UDC 502 957 7525

Boiler Condition Assessments why and how?

Defining a Strategy for Boiler Condition Assessment

"The underlying driver for performing component condition assessment is the need to

manage component life to achieve plant operating safety, reliability and economic

objectives".

Condition assessment is the primary requirement for managing the useful life of plant

boiler components, and it relies on the following research:

How long has the unit been in operation and under what conditions such as;

Thermal cycling, Fuel types, Atmospheric changes, and operational changes.

The degree of damage current in the component

The rate of damage accumulation

The degree of damage causing failure

How many years of service are required

Are there upgrades or replacements in the future

Will the unit operational conditions remain the same as found in step one

To carry out a boiler condition assessment program successfully, Plant Personnel must

have several key elements in place. These elements have been well-established by a

successful BTF reduction program and are summarized as follows:

Support of Management

Cross-functional teaming (including maintenance, operations, and engineering

personnel) in performing the program (Boiler Inspection Team)

Attention to long-term solutions to root cause problems Training

Documentation of results and periodic review

A Final Boiler Condition Assessment Document should include:

Date the assessment was performed

Summary of assessment activities, such as inspections, material tests, and

results

Estimate of Component Remaining Life and summary of basis

Damage mitigation/prevention actions, if appropriate

Follow-up inspections or monitoring actions and their timing, if

appropriate

Recommendations for next assessment, including operating changes/upsets that

would prompt a re-assessment

Determination of assessment priorities

The scope depends on factors such as the boiler design type, design temperatures

and pressures, materials, fuels, age, unit history and future plans for the boiler or

plant. We suggest a multi-level approach in the planning of the survey scope which

is similar to the approach developed by the Electric Power Research Institute (EPRI)

for utility boilers. Basic to all levels of the fitness survey is a comprehensive

inspection by an experienced field Service Engineer.

A first level survey depends on minimal if any testing or nondestructive examination

(NDE).

Level I

Evaluate past operating and maintenance history.

Provide means for monitoring conditions in the component area such as;

Thermal probes, or flue gas analysis.

Identify any critical components on basis of history, experience with similar

boilers, and objectives for future of unit.

Perform complete visual inspections of all accessible areas of the boiler and/

or auxiliaries - photo-document problem areas as needed.

Identify the root cause of damage found to the limits of level I survey.

Develop a final boiler fitness report with recommendations.

Level II includes NDE testing with little material sampling although tube samples

may be included.

Level II (in addition to items in Level I)

• Establish the outage inspection and testing plan based on information gathered

during initial research and data collection of the unit.

• Define support requirements for the inspections including any materials that

may be needed.

• Assess operation - may include hot walk down of boiler and piping, and data

gathering to evaluate performance of auxiliary equipment.

• Implement inspection and testing plan which may include tube samples for

basic condition assessment analysis.

• Perform preliminary life estimates and provide recommendations for immediate

action as needed.

• Prepare for follow up operational testing as required/ planned.

• Estimate remaining life - analyze data and inspection results.

• Implement operational testing if required.

Level III surveys incorporate material testing, engineering studies and more

extensive analysis in support of the assessment. Proceeding from a level I effort to a

level III survey is dictated by the objectives of the project, i.e., the scope of data

needed to predict future operation to the extent needed by the owner. Typical multi-

level activities are as follows.

Level III (in addition to Levels I and II)

• Perform engineering analysis such as piping stress analysis, finite element

analysis, and boiler performance/upgrade analysis.

Remove materials for laboratory analysis, i.e. boat samples, tube materials for

accelerated creep rupture tests, fatigue tests, etc.

Perform specialized site testing such as strain measurements, support load

testing, etc.

After the conclusion of the condition assessment program, the plant owner

utilizes the results in the planning for the plant - whether long range or short

range. The information may simply aid in the planning of re-inspection and

regular preventive maintenance to ensure reliable steam production. The assess-

ment may be used to define the scope of a major upgrade or plant overhaul by

determining what components need replacement.

Scope of work of Critical Systems and Components

Described below are the types of problems found in the various components as well

as the recommended NDE methods. In general, visual examination, the most basic of

NDE, is done for all components. It is recommended to photo-document the

inspection to provide a permanent record in the report. Internal inspections are

frequently done by video probe and recorded on tape.

1.) Drums: The steam drum is the single most expensive component in the boiler.

Consequently, any assessment program must address the steam drum as well as

any other drums in the convection passes of the boiler. In general, problems in

the drums are associated with corrosion. Problems in the drums normally lead to

indications that are seen on the surfaces - either ID or OD.

Assessment: Inspection and testing focuses on detecting surface indications.

The suggested NDE method is Wet florescence magnetic particle method.

Because WFMT uses fluorescent particles which are examined under

ultraviolet light it is more sensitive than dry powder type MT and it is faster

than PT methods. WFMT should include the major welds, selected attachment

welds and at least some of the ligaments. If locations of corrosion are found

then ultrasonic thickness testing (UTT) may be performed to assess thinning

due to metal loss. In rare instances metallographic replication may be

performed. Replication is done by polishing the surface of the drum to a

mirror finish, etching the polished surface with a nitric acid, and then lifting

an image of the metal surface by applying a softened acetate tape (the

replica). The procedure, analogous to finger printing, allows the metal grain

structure to be examined under a microscope.

1A.) Unit #6

Steam Drum- Routine visual inspections have been conducted

inspecting drum internals, and drum externals in both hot and cold

conditions. Upon visual inspection numerous attachment cracks, loose bolts,

moderate accumulation of magnetite, and slight caustic corrosion have been

noted over the last two years. The cracks and surrounding areas were

immediately Wet Magnetic Particle tested and all cracks and indications were

removed with no reoccurring instances. In addition all loose items were re-

secured, all debris was removed and the slight corrosion is being monitored.

Mud Drum- Routine visual inspections and documentation have also

been conducted on the front and rear Mud Drums. The most critical of

concerns are indications of circumferential cracks that are located in the

downcomer to shell weld. The locations and size of these cracks have been

documented and are planned for NDE during the 2001 inspection. Also

planned for 2001 outage is the “Go no Go” testing of the inlet orifices of the

front and rear water walls. As with the Steam Drum cracked attachment

welds and loose items were corrected without further incidents and slight

corrosion is being monitored.

1B.) Unit #7

Steam Drum- Routine visual inspections have been conducted

inspecting drum internals, and drum externals in both hot and cold

conditions. Upon visual inspection numerous attachment cracks, loose bolts,

moderate accumulation of magnetite, and slight caustic corrosion have been

noted over the last two years. The cracks and surrounding areas were

immediately Wet Magnetic Particle tested and all cracks and indications were

removed with no reoccurring instances. In addition all loose items were re-

secured, all debris was removed and the slight corrosion is being monitored.

Mud Drum- Routine visual inspections and documentation have also

been conducted on the front and rear Mud Drums. The front water wall

orifices were gauge tested with no existing problems found the rear water

wall orifices will be tested next scheduled outage. As with the Steam Drum

cracked attachment welds and loose items were corrected without further

incidents and slight corrosion is being monitored.

2.) Headers: Boilers designed for temperatures at or above 1000 F can have

superheater outlet headers that are subject to Creep, the plastic deformation (strain)

of the header from long term exposure to temperature and stress. For high

temperature headers, tests should include metallographic replication and ultrasonic

shear wave inspections of higher stress weld locations. Lower temperature headers

are subject to corrosion or possible erosion. Additionally, cycles of thermal

expansion and mechanical loading may lead to fatigue damage.

Assessment: Inspection should include testing of the welds by MT or WFMT.

In addition, it is advisable to perform internal inspection with a video probe

to assess waterside cleanliness, to note any buildup of deposits or

maintenance debris that could obstruct flow, and to determine if corrosion is

a problem. Inspected headers should include some of the water circuit

headers as well as superheater headers. If a location of corrosion is seen then

UTT to quantify remaining wall thickness is advisable.

2A.) Unit #6 Final Superheat Outlet- Case history has found that certain seamed

headers have failed within Southern Co. system. Since this failure has been

recognized we have identified our FSH header as a seamed header and have

sandblasted and WMPT the seam to ensure no cracks were present.

Radiant Reheat Inlet- Previously documented leaks located in the

circumferential terminal tube weld to header combined with thermal fatigue

cracks in the Radiant wall tubes led us to re-inspect the header for potential

reoccurring problems. In addition to the documented problems repair procedures

at the time were felt to be inadequate. Upon repairing the previous cracks WMPT

was used to verify that the cracks were entirely removed which led to numerous

additional repairs. The entire header was then sandblasted and WMPT leading to

additional repairs on all four headers. Research showed that pressure excursions

and start up/shut down procedures were the root cause of the problem.

2B.) Unit #7 Final Superheat Outlet- As with Unit #6 the FSH header was identified

as a seamed header. The seam was located, sandblasted, and WMPT to ensure no

cracks were present.

Radiant Reheat Inlet- Unit #7 was a mirror image of Unit#6, documented leaks located in the circumferential terminal tube weld to header

combined with thermal fatigue cracks in the Radiant wall tubes led us to re-

inspect the header for potential reoccurring problems. In addition to the

documented problems repair procedures at the time were felt to be inadequate.

Upon repairing the previous cracks WMPT was used to verify that the cracks

were entirely removed which led to numerous additional repairs. The entire

header was then sandblasted and WMPT leading to additional repairs on all four

headers. Research showed that pressure excursions and start up/shut down

procedures were the root cause of the problem.

3.) Piping - Main Steam: For lower temperature systems the piping is subject to the

same damage as noted above for the boiler headers. In addition the piping

supports may experience deterioration and become damaged from excessive or

cyclical system loads.

Assessment: The NDE method of choice for testing of external weld

surfaces is WFMT. MT and PT are sometimes used if lighting or pipe

geometry make WFMT impractical. Non drainable sections such as

sagging horizontal runs are subject to internal corrosion and pitting. These

areas should be examined by internal video probe and or UT

measurements. Volumetric inspection, i.e. shear wave, of selected piping

welds may be included in the NDE; however, concerns for weld integrity

associated with the growth of subsurface cracks is a problem associated

with creep of high temperature piping.

4.) Feed water Piping: A piping system often overlooked is feed water piping.

Depending upon the operating parameters of the feed water system, the flow

rates, and the piping geometry, the pipe may be prone to corrosion or flow

assisted corrosion (FAC). This is also referred to as erosion-corrosion. If suscep-

tible, the pipe may experience material loss from internal surfaces near bends,

pumps, injection points and flow transitions. Ingress of air into the system can

lead to corrosion and pitting. Out-of-service corrosion can occur if the boiler is

idle for long periods.

Assessment: Internal visual inspection with a video probe is recommended if

access allows. NDE can include MT, PT or WFMT at selected welds. UTT should

be done in any locations where FAC is suspected to ensure there is not significant

piping wall loss.

5.) Deaerators: deaerators have been known to fail catastrophically in utility plants.

The damage mechanism is corrosion of shell welds which occurs on the ID

surfaces.

Assessment: Deaerators' welds should have a thorough visual inspection. All

internal welds and selected external attachment welds should be tested by

WFMT.

6.) Attemperators: The spray flow attemperator, a device for controlling superheater

outlet steam temperature, is normally located in the piping system between the

primary (1st stage) superheater outlet and the secondary (2nd stage) superheater

inlet. The attemperator is subject to failures associated with thermal fatigue cracking

of its components and welds. Since it is in a non viewable area of the boiler, failures

may go undetected until pieces of the attemperator lead to other damage, such as su-

perheater tube failures. These steam temperature control systems should also be part

of the boiler fitness survey testing.

Assessment: For the inspection is recommended by removal of the spray head

assembly. The spray head is inspected visually and tested nondestructively

by MT/PT methods. Following removal of the spray head from the body of

the attemperator, the attemperator thermal liner can be internally inspected

with a video probe.

7.) Tubing: Statistically the greatest numbers of forced outages in all types of boilers

are related to tube failures. Failure mechanisms vary greatly from the long term to

the short term. Tubes are more likely to fail because of abnormal deterioration such

as: water/steam-side deposition inhibiting heat transfer, flow obstructions, tube cor-

rosion (ID and/or OD), fatigue, and tube erosion.

Assessment: Tubing is one of the components where visual examination is of

great importance because many tube damage mechanisms lead to visual signs

such as distortion, discoloration, swelling or surface damage. The primary

NDE method for obtaining data used in tube assessment is contact UT for

tube thickness measurements. Sample removal for laboratory analysis is by

far the best test to conduct for the assessment of life in the component.

7A.) Water walls-

Unit #6- Starting in the Coutant throat and extending to the Screen tubes

multiple problematic conditions exists in Unit #6; Caustic corrosion, Internal

corrosion resulting in corrosion fatigue failures, erosion, overheat, thermal fatigue,

reducing atmosphere, and past maintenance repair problems.

Caustic corrosion exists on both hot and cool surfaces of the boiler. The external

surface of the boiler tube walls appears as heavy oxide deposits that when chipped

away left a 1/16” divot. Tube samples have been removed for analysis by Dr.

French. Root cause of the boiler external corrosion apparently is caused by the acidic

nature of the ash combined with external pre-outage wash downs. It is

recommended to target two more samples from the water walls next outage to

compare remaining life to the last samples taken. In addition two samples from the

bottom side of the Coutant should also be taken for base line analysis due to recent

failures in this area.

Internal corrosion has also been documented correlating to failures in the burner

corners relating to corrosion fatigue. A combination of internal corrosion, high heat

flux zone, and degradation of the support system in this area are believed to have

been the root cause for previous leaks in this area. Water wall panels have been

replaced in this area to remove the afflicting conditions and this area is now under

monitoring status.

Erosion was a problematic condition around wall blowers however the plant

does not use the wall blowers anymore hence this area is in monitoring status. Soot

blower erosion on the other hand has been a concern on the rear side of the

Superheat Pendant Platen, front side of the Final Superheat, front side of the vertical

outlet legs of the Primary Superheat, Coutant, and Deflection Arch. In the past these

areas have been shielded with success except for the rear side of the Superheat

Pendant Platen. Due to the intense heat in this area the shields have been

unsuccessful in protecting the trailing side of the pendant and multiple repairs have

been conducted outage to outage. Flame spray is a potential candidate for this area

and budget allowing will be utilized this outage. Other locations of concern are the

Coutant area. Previous UT scans across the upper side of the throat and along the

side walls revealed four areas of immediate attention during last outage. All areas

were cleaned and flame sprayed to extend the life an additional 5 years. During the

upcoming outage the upper Coutant transition to front and rear water walls will be

accessed for more UT scans to provide a baseline reference for future work. Last but

not least the upper side of the Deflection Arch between rear wall Hangers, and

Screen tubes, the Arch was found to have lost up to 40% of minimum wall

requirements. Due to this area being replaced in the next five years the area was

prepared and Flame sprayed.

Over the course of the last two years hundreds of swelled tubes have been

documented in the water walls from the Coutant to the Radiant Reheat wall

elevation. Research discovered that for a length of time one of the boiler circ. Pumps

was not being utilized resulting in a starvation of flow leading to the overheated

sections of tubing. A few samples were taken two years ago to visually determine

the severity however none of the samples were sent for analysis. Two samples are

recommended to be sent for analysis of remaining life. All circ. Pumps have been in

operation thereof and no failures have been documented since the condition has

been recognized. The two planned samples will establish a rate of progressive

degradation if any exists.

Another problematic area concerning heat related issues is the propagating

thermal fatigue cracks located in the membrane of the Deflection Arch. Due to the

mass quantity of cracks over the last few outages the most severe areas of membrane

have been removed and replaced with new membrane. The new membrane has also

been documented as developing cracks in just the few short years it has been

installed. Research proved that in the past, due to the unit being positive pressure

the membrane was changed from peg to solid; however the gap between the tubes

does not allow for proper coolant of the solid welded membrane hence the

propagating crack issue. To solve the problem a long term solution has been made

to reengineer the Deflection Arch tube spacing to allow adequate cooling area for the

membrane.

Reducing atmosphere conditions exist due to the combination of Low Nox

Burners and Over Fired Air. Slight corrosion pitting is apparent on the water walls

and was ground smooth for UT verification. Remaining wall thickness was .180”

leaving the tube well above action criteria. We recommend that a tube be removed

in this same general area for analysis to determine a rate of progressive degradation

if any exists.

7B.) Radiant Reheat-

7C.) Pendant Platen Superheat-

7D.) Pendant Reheat-

7E.) Final Superheat-

7F.) Primary Superheat-

7G.) Economizer-