guidlines

Fans

• Fan deck support condition?

• Loose tension rods, staves, panels, bands, and bracing?

• Air seals left off?

Blades

• Has there been a change in blade clearance from fan cylinder?

• Any corrosion and fouling of fan blades?

• Any cracking in fan blades, which is sometimes brought on by abnormal

obstructions?

• Improper pitch on fan blades:

o Is the tower operating with the proper L:G ratio? All towers are designed for a certain L:G ratio.

These ratios are set by the manufacturer, and the blade pitch is

adjusted to achieve the desired L:G.

Changing the pitch will change the L:G.

o Has the amp draw on fan motors changed recently?

o Many plants will re-pitch in order to decrease the amp draw on the motors.

While this may save on electricity use to operate the fan, the

change in tower efficiency will negate this savings.

• Is the blade tip level in accordance with design?

Gear-Driven

• Drive shaft and coupling alignment should be checked.

• Check for misalignment in fan drive mechanism from broken motor mounts,

fungus and iron rot in wooden support members and corrosion in steel support

members.

• Ensure proper lubrication of bearings and gears, and check for leaky gear boxes.



XXIX

• Gearbox oil level and quality should be checked and maintained according to

manufacturers specs.

Belt Drive

• Belt tension systems and drive alignment should be checked on a monthly basis.

Drive shaft

• Bearings should be lubricated every 2000 hours or every three months.

• Corroded drive shaft, oil lines, drive shaft guard, and gear box, often causing

improper oil level in gear box.

• Vibration cutout switch (VCOS) must be operational and maintained.

Water Distribution

Headers

• If possible, visually inspect all headers for obstruction.

o This is particularly critical in systems that operate with high turbidity

waters.

o Typically, when turbidity levels are high, a large amount of debris can

collect in the ends of the headers, which will greatly affect proper water

distribution.

• Is there any scale and debris accumulation in water distribution system piping and

nozzles?

• Distribution piping corroded or broken?

• Failure of fasteners and or wood deterioration causing distribution trough leaks,

spreading of troughs, and unlevel troughs?

• Drying out of tower during down time causing cracks in distribution system and

consequent leaks.Distribution Nozzels

• Missing spray nozzles splash plates, deteriorated splash boards?

• All nozzles intact?

• All nozzles present?

• Nozzles obstructed with scale or debris?

• Nozzles are critical to ensure proper water distribution and prevent channeling.

o Channeling can cause drying in areas of the fill, which can lead to scale

formation.

o Channeling can also lead to large amounts of water falling across a small

section of the fill, thus impeding evaporation.

o Both events decrease tower performance.

• Improper water flow will affect L:G and degrade cooling tower performance.

Strainers

• Installed?

• Free of obstruction?



XXX

• Any corrosion taking place?

• How often are they being cleaned?

• Any tower related issues due to lack of a PM for cleaning strainers?

Tower Decks

Some towers have water distribution decks instead of a network of distribution piping.

The following applies:

• The deck should have a uniform water level, and the gravity distribution holes,

which feed the distribution nozzles, should be free of obstruction.

o If the water level is not level, it is typically related to a riser valve

synchronization issue.

o Is the water overflowing over the deck weirs? This can be an indication of

imbalanced flow control or obstruction of distribution holes.

• Algae is of particular concern with systems where the decks are not closed, and

are exposed to sunlight.

•

Because this area is typically sees the hottest bulk water temps, scaling and fouling typically occurs in the Tower Deck section.

o This can be scales such as calcium carbonate, as well as iron or other

metals fouling.

Even in field erected towers that employ the use of a lateral system, the Tower Decks

may be uncovered, which can lead to algae growth in the drift eliminators and fill below.

It is always advised that the decks be covered and shielded from sunlight.

Fill

• Any chemical attack observed?

• Biological surface attack causing fill sagging?

•

Deposition between fill sheets?o If biological and scale are found, which came first? Again, it is important

to find the root cause, not the symptom.

o Understanding the chemistry during normal operation will help determine

this.

• Is the tower located near a field or other industry such as concrete plants?

o Because towers act as very good scrubbers, outside influences can cause

fouling of the fill, which can in turn cause physical damage.

o Debris accumulation on the fill can cause air flow disturbances, which can

then alter the performance of the tower during normal operation.

• The top section of the fill is most prone to deposition due to the natural effects of

the evaporation profile across the fill.

• Fill slats out of position?

• Fill damage by ice, particularly in forced draft towers?

• Mud, oil, scale accumulation?

• Air and water leaks in casing walls?



XXXI

o Casing wall leaks can cause short circuiting of air and water, thus

degrading cooling tower performance.

Basin

• When was the basin last cleaned?

• Any water leaks?

o Does the conductivity of the bulk water fluctuate greatly? Particularly

during down times?

o This can indicate a leak since you are losing concentrated water and

replacing with dilute makeup.

o If a leak is suspected, ensure there is not a basin level control issue

causing an overflow, which may be assumed to be a leak.

• Basin sludge level:

o Sludge can cause problems in heat exchangers as well as tower fill.

o If a large amount of sludge is present, is there a large amount of biologicalgrowth underneath?

This is typically associated with a black colored sludge and foul

odor.

Bioactivity can be detrimental to the basin, no matter the material

of construction.

Anaerobic bacteria secrete acids, which corrode metals, and can

cause deterioration of concrete basins as well.

o Where is the sludge located?

Near circ water pumps?

At the ends of the basin? Is it due to low flow areas?

• Visible deterioration or corrosion of basin?

o If so, what is causing the deterioration or corrosion?

o High sulfates or chlorides?

Sulfates are aggressive to both galvanized and concrete basins.

Chlorides aggressive to galvanized and stainless.

o Cracks?

o Concrete damage:

Excess sulfates?

Cracks?

Deformation?

• Presence and condition of screens ahead of circ water pumps

o Are screens obstructed with debris?

o Where did it come from?

o How do we prevent it from reoccurring?



XXXII

o Corrosion of screens?

• Corrosion and fouling of pumps?

Louvers

• Check for obstruction?

o Algae

o Debris

o Scale

o Mud

• Sagging louver boards?

o Wood deterioration? (if applicable)

• Missing louvers?

• Corrosion of connection hardware?

Plenum

•

Defined as the enclosed space between the drift eliminators and the fan in theinduced draft towers or the enclosed space between the fan and the fill in forced

draft towers

• Broken or missing drift eliminator slats and sections caused by deterioration of

wooden or metal holders causing bypass of air, drift loss, and improper air

distribution

Chemical Injection

Inhibitor Feed

• Line integrity

• Location provides adequate mixing?

Acid Feed• Proper dilution

o Fed to side stream for motive/dilution water?

o Acid dilution box?

• Concrete or metallurgy damage near injection point?

• Acid will be aggressive to all basin materials of construction.

o Key is to ensure the feed system is set up properly.

Bleach Feed

• Distributed evenly across backside of tower?

• Piping free of obstruction and crystallized bleach?

• If wood tower, is bleach attacking wood?

o See Wood Inspection section.

Piping and Valving

Blowdown

• What is the method of blowdown?

• In reviewing the chemistry logs, has the cycles of concentration been controlled

consistently?



XXXIII

o If not, could indicate a blowdown control issue, such as uncontrolled

blowdown via leaks in piping, basin, etc.

• Where is the blowdown taken from?

o Basin, riser, or other?

o Should be off the return to where hot water is blown down.

• Is the control system manual or automated?

o Any issues experienced with the control system?

• Where does the discharge go to?

o How does it affect the plant and is further inspection of downstream

equipment needed?

o Has the blowdown control caused any issues with discharge permit limits?

Makeup

• How is makeup controlled?

o Is it based on a level sensor?

o If so, how well does the system work.o Excessive foaming in a cooling tower can have adverse effects on many

level sensors.

• What is the source of the makeup water?

o Is it high in metals or turbidity?

o Both can cause fouling in other tower components such as fill.

• Has the tower experienced overflow incidents indicating poor level control and

uncontrolled blowdown?

o This not only affects the chemical program, but affects the program costs,

both chemical and in water usage.

Risers

• Piping intact?

• Water distribution balance achieved during normal operation?

• Control valves operating as needed?

• If using a gravity fed distribution system, are the riser valves to maintain the

appropriate water level throughout the distribution deck?

Support Structure

Wood

The following outlines the mechanisms at which a wood structure can be compromised.

Chemical Attack

• Delignification due to removal of lignin.

o Lignin is the component that binds to the cellulose fibers, providing

strength and hardening of the cell walls.

o Excessive chlorination, <1.0ppm for extended periods, or improper

location of bleach feed can cause delignification.



XXXIV

o Typically a thin layer on the external surface, but can be much deeper

under prolonged conditions.

o Most prevalent in the flooded sections of the tower

Biological Surface Attack

• Commonly called Soft Rot.

o Caused by fungi, which attacks the cellulose of damp wood. Leaves

primarily lignin.

o Seen as dark appearance on the wood surface.

o Active growth of wood-destroying fungi is typically confined to the

surface layers unless the wood is allowed to dry frequently.

Biological Internal Attack

• Occurs below the surface of the wood and goes undetected until the infection

spreads widely.

o The decay can be white rot , attacking both cellulose and lignin and leaving

a spongy, stringy mass, or a brown rot attacking the cellulose and leaving

a brown cube-like pattern.

o This type of attack is more apt to occur in warm, moist, but non-flooded

portions of the tower.

Iron Rot

• Chemical attack caused by the formation of iron salts around corroding ferrous

parts in contact with wood.

o The wood has a charred appearance and may be more susceptible to fungi

attack.

Galvanized• Galvanized components are very susceptible to white rust, which can be due to

high pH, that is, above 8.3.

• Low pH can also cause a loss of the zinc coating, thus promoting corrosion.

• Whit rust can appear as either a very tenacious or very soft white, chalky

formation.

• Low hardness levels can also promote white rust formation.

• Elevated chloride and sulfate levels can promote corrosion of galvanized parts,

particularly wet/dry areas and areas where tower drift may come in contact.

• Consult the manufacturers’ operational manuals for recommended water

chemistry limits.

Structural Inspection

• Bowing columns?

• Sagging braces?

• Loss of any pieces of structure?

• Bolts and bracing?

o Loose



XXXV

o Deteriorating

o Stainless bolt corrosion due to high chloride concentrations in the bulk

water?

o Galvanized hardware may be used, and is susceptible to corrosion under

high pH extremes, as well as chloride and sulfate concentrations

How to inspect

Visual-

What is appearance of the wood, and the depth at which the loose material could be

scraped off with a dull instrument?

Strength-

The breaking strength and brittleness of fill, splash boards and drift eliminators can be

tested by hand.

Touch-

Is the surface of the wood material soft, stringy, spongy, or intact and solid? Probe-

When inspecting for Internal Rot, an ice-pick or screwdriver can be used for probing.

How deep does the probe penetrate the wood? How easy does it penetrate? A

penetration of greater than ¼” could be the indication of Internal Rot. If the probe

penetrates and feels like when missing a stud on a sheetrock wall, this is an indication of

Internal Rot as well. Hammer-

Striking a wood member with a hammer should give good resonance if the wood is sound.

Ig the sound is a dull thud or a hollow sound, Internal Rot may be present.

Ladders and Walkways

• Stable and intact?

• Some are manufactured using galvanized parts.

o

Susceptible to corrosion as outlined in the section above.• All connecting hardware present?



XXXVI

Appendix 6

Electrostatic Precipitator (ESP)

Should already have design documentation, previous inspection reports with either OEM

or station inspection protocol, general operating condition, electrical readings, rapper

issues and problem fields (coupled to routine walkdown), and opacity and particulatematter emissions events and history. [Proper LOTO and keys, grounding procedure,

Confined Space procedures and appropriate Personal Protection Equipment should be in

place before inspection.]

Inspection should comprise of a multi-disciplinary team – operators, mechanical and I&Emaintenance staff, specialist/engineer, OEM (consultants) if required. All findings

should be recorded and properly documented in inspection data sheets with pictures.

This together with previous reports will serve as the maintenance plan for the currentoutage. The main objective is to improve ESP performance, lower the outlet grain

loading to downstream equipment, and lower the gas flow/draft losses/fan power.

In addition to ESP operating history, other boiler and air preheater (APH) operatinghistory and recent test results (boiler gas flow, boiler casing air in-leakage, flyash

unburned carbon (UBC)/loss on ignition (LOI), APH air inleakage and gas outlet

temperatures, SO2 and SO3 concentration, induced draft fan and/or booster fan amp and power history, etc. will be useful as documentation and for root cause analysis. If flue

gas conditioning is used, then operating history (flow, ppm) should be collected as

documentation and for root cause analysis.

Due to different vintages and rapping devices, the inspection is broadly categorized as

follows:

Mechanical –

☺ General appearance and ash deposition before maintenance cleaning – ductwork

and expansion joints, cracks, wires (discharge electrodes, DE) and plates(collecting electrodes, CE), flow conditioning devices, any in-leakages, wet

appearances and unusual buildup.

☺ Check for proper alignment and clearances of DE and CE, and toleranceallowed.

☺ Plate and wires (slacked and broken wires, bowed plates, corrosion and erosion)

☺ Condition of frames – plate assembly and rigid DE.☺ Insulators including rapper/shaft/vibrators and stand-off insulators of DE frame.

☺ Rappers (hammers, pneumatic, vibrators, electromagnetic, electric, etc.), roof and side wall penetrations and rapper/shock bar

If chronic buildup exists and rapping energy/G-force is a suspect,could conduct certain rapping intensity test for inadequacy of G-

force.☺ Inlet gas conditioning devices – turning vanes, straightening devices, perforated

plates, and rapping system if equipped.



XXXVII

☺ Outlet gas conditioning devices – turning vanes, perforated plates, and rapping

system if equipped.☺ Hoppers (plate and ESP proper interface and air in-leakage condition, ash

bridging, deposition, rat hole), vibrators/fluidizing devices, level detectors and

heaters.☺

Bypass – anti-sneakage plates/devices, ash hopper.☺ If applicable, check condition and operating history with respect to the ESP flue

gas inlet:o Flue gas conditioning system – SO3 and ammonia - skid, metering,

injection system and nozzles.

o check SNCR – skid, metering, dilution/injection system and nozzles

injection nozzles, set point vs. actual, and ammonia slip.o SCR operating history – ammonia slip and (total) SO3.

Instrumentation and Electrical – ☺ Grounding, ground cables (doors, frame, etc.)☺

TR sets – access area with insulators (tracking, appearances) – ducts and cables+ cable trays☺ Rappers and rapper controls.☺ Controllers/Automatic Voltage Control – check settings and parameters after

maintenance or replacement.

☺ ESP flue gas pressure drop – check condition of sensing lines and transmitters.☺ If equipped – check condition of particulate or opacity monitors.

For wet ESP (WESP) applications, the attention to detail is the same as dry ESP withsimilar mechanical and electrical inspection of field alignment, DE and CE conditions,

and electrical equipment. The exception is the lack of rapping system, however, there isthe wet or water side. Since WESP is usually the last emissions control equipment and

most are designed to collect acid mist and minor carryover from scrubbers, attention

should focus on wet and acidic corrosion as mentioned below.

Additional subsystems:

• Wash water system, head tanks, and valves and pumps.

• Purge or/and acid recycle and conductivity control, and makeup water subsystems.

• Internal to each field (upflow stage) - Wash headers, nozzles, weirs and troughs.

• Deposition along wet/dry zones, water coverage/distribution and coloration on CE.(If fiberglas look for – smoothness, peeling, uneven wet zones, etc.)

• DE Insulator boxes - cleanliness/puddling/tracking; purge air annulus from insulator

box (dry side) to internal (wet side).• Purge air system – condition of heaters, dampers and operators, headers and branches.




Appendix 7

Feedwater Heater Deaerators Inspection Guidelines

1. General Area

A condenser water box inspection should be undertaken as a team effort. It is recommended

that a minimum of two individuals participate. Utilizing Inspection team members frommaintenance, engineering, and operations will broaden the view and improve the findings.

One may rotate as the outside safety watch or all may enter simultaneously if the safety-watch

function can be performed by another. It is recommended that one person serve as scribe and another carry the camera or video recording device. The notes / records may be recorded in

writing or via sound recording to be transcribed immediately thereafter. Upon exitingcondenser waterboxes all notes, records, and photographs should be duplicated and stored

separately to ensure preservation of this information. Most power plants contain two or more

waterboxes and all notes should be properly labeled to ensure they refer to the correct water box.

2. Cleanliness, Corrosion, and Cleaning

The initial inspection should occur prior to any cleaning activities. The initial inspection of the tubesheets shall verify surface cleanliness. Debris, bio-growth and sediment should beremoved prior to any cleaning of or testing of the individual tubes. Any loose debris should be

remove and all debris lying within the in the first few inches of the tubes should be removed.

If the debris on the surface of the tubesheet is significant, high pressure water cleaning should be performed.

After cleaning the tubesheet, a general inspection shall be conducted to verify its

condition. Any pitting, erosion, separation or other defects should be noted and plant personnel informed.

Inspection of the tube to tubesheet joints is in order to determine potential problems

and/or current issues that have not been discovered. The inspection should look for separation between the tube and tubesheet, cracking, or general corrosion.

If the tubesheet has an existing coating, the coating should be inspected for cracks, air pockets, chips and/or any major loss of the coating leaving the tubesheet exposed.

Individual tubes should be inspected for fouling. Conduct a visual inspection of the tubes byscanning the entire tube sheet, looking down the inside diameter of the tubes for visual

comparison to determine if all areas are similar in cleanliness or if some areas, such as the top

or bottom sections of the tube sheet, have different levels of fouling.1. This visual inspection should be conducted on both the inlet and outlet ends of the

tubes. In many cases one end of the tube may be significantly more fouled thanthe other as a result of water temperature and or flow conditions.

2. Note the findings for reference as you proceed with the remainder of theinspection.

To verify the amount or the presence of down tube fouling, it is suggested thatmechanical tube cleaners, such as metal scraper or brush type cleaners, be shot through



XXXIX

sample tubes and that the deposits being removed by these cleaning tools should be

captured in a container for qualitative and quantitative analysis.

1. This captured sample can be strained and filtered leaving only the fouling material

in the sample.

2. The fouling can then be analyzed for it quantitative and qualitative content.3. Samples should be gathered from various sections of the condenser in order to

determine if the fouling material is consistent.

4. It is recommended that a second sample be taken these sampled tubes todetermine if all removable fouling has been successfully removed.

5. If there is considerable fouling found in the 2nd

pass or even 3rd

pass cleaning

sample it may be determined that multiple cleaning passes will be required.6. If the tube debris is such that a cleaner cannot be shot or becomes lodged and

unable to be removed, the suitable tube plug should be installed into both the inlet

and outlet ends of the tube.

There are multiple tube cleaning tool designs available so it would be beneficial toevaluate different style cleaning tools in this same way to determine what tool is most

effective.

To further qualify the extent of tube cleanliness an inspection can be done by inserting a

boroscope or videoprobe into individual tubes.

1. In this type inspection it is recommended to inspect prior to and after sample tube

cleaning.2. It is also recommended to inspect from both the inlet and outlet ends of the tube

and as far down the tube length as possible depending on the length of scope or probe being used.

The results of the bore-a-scope inspection combine with the comparison of the tube

deposits gathered during sample tube cleaning are excellent ways to determine condenser cleanliness and the effectiveness of the chosen cleaning method.

The video inspection also provides a means of determining the condition of the tubes and whether an Eddy Current test is needed. Some tube damage can be observed visually and

through the use of the video probe.

Identifying the source of the foreign material will assist in preventing its recurrence. Most

cooling water systems contain one or more methods of excluding foreign material, eg screens,

debris filters, etc. Depending upon the material found, the component can be identified thatfailed or is unable to preclude it entering the condenser.

While in the water box, an inspection of any sacrificial anodes should be conducted to verify

condition.

3. Eddy Current Testing



XL

Eddy Current testing on a sample of tubes provides information to determine the general

condition of the condenser tubes.1. If considerable tube wall loss or tube pitting is noted, it is recommended that you

expand this testing to analyze the extent of the problem.

2. Plugging of tubes should be completed on those tubes that exceed the standards

set by the plant.

4. Expansion Joints

Flexible expansion joints may be located between the cooling water piping and the water boxes to accommodate different thermal growth rates of those components during startup,

operation, and shut down. They should be inspected to ensure no cracking, tears, or

damage is visible that may progress and create a leak or catastrophic failure duringoperation prior to the next planned outage.

5. Instrumentation

There may be several sets of level taps used to monitor and control the level in each

waterbox. Ensure all are open and free from debris.

All temperature probes should be encased in a thermowell. Temperature probes may be

located in the cooling water piping upstream / downstream of the water boxes. Thethermowells should be free of debris and un-damaged.

6. Penetrations

Examine the penetrations through the water box for signs of fatigue cracks, erosion, or

corrosion. In advance of the inspection, inspectors should familiarize themselves with

the location and purpose of these penetrations as identified on design drawings.

7. Valves

In addition to inlet and outlet isolation valves, the water boxes may contain large valves

used for back-washing. Examine the seats and disks of all visible valves to ensure they

free from obstructions and they provide a seal.



XLI

Appendix 7

Feedwater Heaters, Deaerators

Table of Contents

TABLE OF CONTENTS ....................................................................................................... XLI

GENERAL FEEDWATER HEATER INSPECTION GUIDELINES ....................... XLII SAFETY ................................................................................................................................ XLIV

1. GENERAL AREA ............................................................................................................. XLV 1.1 GENERAL ........................................................................................................................... XLV 1.2 CLEANLINESS / DEBRIS / CORROSION ............................................................................... XLV

2. PARTITION PLATE ........................................................................................................ XLV 3. TUBE SHEET .................................................................................................................... XLV

4. TUBE ID .............................................................................................................................. XLV

5. SHELL SIDE ...................................................................................................................... XLV 5.1 CLEANLINESS / DEBRIS / CORROSION .............................................................................. XLVI

5.2 TUBESUPPORT SHEETS .................................................................................................... XLVI

5.3 BAFFLE PLATES ................................................................................................................ XLVI 5.4 DRAIN COOLER SECTION (WHERE APPLICABLE).............................................................. XLVI 5.5 TUBEOD ..........................................................................................................................XLVI

6. DEAERATORS AND THEIR DRAIN/STORAGE TANKS ................................... XLVI 6.1 CLEANLINESS / DEBRIS / CORROSION .............................................................................. XLVI 6.2 TRAYS............................................................................................................................... XLVI

6.3 DRAIN TANK ..................................................................................................................... XLVI

7. EXTRACTION STEAM PIPING ................................................................................. XLVI



XLII

General Feedwater Heater Inspection Guidelines

This is a general inspection procedure, not all areas or items will pertain to everyfeedwater heater.








-review recent operating history-terminal difference

-feedwater temperature rise-drain cooler approach (where applicable)

-feedwater pressure drop

-tube leak history and map-abnormal operating events


-Obtain the drawings and specifications of each feedwater heater prior to inspection toaide in the inspection and report/documentation.

-make a plan or checklist on the items and areas of interest that should be inspected. This

plan of which feedwater heaters should be opened and inspected should be justified based on historic performance and maintenance

-make a safety plan and conduct a briefing prior to the inspection


-gather cameras, flashlights, and writing equipment, and ensure sufficient lanyards are

available for all equipment that enters the feedwater heater



-Inspect the heat exchanger systematically, from top to bottom or left to right, to ensure

all tubes and other internal areas receive adequate attention



XLIII

-Record all information as observed; do not rely on mental notes. This is critical toensure all findings will be included on the inspection report.



contacts.

-Safety issues require immediate reporting and correction to remove the hazards.

-ensure all material brought into the feedwater heater as part of the inspection iswithdrawn


-summarize all recommended actions




XLIV

Safety

The following safety equipment and procedures are required prior to performing an

inspection.


Gloves, Primary and backup Flashlights, Dust Mask or respirator with HEPA filter for

ceramic fibersCell phone or radio

Confined space gas monitor

Confined space training must be completed.Complete the confined space testing procedure prior to entering the confined space.

Restrict access until the confined spaces of the unit are below xxx0F



All energy sources, steam, feed water or recirculation pumps, lay-up and chemicalinjection equipment such as those supplying a nitrogen blanket must be removed from

service.

Consider double block & bleed valve isolation for inspections if any connections exist tooperating units.

Inspecting a feedwater heater usually involves entering the end bell of the heat exchanger with your head or upper body. While not a typical confined space since egress is much

easier, it still presents many of the same hazards as those spaces in which your entire

body enters the confined space.



MARCH 2010 XLV

1. General Area

1.1 General A feedwater heater inspection should be justified and planned in advance. The frequency of

inspection is dependent upon the history of operation, performance, and maintenance of the

heater. Scheduling when the heater will be open during an outage should incorporate any

contingencies to ensure time exists to complete any required repairs. If eddy-current testing of the tubes or other wall thickness data is desired, arrangements should be made to ensure

personnel with those capabilities and the related instruments are available. The notes / records

may be recorded in writing or via sound recording to be transcribed immediately thereafter.Upon completing the inspection of each feedwater heater all notes, records, and photographs

should be duplicated and stored separately to ensure preservation of this information.

For those feedwater heaters located in the condenser neck, refer to the section on condenser steam space inspection. The next four sections pertain to shell and tube heat exchangers; the

following section pertains to deaerating heaters, and the last section pertains to both type

heaters.


Note any signs of debris, foreign material, and corrosion products. Identifying the source of the foreign material will assist in preventing its recurrence.

2. Partition Plate

Leakage of cold feedwater to the heater outlet can be avoided if the partition plate and the

associated hardware are intact. The partition plate should be visually inspected for any

signs of wear or erosion. If signs of wear or erosion are evident, the wall thickness of the plate should be determined and compared to design. Check the hardware, gaskets of

other materials that keep the partition plate in place and maintain the seal between the

feedwater inlet and outlet. Again, signs of erosion, bolt-hole enlargement, or other signsof unintended flow paths should be identified.

3. Tube Sheet

The tube to tube sheet seal should be inspected to ensure no leakage is occurring. Look

for erosion or shiny wear spots. The tube sheet should be flat and not warped or uneven.

If necessary an ultra-sonic depth gage can be used to determine any metal loss from the

tube sheet. There should not be signs of any flow between the edges of the tube sheetand the heater shell.

4. Tube ID

The tubes should first be visually examined for damage, or the existence of foreign

material, fouling, or scaling. This visual inspection may continue deeper into the tubes

through the use of a video probe. If the tubes are not clean or clear, the source of thefouling or foreign material should be identified and the tubes should be cleaned or

performance will suffer and tube leaks may occur in the future.

If tube leaks have occurred in the past, the map of plugged tubes should be used to ensure

all plugs are intact. Quantitative tube wall thickness measurements can be done with a

eddy current testing.

5. Shell Side

A visual inspection of the shell side can be conducted with a video probe through an

instrument connection. While it is not normal practice to conduct an internal inspection



MARCH 2010 XLVI

of each feedwater heater during each planned outage, occasional inspections of mal-

performing heaters can help identify the causes and potential solutions.


Note any signs of debris, foreign material, and corrosion products. Identifying the source of the foreign material will assist in preventing its recurrence.

5.2 Tube Support Sheets

The tube support plates should be secure and parallel to each other, perpendicular to the tubes.The holes should not be enlarged or uneven.

5.3 Baffle Plates

Examine all baffle plates for structural soundness. These are installed to prevent tubedamage by absorbing or deflecting the high energy flows entering the heater and are

subject to wear and failure. If any unattached baffle plates are found in the belly of the

heater, identify its source and ensure the penetration it was covering is covered with a

replacement. Examine all unprotected penetrations for signs that a baffle was previously

installed and may have torn loose.

5.4 Drain Cooler Section (where applicable)Inspect the “can” surrounding the drain cooler section for cracks, holes, or other openings. It

should contain the final pass of tubes.

5.5 Tube ODThe external surfaces of the tubes should be clean and undamaged. If fouling or scaling is

identified, a sample should be acquired to determine its composition and source to prevent

further buildup. Those surfaces should be clean for maximum performance. If the tubesexperienced excessive vibration, fretting or wear may be evident at some of the support sheets.

6. Deaerators and their Drain/Storage Tanks

Deaerators are usually larger vessels than shell and tube feedwater heaters, and can permit

human entry. There is not a lot of space, though and prior planning and very carefulmovements will help one conduct a safe internal inspection. Once inside the heater, a video

probe can assist the inspection.

6.1 Cleanliness / Debris / Corrosion Note any signs of debris, foreign material, and corrosion products. Identifying the source of

the foreign material will assist in preventing its recurrence.

6.2 TraysThe trays should be secure and undamaged. They should be checked for signs of wear. .

6.3 Drain TankThe internal supports should be examined to ensure structural integrity. In addition to avisual inspection, the welds may be checked via non-destructive testing (NDT) methods.

7. Extraction Steam Piping

The inside of extraction steam piping can be viewed using a flexible video probe as

accessed through an instrument connection, high point vent, or low point drain. The non-

return check valve should be checked to ensure it is in place and fully functional. (The



MARCH 2010 XLVII

wall thickness of elbows on wet extraction steam lines can be checked using NDT from

the outside of the pipe.)



MARCH 2010 XLVIII

Appendix 8

Feedwater Heaters, Deaerators



MARCH 2010 XLIX

Appendix 9

Heat Recovery Steam Generators (HRSGs)Table of Contents

TABLE OF CONTENTS .................................................................................................... XLIX

GENERAL INSPECTION GUIDELINES............................................................................ IV

SAFETY ....................................................................................................................................... V1. DUCTWORK ......................................................................................................................... 54

1.1 GENERAL .............................................................................................................................. X

1.2 OFFLINE VISUAL I NSPECTION .............................................................................................. X1.2.1 Ductwork from CT Exhaust to HP Secondary Superheater ............................... X

1.2.2 HRSG Exterior ................................................................................................... X

1.2.3 HRSG Interior .................................................................................................... X

1.2.4 CT Outlet (Gas Inlet to HRSG) .......................................................................... X

1.2.5 Penetrations ....................................................................................................... X

1.2.6 Expansion Joints ................................................................................................ X

1.2.7 Bypass Stack & dampers................................................................................... X

1.3 DUCTWORK NOTES .............................................................................................................. X1.3.1 Hotspots and leaks ............................................................................................ X

2. HP SECONDARY SUPERHEATER .................................................................................. X

2.1 GENERAL .............................................................................................................................. X2.2 OFFLINE VISUAL I NSPECTION .............................................................................................. X

2.2.1 Tube Elements .................................................................................................... X

2.2.2 Pole Baffle .......................................................................................................... X

2.2.3 Side Baffles ......................................................................................................... X

2.2.4 Tube Sheets ........................................................................................................ X

2.2.5 Lower Shield ..................................................................................................... X

3. SECONDARY REHEATER ................................................................................................ X3.1 GENERAL .............................................................................................................................. X

3.2 OFFLINE VISUAL I NSPECTION .............................................................................................. X

3.2.1 Tube Elements .................................................................................................... X

3.2.2 Center Baffle ...................................................................................................... X

3.2.3 Side Baffles ......................................................................................................... X

3.2.4 Tube Sheets ........................................................................................................ X

3.2.5 Lower Shield ...................................................................................................... X

4. DUCT BURNERS ................................................................................................................... X

4.1 GENERAL .............................................................................................................................. X4.2 OFFLINE VISUAL I NSPECTION .............................................................................................. X

4.2.1 Burner runner and baffles .................................................................................. X 4.2.2 Fuel Supply Piping ............................................................................................. X

4.2.3 Burner Supports ................................................................................................. X

4.3 Catalysts & chemical injection grids ....................................................................... X

5. PRIMARY REHEATER ....................................................................................................... X

5.1 GENERAL .............................................................................................................................. X




MARCH 2010 L

5.2.1 Tube Elements .................................................................................................... X

5.2.2 Center Baffle ...................................................................................................... X

5.2.3 Side Baffles ......................................................................................................... X

5.2.4 Tube Sheets ........................................................................................................ X

5.2.5 Lower Shield ..................................................................................................... X

6. HP PRIMARY SUPERHEATER ........................................................................................ X7. HP EVAPORATOR ............................................................................................................... X


5.2.1 Tube Elements .................................................................................................... X

5.2.2 Center Baffle ...................................................................................................... X

5.2.3 Side Baffles ......................................................................................................... X

5.2.4 Tube Sheets ........................................................................................................ X

5.2.5 Lower Shield ..................................................................................................... X

8. IP SUPERHEATER ............................................................................................................... X

8.1 GENERAL .............................................................................................................................. X


8.2.1 Tube Elements .................................................................................................... X 8.2.2 Center Baffle ...................................................................................................... X

8.2.3 Side Baffles ......................................................................................................... X

8.2.4 Tube Sheets ........................................................................................................ X

8.2.5 Lower Shield ..................................................................................................... X

9. HP / IP PRIMARY ECONOMIZER ................................................................................... X

9.1 GENERAL .............................................................................................................................. X


9.2.1 Tube Elements .................................................................................................... X

9.2.2 Center Baffle ...................................................................................................... X

9.2.3 Side Baffles ......................................................................................................... X

9.2.4 Tube Sheets ........................................................................................................ X

9.2.5 Lower Shield ..................................................................................................... X

10. LP EVAPORATOR ............................................................................................................. X

10.1 GENERAL ............................................................................................................................ X10.2 OFFLINE VISUAL I NSPECTION ............................................................................................ X

10.2.1 Tube Elements .................................................................................................. X

10.2.2 Center Baffle .................................................................................................... X

10.2.3 Side Baffles....................................................................................................... X

10.2.4 Tube Sheets ...................................................................................................... X

10.2.5 Lower Shield .................................................................................................... X

10.2.6 Flow Accelerated Corrosion (FAC)................................................................ X

11. FW HEATER ........................................................................................................................ X

11.1 GENERAL ............................................................................................................................ X

11.2 OFFLINE VISUAL I NSPECTION ............................................................................................ X

11.2.1 Tube Elements .................................................................................................. X

11.2.2 Center Baffle .................................................................................................... X

11.2.3 Side Baffles....................................................................................................... X

11.2.4 Tube Sheets ...................................................................................................... X



MARCH 2010 LI

11.2.5 Lower Shield .................................................................................................... X

11.2.6 Flow Accelerated Corrosion (FAC) ................................................................. X

11.2.7 Inlet Header .................................................................................................... X

12. SUPPORTS, GUIDES, EXPANSION JOINTS ............................................................... X

12.1 CT/HRSG MAIN EXPANSION JOINT.................................................................................. X

12.1.1 General ............................................................................................................ X 12.1.2 Visual Inspection............................................................................................. X

12.2 GENERAL GROUND LEVEL ................................................................................................. X

12.3 GENERAL TOP LEVEL ......................................................................................................... X

13. HIGH PRESSURE DRUM ................................................................................................. X

13.1 GENERAL ............................................................................................................................ X


13.2.1 Chevron Dryers ................................................................................................ X

13.2.2 Vortex Duct ...................................................................................................... X

13.2.3 Piping and Tubing........................................................................................... X

14. INTERMEDIATE PRESSURE DRUM ........................................................................... X

14.1 GENERAL ............................................................................................................................ X14.2 OFFLINE VISUAL I NSPECTION ............................................................................................ X

14.2.1 Chevron Dryers ................................................................................................ X

14.2.2 Vortex Duct and Separators............................................................................. X

14.2.3 Piping and Tubing........................................................................................... X

15. LOW PRESSURE DRUM & INTEGRAL DEARATOR ............................................. X

15.1 GENERAL ............................................................................................................................ X


15.2.1 Chevron Dryers ................................................................................................ X

15.2.2 Drum Baffles .................................................................................................... X

15.2.3 Piping and Tubing........................................................................................... X15.3 Integral Dearator .................................................................................................. X

16. STACK AND STACK DAMPER ...................................................................................... X

16.1 STACK ................................................................................................................................. X

16.2 STACK DAMPER .................................................................................................................. X



MARCH 2010 LII

General HRSG Inspection Guidelines

This is a general inspection procedure, not all areas or items will pertain to every HRSG.If HRSG’s contain upper and lower dead air spaces these will need to be inspected to

complete the procedure.

Prior to Inspection: Check last inspection report.

Check if unit is scheduled for SCR catalyst sample/coupon testing.

Inspect unit from front to rear, stack being the rear of the unit.

Obtain a side elevation drawing of the unit prior to inspection to aide in documentation.

Access doors are numbered from front to rear. The number one (1) access door is located

in the CT’s outlet ductwork just before the high pressure superheater.

Before the unit is shut down for inspection it is recommended to use thermography tolocate hot spots on the external casing. Any hot spot 130 F and above should be

documented

Record all information and findings on the inspection report.

Report the significant findings from the inspections immediately to the responsible plant

contacts. Safety issues require immediate reporting and correction to remove the hazards.



MARCH 2010 LIII

Safety




Life line Harness for stack inspection.

Cell phone or radioConfined space gas monitor for all interior sections


Complete the confined space testing procedure prior to entering the confined space.Restrict access until the confined spaces of the unit are below 115

0F

Safety person for hole watch for permit required confined spaces.

Equipment taken out of service (LOTO) and sign on the clearances for that equipment.All energy sources, steam, feed water or recirculation pumps, fuels and chemical

injection equipment such as the ammonia must be removed from service.Consider double block & bleed valve isolation for drum inspections when two or more

HRSGs are tied to a common steam turbine. Then confirm no leak thru of the root valves

on common systems, HP, IP or LP.



54

1. Ductwork

1.1 General Any part of the HRSG exterior that contains flue gas and HRSG tubes is considered ductwork.

Ductwork configuration varies with each vendor but typically consists of insulation between

liner plates (HRSG interior) that are held to an external casing by anchor pins. The HRSG gas-

tight exterior casing is typically made from carbon steel and liner plates are generally made fromstainless steel in high temperature areas and carbon steel in low temperature areas.

1.2 Offline Visual InspectionInspect and record the overall condition of the HRSG exterior casing and interior (liner plates).

- Check for missing or damaged sections- Loose or missing fasteners.

- Corrosion

- Check for deposits on liner plates interior.

- Inspect all locations where pressure parts penetrate the external casing.

1.2.1 Ductwork from CT Exhaust to HP Secondary Superheater1.2.2 HRSG Exterior

Inspect and record the overall condition of the HRSG ductwork.- Check for hot spots on exterior ductwork. Areas where the ductwork paint has stripped

off and there is metal discoloration may be due to hotspots. They can also be found

prior to shutdown using a thermographic camera.- Check for any openings (or cracks) in ductwork that allows flue gas to escape. Leaks

can often be identified during an offline inspection by the discolored smear flue gas on

the ductwork.- Check for water collection points. These points are susceptible to corrosion and may

develop weep holes.

1.2.3 HRSG Interior

Inspect and record the general condition of the liner plates (HRSG interior).

- Check for cracks, physical damage, and deformation in liner plates.- Check welds for cracks.

- Record any missing sections.

- Check for loose or missing fasteners.- Check tack welds on washers. These tack welds prevent spinning and wear.

- Check for deposits on liner plates especially in sections downstream in the HRSG.

Collect samples for testing.- Check deposit distribution, if any. This gives an indication of the types

operational/distribution conditions that exist.

1.2.4 CT Outlet (Gas Inlet to HRSG)

This area is extremely turbulent. Liner attachments are usually on closer spacing with batten

channels installed for additional support.

- Inspect cover plates for misalignment, bending or warpage.



55

- Liner plates at the area of open duct, especially from the turbine exhaust to the first bank

of tubes which is exposed to the highest velocity of CT exhaust, must be inspected thoroughly.

- Check liner plates for deformation such as warping and buckling due to binding and

high temperature ramp rates.

- Inspect studs for gouging due to rapid movement of liner plates.- Tack welds and nuts must be inspected for erosion.

- Check for damaged or missing batten channels (it may be difficult to identify missing

sections). If any missing sections are identified, debris may be located downstream theHRSG.

1.2.5 Penetrations

Inspect penetrations and record misaligned tubes. Check for physical damage of HRSG exterior

duct work and liner plates (and tubes) from tubes due to vibration.

1.2.6 Expansion Joints

Supports Guides and Expansion Joints.1.2.7 Bypass Stack

Inspect the damper, guides and ductwork interior of the bypass stack.

Ensure that all inside skin casings are intact.

Check inside skin casings for:

• misalignment

• missing sections

•

binding• warpage

• Missing hold-down clips.

Inspect the damper for missing components, worn guides or binding

Check that insulation is intact, pay particular attention to the expansion joints and the blanking

plate.

Inspect the gas shields around the expansion joints for damage.If the bypass stack silencer and upper portions need inspection an outside contractor will be

needed to install rigging. An NDE contractor will be needed to perform thickness testing of thestack walls. Still visually inspect and record any physical damage that is visible from base level.

Scheduled inspection frequencies are located at

jb\cap\insp_rept\combustion air\stack inspection schedule



56

1.3 Ductwork Notes

1.3.1 Hotspots and leaks

Hotspots usually occur in areas where there are missing liner plates and the insulation has broken

down due exposure to flue gas. There are also areas where the liner plates are intact (possibly

warped) but there is insulation breakdown. In this case the breakdown of insulation may have

been caused by moisture degradation of the insulation.

Hotspots can best be found with the thermographic camera before shutdown.

Insulation on tube fins downstream - possible problem at CT outlet (HRSG Inlet).



57

2. HP Secondary Superheater

2.1 General The front row is easily accessible for inspection. It will be difficult to inspect the other rows of

tubes.

- Most tubes are top supported with tube bundle guides at the bottom. Some are bottomsupported with expansion guides located at the top.

- Tubes are finned tubes.

- Baffles are installed in the gas path to reduce gas bypassing and improve eat transfer.- When conducting an inspection look as deeply in the tube bundles as possible for any

defects.

2.2 Offline Visual InspectionInspect the overall condition of the tube elements and fin structure.

- Check for cracks.

- Check for damaged fins on tube elements.- Check for deformed tubes.

- Check for deposits on tube elements and fins. Collect samples for testing where possible.

- Check for deposits or debris on roof and floor of HRSG.

- Check for corrosion.

2.2.1 Tube Elements

- Inspect tubes for physical damage.- Check for damaged fins on tube elements.

- Check for warped or deformed tubes.- Check for misaligned tube elements.

- Check for tube bundle misalignment.

- Check for deposits, corrosion and debris. Collect samples for testing where possible.

- Inspect deposit distribution.

Inspect deposit distribution and damaged fin distribution, if any, for any unusual patterns. This

may give an indication of operating and/or distribution problems in HRSG.

Tube bundle misalignment may indicate tube support problems or thermal expansion issues.

2.2.2 Baffles

Thorough inspection of the existing baffles is very important at this location.

- Inspect baffles for warping.- Inspect baffle welds for cracks.

- Check for missing or damaged guide vanes on baffles.

- Inspect guide vane welds for cracks.

- Inspect baffle penetrations.



58

2.2.3 Side Baffles

The Side Baffles should be thoroughly inspected especially those in the HP SecondarySuperheater since they are in direct path of the CT exhaust gas.

- Inspect baffle for warpage.

- Inspect baffle welds for cracks.- Check for missing or damaged sections.

- Inspect wall connection for cracks.

- Check for excessive gaps that allow gas bypassing.- Check for binding due to thermal expansion.

2.2.4 Tube Sheets

Tube sheets are installed in horizontal sections. They help to keep tubes aligned during

operation. During inspection look as far as possible in the tube bundles for any damage,

misalignment, missing sections, deposits, or any abnormalities.

- Inspect tube sheets for warpage.- Check for cracks in welds or in tube sheet material.

- Check for damaged or missing sections.- Check for misalignment. Misalignment may cause damage to tube fins.

2.2.5 Lower Shield

- Inspect shield for warpage.

- Check for cracks in welds or in shield material.

- Check for damaged or missing sections.- Check for guide misalignment and missing bolts and fasteners.



59

3. Secondary Reheater


tubes.




defects.

.

Care should be taken when entering this area since the Pyro-Bloc insulation may be installed and

is damaged easily. The Pyro-Bloc insulation is a ceramic fiber with a coating of inorganic

hardening agent is susceptible to trampling. Plywood should be installed prior to entering this

section to protect insulation.


- Check for cracks.- Check for damaged fins on tube elements.

- Check for deformed tubes.


- Check for deposits or debris on roof and floor of HRSG.- Check for corrosion.

3.2.1 Tube Elements


- Check for warped or deformed tubes.

- Check for misaligned tube elements.- Check for tube bundle misalignment.






3.2.2 Center Baffle

- Inspect center baffle for warpage.- Inspect center baffle welds for cracks.

- Check for missing or damaged sections.



60

3.2.3 Side Baffles

The Side Baffles should be thoroughly inspected especially those in the HP SecondarySuperheater since they are in direct path of the CT exhaust gas.





3.2.4 Tube Sheets






3.2.5 Lower Shield

- Inspect lower shield for warpage.

- Check for cracks in welds or in shield material.

- Check for damaged or missing sections and loose or missing fasteners.

3.2.6 Pyro-Bloc Module( If Applicable)

Pyro-Bloc module is composed of two monolithic pieces of edge grain ceramic fiber with an

internal yoke and two support tubes. It is covered with a sprayed on inorganic hardening agent

to improve its velocity resistance. It protects the outer casing from the flame generated from the

duct burners combined with the hot gas from the CT.

Refer to the Manufacturer’s manual for more information on the structure of the module.

- Inspect module for damage.

- Check for missing sections.

- Check for deposits. Collect samples for testing where possible.- Inspect hardening agent and assess if reapplication is needed.

- Inspect downstream fins for ceramic fiber (evidence of Pyro-Bloc erosion).



61

4. Duct Burners & Catalysts

4.1 General The duct burners are located downstream the Secondary Reheater. There are four rows of burner

runners. Each row consists of a gas runner with orifices and flame retention baffles on the top

and bottom or the runner. The baffles help create a recirculation zone to assure stable ignition

and combustion.

4.2 Offline Visual InspectionInspect the overall condition of the burner runners and baffles.

- Check for cracks.

- Check for damaged elements.- Check for deformed elements.

- Check for deposits. Collect samples for testing where possible.

4.2.1 Burner runner and baffles

- Inspect runners and baffles for physical damage.- Check for damaged supports on burner assemblies.

- Check for warped or deformed baffles.- Check for runner integrity.

4.2.2 Fuel Supply Piping

4.2.3 Burner Supports

4.3 SCR Catalysts

4.3.1 Ammonia Injection Grid (AIG)

- Inspect for damage and binding.

- Inspect ammonia injection grid structure and supports.

- Check for pluggage due to foreign objects inside nozzles. If extruded nozzles are

installed check for missing sections. If there are any missing sections check if themissing section (s0 is logged in the catalyst or has caused damage to the catalyst.

- Check for runner integrity. This is of critical importance. Plugged nozzles can lead to

severe system under performance. Any debris from the vaporization system will lead to plugged nozzles.

- Check for deformation and corrosion

- Inspect injection lance wall penetrations- Confirm the condition of tube banks down stream for evidence of any deposits and

plugging.

4.3.2 CO Catalyst

- Look for evidence of flow imbalances (strange dusting pattern).

- Inspect the support frame (reactor) for deformation or physical damage such as cracks.

- Check support frame for corrosion.- Check for catalyst deformation or physical damage.

- Check for any shift in catalyst layer.



62

- Check for dust erosion of catalyst.

- Check catalyst for pluggage and dust accumulation- Collect any corrosion and/or deposit sample where applicable.

- Remove catalyst test sample for laboratory testing if required.



63

5. Primary Reheater


tubes.




defects.


- Check for cracks.





5.2.1 Tube Elements









5.2.2 Center Baffle

- Inspect center baffle for warpage.

- Inspect center baffle welds for cracks.- Check for missing or damaged sections

5.2.3 Side Baffles

The Side Baffles should be thoroughly inspected especially those in the Primary Reheater sincethey are in direct path of the duct burners and CT exhaust gas.



64




- Check for excessive gaps that allow gas bypassing.

- Check for binding due to thermal expansion.

5.2.4 Tube Sheets

Tube sheets are installed in horizontal sections. They help to keep tubes aligned duringoperation. During inspection look as far as possible in the tube bundles for any damage,


- Inspect tube sheets for warpage.

- Check for cracks in welds or in tube sheet material.

- Check for damaged or missing sections.

- Check for misalignment. Misalignment may cause damage to tube fins.

5.2.5 Lower Shield



- Check for misalignment.



65

6. HP Primary Superheater


tubes.




defects.

6.2 Offline Visual Inspection

Inspect the overall condition of the tube elements and fin structure.


- Check for deformed tubes.- Check for deposits on tube elements and fins. Collect samples for testing where

possible.


6.2.1 Tube Elements

- Inspect tubes for physical damage.

- Check for damaged fins on tube elements.- Check for warped or deformed tubes.

- Check for misaligned tube elements.


- Check for deposits, corrosion and debris. Collect samples for testing where possible.- Inspect deposit distribution.

Inspect deposit distribution and damaged fin distribution, if any, for any unusual patterns. Thismay give an indication of operating and/or distribution problems in HRSG.


6.2.2 Center Baffle

- Inspect center baffle for warpage.- Inspect center baffle welds for cracks.

- Check for missing or damaged sections

6.2.3 Side Baffles

The Side Baffles should be thoroughly inspected especially those in the Primary Reheater since

they are in direct path of the duct burners and CT exhaust gas.



66

- Inspect baffle for warpage.- Inspect baffle welds for cracks.




6.2.4 Tube Sheets








6.2.5 Lower Shield



- Check for damaged or missing sections.- Check for misalignment.



67

7. HP Evaporator


tubes.




defects.


- Check for cracks.





7.2.1 Tube Elements









7.2.2 Center Baffle


- Inspect center baffle welds for cracks.- Check for missing or damaged sections

7.2.3 Side Baffles

The Side Baffles should be thoroughly inspected especially those in the Primary Reheater sincethey are in direct path of the duct burners and CT exhaust gas.



68






7.2.4 Tube Sheets







7.2.5 Lower Shield



- Check for misalignment.



69

8. IP Superheater


tubes.




defects.


- Check for cracks.





8.2.1 Tube Elements









8.2.2 Center Baffle


- Inspect center baffle welds for cracks.- Check for missing or damaged sections.

8.2.3 Side Baffles

The Side Baffles should be thoroughly inspected especially those in the IP Superheater.


- Inspect baffle welds for cracks.



70


- Inspect wall connection for cracks.- Check for excessive gaps that allow gas bypassing.


-

8.2.4 Tube Sheets







8.2.5 Lower Shield





71

9. HP / IP Primary Economizer


tubes.




defects.

Close inspection of adjoining headers at the floor location is recommended. Differential

expansion between the IP and HP sections may result in damage. Pay attention to straightness of

the bundle and individual tubes. Bowed tubes indicate differential thermal expansion and future

tube failures at tube to header connections.


Inspect the overall condition of the tube elements and fin structure.- Check for cracks.

- Check for damaged fins on tube elements.


possible.


9.2.1 Tube Elements






Inspect deposit distribution and damaged fin distribution, if any, for any unusual patterns. Thismay give an indication of operating and/or distribution problems in HRSG.

Tube bundle misalignment may indicate tube support problems or thermal expansion issues.Record the location of bowed tubes for analysis of the root cause of the damage and for future

inspections to monitor the change in damage or distortion. Distorted tubes may be located at

baffles or feeder and riser tubes.



72

9.2.2 Center Baffle


- Inspect center baffle welds for cracks.


9.2.3 Side Baffles

The Side Baffles should be thoroughly inspected especially those in the HP Primary Economizer

tube.






9.2.4 Tube Sheets






9.2.5 Lower Shield






73

10. LP Evaporator


tubes.




defects.

In addition to the normal gas-side issues it is critical that NDE methods are utilized to determine

the presence and extent of flow accelerated corrosion (FAC) – see section 10.2.6 .



- Check for deformed tubes.




10.2.1 Tube Elements



- Check for warped or deformed tubes.

- Check for misaligned tube elements.- Check for tube bundle misalignment.






10.2.2 Center Baffle






74

10.2.3 Side Baffles

The Side Baffles should be thoroughly inspected especially those in the IP Superheater.


- Inspect baffle welds for cracks.

- Check for missing or damaged sections.- Inspect wall connection for cracks.



10.2.4 Tube Sheets




- Check for cracks in welds or in tube sheet material.- Check for damaged or missing sections.


10.2.5 Lower Shield



10.2.6 Flow Accelerated Corrosion (FAC)

Flow accelerated corrosion occurs at the pressure and temperature typically found in LP systems.- If the alloy of the riser pipes to the LP drum are confirmed to be P-11 or an alloy with a

minimum chrome equivalency content the risk of FAC damage in that area is small. If unsure

of the alloy, it is recommended that the insulation be stripped off the risers from the LP

evaporator to the drum, alloy test to confirm the installed material and if not chrome alloy thenthe pipe thickness should be mapped downstream at every change in flow direction of riser

pipes and at the upper tube bends to the header (i.e. check each bend). It may be possible to do

an internal inspection of the riser tube with a video probe from inside the LP drums to confirmthe surface appearance and any visual FAC damage. Refer to section 15 for the LP drum

internal inspections.

- Similar to the riser pipe the downcomers and feeder or supply tubes from the downcomers tothe lower headers should be inspected for any indications of FAC damage.

The inspection will be necessary on an annual basis until sufficient trend data is available to predict

wastage rates. Inspection frequencies should be extended for units with chrome alloy components.Some units have partial sections of tubing or piping with chrome alloys and these areas will not

require the same frequency of inspections. A unit with chrome alloys may delay inspections until five

years of base load operations or less if operated in a cyclic mode. Reassemble insulation and consider

removable sections with periodic inspection maintenance in mind.



75

11. FW Heater


tubes.




defects.

In addition to the normal gas-side issues it is critical that NDE methods are utilized to determine

the presence and extent of flow accelerated corrosion (FAC) – section 11.2.6 . This examination

must include the return bends at the top of the economizer and, the outlet and inlet piping.


Inspect the overall condition of the tube elements and fin structure.- Check for cracks.



possible.


11.2.1 Tube Elements






Inspect deposit distribution, damaged fin distribution, if any, for any unusual patterns. This maygive an indication of operating and/or distribution problems in HRSG.

Typically corrosion is heavier in this area because of cooler tubes.


11.2.2 Center Baffle





76


11.2.3 Side Baffles

The Side Baffles should be thoroughly inspected especially those in the FW Heater tubes.

- Inspect baffle for warpage.- Inspect baffle welds for cracks.


- Inspect wall connection for cracks.- Check for excessive gaps that allow gas bypassing.


11.2.4 Tube Sheets







11.2.5 Lower Shield



11.2.6 Flow Accelerated Corrosion (FAC)

The critical area to examine for FAC is the final return bend at the top of the economizer. NDE

thickness measurements should be used to map wastage rates in this zone. This inspection should be

done biannually.

11.2.7 Inlet Header

The inlet header/economizer tube stub region is subject to thermal shock in service. A biannual

inspection of the pipe internal bore at the tube holes is recommended.



77

12. Supports, Guides, Expansion Joints

12.1 CT/HRSG Main Expansion Joint

12.1.1 General

The expansion joint is located at the CT exit and the HRSG inlet duct.

12.1.2 Visual InspectionInspect the overall condition of the expansion joint

- Inspect joint cover plates

- Ensure there is no binding of the plates but they are maintaining protection for the joint.- Check for tears in fabric.

- Check for over extension.

12.2 General Ground level Walk around and under the HRSG exterior and examine every penetration. Check all the

bellows expansion joints, insulated pipe and header drains, tube bundles guides, beam supports,

column supports and grouting.

- Check for loose or broken grouting on columns and pedestals- Check for pips with damaged or missing insulation.

- Check for deformed, cracked or misaligned bellows expansion joints

- Check header and drain guides for alignment.

12.3 General Top level Walk around the top of the HRSG exterior and examine every hanger, support and downcomer penetration. Check all the drum pedestals, line hangers and gratings. At this level, inspections

will be made inside the HP, IP and LP Drums.

- Check for lines and pedestals for out of alignment issues.- Check for pipes with damaged or missing insulation.

- Check for deformed, cracked or misaligned expansion joints

- Check supports for alignment and condition.

NOTE: Example of overstressed hanger supports on a reheat header section. See picture below.



78

Reheat hanger support



79

13. High Pressure Drum (example)

13.1 General

- Check for any deposits or debris upon entry. Any debris found should be placed in asample bottle and sent to lab for identification.

- Normal HP drum coating would be a light layer of black magnetite for optimal

chemistry.- Inspect condition of the manway and manway gasket surface.

- Check for any cracks in external welds and check for any signs of leaking.

- Check for lock welds or jam nuts on internal bolted attachments.



80

13.2 Offline Visual InspectionInspect the overall condition of the assemblies inside. Any debris found should be placed in asample bottle and sent to lab for identification.

13.2.1 Chevron Dryers

- Check the chevron dryers to be in place and all brackets secure.- Check supports for damage or cracks.

13.2.2 Vortex Duct

- Check the Vortex connector duct and separator for cracking and alignment.

13.2.3 Piping and Tubing

- Check general condition of tube penetrations. Check for cracks in welds or any

physical damage

- Check for plugged tubes.

- Check the feed water piping to be intact.

- Check all brackets and bolting to be in place.



81

14. Intermediate Pressure Drum (example)

14.1 General - Check for any deposits or debris upon entry. Any debris found should be placed in a

sample bottle and sent to lab for identification.- Inspect condition of the manway and manway gasket surface.

- Check for any cracks in external welds and check for any signs of leaking.

14.2 Offline Visual InspectionInspect the overall condition of the assemblies inside. Any debris found should be placed in a

sample bottle and sent to lab for identification.


- Check the chevron dryers to be in place and all brackets secure.

14.2.2 Vortex Duct and Separators

- Check the vortex duct and separators for cracking and alignment.



82


- Check general condition of tube penetrations. Check for cracks in welds or any physical damage

- Check for plugged tubes.





83

15. Low Pressure Drum & Integral Deaerator

15.1 General

- Check for any deposits or debris upon entry. Any debris found should be placed in asample bottle and sent to lab for identification.

- Inspect condition of the manway and manway gasket surface.

- Inspect for evidence of FAC damage in the riser baffle plates and the dowmcomer

entrances.- Check for any cracks in external welds and check for any signs of leaking.

15.2 Offline Visual InspectionInspect the overall condition of the assemblies inside.


- Check the chevron dryers to be in place and all brackets secure.

- Check supports for damage or cracks.

15.2.2 Drum Baffles

- Check the baffles for cracking and alignment.- Inspect baffles for FAC damage where the riser tubes penetrate the drum. If damage is

found additional inspect is recommended for FAC damage in the LP and feed water sections.


- Check general condition of tube penetrations. Check for cracks in welds or any

physical damage- Check for plugged tubes.




84


15.3 Integral Deaerator

- Inspect trays for damage, Orientation and in place and not shifted.

- Loosen bolts on upper tray retaining bar and slide bar upward so that the trays can beremoved

- Remove trays from the tray compartment and inspect for deposits or damage.

- To remove and inspect the spring-loaded nozzles, the trays and the access door cover inthe preheater section floor must be removed.

- The spring-loaded nozzles should be inspected to ensure that they are in place and free of

sediment and deposit.- Record all defects on the data sheet provided and report them to the foreman and/or

supervisor or outage manager.



85

16. Stack and Stack Damper

16.1 StackInspect the general condition of the stack. Check for damage, cracks and any unusual condition

where possible.

Recommendation: UT inspection of stack wall thickness should be done every 6 years.

16.2 Stack Damper

Walk the access walkway around the stack at the damper location and examine damper area.Inspect the overall condition of the stack damper, linkage, and actuator.

- Check damper for alignment, broke welds or missing components.- Check for any loose fasteners.

- Check piping connections, solenoid fasteners, limit switches and any other controls for

looseness.

Refer to the manufacturer’s manual for maintenance guidelines.

16.2.1 Damper Flange

- Inspect damper flange for damage or corrosion. Check for any signs of leakage at

flange.

16.2.2 Blades

- Inspect the overall condition of the damper blades.

- Check that the blade shaft bearings are lubricated and appear to be working.

16.2.3 Blade Seals

- Check blade seals for damage, looseness or missing sections. Damaged or loose seals

will prevent proper sealing and possibly prevent damper operation. [Damaged seals

should be recorded for immediate replacement.]

16.2.4 Linkage

- Linkage hinge pins ride in self-lubricating sintered bronze bearings. Check for metal(bronze) filings on and around linkage.

- Check linkage for damage.

16.2.5 Packing Glands

The manufacturer recommends inspecting Packing Glands after three months of operation and

retighten as required. For offline inspection, inspect glands for damage, corrosion or anythingunusual.

16.2.6 Actuator

- Inspect the actuator for damage.- Check the actuator for missing pins, alignment and signs of binding.



86

16.2.7 Limit and Torque Switches

Limit and Torque switches are located on the interior of the actuator. Refer to the manufacturer’sspecific instructions for details.



87

Appendix 10

Steam Turbines

TABLE OF CONTENTS ....................................... ERROR! BOOKMARK NOT DEFINED.

GENERAL STEAM TURBINE INSPECTION GUIDELINES ........................................ 89

SAFETY ....................................................................................................................................... 90

1. HIGH PRESSURE TURBINE .......................................................................................... 90

1.1 GENERAL .......................................................................................................................... 90

1.2 OUTER CASING ................................................................................................................. 90

1.3 I NNER CASING .................................................................................................................. 901.4 BOLTING ........................................................................................................................... 90

1.5 NOZZLE BLOCKS .............................................................................................................. 901.6 DIAPHRAGMS.................................................................................................................... 90

1.7 BUCKET ............................................................................................................................. 90

1.8 SHAFT SEALS .................................................................................................................... 91

1.9 R OTOR SHAFT................................................................................................................... 911.10 BEARINGS..................................................................................................................... 91

1.11 OTHER HIGHPRESSURE TURBINE COMPONENTS........................................................ 91

2. INTERMEDIATE PRESSURE TURBINE .................................................................... 92

3. LOW PRESSURE TURBINE ........................................................................................... 93

4. VALVES ............................................................................................................................... 94

4.1 MAIN STOPVALVES ......................................................................................................... 944.2 CONTROL VALVES............................................................................................................ 94

4.3 I NTERCEPT VALVES.......................................................................................................... 94

4.4 R EHEAT STOPVALVES ..................................................................................................... 944.5 COMBINED I NTERCEPT VALVES....................................................................................... 94

4.6 MISCELLANEOUS DRAIN & VENT VALVES ..................................................................... 94

4.7 OTHER TURBINE VALVES................................................................................................. 94

5. PIPING.................................................................................................................................. 95

5.1 CROSS-OVER PIPING ........................................................................................................ 955.2 LUBE& CONTROL OIL PIPING ......................................................................................... 95

5.3 TURBINE DRAIN PIPING.................................................................................................... 95

5.4 MISCELLANEOUS TURBINE PIPING................................................................................... 95

6. LUBE OIL ............................................................................................................................ 96

6.1 LUBEOIL PUMPS .............................................................................................................. 96

6.2 LUBEOIL COOLERS.......................................................................................................... 96

6.3 LUBEOIL CONDITIONERS................................................................................................. 96

6.4 LUBEOIL SYSTEM VALVES & PIPING.............................................................................. 966.5 LUBEOIL PUMPDRIVE..................................................................................................... 96

7. CONTROLS......................................................................................................................... 97

7.1 HYDRAULIC SYSTEM PUMPS ............................................................................................ 97



88

7.2 HYDRAULIC SYSTEM COOLERS ........................................................................................ 97

7.3 HYDRAULIC SYSTEM FILTERS .......................................................................................... 977.4 HYDRAULIC SYSTEM PIPES & VALVES............................................................................. 97

7.5 TURBINE SUPERVISORY SYSTEM...................................................................................... 97

7.6 TURBINE GOVERNING SYSTEM......................................................................................... 97

7.7 TURBINE TRIPDEVICE...................................................................................................... 977.8 EXHAUST HOOD & SPRAY CONTROLS .............................................................................. 97

7.9 AUTOMATIC TURBINE CONTROL SYSTEMS ..................................................................... 97

7.10 AUTOMATIC TURBINE CONTROL SYSTEM - MECHANICAL......................................... 977.11 AUTOMATIC TURBINE CONTROL SYSTEM – MECHANICAL-HYDRAULIC................... 97

7.12 AUTOMATIC TURBINE CONTROL SYSTEM – ELECTRO-HYDRAULIC-ANALOG........... 97

7.13 AUTOMATIC TURBINE CONTROL SYSTEM – ELECTRO-HYDRAULIC-DIGITAL ........... 977.14 AUTOMATIC TURBINE CONTROL SYSTEM – DIGITAL CONTROL & MONITORING........ 97

8. GENERATOR ..................................................................................................................... 98

8.1 R OTOR WINDINGS ............................................................................................................ 98

8.2 R OTOR COLLECTOR RINGS ............................................................................................... 98

8.3 STATOR WINDINGS, BUSHINGS AND TERMINALS............................................................. 988.4 STATOR CORE IRON........................................................................................................... 98

8.5 BRUSHES & BRUSH R IGGING ........................................................................................... 98

8.6 GENERATOR BEARINGS AND LUBE OIL SYSTEM .............................................................. 988.7 GENERATOR CASING ........................................................................................................ 98

8.8 GENERATOR COOLING SYSTEM ....................................................................................... 98

Hydrogen Coolers ..................................................................................................... 98

Hydrogen storage system .......................................................................................... 98

Hydrogen seals .......................................................................................................... 98

Air Cooling System................................................................................................... 98

Liquid Cooling System ............................................................................................. 98

Seal Oil System & Seals ........................................................................................... 98

8.9 GENERATOR CONTROLS................................................................................................... 98Generator Metering Devices ..................................................................................... 98

Generator synchronization equipment ...................................................................... 98

Generator Current & Potential Transformers ........................................................... 98

Emergency Generator trip devices ............................................................................ 98

8.10 EXCITER ........................................................................................................................ 99

Exciter Drive ............................................................................................................. 99

Exciter commutator & brushes ................................................................................. 99

9. MISCELLANEOUS ............................................................................................................ C



89

General Steam Turbine Inspection Guidelines

This is a general inspection procedure, not all areas or items will pertain to every Steam Turbine.

Prior to Inspection: Check last inspection report.

Inspect unit from front to rear, generator being the rear of the unit.

Before the unit is shut down for inspection it is recommended to use thermography to locate hot

spots on the external casing. Any hot spot 130 F and above should be documented

Record all information and findings on the inspection report.

Report the significant findings from the inspections immediately to the responsible plantcontacts. Safety issues require immediate reporting and correction to remove the hazards.



90

Safety

The following safety equipment and procedures are required prior to performing an inspection.


Gloves, Primary and backup Flashlights, Dust Mask or respirator with HEPA filter for ceramic

fibers

Cell phone or radioConfined space gas monitor for all interior sections


Complete the confined space testing procedure prior to entering the confined space. Restrictaccess until the confined spaces of the unit are below 115

0F

Safety person for hole watch for permit required confined spaces.

Equipment taken out of service (LOTO) and sign on the clearances for that equipment.

All energy sources, steam, feed water or recirculation pumps, fuels and chemical injection

equipment such as the ammonia must be removed from service.

Consider double block & bleed valve isolation for inspections when two or more boilers are tied to a common steam turbine. Then confirm no leak thru of the valves from the auxiliary steam

supply header.

1. High Pressure Turbine

1.1 General

1.2 Outer Casing

1.3 Inner Casing

1.4 Bolting

1.5 Nozzle Blocks

1.6 Diaphragms

1.7 Bucket

- Tenon- Shroud

- Airfoil

- Blade root



91

- Tie Wire

1.8 Shaft Seals

1.9 Rotor Shaft

1.10Bearings

1.11Other High Pressure Turbine Components



92

2. Intermediate Pressure Turbine



93

3. Low Pressure Turbine



94

4. Valves

4.1 Main Stop Valves

4.2 Control Valves

4.3 Intercept Valves

4.4 Reheat Stop Valves

4.5 Combined Intercept Valves

4.6 Miscellaneous Drain & Vent Valves

4.7 Other Turbine Valves



95

5. Piping

5.1 Cross-Over Piping

5.2 Lube & Control Oil Piping

5.3 Turbine Drain Piping

5.4 Miscellaneous Turbine Piping



96

6. Lube Oil

6.1 Lube Oil Pumps

6.2 Lube Oil Coolers

6.3 Lube Oil Conditioners

6.4 Lube Oil System Valves & Piping

6.5 Lube Oil Pump Drive



97

7. Controls

7.1 Hydraulic system Pumps

7.2 Hydraulic system Coolers

7.3 Hydraulic system Filters

7.4 Hydraulic system Pipes & valves

7.5 Turbine Supervisory system

7.6 Turbine Governing system

7.7 Turbine Trip Device

7.8 Exhaust hood & spray controls

7.9 Automatic Turbine Control Systems

7.10Automatic Turbine Control System - Mechanical

7.11Automatic Turbine Control System – Mechanical-Hydraulic

7.12Automatic Turbine Control System – Electro-Hydraulic-analog

7.13Automatic Turbine Control System – Electro-Hydraulic-digital

7.14Automatic Turbine Control System –digital control & monitoring



98

8. Generator

8.1 Rotor Windings

8.2 Rotor Collector rings

8.3 Stator Windings, bushings and terminals

8.4 Stator core iron

8.5 Brushes & Brush Rigging

8.6 Generator Bearings and lube oil system

8.7 Generator Casing

8.8 Generator Cooling System

Hydrogen Coolers

Hydrogen storage system

Hydrogen seals

Air Cooling System

Liquid Cooling System

Seal Oil System & Seals

8.9 Generator Controls

Generator Metering Devices

Generator synchronization equipment

Generator Current & Potential Transformers

Emergency Generator trip devices



99

8.10Exciter

Exciter Drive

Exciter commutator & brushes



ASME, PTC 101 / 102 (Draft) February 2011 Submittal, Rev. 1

9. Miscellaneous



CI

Appendix 11

Boiler and Regenerative Airheater

Inspection Guidelines

Submission and Revision by Stephen K. Storm (Stephen Storm, Inc.)

Requested review / Additions by, Jon S. Cavote (United Dynamics Corporation)

Focus

- General Boiler Condition- Boiler Setting Air Infiltration- Regenerative Airheaters- Airflow Measurement Systems- Total Air and Gas Management

PTC 101

Standard being developed for plant performance related outage inspections. The

standard includes a list of power plant components to inspect during planned outages,what to look for during those inspections, and how to establish repair priorities.

Examples of indications of both problems and proper equipment performance are

provided.

PTC 102Standard being developed for plant performance related operating walk-downs.

The standard includes a list of power plant components to visually inspect via a closewalk-down while the equipment is in service and what to look for during those

inspections. Examples of indications of both problems and proper equipment

operation are provided.



CII

Table of Contents

TABLE OF CONTENTS ERROR! BOOKMARK NOT DEFINED.I

GENERAL INSPECTION AND SAFETY GUIDELINES VIII

1. GENERAL AREA IX

2. INITIAL / PRELIMINARY INSPECTION – BEFORE CLEANING IX

3. GENERAL BOILER, DUCTS, FAN AND AIR IN-LEAKAGE INSPECTIONS - AFTER

CLEANING 7

4. REGENERATIVE (ROTARY) AIRHEATER INSPECTION GUIDELINES

……………………………………………….10

PTC 102

5. STANDARD FOR BOILER OPERATING WALK-DOWN…

…………………………………………………………..12

6. PERFORMANCE TESTING OBJECTIVES………………………………………………………………………..15



CIII

General Inspection Guideline for Boiler Setting Air In-Leakage and Regenerative (Rotary)

Air Heaters

This is a general inspection procedure, not all areas or items will pertain to every boiler type

and/or airheater.

Equipment reliability and performance have parallels. Indications of poor performance areclosely tied to those of reduced reliability. Abnormal wear patterns, poor cleanliness, increased

corrosion, and mechanical failures, no matter how small have effects on both unit reliability and

unit performance. Identifying the root cause is the first step in improving the overall performanceof a piece of equipment and the power generating unit it is a part of. While these inspections

guidelines are written to ultimately enhance the plant’s performance, all observations should be

noted and acted upon.

Prior to the outage

• Review the last inspection report.

• Review recent operating history for the boiler efficiency and regenerative airheater performance

o

Boiler efficiencyo Regenerative Airheater Performance

Leakage

Efficiency X-Ratio

o Draft, Pressure drops, both air and flue gas sides (including all fans, ducts,

windbox, furnace, convection pass, airheater, air pollution control equipmento Past inspection and/or forced outage reports to review trends /issues

o Abnormal operating events

Contact plant operations for additional information on operating history

Safety

The following safety equipment and procedures are required prior to performing an inspection.• Steel Toed Boots, Hard Hat, Safety Glasses or goggles, Coveralls

• Gloves, Primary and backup Flashlights, Dust Mask or respirator with HEPA filter for ceramic fibers

• Life line Harness

• Cell phone or radio

• Confined space gas monitor

• Confined space training must be completed.

• Complete the confined space testing procedure prior to entering the confined space.

Restrict access until the confined spaces of the unit are below 1000F

• Safety person for watch for permit required confined spaces.


All energy sources, steam, soot blowers, fuels and chemical injection equipment such as

ammonia must be removed from service. Consider double block & bleed valve isolation for inspections if any connections exist to operating units.



CIV

If other boiler back-pass maintenance activities (ie. economizer cleaning or replacement) will be

conducted during the outage, this inspection should be scheduled to avoid those times whenwork will be occurring directly overhead. Mechanical parts and tools are heavy and if dropped

may present a serious threat to safety. If the areas upstream (or downstream) of the inspection

area are taking place, the area of inspection should be covered to prevent unanticipated ingress of

tools and personnel. Inspections involve heights, close spaces, hard metal, sharp edges and flyash. Inspectors should be physically fit and able to climb and should not be bothered by feelings

of claustrophobia.

Obtain the following drawings prior to inspection (as feasible) to aide in the inspection and report/documentation:

• Elevation, Boiler, Fans , Airflow ducts, Flue gas ducts , Airheater, General Layout

• It is recommended to use thermography to locate hot or cold spots on the external casingof the air boiler, ducts and/or airheater. Thoroughly evaluate all deteriorated insulation

and casing.

An example side elevation with the primary boiler and/or rotary airheater inspection points is as

follows:



CV

Example of Primary Inspection Locations on a Tangentially Fired PC Unit

Illustration courtesy of Storm Technologies, Inc.



106

Exterior Heat Loss

The unit loses heat through the exterior walls of the furnace and ductwork. If the surfacetemperature is reduced through insulation or lagging, then the amount of heat leaving the unit is

reduced and efficiency increases.

There are three ways that heat can be transferred:Convection: heat transfer from a solid to a fluid (liquid or gas) of different temperatures

Radiation: heat transfer requiring no transfer medium

Conduction: heat transfer through direct contact between two surfaces of different temperatures

Because we are not really worried about heat transfer into the ground or structures in direct

contact with the ductwork or insulation, the two main focuses should be convection and radiation.

As the temperature difference between the surface and the surrounding air increases, heat

transfer increases. Normally, as the air heats up, the heat transfer slows down because the

temperature difference is becoming less and less. Slowly the heated air begins to rise above the

cooler air and the cold air takes the place of the now heated air. However, if the heated air is blown away by the wind or by a draft faster than it would normally rise, then the heat transfer

does not slow. This is called forced convection.Each of these losses can be measured by mapping temperature and wind speeds. However,

considering the losses are typically minimal as compared to other opportunities identified during

an outage, all of the boiler inspection locations should be monitored, measured with an infra-red / thermal imaging camera to determine if there are exterior heat losses which warrant insulation

replacements that may be required during an outage.

Prior to the outage (Continued):

•

Make a plan or checklist on the items and areas of interest that should be inspected.Know which access doors you plan to use to enter and exit during the inspection.

• Make a safety plan and conduct a briefing prior to entering any confined space. Ensureall participants are aware of their responsibilities, including looking out for each other,


• Gather personal safety equipment

• Gather cameras, flashlights, and writing equipment, and ensure sufficient lanyards are

available for all equipment brought into the air heater.

• If necessary, arrange for temporary scaffolding or ladders.


• Record all information as observed; do not rely on mental notes. This is critical to ensure

all findings will be included on the inspection report.

• Obey all instructions from the outside safety watch person.


• Report the significant findings from the inspections immediately to the responsible plantcontacts.



107

• Safety issues require immediate reporting and correction to remove the hazards.

• Ensure all material brought into the boiler and/or airheater as part of the inspection leaveswith you

• Sign out on the appropriate forms

• Document all findings in a report that is retrievable in the future

• Summarize all recommended actions• Plan for a re-inspection if recommended actions require it

1. General Area

1.1 General Boiler, ductwork, airheater and fan inspections should be undertaken as a team effort. It is

recommended that a minimum of at least three individuals participate. Utilizing Inspection teammembers from maintenance, engineering, and operations will broaden the view and improve the

findings. One may rotate as the outside safety watch or all three may enter simultaneously if the

safety-watch function can be performed by another. It is recommended that one person serve as scribe

and another carry the camera or video recording device. The notes / records may be recorded in

writing or via sound recording to be transcribed immediately thereafter. Upon exiting the air heater allnotes, records, and photographs should be duplicated and stored separately to ensure preservation of

this information.This is a multi-part inspection, first prior to any cleaning, then after cleaning, and even later if needed.

Ensure all notes and recordings are accurately labeled to ensure future reference to the correct issues

as identified.

2. Initial Crawl Through Inspection – prior to cleaning

The first inspection should be conducted prior to any cleaning activities as deemed safe for entry.

This initial inspection is for the purpose of identifying accumulation of ash, overall boiler

cleaning / vacuuming needs as well as areas of air in-filtration by viewing air washed areas,mechanical discrepancies with tube alignment and/or any issues that would accelerate localized

erosion, change the furnace performance and dynamics, impact heat transfer, etc.

Photograph, Video or sketch the general condition of the unit. Piles of ash or slag may be

significant, record their size and location. Look for wear patterns from soot blowers and look for

cleaning patterns to identify any area missed. Also, note any signs of debris, foreign material,and corrosion products.

Check to ensure instruments and their connections are not buried, covered, or insulated bymounds of ash or other debris.

3. Second Inspection – post cleaning /scaffolding

A second and thorough inspection should be conducted after initial vacuuming, cleaning of the boiler and/or a water-wash down. This inspection will enable those entering the unit to observe

the actual mechanical condition of the components. Again, look for wear patterns, cleaning patterns, alignment, mechanical issues of any sort. Note any signs of debris, foreign material,

and corrosion products. Material and tools may have been inadvertently dropped from work in

the duct work above the air heater. Identifying the source of the foreign material will assist in preventing its recurrence. A localized concentration of corrosion products are typically the



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indication of a problem. A further investigation is warranted to determine the root cause and

potentially prevent recurrence.

3.0 General Boiler, Ducts & Fan - Air In-Leakage Inspections3.1 General Inspection Areas

A general inspection should conduct a preliminary crawl through inspection that immediately

includes comments regarding the general boiler condition, tube alignment, areas of erosion, plugging, etc. This is considering that the boiler condition and paths for air and gas delivery can

influence a unit’s performance in such a way that combustion dynamics, thermal efficiency and

the overall ratio of the air and gas paths will influence the operational performance and reliabilityof the unit. An outline of a general inspection is listed as follows:

3.1 Lower Furnace

3.1.1 Note tube erosion and/or wastage (if any)

3.1.2 Evaluate the lower slopes for quench cracking from possible bottom ash water

splash

3.1.3 Evaluate and inspect for any possible gouged, crushed, sliced and dented tubes

3.1.4

Seal trough-bottom ash hoppers erosion/corrosion 3.1.5 Note Ash pit condition (refractory / general)

3.1.6 Check the Ash hopper water seal (if applicable) 3.1.7 Clinker grinder/Drag chain (if applicable)

3.1.8 Inspect sidewall and buckstay damage adjacent to and behind the lower slopes as

a result of possible clinker falls

3.2 Mid Furnace

3.2.1 Access Doors3.2.2 Closure / Seal

3.2.3 Refractory (inside furnace) 3.2.4 Wind Box casing

3.2.5 Soot Blower lance penetrations

3.2.6 Seals

3.2.7 Refractory (inside furnace) 3.2.8 Tube Alignment / Wind-box / Furnace Casing Construction

3.3 Lower – Mid-Upper Furnace Inspections / Observations

3.3.1 Tube Alignment / Wind-box / Furnace Casing Construction

3.3.2 Tube Alignment / Wind-box / Furnace Casing Construction

3.3.3 Slag and fouling pattern

3.3.4 Burner zone condition

3.3.5 Furnace (lower slope and division wall - UT/erosion/corrosion)

3.3.6 Radiant section - UT/alignment/erosion/corrosion

3.3.7 Note any or all blister/bulges

3.3.8 Convection passes - UT/alignment/erosion/corrosion

3.3.9 Economizer - UT/alignment/clips/erosion/corrosion

3.4 Dead Air Spaces

3.4.1 Lower Furnace



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3.4.2 Nose arch Apex

3.4.3 Penthouse

3.5 Fans (Forced Draft, Induced Draft, Primary Air, Seal Air, Gas Recirculation, Over-Fire Air

- if boosted, Burner Cooling Fans)

3.5.1 Fan Housing3.5.2 Fan wheel observations – Fly ash erosion – tip cracks, loose bolts or rivets, rubs

3.5.3 Inlet vanes - stroke, fly ash wear, linkage, bushings

3.5.4 Inlet louvers – outlet dampers – check stroke, fly ash erosion, linkage pins/bolts3.5.5 Casing wear

3.5.6 Blade condition

3.5.7 Shaft seals3.5.8 Inlet / Outlet Ducts / Joints

3.5.9 Inlet Box Screens (if applicable)

3.5.10 FD Fan Discharge Duct / Steam Coils (if installed ) Cleanliness and Condition

3.6

Wind Box / Secondary Air3.6.1 Synchronize secondary air dampers and verify operation from inside and outside

damper drive limits and travel3.6.2 burner tilts

3.6.3 linkages

3.6.4 Draft Gauges

3.7 Over-fire Air

3.7.1 General condition3.7.2 Dampers and registers

3.7.3 tilt and yaw (tangentially fired units)

3.8 Instrumentation

3.8.1 Airflow measurement elements

3.8.2 pressure/taps/sensing lines/connections3.8.3 Leak Checks

3.8.4 temperature/wells

3.9 Ductwork (Air Ducts, Gas Ducts, Economizer Hoppers)

3.9.1 Flyash Erosion

3.9.2 Expansion Joints3.9.3 Casing cracks – joint integrity – corrosion

3.9.4 Ductwork supports

3.9.5 Flyash weight accumulation damage

3.10 Expansion Joints

3.11 Burners (Signs of erosion / physical damage / malformation)

3.11.1 Mechanical Tolerances

3.11.2 Condition / Centering (Wall-Fired )



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3.11.3 Tilt/Yaw Adjustment (Tangential Fired )

3.11.4 Igniters3.11.5 Air Registers

3.11.6 Nozzle Condition

3.11.7 Separated Air Zones

3.11.8 Burner refractory3.11.9 Condition

3.11.10 Angle

3.12 Burners should be refurbished to design / optimum conditions

3.12.1 Fuel Pipe Orifices

3.12.2 Burner throat refractory3.12.3 Coal pipe nozzle

3.12.4 Diffuser vanes, position

3.12.5 Oil gun position relative to diffuser

3.12.6 Gas ring/spuds

3.12.7 Burner register vanes / actuating linkage /actuators

3.13 Soot Blowers / Performance

3.13.1 Ensure all blowers are in working order

3.13.2 Install tube shields and repair thermal drains (as required )

3.13.3 Note lance corrosion (if any)

3.13.4 Note General operation / stroke / alignment

3.13.5 Soot Blower performance is also essential to ensure the gas lanes are clear, flue

gas dynamics are equalized and localized erosion is minimal; Evaluation of performance should be noted by visual observation prior to boiler cleaning

Note ash bridging at the SH (if any) Note cinder carry-over into the convection pass (if any)

3.14 Penthouse

3.14.1 Hangar rod corrosion / condition3.14.2 Roof seal condition

3.14.3 Weather proofing – lagging condition – joint integrity

3.14.4 Penthouse Floor 3.14.5 Seal Boxes / Crown Seals

3.14.6 Tube penetrations

3.14.7 Determine air washed areas / intensity of leakage as viewed from the boiler side3.14.8 Refractory Condition

3.14.9 Isomembrane Condition (if installed )

3.15 Access Doors

3.15.1 General Condition / Closure

3.15.2 Gaskets / Sealing

3.16 Convection Pass

3.16.1 Erosion Baffles



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3.16.2 Gas Lanes

3.16.3 Casing and header penetrations3.16.4 Improved RH and SH damper control

3.17 Access Doors / Hatches (all)

3.17.1 Closure / Hinge / Seals

3.18 Environmental Control Equipment (Typical)

3.18.1 SCR 3.18.2 Hoppers / Mechanical Collectors / Turning Vanes / Delta Wings

3.18.3 ESP

3.18.3.1 Gas seals around rapper and vibrator rods3.18.3.2 Dust accumulations in ducts and on plates and wires

3.18.3.3 Plates – alignment, structural attachments, bowing

3.18.3.4 Penthouse heaters and blowers (if applicable)

3.18.3.5 Rappers, Vibrators, Electrical connections

3.18.4 Bag house3.18.5 FGD / Scrubber (wet/dry)



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4.0 Regenerative (Rotary) Airheater Inspection4.0 Housing

4.1 Thickness4.2 Erosion, Corrosion Damage

4.3Deformation, Warping

4.4 Weld Cracking

4.5 Expansion Arrangement

4.1 Basket Frame Inspection

4.1.1 Basket Condition / Bypass

4.1.2 Basket Support / Attachment

4.2 Rotor Inspection

4.2.1 Rotor Post to Diaphragm Joint

4.2.2 Diaphragm, Grating, Shell Plate (Thickness, Warping, Cracking)

4.2.3 Pin Rack ( Attachment to Shell, Pin/Pinion Wear )4.2.4 Pinion Gear Contact with Rails

4.3 Heating Element Inspection

4.3.1 Layer Design (ie. 2 layer or 3 layer)

4.3.2 Profile Description /General Condition4.3.3 Surface Condition

4.3.4 Plugging / Cleanliness

4.3.5 Tightness4.3.6 Cracking / Break-up

4.3.7 Soot blower damage (if any)

4.4 Rotor Sealing Arrangement

4.4.1 Radial & Circumferential / Bypass / Axial Seals / Post

4.4.2 Bent, Deformed, Thinning4.4.3 Clearances

4.4.4 Contact with Sealing Surfaces

4.4.5 Fasteners

4.5 Sealing Surfaces

4.5.1 Maintaining a tight seal on the air heater is essential for optimization of thecombustion air fan capacity (FD/PA) in regards to the combustion process and

also such that the ID fans do not exceed capacity, limit load and/or consume

unnecessary power consumption. During inspection, the rotation and corners of each sector plate should be numbered to reference the location for all areas of

contact (Hot & Cold ends – Radial, Bypass and Axial)

4.5.2 Surface Wear, Thickness, Holes

4.5.3 Cracking, Warping4.5.4 Alignment, Adjuster Condition



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4.6 T-Bars

4.6.1 Surface Wear, Thickness4.6.2 Cracking, Warping

4.6.3 Fasteners

4.7 Rotor Drive System / Mechanisms4.7.1 Oil level, Leakage

4.7.2 Pinion Gear Wear

4.8 Rotor Bearings

4.8.1 Oil Level, Leakage, Contaminations

4.8.2 Oil Circulation System, Filters

4.8.3 Evidence of Wear, Clearances

4.9 Cleaning / Washing Equipment

4.9.1 Condition

4.10 Instrumentation4.10.1 Static pressure Taps / Sensing Lines

4.10.2 Differential 4-20mA transmitters4.10.3 Excess Oxygen Probes / Online Analyzers

4.10.4 Thermocouples

4.10.5 Air Inlet4.10.6 Air Outlet

4.10.7 Gas Inlet

4.10.8 Gas Outlet (Cold end thermocouple condition / representation)

4.11 Auxiliary Equipment (as installed) 4.11.1 Rotor Stoppage Alarm

4.11.2 Leakage Control System

4.11.3 Infrared Detection System

4.12 Expansion Joint, Ductwork, Support bracing

4.12.1 General Condition

4.12.2 Check for erosion and/or leakage

4.13 Dampers

4.13.1 Isolation4.13.2 Bypass



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5.0 PTC 102, Standard for Operating Boiler Walk-Down and ReviewWhile operational, review pre-outage and post outage operations, abnormal events and operating

history. Post outage performance testing and tuning should be considered as a pre and post

outage performance evaluation.

Variables such as poor air and fuel flow management, distribution, and coarse particle fly ash

with influence sub-stoichiometric zones in the lower furnace, localized reducing areas, carbon

carry-over into the upper furnace and often result in a host of reliability issues. Just for clarification, a typical series of events that occur under non-optimum conditions related to air in-

leakage and/or inadequate air and gas flow management are as follows:

Secondary combustion results in the upper furnace.

Furnace exit gas temperatures become elevated.

Flue gas density is reduced and increased flue gas velocities occur. Plugging within the pendants induces accelerated velocities and increased flue

gas volume in localized zones. Increased entrainment of coarse particle ash occurs. Accelerated erosion rates are introduced. Unit reliability issues occur due to tube leaks.

Considering the previous, the synergy between the boiler inspectors, plant operations, performance, results, engineering and management teams is crucial to evaluate a system

holistically. Some of the information that should be shared is as follows:

• Fuel Quality Evaluation

• Fuel Loading Curves

•

Fuel and Air Delivery Systems / Rates of Flowo Actual Indicated vs. Theoretical vs. Measured Valueso Temperature compensationo Pressure transmitter accuracy

• Post outage performance tests to be considered should include:o Air In-Leakage Survey

Furnace exit HVT Traverse to measure actual furnace exit oxygen levels

via a representative grid

Boiler Exit flue gas oxygen (upstream of the airheater) Upstream and Downstream of Air Pollution Control Equipment

Stack measurement

o

Regenerative Airheater Performance Leakage

Efficiency

X-Ratioo Boiler Efficiencyo Operational Performance

Fan Amps (FD, ID) Draft (Air / Gas)



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Stack Flow

Damper Setttings

• Fans

• Windbox, Burners

• Air & Gas Balancing Dampers

Furnace• Flame propogation

• Secondary Combustion (if present)

• Slagging propensity

• Temperature at the furnace exit Convection Pass

• Pressure variations

• Temperatures

• Oxygen and CO levels

While operational, it’s also very important to understand the fuels being fired and the expected

impacts on a unit’s performance and reliability. Standards of understanding for normal plant performance and expected plant performance should be understood. These results when

collected can serve as a “baseline” for actual plant performance or pre/post outage evaluation

results. Fuel selection should dictate operating parameters and the operational changes to thecombustion airflow set-points and/or other related variables such as airflow, fuel HHV, fuel

moisture and the ash will have on the overall flue gas volume leaving the unit.

In regards to the Airheater, a heat balance around the APH can be used to evaluate the

effectiveness of the heat transfer, element performance and/or the thermal efficiency impacts of

the APH. The airheater is often referred to as the “last heat trap” on a utility boiler system. Gasside efficiency should be corrected for “no leakage” and evaluated based on the expected

efficiency at a given (or tested ) X-ratio. For example, a lower than design X-Ratio can lead to ahigher APH gas outlet temperature and can be used as an indication for determining if there is boiler air in-leakage upstream of the APH and/or high primary/tempering airflow (cold air

bypassing the APH) on a coal fired unit. In conjunction with the X-ratio checks, total combustion

airflow measurement and actual furnace exit gas oxygen measurements can be used to validate

the ratios of air and gas flow.

Considering the previous, there are a number of online plant operational checks that can

be considered and trended through a data archive for evaluating overall plant performance and condition. Some of these are as follows:

5.1 Operational Checks 5.1.1 Airflow on curve5.1.2 Primary air fan/exhauster – observe the flow, pressure, hot and cold temperature

and damper positions, primary air flow control damper position, coal air

temperature and motor amps are within expected operating ranges.5.1.3 Secondary air fan – observe that flow, pressure, temperature, damper position (if

applicable) and motor amps are within the expected operating ranges.



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5.1.4 Windbox to furnace differential pressure (damper positions) should be observed

and compared with expected for normal operation.5.1.5 Tertiary-fired and/or wall fired boilers: note the register positions, and over-fire

air (OFA) flow rates, for comparison with expected.

5.1.5.1 Instrumentation - Note the operation of the Primary air and

Secondary air flow measuring devices (damper positions).Readings should be compared to expected along with

cleanliness and general maintenance of the instrumentation

5.1.6 Coal Feeder feed rates

5.1.6.1 Flow (Volumetric or Gravimetric Evaluations) 5.1.6.2 Bias

5.1.7 Damper strokes5.1.8 Temperature / Thermo-wells (all)

5.1.9 Wind box to furnace pressure drop

5.1.10 Draft Gauges (all) – Air & Gas

5.1.11 Operating Air-Fuel ratios on Curve

5.1.12 Balanced combustion airflow5.1.13 Air heater temperatures (air side & gas side)

5.1.14 Burner/Over-fire Air 5.1.14.1 air register, air sleeve settings; feedback vs. local indications

5.1.15 Excess oxygen on curve (Although excess oxygen is an indication of excess air,

the indication is only good if its representative of the true oxygen levels in thefurnace. Because of this, a sufficient quantity of probes is required. Furthermore,

tramp air in-leakage upstream of the excess Oxygen probes can have a major

impact on combustion and overall thermal efficiency. Considering this, it iscritical that the plant O2 probes at the boiler exit are calibrated and representative

of the average)5.1.16 Gas side

• Flue gas constituents, as reported on the emissions monitoring system, should be within expected operating ranges:

Economizer gas outlet – Oxygen, CO, gas temperatures, NOX

Upper furnace – O2 and temperature if available.

• Seal trough level and temperature

• Gas tempering or Gas Recirculation (GR) fans – expected temperingachieved; drives and dampers, motor amps at expected operating levels.

• Induced Draft (ID) fans (and booster fans) – flow, pressure and temperature;drives and dampers, motor amps.

5.1.17 Coal crushers

5.1.17.1 Sizing5.1.18 Pulverizer Operation

5.1.18.1 Mill outlet temperature

5.1.18.1.1 Set-point vs. Actual

5.1.18.2 Level control and bias (Ball Mills)5.1.18.3 Classifier Performance

5.1.18.3.1 Positions (Static)

5.1.18.3.2 Speed (Dynamic)



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5.1.18.4 Coal Pipe temperatures

5.1.18.4.1 Indicated 5.1.18.4.2 Local Infra-Red

5.1.19 Pulverizer Performance to drive maintenance activities / priorities.

5.1.19.1 Fineness

5.1.19.2 Dirty Airflow Distribution5.1.19.3 Fuel Flow Distribution

5.1.19.4 Air-Fuel Ratios

5.1.19.5 Mill Outlet Temperatures5.1.19.6 Heat Balance

5.1.19.7 Pulverizer coal reject quantity (on Vertical Spindle Mills)

5.1.20 Economizer Hoppers (temperature)5.1.21 Visual appearance of flames

5.1.21.1 Burner Zone / Burner Condition

5.1.22 In furnace camera, or visual through observation ports

5.1.23 Nose arch and superheater area for slag appearance / patterns

5.1.24 Lower furnace for possible slag bridging5.1.25 Verify all flame scanners are well-positioned, and check the following:

5.1.25.1 Furnace (lower slope and division wall)5.1.25.2 Radiant section

5.1.25.3 Convection passes (as feasible)

5.1.26 Lower furnace for clarity, oxidizing atmosphere5.1.27 Air heater inlet gas duct hoppers, hot, not plugged

5.1.28 Soot blower pressures and effectiveness

5.1.29 Steam temperatures optimum5.1.29.1 Superheater and/or Reheater tube circuit temperatures

5.1.29.2 Superheater and/or Reheater steam temperatures5.1.29.3 Header temperatures

5.1.30 Spray flows normal

5.1.31 Soot blower steam/air temperatures, condensate/thermal drains

5.1.31.1 Operation and/or bypass5.1.32 Raw coal sizing (yard crusher output less than ¾ inch)

5.1.33 Leak checks of airflow measuring elements (primary and secondary)

5.1.33.1 All pressure taps / sensing line connections

5.1.34 Fly ash sampling (by an in-situ sampler)5.1.35 Airflow and Fuel Flow Distribution and Balance (all)

5.1.36 Oxygen analyzer calibrations and local representation measurements5.1.37 Damper stroke verifications

5.1.38 Steam temperatures and spray flow measurements

5.1.39 Furnace exit excess oxygen measurement (traverse not single point)5.1.40 Air heater leakage

5.1.41 Soot blowing steam temperatures and thermal drains

5.1.42 Superheater and reheater tube metal temperatures

5.1.43 ID Fan Performance5.1.43.1 Inlet/Outlet Pressure

5.1.43.2 Flow



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5.1.43.3 Fan Curve Evaluation

5.1.44 Normal plant results tests5.1.45 Hot “K” calibrations of airflow measuring elements (primary and secondary)

5.1.46 Furnace excess oxygen traverse by HVT probe to check oxygen and stratifications

5.1.47 Measure oxygen rise from furnace to stack

5.1.48 Drum vents should be verified closed and not leaking5.1.49 Bypass and letdown lines should be verified isolated using both local and control

system indication for downstream temperatures and flows (as available)

5.1.50 Sky vents should be verified closed and not leaking.5.1.51 Water side

• Boiler water wall and riser temperatures

• Economizer – inlet and outlet temperatures

• Boiler drum pressure

• Drum levels local, side to side, control room indication

control method / feedback signals used

• Drum metal temperatures



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6.0 Performance Testing Objectives (Recommended)

The primary objective of any performance testing and tuning project should be to reduce fuel

consumption, improving plant safety and working towards operating a plant in a reliable and

environmentally conscious manner.

In an effort to optimize plant performance, comprehensive boiler performance testing of at least

(7) seven areas should be completed in an effort to determine performance improvements inregards to heat rate, efficiency & overall combustion performance.

A summary of the varying tests to be considered on a PC fired unit (for example) are as follows:

Item Description Outage Provisions (as required)

1.0Pulverizer & Fuel Line

Performance

Test Ports1.1 Clean Airflow Balance1.2 Dirty Airflow Balance

1.3 Fuel Flow Balance

1.4 Air-Fuel Ratios

1.5 Pulverized Coal Fineness

2.0Primary Airflow

Calibration

Test ports, accessibility to the test ports needs to be evaluated. Local manometer hook-ups at

each Primary Air Transmitter

3.0Secondary Airflow

Distribution & ControlAccessibility & New Test Ports

4.0Excess O2 Probe

Measurement Accuracy

Multi-point test probes should be installed or refurbished at the economizer outlet

5.0

Furnace Exit Gas

Temperature & Flue Gas

Measurement

Water & Air Supply Hoses & Fittings will need should be prepared; Safe Test Platforms; Test

Ports (test ports - bent tube openings with

observation / test door assemblies installed asnecessary)

6.0

Boiler Exit to Stack Flue

Gas Measurements; Air

Heater Performance; Boiler

Efficiency & Total SystemAir In-leakage Measurement

Accessibility & Testing Port installationsThroughout the Boiler System. (Multi-Point

Probe Installations at the Economizer Outlet /

Air Heater Inlet, and the Air Heater OutletLocations) – All should be based on ASTMstandards for representative sampling methods.

7.0

Insitu Flyash Sampling &

Analyses for Sizing &

unburned carbon

Accessibility & testing ports for representative

sampling



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APPENDIX 12

BOILER- STEAM AND WATER SIDE OUTAGE INSPECTION

GUIDELINES

Contents

SAFETY 120

GENERAL GUIDELINES 121

INPSECTION GUIDLINES 123

STEAM DRUM........................................................................................................................................ 123

Drum Inspection.................................................................................................................. 123Steam Separation Equpiment .............................................................................................. 125

Blowdown Line ................................................................................................................... 125

Feedwater Line .................................................................................................................... 125

Chemical Injection .............................................................................................................. 125TUBES.................................................................................................................................................... 125

Risers (Generating) and Downcomers ................................................................................ 126

Water wall Headers ............................................................................................................. 127MUD DRUM(IF APPLICABLE) ................................................................................................................ 127

Safety

Safety should be paramount in any undertaking performed.

• Identify all hazards that may be encountered during the inspection

o Steam Lineso Blowdown Lines

o Feedwater Lines

o Chemical Addition Lines

o Oxygen content in the drums should be monitored continuously

• Lock-out/Tag-out

o Ensure all energy sources are isolated.

o For systems with multiple drums to a common header, there should be two

isolation valves between any live steam and the boiler to be inspected. Ideally a

bleed valve between the two isolation valves.

Important to note that steam is not the only concern.

An example is ammonia leaking from one operating drum to another drum

to be inspected in a 2 x 1 HRSG configuration.

o Same is true for blowdown lines that feed a common header.

o Double block and bleed to ensure live steam and water cannot be introduced into

the boiler during inspection.

• PPE



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o Hardhat

o Safety Glasses or Goggles

o Gloves

o Flashlight

o Fall Protection if mandated

o Common sense

General Guidelines

• Understand the boiler operation and construction, as they will influence the inspection

process. Some examples include:

o Know the materials of construction

o Is the boiler laid-up properly during down times?

Break vacuum?

Air-in-leakage during lay-up?

o

Copper Feedwater Heaters? Check for copper deposition throughout the drum and generating sections.

• Plant operations can greatly affect the cooling tower integrity. For instance, if the plant

yearly capacity is 30%, then we can assume the boiler is sitting idle for extended periods

of time.

o Therefore, it is important to understand the consequences of this type of

operation.

• P+ID’s/drawings will improve the quality of the inspection by:

o Improving the ability to communicate inspection findings, as well as any

corrective actions that need to take place.

o Helping to determine the root cause of any failures identified during theinspection.

For instance, if iron deposits are found in the drum, understanding the

entire system may help determine where the origin of the iron fouling, as

well as how to prevent the reoccurrence.

o If P+ID’s are not available, hand sketches will do.

• Pretreatment reliability:

o Understanding the chemistry of the makeup source can also help guide the

inspection.

For example, if the pretreatment is unreliable, scaling and deposition may

be seen throughout the system.

o Understanding if the makeup source varies will also help to understand any

failures identified during the inspection.

• Review of operating chemistry:

o The most critical aspect of an inspection when determining root cause.

o Upsets in boiler chemistry can lead to many problems seen during the inspection.



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o A good understanding of the operating chemistry, and all upsets experienced, can

improve the ability to identify root causes during the inspection.

o Knowing the type of program used for internal treatment is also critical.

Those boilers on an AVT or Phosphate program should have a gray

coloration in the drums and tubes, indicating a good formation of the

passivating magnetite layer.

Because an OT treatment forms a hydrated Hematite layer, there will be

more of a red coloration.

It is also important to be able to distinguish between true corrosion and

flash corrosion.

• Flash corrosion typically occurs when a boiler is open to

atmosphere, as with during an inspection, and there is a formation

of a very thin, dusty red layer of hematite.

• This is normal.

• However, you should be able to brush this layer off to expose thesmooth, passivated layer described above.

• Photos are critical for any inspection:

o It is one thing to describe what was seen, it is another to show what was seen.

o Photos help when sharing ideas with, as well as asking for assistance from, others.

o Photos also help to determine year over year conditions, and allow for

determination of improvement or worsening of any existing conditions

• Analyses are critical in understanding what may be causing a particular issue. They can

help indentify root causes, as opposed to chasing down symptoms. Examples of pertinent

analyses are:

o Water analyses-

Particularly makeup source

Pretreatment water if still some available

o Deposit analyses-

Any scaling seen

Any fouling found

o Tube analyses-

Deposit Weight Density (DWD) to help determine if the boiler should be

cleaned, as well as to monitor change over time.

•

Sample should be taken from the section of the boiler experiencingthe highest heat fluxes.

• Also look at the tubes with low flow and slightly reduced heat flux,

such as lower water wall tubes in field erected boilers

• This will depend on the type and configuration of boiler.

Metallurgical analyses for any failed tubes.

• Inspection Tools:



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o Boroscope

o Inspection Mirror

o Flashlight

o Camera (video or still)

o Plastic scraper for deposit collection

o Lab for analyses (metallurgical, deposit, and water)

Inpsection Guidlines

Steam Drum

Drum Inspection

• Waterline

o Steady or erratic?

o Level?

How is operations maintaining level?

Centerline is not always operating level. Understand what is design operating level and compare to actual.

o Should run the length of the drum at the same height.

Any deviations can be due to turbulent drum level.

Deviations can also occur due to an improperly functioning feedwater line.

• FW lines are designed with a certain amount of ports, which are a

designed diameter.

• Obstruction of ports can lead to uneven distribution.

• Uneven distribution can lead to excessive drum mechanical

carryover.o Sight gauges:

Where are they located?

Is it a local reading only, or is it sent to a DCS?

How far is it from the actual drum?

• There have been instances where the sight glass was 3-4ft away

from the drum to make it easier to see from the ground.

• If the piping is not insulated, the water in the glass cools, which

changes the density of the water.

• This in turn causes the level to change based on temperature, not

actual drum level.

• This can cause the operators to elevate the drum level based on

false glass readings, which in turn leads to carryover into the steam

piping.

• Corrosion

o Oxygen:

This is typically seen at the water/air interface, the water line.



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Historical information in regards to oxygen scavenger control or lay-up

processes is important to know.

Typically seen as tubercles.

o Organic:

Not extremely common, but does occur.

Organics in feedwater tend to form organic acids, depending on pressure

and temperature.

• For example, in a multi-pressure HRSG, organics may breakdown

and go with the HP steam.

• However, the organics tend to accumulate in the IP Drum.

• This accumulation leads to elevated organics in the drum water, as

well as the moisture contained in the steam section of the drum.

• Therefore, the moisture in the steam is very acidic, which in turn

causes corrosion to occur in the drum in all metallurgy above the

water line.o If corrosion is seen, take pictures and make note of where the corrosion was seen.

This will help identify the type of corrosion, as well as how to minimize

future corrosion issues.

o Again, as noted in the General Guidelines section, there may be some flash

corrosion seen due to the opening of the boiler to atmosphere. Make sure you

distinguish between it and true corrosion.

True corrosion will not be easily wiped away.

True corrosion will be very rough, with a brittle exterior.

• Deposition

o Where is the deposition taking place?

o Again, hardness, sodium, etc., deposition tends to accumulate at the water line.

o Iron and copper fouling can appear as a sludge build up in the bottom of the drum.

o As previously stated, a thorough understanding of the operating chemistry and

control is crucial in identifying root cause.

Have there been issues with the pretreatment systems?

Has the plant experienced condenser leaks? If so, how long did the plant

operate with the leaks?

• Belly-Plates:

o Some are welded, some are bolted down.o Check for cracks or loose bolts.

• Penetrations:

o Check all penetrations inside and outside of the drum for cracks, deposition, or

corrosion.



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Steam Separation Equpiment

• Types

o Cyclone separators (primary)

o Chevron separators (secondary)

• Condition

o Cracks?

o Missing mist eliminator pads?

o Obstructed mist eliminator pads?

o Corrosion of the Cyclone separators? (Particularly from FAC in multi-pressure

HRSG’s)

o Deposition within the equipment, which can be an indication of

carryover/foaming?

Blowdown Line

• Check for plugged holes.

•

Compare with waterline to make sure the blowdown line is near the surface of the water.• Check for corrosion, deposition, or cracking throughout the blowdown line.

• Check hold down clamps

Feedwater Line

• Check for plugged holes.

• Check for corrosion or cracks along the line.

• Check all supports to ensure they are intact and supporting the FW line as designed.

• Check FW line penetrations inside and outside of the drum.

Chemical Injection

• Location of injection provides adequate mixing and distribution?

• Check penetrations inside and out of the drum.

• Check for obstruction of injection ports.

o This is particularly true for phosphate injection.

o If the phosphate is not diluted enough, it can precipitate upon injection, which

causes obstruction of the ports.

• Ensure there is no corrosion or deposition seen around the injection points, which could

be an indication of excessive feed/ poor mixing in that particular location.

Tubes

• As with the visual testing outlined in the following sections, the following practices are

recommended:o Deposit Weight Density testing (DWD’s):

Used to identify deposition within tubing.

Measured in grams/square foot.

Once a certain level is reached, for instance 20g/sqft, boiler cleaning

should take place.

Use to trend changes year over year and identify operational issues.



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Testing should be performed on tubing located in the highest heat flux

areas:

• Different for different configurations.

• Conventional- typically just above the burners.

• HRSG- HP circuit near the top of the HRSG.

o Ultra-sonic testing:

Non-destructive wall testing.

Identify metallurgical deformations.

Trend wall thickness to determine if wall thinning is taking place.

Very useful in identifying wall loss to FAC in plants prone to this type of

corrosion.

o Boroscope:

Particularly useful in inspecting tubes more thoroughly.

Much more valuable than inspecting a tube with a flashlight just at the

opening. Can help determine if scaling and corrosion is occurring uniformly

throughout the tube.

Due to the magnification of the boroscope, know what the relative size is

of any formation identified through the boroscope

Risers (Generating) and Downcomers

• Scaling:

o New or old?

New will be smooth and typically uniform over the tube.

Old will appear patchy and have definite edges. This scale is commonly

called Chip Scale because it is easily “flaked” off, and the pieces are chips

of scaling.

Chip Scale can typically be found lying in the bottom of tubes or the mud

drum.

• Corrosion:

o Try to determine the type.

Oxygen?

Acid-Phosphate attack?

Caustic gouging?

o Is it uniform or localized?

• When scaling or corrosion is identified, it is important to note whether it is localized or

uniform.

o Localized indicates there is a possible circulation issue.

o Uniform tends to indicate a chemistry issue.



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• When inspecting tubes that are other than vertical, pay close attention to the possibility of

steam blanketing.

o This is typically considered during engineering, but may still occur.

o It will typically appear as a water line, thus indicating the stratification of steam

and water.

o This can cause overheating of the tubes.

Water wall Headers

• Supply water to the Water Wall tubes of the radiant section of the boiler.

• Large portion of the steam generated occurs here.

• Very high flux rate, and are prone to chemistry problems.

• Obstruction, whether scale or corrosion by-product, can cause circulation issues and

overheating of the tubes.

• Important that the plant allow inspection via Man Holes.

• Boroscope is highly recommended.

• As with inspecting the Risers and Downcomers, look for scaling and corrosion, as well asany other types of damage or obstruction.

o Make note of the type of scaling or corrosion identified.

o Is it localized or uniform across the sections?

o Any signs of overheating?

Mud Drum (if applicable)

• Blowdown ports

o Typically covered with angle iron to evenly distribute the blowdown.

o What is the condition of the angle iron?

• Scaling and corrosion?

o Where is it?

o Is it chip scale or is it a uniform scaling?

• Inspect the tubes for deposition, scaling, and corrosion, especially the tubes that are more

horizontal

• Important to be able to distinguish between the risers and downcomers.



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Appendix 14

TBD

Heater Tube Inspection

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