guideline technology guideline for detection and 240 ... · pdf filefrom high pressure heater...

PCM Reference : 240-53458931 (Power Plant Turbine Engineering)

SCOT Study Committee Number/Name : Materials and Welding

Guideline Technology

Title: Guideline for Detection and Management of Flow Accelerated Corrosion in Fossil Fired Power Plant

Unique Identifier: 240-60238419

Alternative Reference Number: GGL 36-939

Area of Applicability: Engineering

Documentation Type: Guideline

Revision: 2

Total Pages: 83

Next Review Date: December 2020

Disclosure Classification: CONTROLLED DISCLOSURE

Compiled by Approved by Authorised by

…………………………………. ………………………………… …………………………………..

K. Northcott

Senior Consultant

Corrosion

M. Maroga

Materials, Welding and NDT SC Chairperson

K. Sukhnandan

Manager: Turbine Plant CoE (Acting)

Date: …………………………… Date: …………………………… Date: ……………………………

Supported by SCOT TC

…………………………………..

T. Mathe

SCOT TC Chairperson

Date: ……………………………

Guideline for Detection and Management of Flow Accelerated

Corrosion in Fossil Fired Power Plant

CONTROLLED DISCLOSURE

When downloaded from the EDMS, this document is uncontrolled and the responsibility rests with the user to ensure it is in line with the authorised version on the system.


Revision: 2

Page: 2 of 83

CONTENTS

Page

1. INTRODUCTION ...................................................................................................................................................... 4

2. SUPPORTING CLAUSES ........................................................................................................................................ 6

2.1 SCOPE .............................................................................................................................................................. 6 2.1.1 Purpose ..................................................................................................................................................... 6 2.1.2 Applicability................................................................................................................................................ 6

2.2 NORMATIVE/INFORMATIVE REFERENCES .................................................................................................. 7 2.2.1 Normative .................................................................................................................................................. 7 2.2.2 Informative ................................................................................................................................................. 8

2.3 DEFINITIONS .................................................................................................................................................... 8 2.3.1 Classification ............................................................................................................................................. 8

2.4 ABBREVIATIONS .............................................................................................................................................. 8 2.5 ROLES AND RESPONSIBILITIES .................................................................................................................. 10 2.6 PROCESS FOR MONITORING ...................................................................................................................... 10 2.7 RELATED/SUPPORTING DOCUMENTS ....................................................................................................... 10

3. THE DETECTION AND MANAGEMENT OF FLOW ACCELERATED CORROSION IN FOSSIL FIRED POWER PLANT .................................................................................................................................................... 11

3.1 REQUIREMENTS ............................................................................................................................................ 11 3.1.1 Site Procedure ......................................................................................................................................... 11 3.1.2 Guideline Appendices ............................................................................................................................. 12

3.2 RECORDS ....................................................................................................................................................... 12

4. AUTHORISATION .................................................................................................................................................. 13

5. REVISIONS ............................................................................................................................................................ 13

6. DEVELOPMENT TEAM ......................................................................................................................................... 13

7. ACKNOWLEDGEMENTS ...................................................................................................................................... 13

APPENDIX A : OVERVIEW OF FAC MECHANISM AND INFLUENCING FACTORS ............................................ 14

APPENDIX B : OVERVIEW OF EROSIVE MECHANISMS ...................................................................................... 27

APPENDIX C : METHODOLOGY AND REMEDIAL ACTIONS ................................................................................ 39

APPENDIX D : OVERVIEW OF FAC INSPECTION ACTIVITIES............................................................................. 57

APPENDIX E : CLOSING OF HEATER VENTS AND MONITORING OF HEATER DRAIN LINES ........................ 77

FIGURES

Figure 1: Mechanism of FAC in Flowing AVT (R). ..................................................................................................... 16 Figure 2: Typical visual appearance of (orange peel or scalloped) FAC damage in single-phase environments. .... 19 Figure 3: Typical visual appearance of FAC damage in two-phase environments. ................................................... 22 Figure 4: Cavitation Damage in the Body of a Plug Valve ......................................................................................... 30 Figure 5: Cavitation Damage in the Body of a Plug Valve ......................................................................................... 31 Figure 6: LIE damage on a turbine blade together with a sample from a laboratory test. ......................................... 32 Figure 7: SPE damage of a valve internals stem ....................................................................................................... 33 Figure 8: Schematic of the rate of damage for cavitation or liquid impact erosion..................................................... 35 Figure 9: Normalized Cavitation or Impingement Erosion Resistance of Common Materials Normalized to SS

316. .............................................................................................................................................................. 36 Figure 10: Erosion Resistance of Stainless Steels, Carbon Steel and Inconel. ......................................................... 37 Figure 11: Resistance of Selected Metals to Solid Particle Erosion. ......................................................................... 37 Figure 12: Flow-diagram detailing key activities for the Flow Accelerated Corrosion Management Programme ...... 52






Revision: 2

Page: 3 of 83

Figure 13: A-Scan Display Format ............................................................................................................................. 62 Figure 14: B-Scan, C-Scan and D-scan Conventions ................................................................................................ 62 Figure 15: B-Scan Display Format ............................................................................................................................. 63 Figure 16: C-Scan Display Format ............................................................................................................................. 63 Figure 17: Maximum Grid Sizes for Standard Pipe Sizes .......................................................................................... 66 Figure 18: Grid Pattern marking convention ............................................................................................................... 67 Figure 19: Tabular form for recording measurements ................................................................................................ 69 Figure 20: Wall Thickness Measuring Devices .......................................................................................................... 73 Figure 21: Additional Equipment Required for Wall Thickness Measurement ........................................................... 73 Figure 22: Examples of two-phase FAC Failures in Heater Drain Lines of Eskom Power Stations .......................... 78 Figure 23: Increased dissolved oxygen in LP Heater drain line after closing vents of LP Heater.............................. 81 Figure 24: Mobile Sample Conditioning and Monitoring System for Corrosion Product Monitoring on Heater

Drain Lines .................................................................................................................................................. 82 Figure 25: Fixed Sample Conditioning System & Mobile Trolley for Corrosion Product Monitoring on Heater

Drain Lines .................................................................................................................................................. 82

TABLES

Table 1: Load Cycling and the impact on FAC – “Typical” fossil plant utilizing reheated steam. (Courtesy EPRI) ... 26 Table 2: Cavitation Regimes with Typical Noise Levels for Standard Trim Valves .................................................... 29 Table 3: Summary of the four types of erosive attack mechanisms discussed above. .............................................. 34 Table 4: Example of Scope of Work Template ........................................................................................................... 55 Table 5: Example of typical items to exclude from the inspection Scope of Work ..................................................... 56 Table 6: Probe Selection Criteria ................................................................................................................................ 74






Revision: 2

Page: 4 of 83

1. INTRODUCTION

Flow-accelerated corrosion (FAC), sometimes called Flow-assisted corrosion, occurs in carbon steel/mild steel/low-alloy steel piping, valves and vessels containing single-phase water or two-phase steam and water. The result of FAC is piping or component wall thinning.

FAC is a process whereby the normally protective oxide layer on carbon, mild or low-alloy steel dissolves into a stream of flowing water or a water-steam mixture. The oxide layer becomes thinner and less protective, and the corrosion rate is increased. Rates of up to 3mm p.a. have been observed in power plant.

FAC-induced damage produces a different appearance for single-phase and two-phase conditions.

The FAC process involves several influencing factors. Although a summary of the relative impacts of each of the factors will be discussed in Appendix A. it is beyond the scope of this guideline document to discuss the in-depth details and inter-relationship of these factors. The reader is referred to the reference literature for further reading. The influencing factors include hydrodynamics, environmental (chemical) and metallurgical factors.

Systems and locations that are susceptible to FAC in Eskom fossil power plants include all carbon steel systems and components in the feedwater/boiler circuit that convey water and water/steam mixtures where temperatures are below 300ºC.

FAC susceptible systems and piping in fossil power plants include the following:

Locations of FAC damage in single-phase environments in conventional fossil plant include:

a. Low Pressure Feedwater Piping (normally before deaerator)

Expander in piping between Feedwater Heater and deaerator

Discharge of Low Pressure Drains Pump

Low Pressure piping, 90° elbows

b. Feedwater Piping around deaerator and Boiler Feed Pumps

Deaerator Outlet piping to Condensate Booster Pumps: elbows, tees

Condensate Booster Pump Discharge Piping: elbows

Boiler Feed Pump Suction Piping: tees and 90° bends in supply piping from deaerator

Boiler Feed Pump Discharge: elbows, reducers, welds

Boiler Feed Pump Discharge: SH/RH Attemperation supply piping and fittings

Boiler Feed Pump Discharge recirculation piping: after control valves

Boiler Feed Pump leak-off lines

Boiler Feed Pump balancing lines

Feedwater Control Systems: orifices, thermowells and Regulating Valves

Start-up Boiler feed Pump warm-up lines: bends following orifices

c. Attemperation Piping

Near Main Feedwater line: tees to Superheat and Reheat Attemperation Systems

Main Steam Attemperation piping: control valves, elbows






Revision: 2

Page: 5 of 83

Reheat Attemperation piping: control valves, elbows, tees, valve bodies

Low pressure drains – single-phase locations

High pressure drains – single-phase locations

d. Feedwater Piping between Boiler Feed Pumps and Economizer Inlet

High Pressure Feedwater Piping: elbows, expanders, reducers, tees

High Pressure Feedwater Piping: flow nozzles and check valves before Economizer

High Pressure Feedwater Heater tube sheets and tubes (carbon steel)

e. Near Economizer Inlet Header

Approach piping to economiser inlet header

Economizer Inlet Header tube stubs (especially those nearest the supply)

Locations of FAC damage in two-phase environments in conventional fossil plant includes:

f. Low Pressure Heater Distillate Drains

Low Pressure Heater Distillate Drains piping: Level Control Valves (component immediately before/all components after), valve bodies, reducers, expanders, tees

g. High Pressure Heater Distillate Drains

High Pressure Heater Distillate Drains piping: Level Control Valves (component immediately before/all components after), reducers, expanders, elbows, valve bodies, gate valves (all components after)

h. Alternate (High Level or Emergency) Drains

From High Pressure Heater to Lower Pressure Heater: after Level Control Valves

From High Pressure Heater to deaerator: after Level Control Valves

Tee joining Normal and Alternate High Pressure Drain lines

Drains to Condensers: after Level Control Valves, after gate valves, elbows (including elbows in Condensers)

Drains Bypass piping

Shells

Low Pressure Heater Shells (near to cascading drain entries)

Heater vent lines to Condenser: elbows

High Pressure Feedwater Heater shells (near to cascading drain entries)

Deaerators (near to fluid entries especially HP cascading drains)

Drain Flashboxes

Air-cooled Condensers

International literature and experience suggests that FAC damage is not considered to be prominent in systems such as:






Revision: 2

Page: 6 of 83

i. Air preheater piping systems

j. Gland and auxiliary steam systems

k. Turbine drains

l. Boiler drains

m. Blow down vessels

However, Eskom’s stance is that in the above systems and locations, wall thinning could still occur due to erosion, cavitation, and impingement. It is therefore considered that these systems/locations be included in the FAC Management Programme. The mechanisms of erosion, cavitation, and impingement will be discussed later in the guideline (Appendix B).

FAC is an extremely detrimental form of corrosion in two major respects.

If undetected it can result in unexpected severe wall thinning and eventual catastrophic rupture of high pressure piping with extensive damage to surrounding plant and possibly personnel injuries and fatalities. In some instances an operational transient such as a pump trip can be the “last straw”. Several well know incidents have occurred in other utilities in both fossil and nuclear plants with, unfortunately, several fatalities.

Iron dissolution by FAC in the feedwater system eventually results in increased iron transport to the boiler; excessive deposition of these deposits can initiate under-deposit corrosion mechanisms and increase the risk of associated boiler tube failures. Post operational chemical cleaning, with its own inherent risks, is therefore required to remove these deposits.

In terms of inspection for the detection of FAC damage, screening techniques such as Digital Radiographic Testing (DRT) and visual methods either direct visual (for vessels with suitable access or in the case of restricted access remote visual i.e. fiberscope and/or camera systems) are required. If any damage is observed or suspected by the screening techniques then the extent of damage or wall thinning needs to be quantified by Ultrasonic Testing (UT).

This guideline details various aspects related to performing inspections for the detection and quantification, monitoring and mitigation of FAC damage in Eskom’s fossil fired power plants.

2. SUPPORTING CLAUSES

2.1 SCOPE

2.1.1 Purpose

The aim of this document is to provide advisory information regarding the development and implementation of a station specific FAC management programme.

This guideline is intended to aid system engineering personnel in developing their own site specific FAC management programme which includes the key elements of inspection scope compilation, FAC detection and quantification and remedial measures. The management programme as outlined in this document caters for activities prior to outages, during outages (inspections) and post outage. It therefore considers the management of FAC as a continual process.

2.1.2 Applicability

This document shall apply to all Eskom Coal Fired power stations.






Revision: 2

Page: 7 of 83

2.2 NORMATIVE/INFORMATIVE REFERENCES

Parties using this document shall apply the most recent edition of the documents listed in the following paragraphs.

2.2.1 Normative

[1] Fossil FAC International Conference, June 29 – July 1 2010, Lessons Learned from Fossil FAC Assessments, R. Barry Dooley, Kevin J. Shields, Stephen J. Shulder

[2] Fossil FAC International Conference, June 29 – July 1 2010, Although Understood, FAC Remains an Enigma, R. Barry Dooley

[3] Flow-Accelerated Corrosion in Fossil and Combined Cycle/HRSG Plants, R. Barry Dooley, PPChem 2008

[4] Level One FAC Assessment at 8 Eskom Plants, Report 0800138.401, February 2011, R. Barry Dooley, Structural Integrity Associates, Inc

[5] EPRI, Final Report 1008082: EPRI Guidelines for Controlling Flow-Accelerated Corrosion in Fossil and Combined Cycle Plants, Dr. B. Dooley, March 2005

[6] Eskom Chemistry Standards: 240-55864800, 240-55864811, 240-55864792

[7] EPRI, Symposium: Detection and Control of Flow-Accelerated Corrosion in Fossil Power Plants, December 1997

[8] Interim Recommendations for an Effective Program Against Erosive Attack, 1015071, Technical Update, December 2007

[9] Examination of Heat Recovery Steam Generator (HRSG) Plants Assessment of Fiber-Optic Techniques, 1008092, Final Report, November 2005

[10] Guidelines for the Nondestructive Examination of Heat Recovery Steam Generators, Revision 1 1012759, Final Report, February 2007

[11] Email correspondence by R.B. Dooley to Eskom - Proposal for Fossil Plant Flow-accelerated Corrosion (FAC) Assessment – 120510

[12] 240-86546783 - Procurement Standard for Material Certification for Metallic Products used on Low and Medium Pressure Applications

[13] 240-92944687 - Standard for Performing Digital Radiography for Screening of FAC and Erosive Attack in Fossil Fired Power Plants

[14] Eskom Generation Procedure 36-962, Plant Risk Identification, Assessment, Reporting & Escalation

[15] 240-83539994 (Alternative No: 32-631): Eskom NDT Personnel Approval (NPA) for Quality Related Special Processes on Eskom Plant Standard

[16] 240-8354008 (Alternative No: 32-632): Requirements for Non-Destructive Testing (NDT) on Eskom Plant Standard

[17] Closing of Vents – reference list in Appendix E

[18] Eskom Welding Rule Book (WRB)

[19] 240-56241933: Control of Welding during Construction, Repair and Maintenance Activities

[20] 240-56355225: Welding of High Pressure Temperature Tube and Pipework Standard






Revision: 2

Page: 8 of 83

[21] 240-56246601: Personnel and Entities Performing Welding Related Special Processes on Eskom Plant

2.2.2 Informative

None

2.3 DEFINITIONS

Definition Description

Erosion Is the destruction of materials by the abrasive action of moving fluids, usually accelerated by the presence of solid particles.

Erosion-Corrosion Is also known as impingement attack and (under some circumstances) flow accelerated corrosion. It is the corrosion reaction accelerated by the relative movement of the corrosive fluid and the metal surface. The probability of erosion-corrosion of copper alloy condenser tubes is highest at tube inlets or downstream of any debris lodged in the tubes.

Eskom used for Eskom Holdings SOC Limited, its divisions and owned subsidiaries.

Fiberscope A device used to enable visual inspection of the internal surface of tubes, pipes and vessels.

Maintenance Work performed to keep equipment operable, or to make repairs

Mass transfer Is the process of transporting material (essentially magnetite) from the surface to the bulk of the flowing water or water-steam flow. The local mass transfer coefficient depends in a complex manner on fluid velocity, fluid viscosity, flow geometry, pipe/tube surface roughness, steam quality and void fraction (for two-phase flow) and temperature. Mass transfer is usually described by the dimensionless parameters: Reynolds, Schmidt and Sherwood numbers.

pH The negative logarithm of the hydrogen ion activity (effectively concentration) measured at a defined temperature, usually 25ºC.

Pitting corrosion Localised corrosion of a metal surface that is confined to a small area and takes the form of cavities.

2.3.1 Classification

a. Controlled Disclosure: Controlled Disclosure to External Parties (either enforced by law, or discretionary).

2.4 ABBREVIATIONS

Abbreviation Description

µg/L (µg/kg) Micrograms per litre (kilogram), equivalent of ppb

AVT All Volatile Treatment

AVT(O All Volatile Treatment (Oxidising)

AVT(R) All Volatile Treatment (Reducing)






Revision: 2

Page: 9 of 83

Abbreviation Description

BU Business Unit

CEP Condensate Extraction Pump

CPP Condensate Polishing Plant

CPS Corrosion Product Sampler

CV Control Valve

DRT Digital Radiographic Testing

ECM Engineering Change Management (process)

EI: Economiser Inlet

EPRI Electric Power Research Institute, Inc.

FAC Flow Accelerated Corrosion

Fe(OOH) Ferric Oxide Hydrate

Fe3O4 Magnetite

HP High Pressure

LIE Liquid Impingement Erosion

LP Low Pressure

NDT Non-destructive testing

OD Outside Diameter

OES Optical Emission Spectroscopy

ORP Oxidising/Reducing Potential

OT Oxygenated Treatment

p.a. Per annum

ppb Parts per billion

PEIC Production Engineering Integration Coal

RBI Risk Based Inspection

RT&D Research, Testing and Development

SOW Scope of Work

SPE Solid Particle Erosion

UT Ultrasonic Testing

WT Wall thickness






Revision: 2

Page: 10 of 83

2.5 ROLES AND RESPONSIBILITIES

2.5.1 The Power Station Manager shall be responsible and accountable for ensuring implementation of this document.

2.5.2 The responsibility for the implementation of this guideline resides with the Power Station Engineering Manager with support from the Turbine Plant Engineering, Boiler Plant Engineering, Chemical Services, Operating, Maintenance, Outage and Project Management Managers and to those assigned to participate in the process at each power station.

2.5.3 Specific management responsibilities include:

a. Supporting a programme by providing adequate resources, staff, equipment funding and organisational capabilities to facilitate the advisory recommendations contained in this guideline, as required.

b. Supporting the exchange of information and experience with other sites through the appropriate technical forums.

c. Developing a site-specific FAC Procedure which is fully approved and sponsored by the senior management at the station and PEIC. The procedure is required to provide the roles and responsibilities of the various sections dealing with different isolated aspects of FAC (management, operations, maintenance, boiler engineering, turbine engineering and chemists) at the station but should also include representation (where required) by Corporate level (NDE, metallurgists, feedwater specialists, chemistry specialists and piping engineers).

d. The responsibility for the review and approval of SOW documents resides solely with the Power Station Engineering Manager with support from the Turbine Plant Engineering, Boiler Plant Engineering, Chemical Services, Operating, Maintenance, Outage and Project Management Managers. If required, SMEs (NDE, metallurgists, feedwater specialists, chemistry specialists and piping engineers) may provide input on an adhoc basis.

2.6 PROCESS FOR MONITORING

The site-specific FAC Procedure is the minimum requirement to manage plant reliability and availability. The monitoring of inspection result reports together with extent of scoped inspection successfully executed and then resulting outage Scopes of Work and participation in the associated site forums will serve as the basis upon which the success of the programme is measured.

2.7 RELATED/SUPPORTING DOCUMENTS

The site-specific FAC Procedure shall be registered and kept current, reflecting the latest approach to the management regime implemented.

The outage Scope of Work informs the Maintenance function of the required measures to be performed during every outage to proactively manage the risk associated with FAC.






Revision: 2

Page: 11 of 83

3. THE DETECTION AND MANAGEMENT OF FLOW ACCELERATED CORROSION IN FOSSIL FIRED POWER PLANT

3.1 REQUIREMENTS

3.1.1 Site Procedure

The site-specific FAC Procedure should include, as a minimum, the following elements:

Approval by Power Station management to indicate commitment to monitor and control FAC.

The overall authority and task responsibilities are clearly defined and that the formally appointed personnel have adequate time to complete the work.

Identification of the position (Custodian) that has overall responsibility for the FAC program at each plant.

The means of ensuring that assigned personnel are issued the FAC Guideline and Standard.

Identification of the tasks to be performed (including implementing procedures) and associated responsibilities.

The means of ensuring that FAC experiences at other plants are continuously monitored and evaluated.

This team shall meet formally at least twice a year, before the outage period to discuss scope of work, and after the outage period to discuss the findings and action plans. The terms of reference for this meeting will be compiled and the proceedings appropriately documented.

The means of ensuring that sufficient stock levels are available for the replacement of high risk (e.g. two-phase conditions in pipe sections as defined elsewhere in this document) identified prior to an outage and that these replacements are performed at the first available opportunity.

Ensuring that inspection “Scope of Work” documents are submitted for upload onto hyperwave after review and approval as per section 2.5.3 (d). Refer to ‘Documentation Management & Programme Benchmarking Management’ in Appendix C.2.

Ensuring that the submission of the “Scope of Work” documents is aligned with station requirements and timelines before a scheduled outage. Refer to ‘Documentation Management & Programme Management’ in Appendix C.2.

Ensuring that the appropriate NDT techniques are applied and that appropriate quality control is applied.

Ensuring that the “Inspection Report” documents are submitted for upload onto hyperwave. Refer to ‘Documentation Management & Programme Management’ in Appendix C.2.

Ensuring that the component specific inspection sheets and images are appropriately archived at the particular site via official site documentation management processes such as the Document Management Centre and/or electronic media storage to ensure traceability and future retrieval for audit purposes.

Ensuring that all the component specific inspection sheets and images are archived within a month after submission, finalisation and upload of the particular inspection report and results sheet onto Hyperwave.






Revision: 2

Page: 12 of 83

Ensuring that after the execution/completion of an inspection according to the requirements of this guideline that the compilation of the next inspection and replacement “Scope of Work” documents submitted for upload onto hyperwave after review and approval as per section 2.5.3 (d).

Developing a long-term plan and the identification of long-term goals and strategies for reducing high FAC wear rates.

A method for evaluating team performance against long-term goals. Refer to ‘Documentation Management & Programme Management’ in Appendix C.2.

3.1.2 Guideline Appendices

Detailed in the appendices are key elements to note to ensure that the site-specific procedure addresses the various aspects of FAC and Erosive Attack.

3.1.2.1 Appendix A specifically details the key elements of the FAC mechanism and influencing factors for the purpose of providing insight in terms of prioritising, minimising or excluding certain systems or components from the inspection process.

3.1.2.2 Appendix B specifically details the key elements of Erosive Attack mechanisms and influencing factors for the purpose of providing insight in terms of prioritising, minimising or excluding certain systems or components from the inspection process.

3.1.2.3 Appendix C details the methodology to be followed for determining the inspection scope of work (pre-outage) based on an engineering judgement philosophy as well as the activities to be considered during and post outage.

3.1.2.4 Appendix D provides guideline and advisory information with respect to the appropriate NDT techniques to be applied for the detection (screening) and quantification of pipe component and vessel wall thinning mechanisms.

3.1.2.5 Appendix E details the Eskom position with respect to Closing of Heater Vents. Eskom’s position is that Generation stations on OT and AVT(O) will convert their operating procedures to operate with DA, LP and HP heater vents closed during normal operation in order to reduce single- and two-phase FAC in heater shells, heater normal drain lines and heater emergency drain lines. Generation stations operating on AVT(R) will operate with the all vents opened.

3.2 RECORDS

The management process of records generated by this document is discussed in Appendix C.






Revision: 2

Page: 13 of 83

4. AUTHORISATION

This document has been seen and accepted by:

Name Designation

All members as at January 2016 Materials, NDT & Welding Study Committee

All members as at January 2016 Materials Care Group

All members as at January 2016 Feedheating and Condensate Care Group

Joe Roy-Aikins Discipline Manager – Turbine CoE

Chairman – Turbine Study Committee

Noel Lecordier Senior Consultant Engineering (PEIC Turbine)

Member – Turbine Study Committee

Stephanie Marais PEIC Corporate Chemistry Specialist

Member – Water Sciences and Technology Study Committee

Sumayyah Sulliman PEIC Senior Engineer

Member – Water Sciences and Technology Study Committee

All members as at January 2016 GX Engineering Managers Forum

5. REVISIONS

Date Rev. Compiler Remarks

February 2013 0.1 K Northcott Draft Document for review created from GGL 36-939

March 2013 1 K Northcott Final Document Authorised for Publication

November 2015 1.1 K Northcott First Updated Draft

December 2015 1.2 K Northcott Final Updated Draft for Comments Review Process

February 2016 1.3 K Northcott Final Updated Draft after Comments Review Process

February 2016 2 K Northcott Final Document for Authorisation and Publiction

6. DEVELOPMENT TEAM

The following people were involved in the development of this document:

A.F. Du Preez Corporate Consultant (PEIC)

S. Marais Corporate Consultant (PEIC)

H.C. van Niekerk Senior Consultant (PEIC)

7. ACKNOWLEDGEMENTS

None






Revision: 2

Page: 14 of 83

APPENDIX A: OVERVIEW OF FAC MECHANISM AND INFLUENCING FACTORS

A.1 FAC Mechanism Overview

A.2 FAC Phase Conditions and Damage Characteristics

A.3 Factors and Variables affecting FAC

A.4 Load Cycling and its Impact on FAC






Revision: 2

Page: 15 of 83

A.1 Flow-Accelerated Corrosion (FAC) Mechanism Overview

In older texts (and in some more recent ones) FAC is termed erosion-corrosion. This is incorrect. FAC should not be confused with erosion-corrosion. Although similar from the point of view that it is a corrosion mechanism accelerated by the relative movement of a corrosive fluid and the metal surface, the specific interaction with the metal surface makes it different to erosion-corrosion. In FAC there is no mechanical interaction or disruption of the steel surface but rather disruption or dissolution of the normally protective iron oxide layer.

Mechanisms associated with Erosive Attack may resemble FAC damage and could also occur in similar locations and systems prone to FAC damage. The NDT techniques applied to detect and quantify FAC damage can be applied similarly to areas with suspected Erosive Attack. However the mitigation and management of these mechanisms could differ from those applied to FAC and therefore Erosive Attack mechanisms should be regarded as separate wall thinning mechanisms with respect to prevention and mitigation. The mechanisms involved with Erosive Attack are detailed in Appendix B.

The mechanism of FAC involves the continual removal of the normal protective iron oxide layer coupled with the inherent ability of the steel to attempt to recreate the normally protective oxide layer. It is the continual consumption of the underlying steel (base metal) to produce the “replacement” protective oxide layer that ultimately results in thinning of the base metal. It is therefore the interaction of the environment and the protective oxide layer that affects the FAC process. The resultant consumption of base metal is a consequential part of the process.

FAC occurs in environments that consist of a stream of flowing water or wet steam. Flowing water is referred to as single-phase whilst wet steam (steam-water mixture) is referred to as two-phase. FAC does not occur in a pure steam phase.

From a cycle chemistry perspective the phenomenon of FAC (single-phase flow locations) may be explained in terms of whether the chemistry is oxidising or reducing. Cycle feedwater chemistry may be categorised as either oxidising or reducing and may be determined or quantified using an electrochemical measure known as Oxidising/Reducing Potential (ORP). It should be noted that ORP is not used as a measure in Eskom fossil plant. Further reference to the term ORP in this document is for explanatory purposes only.

The surface oxide differs depending on whether the environment is oxidising or reducing. Eskom has for a number of years been implementing cycle chemistry that is oxidising in nature rather that reducing. These cycle chemistry regimes are commonly referred to as AVT(O) or OT. For further reading refer to the Eskom Chemistry Standards 240-55864800, 240-55864811, 240-55864792.

FAC in single-phase flow locations essentially occurs with AVT(R) chemistry, where magnetite (Fe3O4) is the surface oxide; its solubility peaks at around 150 ºC. FAC in single-phase locations can also occur where AVT(O) or OT is not optimised. Severe FAC occurs when the dissolution and exfoliation or spalling of magnetite from the surface is greater than its growth on the pipe/pressure vessel surface, thus increasing the amount of particulate magnetite in the feedwater circuit.

FAC in two-phase flow locations may occur in all feedwater chemistry regimes, namely AVT(R), AVT(O), and OT. Areas of FAC damage are visually easily observed and characterised as shiny black stripes or patches, in the case of AVT(O) and OT, contrasted against a red-salmon pink protective oxide layer. It typically occurs where flashing occurs with a resultant turbulent two-phase (fluid and steam) environment. The two-phase areas are always black due to there being limited to no oxidising power in the two-phase fluid as it interacts with the surface because of partitioning or separation of any oxygen and ammonia to the steam phase (see figure 3 in A.2.1).Carbon steels are susceptible to FAC. Small quantities of chromium, as an alloying element, have been found to significantly increase the stability of the oxide layer thereby lowering the rate of FAC. The solubility of iron-oxides in the presence of pure water reduces drastically with the presence of chromium with the result of reducing FAC rates.






Revision: 2

Page: 16 of 83

An alloy containing 1.25% nominal chromium content or more would have significantly lower, to possibly negligible, FAC rates.

There are other factors besides the chemistry and material composition aspects (as described above) which accelerate this dissolution process in low chromium content steels. In terms of these additional factors the FAC mechanism under reducing conditions is illustrated in Figure 1.

At low velocities, the flow is laminar and essentially parallel to the surface of the metal or to the adjacent streamlines. In this case the velocity varies from essentially zero near to the oxide/water surface to a maximum at the centreline of the pressure vessel/tube. In this case, the growth of the Fe3O4 at the oxide/steel interface matches the dissolution. At higher velocities, the action of friction between water and oxide induces irregular fluctuating radial and axial velocity components with flow. The fluid is mixed in a random manner and becomes turbulent.

In this case the growth of Fe3O4 and possible conversion to FeOOH cannot match the flow-accelerated dissolution, exfoliation and spallation and the oxide thickness reduces and thus becomes less protective. The result is FAC with the likelihood of high levels of iron oxide (particulate) in the feedwater system.

Figure 1: Mechanism of FAC in Flowing AVT (R).

Note: Cs is the concentration of iron at the oxide/solution interface (oxide solubility) and C is the bulk iron concentration. (Courtesy EPRI)

A.2 FAC Phase Conditions and Damage Characteristics

In terms of damage appearance and morphology FAC damage tends to occur over a fairly wide area as generalised wall loss without localised features such as pitting or cracking.

Cs

C Water

Porous Oxide

Fe3O4

Metal






Revision: 2

Page: 17 of 83

There are two general conditions under which FAC occurs and are known as:

Single-phase FAC which refers to the flow of only water

Two-phase FAC which refers to the flow of both steam and water

The two types have characteristic features which are useful in FAC identification during inspections. Typically single-phase conditions produce a scalloped, wavy or orange peel surface. A tiger striped appearance is commonly associated with two-phase conditions. The absence of a classic tiger striped surface does not exclude the possibility of two-phase FAC.

As discussed in A.1 FAC in single-phase flow conditions is associated with reducing conditions and may therefore be controlled by optimising the applied feedwater chemistry treatment, e.g. AVT(O) or OT. Single-phase FAC is most likely to occur in economiser inlet tubing and piping to the economiser inlet header, heater distillate drain lines (typically before pressure regulating i.e. single-phase environments), piping around the BFP (where there are complex geometries and increased turbulence) and tubesheets and tubes in HP heaters.

Two-phase FAC may occur in all feedwater chemistry regimes, namely AVT(R), AVT(O), and OT. Areas of FAC damage are visually easily observed and characterised as shiny black stripes or patches, in the case of AVT(O) and OT, contrasted against a red-salmon pink protective oxide layer. It typically occurs where a fluid enters a vessel or moves across a control valve and the difference in temperature and pressure between the entering fluid and the bulk fluid results in flashing with a resultant turbulent two-phase environment of steam and fluid. The two-phase areas are always black due to there being limited to no oxidising power in the two-phase fluid as it interacts with the surface because of partitioning or separation of any oxygen and ammonia to the steam phase.

In these situations control of FAC by optimising the feedwater chemistry is ineffective due to the oxidising power of the fluid being lost because of partitioning to the steam phase. The primary control or mitigation of FAC in two-phase environments is accomplished by replacement with higher chromium content materials i.e. 1.25% Cr (nominal content). Additional control/mitigation measures include procedures (where feasible and practical) to increase the oxidising potential in those two-phase zones, including closing of heater vents to retain ammonia and oxygen.

Areas typically prone to two-phase FAC include HP & LP heater shells, deaerators, and HP and LP heater distillate drain lines.

Two-phase areas of the cycle are very susceptible to FAC, especially in those drains where the temperature and pressure changes across level control valves and expanders are greatest.

Two-phase FAC locations with the greatest incidence of damage are deaerator shells followed by high pressure heater distillate drains, particularly following the level control valve when there is a large temperature and pressure differential between the source (feedwater heater) and destination (another heater or the condenser) of the drains.

Mild flashing can occur in heater drain lines upstream of the CV where the upstream heaters are not fitted with drains coolers and the elevation of the CV is higher than the liquid level in the upstream heater or where a high pressure drop occurs in the drain pipe.

Two-phase damage may be observed in alternate (high level or emergency) heater distillate drains when such drains are used frequently.

From international experience two-phase FAC damage in deaerators and feedwater heater shells is very common.






Revision: 2

Page: 18 of 83

A.2.1 Visual Appearance of FAC

The colour of surfaces is always a semi-accurate indicator of the local chemistry environment during service (in the case of AVT(O) and OT, a red-salmon pink protective oxide layer) and thus confirms whether FAC can occur. When the observed colour in deaerators is different than suggested by the feedwater chemistry results action should be taken to investigate and improve chemistry surveillance capabilities.

A.2.1.1FAC in Single-Phase Environments

Damage in single-phase environments is characterised by overlapping “horseshoe” pits that have a scalloped or orange peel appearance.

Figure 2 (a) shows a FAC failure of an economiser inlet header tube. The typical orange peel appearance of single-phase FAC is clearly evident on the inside tube surface.

Figure 2 (b) shows a close up view of the superficial damage of the above failure. The area towards the lower right of the image indicates minor FAC which is just initiating. In this area a series of pit like features are evident. In certain instances these pit like features (horseshoe pits or chevrons) have sharp arrow features pointing in the direction of flow. The directional features of these arrow shaped chevrons or horseshoe pits are established due to small turbulent effects and therefore localised increased mass transfer areas near and on the surface oxide causing dissolution of this oxide.

As the severity of FAC damage increases i.e. from bottom right to top left of Figure 2 (b) the chevron extent (density and depth) increases and begin to overlap until the surface resembles the continuous scalloped or orange peel appearance.

Analysis of the severely scalloped surface as shown in Figure 2 (c) indicates very little remaining oxide on the surface. In this particular case only a couple of microns. When the oxide layer (magnetite) is very thin the surface may appear to be metallic due to the almost transparent film or the surface may reflect hues of different colours due to the refraction of light through the magnetite.

Figure 2 (d) is a magnified image of the scalloped surface obtained by a Scanning Electron Microscope.

In many instances when the areas of FAC damage are first observed they often have an orange colour of flash rust. This is caused if exposed to moisture during the shutdown process and is indicative of the extremely thin oxide layer which is quickly corroded to produce orange corrosion product.

It is important to consider that in the case where the chemistry regime has changed over the years, from AVT (R) to AVT (O) or OT that surfaces previously affected in single-phase environments would now be covered by a sound Ferric Oxide Hydrate (red) oxide layer and would thus not be visually identified as areas having experienced material loss due to FAC. Thus a review of the historical chemistry for each unit (as described later in Appendix C) is required to assess the risk and accordingly define quantitative means of inspection. Screening and quantification NDT techniques are described later in Appendix C and Appendix D.






Revision: 2

Page: 19 of 83

FAC Appearance – In Single-Phase Environments

(a) Scalloped or orange peel surface characteristics of single-phase FAC. Failure occurred in economiser inlet header tube (EPRI - T. Gilchrist, 1991).

(c) Microscopic Image indicates an extremely thin – almost missing protective magnetite oxide layer i.e. less than 5 microns (EPRI)

(d) Single-phase FAC – Magnification of scalloped surface under Scanning Electron Microscope (EPRI)

Chevrons - resembling arrow shaped horseshoe pits.

(b) Chevrons “pointing” in the direction of flow. Flow direction is therefore from bottom left to top right (EPRI).

Figure 2: Typical visual appearance of (orange peel or scalloped) FAC damage in single-phase environments.

Flow Direction






Revision: 2

Page: 20 of 83

A.2.1.2 FAC in Two-Phase Environments

Typical locations have been described earlier in this guideline. Areas typically prone to two-phase FAC include HP & LP heater shells, deaerators, and HP and LP distillate drain lines. Locations with the greatest incidence of damage are deaerator shells followed by high pressure heater distillate drains, particularly following the level control valve when there is a large temperature and pressure differential between the source (feedwater heater) and destination (another heater or the condenser) of the drains.

The characteristic appearance of FAC in two-phase environments is described as follows:

One of the typical appearances of two-phase FAC is known as tiger striping. Figure 3 (a) shows alternate areas of metallic (severely corroded due to FAC) and black surfaces. In most instances the severely corroded areas will appear shiny black contrasted against a red (un-corroded) area.

In the case of deaerator storage tanks most of the surfaces are subject to single-phase flow and therefore not subjected to two-phase FAC. In units operating under oxidizing feedwater i.e. AVT (O) or OT the surfaces will be mostly protected by a red FeOOH oxide layer. However surfaces located close to piping such as distillate drain line entry points conveying fluid to the vessel may be subject to two-phase conditions due to the difference between the entering fluid and the bulk fluid in the vessel. The two-phase area of attack is usually black and shiny contrasted against the red protected areas - Figure 3(b).

Tray type deaerators shells are subject to two phase FAC/erosive attack due water and steam counter flow.

Figure.3 (c) clearly indicates that carbon steel weld overlay is not a long-term mitigation option for FAC. The weld overlay area was obviously previously thinned by FAC and continues to be an area of FAC (black and shiny).

Figure 3 (d) and (e) show an area of two-phase FAC on the shell side of the lowest LP heater on a unit operating on OT. The two-phase area is clearly defined by the red single-phase flow location protected by a FeOOH protective layer. The two-phase area which is black and shiny is where the two-phase fluid is striking the surface due to flashing of a cascading drain entry. A thin transition area of grey magnetite is visible between the red and black and shiny surfaces. In the case of units operating under reducing feedwater conditions AVT(R) protection is provided by magnetite and the protected surfaces will be mostly grey similar to the thin grey magnetite area in A.3 (e). The two-phase areas in AVT (R) will still be black and shiny.

FAC damage in two-phase environments often contains directional pit-like features which occasionally exhibit the chevron or horseshoe pit like indications as seen in single-phase FAC – Figure 3 (e).

Other examples of two-phase FAC damage experienced in Eskom Fossil plant is shown in Figure 3 (f-h).






Revision: 2

Page: 21 of 83

(a) FAC in Two-phase environments – Tiger Striping. (EPRI)

(b) Deaerator drain and fluid entries. Two-phase FAC (Black) and areas that are unaffected and protected by a (Red)

FeOOH oxide layer. (EPRI)

(c) Areas of a deaerator at a drain entry where previous (historic) carbon steel weld overlay was

applied – the weld overlay area is clearly still prone to continued FAC. (EPRI)

(d) Two-phase FAC in a deaerator. Area exposed to the single-phase environment is red while the two-phase area is black

and shiny. (EPRI)

(e) Close-up of (d). Note the thin area of grey magnetite between the shiny black and red

surfaces. The magnetite oxide layer still affording some degree of protection but where the protective

red FeOOH layer has been removed. (EPRI)






Revision: 2

Page: 22 of 83

(f) Two-phase FAC in a HP heater (Courtesy Duvha Power Station)

(g) Two-phase FAC in a HP heater (Courtesy Duvha Power Station)

(h) Two-phase FAC in a LP heater (Courtesy Duvha Power Station)

Figure 3: Typical visual appearance of FAC damage in two-phase environments.






Revision: 2

Page: 23 of 83

A.3 Factors and Variables affecting FAC

As mentioned previously the rate of FAC depends on a complex interplay of factors, the detailed explanation of each of these are outside the scope of this document. However, it is considered important that the reader be aware of the basics of these parameters in order to be able to evaluate each of these in the compilation of an inspection scope of work.

A.3.1 Feedwater Chemistry - Dissolved Oxygen and Oxidising/Reducing Potential

This factor is related to whether the chemical environment is either reducing or oxidizing. Eskom has adopted OT at stations with condensate polishing plants and AVT(O) at stations with partial or no condensate polishing. With oxidizing all-volatile treatment, AVT(O), only ammonia is added to the feedwater.

With AVT(O), an oxidizing environment exists and carbon steel surfaces grow a protective layer of ferric oxide hydrate which is several orders of magnitude less soluble than magnetite. Carbon steel components are very resistant to single-phase FAC when the feedwater treatment is AVT(O) but this particular treatment is limited to units with all ferrous feedwater systems.

The practice of oxygen dosing in combination with treatment to control pH is termed oxygenated treatment, OT. This treatment is used in all-ferrous once-through and drum units in Eskom that meet the criteria to allow use of OT. With OT, the oxidizing environment is even stronger than with AVT(O). The protective ferric oxide hydrate layer formed under OT chemistry prevents carbon steel damage in FAC in single-phase environments.

It is important to note that although Eskom adopted AVT(O) and OT in the early to mid 90’s in a fair number of stations, units had experienced a significant period of operation under AVT(R). Particularly the older units had operated for many years with AVT(R) before converting to AVT(O). It is therefore important to consider “high risk” single-phase areas which may visually appear to be undamaged now but may have accumulated damaged during the AVT (R) era of operation.

Reducing all-volatile treatment, AVT(R), is a treatment in which ammonia is used to control pH and a reducing agent is applied to establish a reducing environment. The oxide formed to protect carbon steel surfaces is magnetite, which is quite soluble at temperatures present in the feedwater system. This treatment should only be used in cycles with mixed-metallurgy to establish a reducing potential as is needed to protect the surface oxide layer formed on copper alloys. AVT(R) should not be used in all-ferrous units since the reducing environment increases the solubility of magnetite. AVT(R) was the treatment regime of choice when stations were first commissioned.

1. High FAC (Fe > 2-5 ppb – measured at EI) may be prevalent when the ORP << 0mV (low oxygen with a scavenger), or where AVT(O) or OT is not optimized.

2. Low to negligible FAC (Fe < 2ppb – measured at EI) should be prevalent when ORP > 0mV (oxygen and/or no scavenger).

3. In the case of the feedwater chemistry control at Eskom fossil fired plants with all ferrous systems downstream of the condenser dissolved oxygen is the determining factor since oxygen scavengers are no longer used. For mixed metallurgy systems, the use of carbohydrazide or the use of amines must be evaluated for feedwater chemistry control.

4. Corrosion of feedwater system materials is influenced by the electrochemical potential (establishment of a reducing or oxidizing environment) and pH of the feedwater. In single-phase FAC,






Revision: 2

Page: 24 of 83

potential (ORP) is the key parameter. Note that this statement is for explanatory purposes – Eskom do not use ORP as a chemical parameter for monitoring of OT or AVT(O) or FAC.

5. The reader should consider that although Eskom’s feedwater/cycle chemistry standard is based on AVT(O) and OT certain areas of the feedwater circuit may be slightly more or less oxidizing or reducing, not necessarily because of improper control but because of depletion of dissolved oxygen in parts of the cycle i.e. drain lines to deaerator.

6. It is important to note that operational philosophy (Load Cycling) can affect the dissolved oxygen content in parts of the feedwater system and hence the passivation potential against FAC. See Table 1

A.3.2 Feedwater Chemistry - pH

1. pH is important in that it influences the solubility of the protective magnetite layer on mild steel.

2. A higher pH reduces FAC.

3. Low pH conditions increase FAC in single-phase environments in stations operating on AVT(O) and FAC in two-phase environments for all operating regimes. In many cases, increasing the pH (up to 9.8) can reduce the damage while use of chromium containing materials (>1.25% nominal Cr content) can eliminate it.

4. For a given environment, pH decreases with increasing temperature.

5. It is important to note that operational philosophy (Load Cycling) can affect pH. See Table 1

A.3.3 Temperature

1. Temperature influences several variables such as density, kinematic viscosity, diffusion coefficient, pH at operating temperature, etc.

2. Temperature affects the formation and solubility of the oxide layer.

3. At lower temperatures, the magnetite layer forms very slowly with subsequent low dissolution and wear rates. Low to negligible FAC occurs in single-phase environments where temperatures are below 90ºC.

4. At “medium” temperatures (140 – 150ºC) the magnetite layer is porous and irregular, the oxidation process results in more rapid dissolution of the magnetite layer.

5. At high temperatures (200 - 250ºC), the magnetite is dense and regular-with subsequent lower dissolution and wear rates.

6. It is important to note that operational philosophy (Load Cycling) can affect temperature, see Table 1

A.3.4 Material Composition

1. The solubility of iron oxides in pure water reduces drastically with the presence of chromium in particular and molybdenum and copper to a lesser degree in the pipe – equipment material.

2. FAC rates are reduced significantly with even trace amounts (1%) of chromium. The minimum amount of chromium recommended for material replacement is 1.25% nominal content.

3. Stainless steels are immune to FAC.






Revision: 2

Page: 25 of 83

4. Material replacement (with a higher content chromium material) is considered a key FAC mitigation strategy in two-phase FAC situations.

A.3.5 Fluid Hydrodynamics – Velocity, Mass Transfer, Geometry and Steam Quality

1. Mass transfer coefficient is a function of localised fluid flow velocity (largely dependent on geometry factors), void fraction (steam quality) and pipe diameter. The mass transfer coefficient directly affects the FAC rate.

2. FAC occurs where there is a change in geometry, associated with an increase in the localised mass transfer coefficient such as elbows, tees, downstream of flow control orifices, flow control valves, isolating valves, backing rings, reducers, expanders, fabrication discontinuities and welds.

3. Local turbulence increases the mass transfer compared to smooth flow in a straight pipe.

A.4 Load Cycling and its Impact on FAC

1. Load cycling affects many of the susceptible systems by changing temperature, flow rates, dissolved oxygen, steam quality, in some instances pH and equipment flow paths.

2. The effects of Load Cycling are both system and plant specific.

3. Table 1 below discusses the impacts of a “typical” fossil fired plant utilising reheated steam.






Revision: 2

Page: 26 of 83

Table 1: Load Cycling and the impact on FAC – “Typical” fossil plant utilizing reheated steam. (Courtesy EPRI)

System Load

(%)

Temp

(ºC)

Flow

(Factor)

Possible Impact on the Propensity and Rate of FAC

Feedwater System

100 246 1.0 1) Although pH should be constant, it may vary due to under or over-dosing of ammonia into the system.

2) Low loads may also result in one heater train being taken out-of-service. Different heater trains may therefore experience differences in operating hours and therefore variance with regards exposure and overall FAC rate.

3) FAC rate increase due to temperature change can be far greater than decrease due to increased pH from lower temperature and lower flow. Temperature being the dominant factor due to the system approaching the peak FAC rate at 150 ºC.

4) The effect of reduced load on FAC feedwater is plant specific, increasing the FAC in some components and decreasing in others.

75 226 0.7

50 205 0.45

Attemperator system

100 166 1.0 1) Reduced temperature can increase or decrease FAC depending on specifics.

2) Lower flow rates and resulting lower fluid velocities and mass transfer will reduce FAC.

75 154 0.7

50 138 0.45

Condensate System

100 121 1.0 1) Both lower temperatures and flow rates will reduce FAC.

75 99 0.7

50 94 0.5

HP Heater Drains

100 215 1.0 1) FAC tends to increase due to decreasing temperature. Temperature being the dominant factor due to the system approaching the peak FAC rate at 150 ºC

2) FAC tends to decrease due to decreasing flow.

3) May have increased oxygen at reduced load.

4) May have flashing in HP drains during load reductions with the result of two-phase conditions.

5) Overall effect is site specific.

75 199 0.65

50 177 0.35

LP Heater Drains

100 63 1.0 1) FAC tends to decrease with decreasing temperature.

2) FAC rate tends to decrease with decreasing flow.

3) May have increased oxygen at reduced load.

4) May have flashing in LP drains during load reductions.

5) FAC tends to decrease at reduced load.

75 57 0.6

50 49 0.25

HP and IP extraction steam lines Normally superheated (dry steam/no fluid phase) at all loads and therefore not susceptible to FAC.

LP extraction lines May be two-phase, reduced load may negatively affect steam quality.

Auxiliary steam system These systems are often two-phase systems and can be FAC susceptible but typically more susceptible to Erosive Attack. In general reduced load reduces FAC.

Boiler Blow-down Can operate intermittently. Blow-downs tend to be more frequent with cycling. These systems typically more susceptible to Erosive Attack rather than FAC.






Revision: 2

Page: 27 of 83

APPENDIX B: OVERVIEW OF EROSIVE MECHANISMS

B.1 Overview of Erosive Mechanisms

B.1.1 Cavitation Erosion

B.1.2 Flashing Erosion

B.1.3 Droplet Impingement or Liquid Impingement Erosion (LIE)

B.2 Solid Particle Erosion

B.3 Differences between Erosive Attack and FAC

B.3.1 Predictability

B.3.2 Water Chemistry

B.3.3 Kinetics

B.3.4 Material Considerations






Revision: 2

Page: 28 of 83

B.1 Overview of Erosive Mechanisms

This Appendix provides an overview of erosive attack mechanisms in order to illustrate the differences and similarities with FAC. It is beyond the scope of this guideline document to detail the in depth aspects of “Erosive Attack” mechanisms. Should “Erosive Attack” be suspected or detected then it is recommended that the appropriate materials specialist in RT&D be contacted for further advice or – the reader is advised to consult the source literature for this Appendix “Interim Recommendations for an Effective Program against Erosive Attack, 1015071, Technical Update, December 2007.

The first evaluation task in the identification of “Erosive Attack” as part of the FAC programme is to identify all piping systems, or portions of systems, that could be susceptible to attack. Similarly to FAC, Erosive Attack is known to occur in piping systems containing flowing water or wet steam. All such systems should be considered susceptible to erosion.

The plant line list and/or the Piping and Instrumentation Drawings (P&IDs) should be reviewed to ensure that all potentially susceptible systems are included in the program. In addition interviews with plant operators, maintenance personnel are useful to identify how lines and systems are actually being used (or have been used) in the various plant operating modes. Guidelines for such interviews can be found in the reference document.

Some susceptible systems, or portions of systems, can be excluded from further evaluation due to their relatively low level of susceptibility. Based on laboratory and plant experience, referenced in the source literature, the following systems can be safely excluded from further evaluation, as follows:

Superheated steam systems, or portions of systems with no moisture content, regardless of temperature or pressure levels. However, drains, traps, and other potentially high-moisture content lines from superheated steam systems should not be excluded, Further, experience has shown that some systems and equipment designed to operate under superheated conditions may actually be operating with some moisture in off-normal or reduced power level conditions, or when upstream equipment is no longer operating as designed. Care should be exercised not to exclude such systems. The boundary interface for FAC/erosion consideration should be the stub connection to the main line.

Systems or portions of systems with no flow, or those that operate less than 2% of plant operating time (low operating time). Caution—if the actual operating conditions of the system cannot be confirmed (e.g., leaking valve), or if the service is especially severe (e.g., flashing flow), that system should not be excluded from evaluation based on operating time alone. Balancing lines between normally flowing lines should not be excluded based on this criterion.

Care should be taken not to exclude piping downstream of leaking valves or malfunctioning steam traps. Leaking valves and steam traps can be identified using means such as infrared thermography or thermocouples, often performed as part of a plant thermal performance evaluation.

It is recommended that the Susceptibility Analysis identify the systems, or portions of systems excluded from the FAC/Erosive Attack program and the basis for their exclusion. This analysis should be appropriately documented and reviewed.

Systems, or portions of systems, should not be excluded from evaluation based on low pressure. Pressure does not affect the level of erosive wear. Pressure only affects the level of consequence should a failure occur. A failure in a low-pressure system could have significant consequences (e.g., failure in a low-pressure extraction line), but in most cases for lines / vessels operating under vacuum, the line might implode before it would explode/rupture. In addition arbitrary ranges of velocity or other operating conditions should not be used to exclude a system from evaluation.






Revision: 2

Page: 29 of 83

The four erosive mechanisms under discussion can be divided into two categories, as follows:

Pressure drop related - Cavitation erosion, flashing erosion, and droplet impingement or liquid impingement erosion (LIE)

Particle related - Solid particle erosion (SPE)

B.1.1 Cavitation Erosion

Erosion due to cavitation can occur when there is a flowing liquid stream that experiences a drop in pressure followed by a pressure recovery. Such a pressure drop (i.e., the difference between the upstream pressure and the downstream pressure) can occur in orifices or valve internals where the flow accelerates through a small cross sectional area. As the fluid moves through the restricted area, the fluid velocity increases while the pressure is decreased.

If the local pressure passes below the vapour pressure at the liquid temperature, then small bubbles are formed. When the downstream pressure rises above the vapour pressure, these bubbles collapse. The collapse of the bubbles causes high local pressures and very high local water jet velocities. If the collapsing bubbles are close enough to a solid surface then damage to that surface will result.

The collapse of the numerous bubbles generates noise and vibration. Often, cavitation causes most of its damage with vibration. The erosion caused by cavitation also generates particles that will contaminate the process fluid. Cavitation has caused leaks and piping/piping component thinning in power plants and damage to the internals of valves. An unsuitable valve (i.e., one that is cavitating) may result in vibration of the valve internals. These vibrations contribute to the noise generated and also cause loosening of parts and mechanical fatigue of valve components or attached piping. In addition to noise, vibration and physical damage, cavitation will also alter the hydraulic characteristics of the pipeline by increasing the resistance in the cavitating region.

Piping in power plants is prone to cavitation normally in water-filled lines containing valves or orifices having a high-pressure drop. The presence of noise indicates that cavitation is occurring, however this does not necessarily mean that damage is occurring. The noise is caused by the collapse of the steam bubbles. Damage of surfaces occurs when the bubbles collapse near to that surface. The absence of noise indicates that cavitation and cavitation erosion are not occurring in a given valve/orifice etc.

Table 2: Cavitation Regimes with Typical Noise Levels for Standard Trim Valves

Table extract courtesy “Interim Recommendations for an Effective Program against Erosive Attack, 1015071, Technical Update, December 2007.






Revision: 2

Page: 30 of 83

Most cavitation problems in power plants are caused by either:

Valves improperly sized for a given application, or

Improper operation (most often throttling) of properly sized valves, or

Improper types of valves being used to control flow (e.g., butterfly valves).

Normally the damage caused by cavitation is rapid and localized. The damaged surface is usually very rough and irregular.

Figure 4: Cavitation Damage in the Body of a Plug Valve

a. Cavitation can also occur in orifices, particularly those used to reduce pressure. The cavitation regimes Table 2) used for valves also applies to describe the degree of cavitation in orifices, and similar prediction methods are used.

b. Since, the geometry of a sharp edge orifice is well defined; studies of the damage location with downstream distance have shown that “roughly” the peak damage occurs at about 1.1 diameters downstream of the orifice although this distance does depend on the degree of cavitation experienced.

Although less common cavitation erosion can also occur in other piping components such as elbows and tees. This behaviour most often occurs at low pressures (below those encountered in power plant steam-feedwater systems).

The following guidance is provided to screen valves for cavitation:

Examine valve maintenance records for valves that have experienced excessive maintenance to the valve internals or to the valve operators. Cavitation-induced vibration may cause damage to the valve operators as well as to the valve internals.

Interview plant operating and maintenance personnel about noisy valves or valves that have caused vibration-related problems in valve, valve operator, or connected piping.






Revision: 2

Page: 31 of 83

Examine the operation of all operating valves. Of particular concern are valves used for controlling flow (i.e., throttling service), which were not specifically designed for this purpose.

Perform screening calculations employing the methodology as presented (in Appendix C of the referenced document).

B.1.2 Flashing Erosion

Flashing occurs when a high-pressure liquid flows through a valve or an orifice to a region of considerably reduced pressure. Some of the liquid will spontaneously convert to steam if the pressure drops below the vapour pressure. The downstream velocity will be significantly increased due to a much lower average density of the two-phase mixture. The impact of the high-velocity liquid on piping or components creates flashing damage.

During flashing the flow may be choked i.e. the maximum possible flow is passing through the restriction at the given upstream pressure. This regime is also known as supercavitation. Increasing the upstream pressure is the only way of increasing the flow.

Researchers have estimated that at a 1% steam quality, an average velocity of 30 m/s would be expected. This average velocity would increase to about 60 m/s if the quality reached 3.5%. These high velocities combined with the presence of slug or plug flow regimes in the downstream piping may result in large pipe movement with resultant high stress levels. In addition to erosion, flashing will result in unstable, chaotic conditions in the downstream piping which may induce harmful vibrations, and can cause the onset of water hammer.

It should be noted that in cavitation, the downstream pressure is normally above the local vapour pressure so that the bubbles collapse. In the case of flashing the pressure is below the local vapour pressure so that the bubbles do not collapse and are transported downstream.

There are ways of preventing cavitation from occurring (e.g., changing the design of the control valve), however if the downstream pressure is below the vapour pressure of the incoming stream, then flashing will occur regardless. Damage due to flashing can be found in and downstream of pressure-reducing valves. The form of the damage is usually referred to as “smooth” or “polished”. The appearance is often compared to a fine sand blasted surface although in some material the surface may be even smoother.”

Figure 5: Cavitation Damage in the Body of a Plug Valve






Revision: 2

Page: 32 of 83

Typically valve manufacturers install erosion resistant materials in valves expected to be in severe service downstream of the most restricted part of the valve.

Flashing damage is found in liquid-filled lines where the pressure drop is sufficient in magnitude to generate vapour. The following are the most common areas:

In and downstream of valves or orifices returning fluid to the condenser. Lines returning fluid to the condenser include normally operating valves, emergency valves, and leaking valves. All of these are capable of generating sufficient velocity to cause material damage.

Downstream of level control valves in cascading drain systems.

Distillate drains entering the DA.

The referenced literature provides guidance with respect to calculating whether flashing damage may be possible. For properly operating valves, the procedure used to determine if flashing damage may be occurring is by comparing the downstream pressure with the saturation pressure corresponding to the fluid temperature. This can be accomplished by means of a hydraulic study, using models such as FLOWNEX, to determine the flow regime of the specific line. This procedure can be applied to all operating valves including those suspected of leaking.

B.1.3 Droplet Impingement or Liquid Impingement Erosion (LIE)

LIE or droplet impingement is caused by the impact of high velocity droplets or liquid jets. LIE normally occurs when a two-phase stream experiences a high-pressure drop (e.g., across an orifice in a line to the condenser). In this situation there is an acceleration of both phases with the liquid velocity increasing to the point that, if the liquid strikes a metallic surface, the surface will be damaged. The main distinction between flashing and LIE is that in flashing the fluid is low quality (mostly liquid with some steam), whereas with LIE, the fluid is high quality (mostly steam with some liquid). The most prevalent area in which LIE occurs is steam turbine internals, typically materials which are high alloy steels and more exotic materials.

Figure 6: LIE damage on a turbine blade together with a sample from a laboratory test.

In contrast to flashing damage, surfaces damaged by LIE are normally very rough and cratered.






Revision: 2

Page: 33 of 83

LIE damage can occur in lines containing high quality two-phase conditions that experience a large pressure drop, such as warming drains on main/reheat steam lines, this could also occur in areas downstream of valves or steam traps that have failed open, and other similar situations.

B.2 Solid Particle Erosion

Solid particle erosion (SPE) differs from the three previous mechanisms described above in that it is damage caused by particles transported by the fluid stream rather than by liquid water or collapsing bubbles.

In situations where hard, large particles are present at sufficiently high velocities, damage will occur. In contrast to LIE the necessary velocities for SPE are quite low i.e. 1 metre per second. The surfaces damaged by SPE can exhibit a very variable morphology.

Features of SPE in service usually include:

wall thinning of components

macroscopic exhibit a scooped appearance following the gas/particle flow field

surface roughening (ranging from polishing to severe roughening, depending on particle size and velocity)

lack of the directional grooving characteristics of abrasion

in isolated instances the formation of rippled patterns on metallic surfaces

Steam turbines are a particular area of damage in fossil power plants. In this particular scenario the particles have been found to be corrosion products from the upstream heat exchanger surfaces that have exfoliated and been transported downstream.

SPE has been found to cause leaks as well as damage to valve internals.

Figure 7: SPE damage of a valve internals stem

SPE and LIE appear to be similar but are in fact quite different. Although both involve the impact of small, discrete bodies the damage mechanisms, the effects of impact variables, and the response of materials are all quite different.

The variables affecting SPE are as follows:






Revision: 2

Page: 34 of 83

Impingement Variables i.e. – particle velocity, angle of incidence, particle concentration, particle rotational speed.

Particle Variables i.e. – particle shape, size, hardness, and friability (i.e., the ease of fracture).

Material Variables i.e. – hardness, work hardening behaviour and microstructure.

Damage due to SPE is more likely to occur in lines from the boiler or other heat exchangers in which exfoliated oxides or corrosion products are transported.

Table 3: Summary of the four types of erosive attack mechanisms discussed above.


B.3 Differences between Erosive Attack and FAC

A distinguishing characteristic of damage caused by FAC is the widespread nature of the attack which can ultimately result in a catastrophic failure of the thinned component or piping.

In comparison, erosive attack mechanisms tend to be more localized. Damage normally manifests itself as locally thinned or perforated areas. Both FAC and erosion can damage piping and equipment and understanding the differences in behaviour between these mechanisms is important in implementing the appropriate inspection and repair approaches.

Significant differences can be discussed according to the following:

Predictability

Water chemistry

Kinetics

Material considerations

Extent of degradation

As discussed previously the differences between solid particle erosion (SPE) and the other three pressure drop mechanisms should also be considered.






Revision: 2

Page: 35 of 83

B.3.1 Predictability

According to the literature source one of the features that distinguish FAC from other corrosion mechanisms is its predictability. There are models that can predict the rate of FAC under a given set of circumstances to about ±50%. However, generally models for the various types of erosion are nowhere near as accurate.

B.3.2 Water Chemistry

From Appendix A it is clear that water chemistry (particularly pH and dissolved oxygen) greatly affect the rate of FAC. Water chemistry is not a significant consideration in erosive attack. In erosive attack mechanisms water chemistry variations may be safely ignored. While water chemistry is not important, SPE is greatly influenced by the size, shape, composition and concentration of the particles contained in the water.

B.3.3 Kinetics

Generally (disregarding some second order influences), the rate of FAC is considered to be linear with time. SPE is also considered to display linear kinetics.

In contrast cavitation erosion and liquid impingement erosion display non-linear kinetics. The referenced literature claims no known description of the kinetics of flashing erosion but it is estimated that the kinetics are more likely to be non-linear than linear.

Figure 8: Schematic of the rate of damage for cavitation or liquid impact erosion


An important consideration in non-linear Kinetics is the fact that not only does the rate vary with time, but there is an incubation period during which there is no apparent damage to the surface. In summary, cavitation and liquid impact erosion (and probably flashing erosion as well) are more difficult to model than FAC and SPE due to their non-linear behaviour.






Revision: 2

Page: 36 of 83

B.3.4 Material Considerations

The influence of alloying on steels for FAC has been discussed in Appendix A. Small amounts of chromium will reduce the rate of FAC. Chromium concentrations of greater than about 1.25% effectively eliminate FAC. However, the behaviour of materials under erosive conditions is more complex. From a materials viewpoint the behaviour of the three pressure-drop related mechanisms will be considered separately from SPE.

The following information provides insight into the relative resistance of materials for the “Pressure Drop” related mechanisms:

Figure 9: Normalized Cavitation or Impingement Erosion Resistance of Common Materials Normalized to SS 316.






Revision: 2

Page: 37 of 83

Figure 10: Erosion Resistance of Stainless Steels, Carbon Steel and Inconel.

The selection of replacement material requires consideration of a number of factors. It is beyond the scope of this guideline Appendix to discuss this aspect in suitable depth. It is recommended that the source literature be consulted and/or the appropriate material specialist in RT&D be contacted for advice in terms of:

Availability – can the material be procured in time to meet the requirements?

Joinability – can the material be welded or fabricated to meet the design?

Code Issues – is material approved for use in the proposed application?

As discussed previously, SPE has unique considerations due to the fact that all the other erosion mechanisms considered showed a non-linear relationship of erosion rate with time. In the case of SPE, the rate of damage is typically linear with time. In addition, while the erosion resistance to cavitation varies over several orders of magnitude the resistance of all metals to SPE may be quite similar. As discussed previously it must be emphasised that the sensitivity of materials to damage to SPE depends on such variables as the flow velocity, the particle composition, etc.

Figure 11: Resistance of Selected Metals to Solid Particle Erosion.






Revision: 2

Page: 38 of 83

The following should be noted:

The scale of the resistance is linear, not logarithmic as was the case in Figure 9

The resistances of the materials are quite close together. There is less than a factor of two difference for the materials considered.

The “hard materials” (e.g., the Stellites) offered only modest improvement over carbon steel.

The Inconels and Incoloy offered only a very modest improvement over carbon steel.

It is therefore fairly safe to conclude that unless exotic materials are used (i.e., ceramics), there is no materials solution to SPE for the systems of interest.

Another aspect that should be considered in the mitigation/prevention of “Erosive Attack” is Design Options – refer to the source literature for more detail.






Revision: 2

Page: 39 of 83

APPENDIX C: METHODOLOGY AND REMEDIAL ACTIONS

METHODOLOGY FOR THE INSPECTION, DETECTION, QUANTIFICATION OF FAC DAMAGE (INCLUSIVE OF “EROSIVE ATTACK”) AND REMEDIAL ACTIONS

C.1 Flow Accelerated Corrosion Management Programme

C.1.1 Step 1 - Development of a station specific FAC Programme

C.1.2 Step 2 “Generic Scope of Work” - Review of susceptible systems, design data (including installed piping component wall thickness [WT]), operational parameters, drawings and materials experience.

C.1.3 Step 3 - Review Cycle Chemistry experience and results

C.1.4 Step 4 - “Unit/Outage Specific Scope of Work” - Identify susceptible systems, lines and locations - prioritise locations for inspection

C.1.5 Step 5 – Initial NDE Inspection (Screening)

C.1.6 Step 6 – Quantification of wall thinning/material loss by appropriate NDE technique. If required - material confirmation by appropriate analytical technique

C.1.7 Step 7 – Decision-making for immediate repairs/replacement OR future management based on remaining WT, FAC rate and time to next inspection

C.1.8 Step 8 – Recommendations (Post-outage) for future inspection and test requirements, plant modifications, revision of operating and maintenance processes and procedures and record keeping

C.1.9 Step 9 – Optimise Cycle Chemistry

C.2 Document Management & Programme Benchmarking Methodology for the Inspection, Detection, Quantification of FAC Damage (inclusive of “Erosive Attack”) and Remedial Actions






Revision: 2

Page: 40 of 83

C.1 Flow Accelerated Corrosion Management Programme

The programme is illustrated in Figure 12 – Flow Diagram. It consists of 9 steps. The 9 steps, with advisory information and points for consideration for each are as follows:

C.1.1 Step 1 - Development of a station specific FAC Programme

Systems and locations that are susceptible to FAC and erosive attack in Eskom fossil power plants include all carbon steel systems and components in the feedwater/boiler circuit that convey water and water/steam mixtures up to temperatures of ± 300 ºC.

As mentioned previously it is important to note that the potential for FAC is not limited to only feedwater systems but can occur in areas of other plant such as the feedheating and boiler plant. It is therefore crucial that all necessary departments and engineering functions and disciplines be involved in the FAC Management Programme.

The information in this guideline document is advisory in nature; it would not be practical or feasible to encompass specific or site specific conditions or situations. Ultimately, site specific FAC Corrosion Management Programmes should be implemented for each site and if necessary each unit.

C.1.2 Step 2 “Generic Scope of Work” - Review of susceptible systems, design data (including installed piping component wall thickness [WT]), operational parameters, drawings and materials experience.

1. Obtain and review design drawings (typically dimensioned isometrics) in conjunction with plant heat balance diagrams and flow diagrams (P&IDs) for the purpose of populating the relevant information into a table as per the example Scope of Work template in Table 4 The following should be noted when populating the example template:

“Item as marked up on drawing” - requires that the component be numbered, the number clearly cross referenced on the Isometric drawing. The Isometric drawing to indicate the flow direction. The Isometric drawings are considered to form part of the Scope of Work.

“Material” – it is important to note that the material could be component specific and should not be assumed to be uniform for a pipe system. If there is any discrepancy or doubt with respect to material composition (especially when it involves “high” chromium) then this should be reflected in the template and where required confirmed/verified as discussed later in this Guideline. In the event that stress calculations are later required it is important that the grade of material is known – refer to later Step 7 for guidance.

“Velocity” – is calculated from the input values in the “Design Information” and “Piping Dimensions” fields.

“Operating Temperature and Pressure” – refers to the operating temperature of the pipe as indicated on the heat balance diagram. It is important to note the risk of using the pipe design temperature (for determining FAC susceptibility) may result in the steam condition being superheated while in reality it is wet.

It is advisable to add “Design Temperature and Pressure” columns to the spreadsheet. Design pressure and temperature are required as input parameters for the purpose of performing stress calculations should these be required.

Installed Wall Thickness” – refers to the installed wall thickness as indicated on the isometric drawing or Piping Schedule/Code List.






Revision: 2

Page: 41 of 83

“ID (mm)” – is calculated from the input values in the “Piping Dimensions – (Isometric)” fields. It is important to note that thick walled (typically feed water pipes) are non-scheduled pipework and specifically dimensionally designed for application. In these cases ID must be entered directly from the drawing and not be calculated.

It is advisable to add “Bend Radius”, “Circumference or OD” and “Actual Installed wall thickness (Max)” columns to the spreadsheet under the “Piping Dimensions – (Actual/Measured) field. All these parameters are required for the purpose of performing stress calculations should these be required, for the scheduled pipes these values can be found in the relevant pipe code and thus need not to be measured on site. The addition of the “Actual Installed wall thickness (Max)” column is recommended specifically for situations where there is doubtful or missing piping system information from Isometric drawings and is intended to reflect the (Maximum) value from the NDT UT and/or an estimated installed wall thickness from appropriate Piping Schedule tables based on the information obtained in the “Circumference or OD” column. It is recommended that as inspections proceed (either visual or UT) in all cases actual piping (OD/Circumference) shall be measured for input into the “Measured Circumference or OD” column for the respective component.

“NDT Wall Thickness Grid Pattern” – is guideline information with respect to the minimum grid sizing for a component and is calculated from (π multiplied with OD)/12. It is recommended that more detailed recommendations concerning grid sizing be obtained in Appendix D.

“Flow Condition” – refers to phase condition i.e. two-phase (1), saturated (2) or compressed liquid or superheated (3). Depending on the phase condition the number input is from 1 – 3.

“Component Classification” – refers to piping location according to whether flashing is expected to occur as follows:

Input (1): Pressure reducing devices (e.g. Flow regulating valve, control valve, orifice) including immediate downstream pipe

Any of the following components and immediately adjacent downstream pipework of these components (e.g. reducers, diffusers, pipe dimension changes, bends, T-pieces, valves etc.) in particular if these components are positioned downstream of the pressure reducing device, i.e. subjected to two-phase flow.

Vessels

High turbulent areas such as pump diffusers

Input (2): Bends, T-pieces, isolating valves etc. upstream of pressure reducing devices in particular if the fluid is sub-cooled. Please note that this classification requires specific review (case by case basis). It is subject to flow characteristics, plant configuration, etc.

LP Cross-overs on non reheat stations

Input (3): Compressed liquid or superheated e.g. (Condensate, Feedwater, Economiser inlet header, Spray or attemperator water, HP & IP extraction, Cross-overs on reheat stations.

“Measured chromium content” – In terms of susceptibility to FAC all material should be regarded as carbon steel until confirmed/verified by means of analysis (PMI). Do not rely on drawings, modifications reports, anecdotal site reports etc. The input values are (1) for <0.25% Cr, (2) for 0.25%<Cr<2% (3) >2% Cr.






Revision: 2

Page: 42 of 83

“Risk Factor” – Is calculated by multiplying the input values in the “Risk Ratings” field. The intention is to provide a means of providing a simple “tool” to enable sorting of high risk areas/components. The lower number the more severe the risk. This column can be used as a guide to identify high risk components and may be used to give an indication in terms of inspection prioritisation. The “Risk Factor” should only be used for systems, components and locations not covered under C.1.4 Step 4 – Point 1. The systems and locations described in C.1.4 Step 4 – Point 1 have been rated according to a much more stringent process on a power station/unit specific basis.

All sites have compiled first revisions of the above. The SOW templates, associated isometric drawings and heat balance diagrams are available at – hyperlink http://hyperwave.eskom.co.za/0x936e3246_0x0238f25f

In addition to point 1 above consider and apply points 2 - 13 below in order to in future supplement/expand and revise the information in the “Generic Scope of Work” template as required.

2. Obtain all as built changes, plant modifications and replacements, historical system operation, passed inspection data, and records of prior leaks and failures.

3. Identify and document all the feedwater materials in all systems i.e. piping, piping components, valves, orifices, heater tubes and shell into the “Generic Scope of Work” document (excel based SOW). The SOW template shall be updated to accurately reflect the status with respect to component material replacement where chromium containing materials have been used.

4. Obtain the installed piping component wall thickness from piping schedules or isometric drawings.

5. Identify susceptible systems by careful consideration of the Factors and Variables affecting FAC as discussed in Appendix A.3 and A.4.

6. Identify susceptible systems by careful consideration of the Factors and Variables affecting Erosive Attack mechanism as discussed in Appendix B.

7. If possible, eliminate low FAC and Erosive Attack susceptible systems as per the example template in Table 5. It is advisable that stations compile and update a “Database of systems excluded from evaluation” for input and consideration complementing the RBI process. The list should note the basis for the system exclusion. This list should be documented and periodically reviewed. Systems should not be excluded from evaluation based on low pressure (absolute pressure i.e. lowest LP heater). Pressure does not affect the level of FAC wear. Pressure only affects the level of consequence should a failure occur.

8. In the AVT(O) and OT stations where single-phase locations with suspected damage due to previous AVT(R) are found to be undamaged and/or still within acceptable wall thickness limits as quantified by UT measurements then these may be excluded from future inspection as long as chemistry parameters are maintained according to Eskom Chemistry Standards [6]. However it is strongly recommended that in the cases where Cycle Chemistry Parameter Excursions have and continue to take place in the Feedwater systems then single-phase locations cannot be excluded from future inspection.

9. If there is any discrepancy, doubt etc. in terms of material composition of components i.e. “high chromium” then these components cannot be excluded as per point 7 above. These components should (if classified as high priority inspection areas) be identified for material analysis using field equipment, Positive Material Identification (PMI) or removing filings for laboratory analysis. Exclusion from inspection can only be considered if “high” chromium material (>1.25%) is confirmed. Refer to Appendix D for guidance on PMI.

http://hyperwave.eskom.co.za/0x936e3246_0x0238f25f






Revision: 2

Page: 43 of 83

10. Note that systems excluded purely in terms of FAC risk could still be susceptible to damage from other corrosion or degradation mechanisms such as cavitation erosion, liquid impingement erosion, etc.

11. Typically systems such as emergency or alternate drains are excluded if used less than 5% of time. Start–up and leak-off systems.

12. Systems used on start-up (warming lines, leak off) may be excluded from FAC inspection listing but may need to be considered due to other possible wall thinning mechanisms.

13. (If applicable) – include in the review, past inspection data such as wall thickness readings, inspection date, UT measurements, grid size and orientation.

C.1.3 Step 3 - Review Cycle Chemistry experience and results

1. Monitor suspended iron levels using online filters to provide indications of iron transport and therefore FAC in the feedwater system. Results from this monitoring should be used in the review to at least provide qualitative information as to the possible extent of FAC. Iron must be monitored using a corrosion product sampler at the economizer inlet and in the HP & LP distillate drains but can also be measured at the Condensate polishing plant inlet, condensate, deaerator inlet, deaerator outlet, and HP distillate into deaerator. This would allow characterisation of the origin of corrosion products and facilitate targeted chemistry treatment responses. Note that specialised vacuum pumping equipment is required where a distillate drain line is under vacuum.

2. Review historical records of feedwater treatment and chemistry. i.e. type of regime applied with timelines, duration, iron levels, oxygen and pH levels, air ingress in Condensate and Feedwater systems, position of deaerator vents and HP and LP heater vents, location of oxygen dosing point for units on OT. It is a requirement that the station chemists and PEIC Chemistry specialists provide trending information with respect to the nature, extent and overall duration of chemical parameter excursions experienced in the single phase system as well distillate CPS samplers since the last inspection. Review of this information is required to recommend whether repeated inspection of single phase locations is required or not in the next planned inspection opportunity. Historic high-level information of Chemical Parameter Excursions are available at hyperlink – http://hyperwave.eskom.co.za/0x936e3246 0x05e7b679

3. Use engineering judgement of the available information to carefully consider the Factors and Variables affecting FAC as discussed in Appendix A.3 and A.4.

C.1.4 Step 4 - “Unit/Outage Specific Scope of Work” - Identify susceptible systems, lines and locations - prioritise locations for inspection

Using the information obtained in Steps 2 and 3 i.e. heat and flow balances, materials, temperature and cycle chemistry develop the interfacial science currently and historically throughout the feedwater system. Identify single and two-phase locations and prioritise them. This step has been completed for all fossil sites the results available at hyperlink - http://hyperwave.eskom.co.za/0x936e3246_0x0238f25f

1. As a minimum inspect locations for single-phase and two-phase FAC as per the Level One Assessments as per the following hyperlink - http://hyperwave.eskom.co.za/0x936e3246_0x02617fd4 Consider the recommendations made in terms of whether a location is regarded as a Priority 1 or 2. Priority 1 or 2 is defined as follows:

Priority 1 for FAC has a number of different connotations which includes:

a. whether the location is a known primary area for FAC based on the plant assessment

http://hyperwave.eskom.co.za/0x936e3246%200x05e7b679


http://hyperwave.eskom.co.za/0x936e3246_0x02617fd4






Revision: 2

Page: 44 of 83

b. whether the location is a known location internationally for FAC failure and/or damage

c. whether there has already been a failure or observed damage (loss of wall thickness or a black/shiny surface appearance) at this plant location in a unit

d. whether it is in a high personnel traffic location

e. whether it should be inspected reasonably soon by a Level Two NDE processes (Digital radiography) which can be used while the unit is operating,

f. whether it should be inspected by a screening NDT process at the next suitable outage.

Priority 2 for FAC defines locations that don’t quite match the Priority 1 assignments. A number of locations were discussed during the plant visits which had been identified by past plant inspections but had not been confirmed to be unequivocally FAC. These locations are also included within the suggested listings and should be confirmed in the near future. If they are subsequently found not to be FAC then they should be removed from the list and dealt with according to the appropriate mechanism of damage.

2. For components, locations not included above but still considered to fall in the FAC envelope OR susceptible with respect to Erosive Attack then proceed to supplement the “Unit/Outage Specific Scope of Work” as per the template to include additional areas as follows:

3. Select components based on susceptibility ranking as per the guidance in Appendix A & B according to:

Highest anticipated relative wear location.

Consider most vulnerable geometry types, while avoiding types with low relative wear rates.

Spread the samples geographically where possible.

Include at least one component, in similar locations from each parallel train for the purpose of comparing FAC or wall thinning rates in parallel trains.

Consider piping repair and replacement data such as locations of known weld repairs and or known replacements.

4. Consider known industry problem areas, such as:

Downstream of control valves and orifices.

Tees and laterals, especially if field fabricated.

Nozzles, reducers immediately adjacent to control valves.

Components with backing rings, significant counterbore or other size mismatch at joints.

Complex or compound geometries i.e. close connected components typically within two pipe diameters of each other.

Downstream of components previously replaced.

Deaerator, HP & LP heater shells, flashboxes

5. Consider plant experience, such as:

Historical problem areas at same or sister plants

Areas with unknown operating conditions or operating history

Components downstream of normally closed valves which have either been found to be leaking or are high consequence if they do leak.






Revision: 2

Page: 45 of 83

Components downstream of emergency drain control valves which have operated more than 5% of the time since the last inspection of these lines.

6. The following factors should be considered in prioritising inspection areas:

Relative level of anticipated FAC damage.

Pipe diameter.

Energy level (temperature and pressure).

Whether a leak can be isolated.

Consequence of the leak (personnel injury or plant shut down).

In consideration of the above points it is also strongly recommended that a plant walk-down be conducted to critically review complex or compound piping areas. The walk-down while the unit is on-load also presents an opportunity to observe passing valves and steam traps, excessive pipe movement/vibration and sounds which could be indicators of Erosive Attack.

In the case of known or high risk areas of two-phase FAC (based on plant, sister plant, fossil plant experience) it is strongly recommended that replacement with chromium material of “high risk” areas i.e. carbon steel expanders immediately preceding the level control valve and all piping components downstream of Control Valves (CV) be considered in preference to inspection. In this regard the station will be required to follow the “Plant engineering change management (ECM) process” with due consideration of the impact on the design base, welding issues, financial benefit (cost of replacement versus cost avoidance associated with future inspection) and scheduling of replacements factoring in possibly long lead times. Replacement as above will “switch off” the FAC mechanism and therefore there is no need for future inspection for FAC. Inspection may be required for erosive attack. In cases where there are extensive pipe lengths after CVs with known wall loss, and sectional / entire line replacements are considered, due diligence must be applied during the modification ECM process to determine the scope of replacements, based on hydraulic studies and/or wall thickness measurement profiles of piping downstream of the CV.

Should material change be implemented then the ECM number shall be captured in the comment column in the SOW template.

In the event of sectional replacement with non-FAC resistant material these components will require future re-inspection for FAC.

If replacements were performed due to erosive attack mechanisms these will require continuous re-inspections regardless of materials selection as erosive attack will occur regardless of material selection.

It is strongly recommended that when material replacement is adopted as the strategy for high risk FAC locations that the replacement material shall be with high chromium material - all replacements shall be made with Cr >1.25% material (including weld repairs). It is imperative that spare material is available for opportunity replacement. Where >1.25% chrome is mentioned, it refers to the actual chrome content and not the trade name 1 ¼ chrome.

7. After consideration of the above select the components to be inspected during a particular outage i.e. “Outage Selection” column by populating the Outage ID and anticipated start date and then select the components for inspection by a X followed by the inspection required i.e. visual, UT, DRT. Refer to Table 4 Example of Scope of Work Template. In the event that a previous inspection has been performed it is imperative that the columns under the heading of “Inspection Results” Table 4. for that particular inspection not be deleted and overwritten but rather an






Revision: 2

Page: 46 of 83

additional set of columns be added adjacent to the previous “Inspection Results” columns with the outage date clearly indicated in anticipation for the next “Inspection Results”. The intention is that all historic results be available in a single spreadsheet.

8. It is recommended that after the review and approval process the Scope of Work Excel sheet be made available to the inspection authority/contractor. It is recommended that the inspection contractor be tasked to populate the “Inspection Results Field”.

C.1.5 Step 5 – Initial NDE Inspection (Screening)

The first NDT phase involves the use of a screening inspection technology such as DRT. With DRT, a qualitative (thinned/not thinned) determination can be made quickly for many components. DRT inspections can be performed while the unit is running and without the need to remove insulation.

1. Screen suggested locations using screening FAC inspection tools (DRT: on-load or off-load, fiber optics: off-load) to identify areas that exhibit wall loss. DRT will indicate wall loss in terms of an image and qualitative measurement while visual inspection relies on the identification of black, black and shiny, scalloped or tiger striped surfaces. Refer to Appendix A.2.1 for detailed descriptions of these morphologies. If there is no wall loss by screening, in the case of two-phase locations, then there is no need to inspect (quantify). However in the case of single-phase locations visual inspection must be followed by quantification for the purpose of determining wall loss under what would appear to be currently undamaged surfaces (red salmon coloured). Although surfaces may appear to be undamaged FAC could have occurred during previous, historic AVT (R).

2. The initial NDE inspection should typically comprise the use of visual methods either direct visual (for vessels with suitable access) or in the case of restricted access remote visual (fiberscope and/or camera systems). The selection of the appropriate NDT inspection technique for the initial screening should not only consider issues such as access, removal of lagging, scaffolding, removal of valves or bonnets etc. but also the suitability of the technique. It is strongly recommended that valve refurbishment/maintenance activities are scheduled to coincide with FAC inspection interventions to optimise access to enable visual/remote visual inspection. Refer to Appendix D for guidance on NDT screening techniques.

3. Two-phase FAC is possible and has been encountered at surfaces near cascading drain line connections in both LP and HP heaters. However, the locations of any damage cannot be reliably predicted and the time and cost associated with inspection over large areas of shell surfaces is significant. A fibre optics system or visual assessment may be used during unit outages to identify and locate any dark, shiny surfaces indicative of two-phase FAC damage. Inspection methods such as UT can then be used to determine and monitor changes in wall thickness. Refer to Appendix D for guidance on UT.

4. In the case of DRT the component specific inspection reports or component specific images in visual inspections must be cross referenced in the SOW Template with unique identification numbering allowing future ease of data retrieval and report or image review/comparison. Refer to Table 4 Example of Scope of Work Template. The component specific inspection sheets and images to be appropriately archived at the particular site via official site documentation management processes such as the Document Management Centre and/or electronic media storage to ensure traceability and future retrieval for audit purposes.






Revision: 2

Page: 47 of 83

C.1.6 Step 6 – Quantification of wall thinning/material loss by appropriate NDE technique. If required - material confirmation by appropriate analytical technique

1. Areas determined to be thinned by DRT or by visual means should receive a second phase inspection by UT to quantitatively determine thickness. Follow-up inspection of areas with thinning may be needed to evaluate remaining life and plan for repair/replacement activity.

2. Quantify the thinned areas by performing UT. Depending on the results it may be necessary to expand the initial inspection sample in a particular component, line or train by performing additional inspections:

In the particular component by refining/reducing the grid pattern to provide sufficient detail of damage extent and depth.

In the vicinity i.e. immediately adjacent to the worn component.

Next highest ranked components in the same line or train.

In the same locations in parallel trains or other generating units.

3. Where necessary and if required determine the alloy content by X-Ray fluorescence (XRF), or OES (Optical Emission Spectroscopy), or removal of filings for laboratory analysis. Refer to Appendix D for guidance on Positive Material Identification (PMI).

4. During the outage daily meetings/interaction between Station Engineering, Outage Co-ordinator and NDT contractor is mandatory for inspection feedback to identify components requiring stress calculations, determining "cut-lines" and Engineering Instructions.

5. In situations of doubtful or missing piping system information from Isometric drawings it is recommended that as inspections proceed (either visual or UT) in all cases actual piping (OD/Circumference) shall be measured for input into the “Measured OD” column for the respective component.

6. In addition to the above, as inspections proceed by UT and "red" or "yellow" components detected then in all these cases bend radius (on neutral axis) shall be measured for input into the ”Measured Bend Radius” column for the respective component.

7. Where there is deviation from the existing or “Generic” isometric then a new Isometric (Unit specific) shall be drawn (hand drawing), or existing drawing be redlined, for future re-draughting and used for the remainder of the respective inspection activity. Confirmed deviations to be recorded as the inspections proceed for later compilation of updated unit specific Isometric drawing.

8. The component specific inspection reports for the UT and DRT inspection must be cross referenced in the SOW Template with unique identification numbering allowing future ease of data retrieval and report review/comparison. Refer to Table 4 Example of Scope of Work Template. The component specific inspection sheets and images to be appropriately archived at the particular site via official site documentation management processes such as the Document Management Centre and/or electronic media storage to ensure traceability and future retrieval for audit purposes.

C.1.7 Step 7 – Decision-making for immediate repairs/replacement OR future management based on remaining WT, FAC rate and time to next inspection

It is strongly recommended that the appropriate RT&D/PEIC metallurgist/piping engineer specialists be consulted in this regard. In certain instances decision-making may be obvious but in others i.e. moderate FAC wear rates decision-making may be more complex. A few points to illustrate are as follows:






Revision: 2

Page: 48 of 83

Based on international experience there is usually an uncertainty with respect to initial thickness.

Typically this information is unknown if baseline data does not exist.

Actual-initial thicknesses may be thicker or thinner than nominal.

In the case of U.S. manufacturing tolerances are typically ± 12.5%.

Thicknesses may vary across the component particularly tees and elbows + 25% is common, particularly for elbows and reducers.

How have historical operating/chemistry parameters changed since the last inspection? (Clearly this will require consideration if no previous inspection or baseline data exists).

Will current/future operating/chemistry conditions compare with historical conditions?

How well will this wear rate, calculated from historical conditions, represent the future?

Guidance is provided in Appendix D detailing suitable approaches for estimating “installed” wall thicknesses. The approach in determining whether a measured wall thickness is acceptable compared to the installed or “estimated” wall thickness is discussed in Appendix D.2.

“% of Wall Thickness (based on Isometric Info)” – is calculated based on the input parameters for “Installed Wall Thickness (based on Isometric Info)” and the “Minimum measured wall thickness” as populated by the NDT contractor.

“% of Wall Thickness (based on Measured Actual)” – is calculated based on the input parameters for “Actual Installed wall thickness (Max) i.e. from UT and/or “estimate” and the “Minimum measured wall thickness” as populated by the NDT contractor.

The “% of Wall Thickness (based on Isometric Info)” and “% of Wall Thickness (based on Measured Actual)” column in the SOW template provides a simplistic/mechanistic three level screening acceptance criteria which is merely based on % wall loss and does not consider pressure containment design margins which would consider parameters such as design pressure, temperature, material stress at temperature, pump cut off characteristics, geodetic head, etc. It is therefore recommended that station engineering perform their own stress calculations (sample basis) on select thick walled piping components in order to confirm/verify the three level screening result below.

Green (≥80% of Installed Wall Thickness as per ISO drawing)

Yellow (≥70% Installed Wall Thickness <80%): Monitor in next planned outage to confirm thinning and rate.

Red (<70% of Installed Wall Thickness): As a first step apply appropriate stress calculations or stress analysis. Based on the result obtained replacement may be required. The associated urgency and/or risk thereof to be evaluated on a case by case basis. Stress calculations shall be confirmed by the RT&D Metallurgist / PEIC / CoE before continued service. In the event that the component is deemed unsuitable for continued service then remove and replace immediately. In these situations patch or temporary repairs by welding or other sealing methods (Furmaniting) are not recommended. If the component is removed for replacement then the wall thinning mechanism needs to be confirmed.

In the event where Yellow or particularly Red components are identified and where Station Engineering request stress calculations/stress analysis and doubt exists as to the exact material grade, then material analysis by wet chemical analyses or OES techniques will be required as part of the input information required by the metallurgical specialist. This will require the removal of filings from the component and sample submission through the RT&D metallurgical site rep. The metallurgical site rep should be requested to advise on the procedure for filing sample removal. The site rep will advise on whether hardness testing may be required.






Revision: 2

Page: 49 of 83

In addition to the above the metallurgical site rep will require the detailed NDT/DRT Inspection Report, accurate Design Pressure and Temperature, the measured OD and Bend Radius as described previously in order to determine acceptable Wall Thickness for continued operation/estimated wear rate/replacement or re-inspection interval etc.

In the case where a component is removed and replaced due to excessive wall thinning then the removed component shall be retained and submitted to the appropriate specialist in RT&D for metallurgical (failure) investigation to determine:

If the wall loss or damage is FAC.

If the wall loss or damage is due to another Erosive Attack mechanism such as cavitation.

If the wall loss or damage is currently active (a very thin magnetite layer).

In the case of a mechanism other than FAC such as Erosive Attack to provide the appropriate repair and mitigation options.

C.1.8 Step 8 – Recommendations (Post-outage) for future inspection and test requirements, plant modifications, revision of operating and maintenance processes and procedures and record keeping

1. The station is required to ensure that the NDT contractor correctly populates the “Inspection Results Field” in the SOW Template and supplies all supporting inspection reports and images. The inspection reports and images are to be correctly referenced in the SOW Template. The final step in populating the SOW template involves input in the “Action” column detailing the action taken as a result of the inspection result i.e. replace or acceptable etc. If replacement was performed the action remark shall also provide details with regard the material used for the replacement and dimensional information especially in the event of change. If no change then the comment only to record such i.e. no change in dimensions. For the purposes of clarity the Return to Service (RTS) column in Table 4. SOW Template shall indicate the wall thickness of the component at the time of return to service. In the vent of changes in dimensions then these changes to be affected in the relevant columns of the SOW Template.

2. The correctly populated “Inspection Results Field” of the approved Scope of Work template together with the supporting metallurgical evaluation report constitutes the “FAC Inspection Report”.

3. In this step it is crucial that the relevant specialists and station multi-disciplinary team consider the outage and post-outage results, conclusions and recommendations with respect to:

Future inspection requirements at the next appropriate outages i.e. interim, extended and G.O.

If necessary, specialized investigation during on-load i.e. specialized corrosion monitoring and NDT.

Possible plant modifications should be considered cautiously. In the case of erosive mechanisms modifications to valves and other pressure reducing devices could be considered. However, the practice of modifying the design to mitigate damage by FAC is often ineffective and may result in FAC developing at another location.

Modifications which reduce fluid velocity are often ineffective since local turbulence, which causes a flow vector over a damage site and increasing mass transfer may not be eliminated. FAC has been found to occur at locations originally designed with low velocity.






Revision: 2

Page: 50 of 83

Possible long-term FAC mitigation and management options i.e. component replacement as described in Step 4 point 6. FAC is stopped by use of FAC resistant (>1.25% nominal chromium content) replacement materials and weld overlays. Weld overlays may find applicability in the case of vessels – weld overlays are not intended for the temporary repair of piping components. The repairs should completely encompass the area of damage. Possible revision of operating and maintenance processes and procedures i.e. feedwater system venting.

Repair and replacement is discussed above in Steps 4 & 7. Repair and replacement may also need consideration in this step i.e. Step 8 for input into Step 2 for the next outage. The following is equally applicable during Steps 4 & 7. It is recommended that the appropriate (metallurgical/welding) specialist in RT&D should be approached for guidance on respect to repairing and replacing of components with respect to:

- Minimum requirements for welding on Level 1 components as per the Eskom WRB, of particular relevance are Standards 240-56241933, 240-56355225 and 240-56246601. The requirements for welder / welding operator qualifications and welding procedure qualifications to weld build-up and overlay alloy steels onto carbon steel are contained in the said Eskom Standards.

- Paragraph 3.1.6.3 of Eskom standard 240-56241933 provides concise steps to follow for build-up of worn pressure boundary surfaces and application of corrosion resistant overlays.

- The pre-and post-weld heat treatment requirements for welding components consisting of creep resistant carbon, chromium-molybdenum and chromium-molybdenum-vanadium containing steels.

- The analysis required with respect to local and long range stresses (i.e. Ceaser model) when a large, typically >6 metre length of a carbon steel line is replaced with austenitic stainless steel, will be included in the ECM process.

- The feasibility of replacing the entire system with a more corrosion-erosion resistant material.

- The possible impact that the application of corrosion resistant overlays, or replacement of existing materials, as required by the original design, with more corrosion-erosion resistant grades may have on the continued functionality of the refurbished components. Concessions and/or formal Eskom design modification procedures may apply in certain cases. Paragraph 3.1.6.4 of Eskom standard 240-56241933 provides detail towards scenarios which constitute design changes.

- The material specification requirements according to the appropriate international codes and specifications such as BSEN10216 (seamless pipes), BSEN 10222 (forgings) and BSEN 10088 (flat products for pressure). The use of other specifications such as ASTM, ASME, TRD or DIN needs to be approved by the Eskom responsible Engineer.

- It is mandatory that when material is purchased that guidance be obtained by the metallurgical/welding specialist with respect to material certification. For all grades of carbon steel, including (16Mo3, 13CrMo45 (T11), 10CrMo910 (T22)), 3.1 material certification to EN 10204 will be acceptable provided the requirements for materials as detailed in 240-86546783 are met.

- It is imperative that sufficient stock levels of material is available for the replacement of high risk areas (e.g. two phase conditions in pipe sections as defined elsewhere in this guideline) identified prior to an outage and that these replacements are performed at the first available opportunities.






Revision: 2

Page: 51 of 83

The above shall be documented according to the requirements of section C.2 of this guideline and all the relevant inspection reports and findings shall be consolidated and archived appropriately for the next scheduled inspection (for input into Step 2).

C.1.9 Step 9 – Optimise Cycle Chemistry

Optimising cycle chemistry should be considered an on-going activity. Where possible, findings of the inspection should be used to further optimise cycle chemistry. In any event the following should be implemented:

The practice of venting the feedwater system should be carefully reviewed and where possible optimised/minimised.

Automated oxygen dosing of pure oxygen at condensate extraction pump to protect both LP and HP sides of the feedwater system.

Automated ammonia dosing performed at condensate extraction pump.

Strict control of pH and other chemistry parameters as per the requirements of Eskom Chemistry Standards 240-55864800, 240-55864811, 240-55864792.

The use of online filters to monitor suspended iron levels at economiser inlet and HP and LP heater drain lines, as a minimum.

Investigate whether the system will allow for operation at a higher feedwater pH.

Change the location of oxygen injection from deaerator outlet to the condensate extraction pump.

Closing the LP and HP heater vents and deaerator vents is discussed in detail in Appendix E.

Details of cycle chemistry optimisation (post inspection/outage) should be documented and included in the review process during the next outage/inspection scope of work review process i.e. Step 3.






Revision: 2

Page: 52 of 83

Figure 12: Flow-diagram detailing key activities for the Flow Accelerated Corrosion Management Programme

Step 1

Pre-

Outage

Inspection Based Activities Cycle Chemistry Activities

Step 2 Step 3

Step 4

Step 5 Step 9

Step 6

Outage

Activity

Step 7

Step 8

Post

Outage

NDT Using

DRT can

be

applied

On-Load

Development of a station specific FAC Programme

“Generic Scope of Work” -Review of design data,

operational parameters, drawings

Review Cycle Chemistry experience and results

“Unit/Outage Specific Scope of Work” Identify susceptible

systems and lines - prioritise

Initial NDE Inspection(Screening Techniques)

Quantification of wall thinning/material loss by appropriate NDE technique

(Where necessary) material confirmation by appropriate analytical

technique

Decision-making for immediate repairs/replacement OR future management based on remaining WT,

FAC rate and time to next inspectionIf piping is removed for replacement always retain and submit for metallurgical

investigation.

Optimise Cycle Chemistry

RecommendationsFuture inspection and test requirementsRecord keeping (Inspection Report)

Plant modificationsOperating proceduresMaintenance processes






Revision: 2

Page: 53 of 83

C.2 Document Management & Programme Benchmarking

1. It is the responsibility of the station to develop a site specific FAC Policy which is aligned with the corporate level Policy and Guideline documents and fully approved and sponsored by the senior management at the station and PEIC. Each site has a FAC Policy which is available at http://hyperwave.eskom.co.za/0x936e3246_0x02d6f22b

2. The station is required to periodically update/revise the site specific policy as and when management/personnel changes and/or management structure changes are implemented.

3. It is the responsibility of the station FAC custodian to ensure that inspection/replacement “Scope of Work” documents are review and approved as per the requirements as described in 2.5.3 d.

4. It is the responsibility of the station FAC custodian to ensure that the future planned or possibly opportunity inspection/replacement “Scope of Work” documents are reviewed and approved within 3 months of the unit returning to service from the previous inspection/replacement outage. Once reviewed and approved the “Scope of Work” documents together with a signed cover sheet to be submitted to RT&D/PEIC for upload onto Hyperwave. The “Outage & FAC SOW/Inspection Monitor” http://hyperwave.eskom.co.za/0x936e3246_0x05e7b673 will be periodically updated to monitor progress with respect to the approval or review process. A SOW will only be considered as approved once loaded onto Hyperwave at http://hyperwave.eskom.co.za/0x936e3246_0x0238f25f

5. The “Scope of Work” document will only be uploaded to Hyperwave if accompanied by a “Cover sheet” that shall include the following information:

Acknowledgement that the “Scope of Work” has considered the following: Recommendations of all previous metallurgical report/s for the particular unit in terms of

actions for inspection or replacement as well as the timelines associated with these recommendations i.e. due consideration of when the metallurgist report was compiled and issued in relation to the timelines described in the report.

All locations for single-phase and two-phase FAC as per the Level One Assessments which have not yet been inspected or only partially inspected in previous inspection opportunities.

Inclusion of locations and specific components where any wall thinning failures occurred on this unit or other sister units at this plant or other plants in the fleet since the last inspection.

Consideration of all guidance and advisory comments described in section C.1.4 Step 4 – Points 1 – 8.

Consideration of all points in section C.1.3 in order to consider whether repeated inspection of single phase locations is required or not in the next planned inspection opportunity.

As a minimum the Engineering Manager, FAC Custodian, Outage Manager and Chemical Services Manager are to be indicated as signatories for approval of the submitted SOW. All signatures with the date of signature to appear on the submitted “Cover sheet”. The Engineering Manager may include additional signatories if so required.

The “Cover sheet” to be correctly dated with correct details of Unit, Outage Code, Outage Planned date, Outage Planned duration.

6. It is the responsibility of the station FAC custodian to ensure that the appropriate NDT techniques are applied and that appropriate quality control is applied.

7. It is the responsibility of the station FAC custodian to ensure that the “FAC Inspection Report” documents are concluded and sent to the appropriate metallurgical site representative within a month after the return to service of the particular unit. The selection of the components to be evaluated shall be based on the criteria and supplementary considerations as discussed in C.1.7. The correctly populated “Inspection Results Field” of the approved Scope of Work template together

http://hyperwave.eskom.co.za/0x936e3246_0x02d6f22b

http://hyperwave.eskom.co.za/0x936e3246_0x05e7b673







Revision: 2

Page: 54 of 83

with the supporting metallurgical evaluation report constitutes the “FAC Inspection Report” which when concluded will be loaded onto Hyperwave at http://hyperwave.eskom.co.za/0x936e3246_0x0238f25f. The “Outage & FAC SOW/Inspection Monitor” http://hyperwave.eskom.co.za/0x936e3246_0x05e7b673 will be periodically updated to monitor progress with respect to inspection report status.

8. It is the responsibility of the station FAC custodian to ensure that components identified as at risk be appropriately managed and mitigated as per the recommendations in the metallurgical report (compliance required both in terms of action and timeframe).

9. The station is responsible for developing a long-term plan and the identification of long-term goals and strategies for reducing high FAC wear rates i.e. possible material replacement strategies, ensuring adequate and sufficient stock levels of replacement components and materials (whether “high chromium” or like for like material) prior to a planned outage opportunity.

10. System Engineer will ensure that no material /line modifications are performed without following the ECM process. In an emergency the emergency ECM process will be followed.


http://hyperwave.eskom.co.za/0x936e3246_0x05e7b673






Revision: 2

Page: 55 of 83

Table 4: Example of Scope of Work Template






Revision: 2

Page: 56 of 83

#

System, Component Description

Reason for exclusion from inspection Scope of Work

1 Condensate System The operating temperature is very low (39-42ºC) for FAC to occur.

2 LP Heaters drain pumps piping system Low operating temperature (45.5ºC) and flow (1.49 m/s) for FAC to occur.

3 EFP's discharge valve bypass line. On units >550MW these lines are chrome-molybdenum alloy with 1.25% nominal chromium content.

4 HP Heaters Vent lines. Material is stainless steel.

5 Live and Reheat Steam lines. FAC does not occur in lines that convey superheated steam.

Table 5: Example of typical items to exclude from the inspection Scope of Work

(Courtesy Matla Power Station)






Revision: 2

Page: 57 of 83

APPENDIX D: OVERVIEW OF FAC INSPECTION ACTIVITIES

D.1 Overview of NDT Inspection Techniques for FAC/Erosive Attack

D.1.1 NDT Screening Techniques

D.1.1.1 Visual Inspection or testing (VT)

D.1.1.2 Digital Radiographic Testing (DRT)

D.1.2 Quantification - Ultrasonic Testing Inspections (UT)

D.1.2.1 Introduction

D.1.2.2 Ultrasonic Data Display Formats

D.1.3 Positive Material Identification (PMI)

D.2 Quantifying FAC Damage/Wear & Data Evaluation

D.2.1 Performing Inspections

D.2.2 Data Evaluation Process

D.2.3 Determining Initial Thickness and Measured Wear

D.2.4 Determining Acceptable Wall Thickness

D.2.5 Determining Maximum Wear Rate

D.2.6 Determining Remaining Service Life

D.3 UT Procurement Specification & Technical Checklist

D.4 Advisory Notes for FAC NDT Contractor – Work Packages






Revision: 2

Page: 58 of 83

D.1 Overview of NDT Inspection Techniques for FAC/Erosive Attack

There are four main purposes for component inspection by appropriate NDT techniques as follows:

To establish if FAC or other Erosive Attack mechanisms are present and to establish a baseline condition of the component.

If FAC damage or wall thinning is present to then determine the remaining wall thickness for decision making whether to repair, replace or to monitor in future. As discussed previously replacement provides an opportunity (1.25% nominal content Chromium) to stop the FAC mechanism.

Examination results provide an indicator to establish risk for other susceptible components.

Scheduled follow-up examinations if cycle chemistry changes are either not feasible or deemed to be ineffective in mitigating FAC or no replacement with a material upgrade has been performed.

This Appendix provides guidance and advisory information with respect to the types of inspection techniques for screening purposes (on-load and off-load) and damage quantification (only off-load) as well as Positive Material Identification (PMI). Other related information is presented with respect to considerations and practical implementation for the above.

D.1.1 NDT Screening Techniques

In terms of FAC and erosive wear, components are typically firstly inspected using screening techniques such as visual testing (VT) and Digital Radiographic Testing (DRT).

DRT has been commonly used for socket-welded fittings and components with irregular surfaces such as valves and flow nozzles. DRT has the advantage of providing broad coverage with a visual indication of any wall loss. DRT can be performed on-load without the need for removing the pipe insulation thereby reducing scaffolding needs, surface preparation and gridding, replacement of pipe insulation - ultimately providing cost and outage savings. DRT is discussed in D.1.1.2.

D.1.1.1 Visual Inspection or testing (VT)

As discussed in Appendix A the morphology and visual appearance of FAC damage in feedwater heaters and deaerators under oxidizing chemistry regimes provides an obvious visual indicator in the form of the colour variation on the surface i.e. salmon pink or black or black and shiny.

Visual techniques, such as direct observation or use of video camera probes are ideally suited for inspection of large diameter piping (<600mm) and vessels such as deaerators and flashboxes where internal access is possible.

Fiberscopes are suited to more confined areas (<20mm) such as through valve bonnets/openings into heater shells.

Several factors should be considered when planning any visual inspection. Due consideration must be given to the following:

1. The internal visual inspector must firstly have a good working knowledge of power plant systems and components as well as a basic understanding of FAC specifically the visual aspects of the mechanism. In many cases NDT Inspection company operators do not have a sufficient level of knowledge with respect to FAC. It is therefore recommended that if there is any doubt with respect to the inspector’s FAC knowledge the inspector then is accompanied by a member of the station FAC team with sufficient knowledge and understanding of FAC and the visual aspects thereof. The level of involvement by the station FAC team representative will be decided at tender award/clarification or at minimum during the “kick off” meeting.






Revision: 2

Page: 59 of 83

2. Visual internal inspection encompasses a vast array of tools to access specific locations. These tools can range from the simple to the sophisticated and can include the following:

Inspection mirrors

Magnifying glasses

Fibre optic devices of various lengths, diameters, and tip articulations

Rigid borescopes (also known as endoscopes), which can view forward or sideways and be either fixed or rotating

Video image scopes (similar to fiberscopes in appearance, but they use charged coupled device (CCD) chips rather than optics to transmit the image

Miniature cameras (analog and digital)

To facilitate an internal visual inspection, it is fairly common to display the image on a monitor. This is beneficial in that it enables plant personnel to view the image.

In most cases modern equipment have capabilities for video recording on DVD allowing later assessment and also a permanent record of the inspection. It is recommended that if video recording is performed, it is essential that the recording be annotated and correctly catalogued and labelled while the examination is in progress. Unfortunately the data storage and then later retrieval and review of video recordings (DVD) have proven to be difficult to manage from a Knowledge Management perspective.

It is therefore mandatory that as a minimum the appropriate still (images of interest) images be captured and converted into appropriate formats for use in standard Eskom word processing packages and databases. Most digital cameras will transfer images directly to a PC. Regardless of image source the images shall be uniquely labelled and correctly referenced in the appropriate “Inspection Results Field” in the SOW Template as described in C.1.8.

3. Internal visual inspection is not possible unless the inspector can gain the required access to the component. In addition to the access requirements for the device/viewer access may be required for a separate light source to illuminate the surfaces. This obviously places constraints on the diameter of the access entry point, how straight it is initially (there might be a bend to pass before entering the vessel or component of interest), and how much room exists between the entrance and the adjacent component or wall.

4. It is recommended that the inspection company/inspector have access to basic drawings/diagrams such as isometrics or vessel drawings to provide basic dimensional information, and flow direction for reference purposes on video recordings i.e. the upstream and downstream directions are referenced correctly.

5. A practical rule of thumb is to always avoid the device exceeding temperatures of more than 50°C. Typically at higher temperatures the device can cease to function because the optics slip out of alignment or the image clouds over. It is therefore recommended that visual inspection not be conducted soon after shut-down or during short term outages unless there is some method of forced cooling.

6. Dust and grit can enter delicate camera parts or prevent crawler wheels from gripping properly. Depending on the equipment used standing water might not be a problem if the water is shallow, but sometimes the heat from the illuminating light source can cause the lens to steam up.

7. It is important that the inspection company/inspector be made aware of any other operations that might be happening in the vicinity of the inspection especially when examining long pipe runs. Electrical interference by welding and grinding operations can impair the quality of the image by interfering with the signals transmitted along the cables. Localised raised temperatures due to






Revision: 2

Page: 60 of 83

welding operations may occur in a component that external of which is out of sight of the inspector who is located at the access entry point.

8. It is mandatory that the inspection company/inspector perform a plant walk down with the appropriate FAC team representative and that the above considerations be discussed in detail during tender award/clarification or at minimum during the “kick off” meeting.

D.1.1.2 Digital Radiographic Testing (DRT)

DRT is a technique that is based on the same principles as conventional radiography. The difference between DRT and conventional radiography lies in the detector, for conventional radiography a silver film is used and for DRT a photo-stimulable screen (phosphor plate) or a Digital Detector Array (DDA) is used. Once digitising of the image is complete, digital measurement and processing tools that are capable of improving the contrast, zooming, measuring of the wall thickness, etc. are used.

DRT allows detection of thinning and provides semi-quantitative thickness measurements. Where required, thinned components identified by DRT can then be selected for more definitive quantitative evaluation i.e. Wall thickness measurement by UT. DRT is therefore aimed at more efficiently focusing the efforts associated with UT. Where systems have previous inspection data that does not indicate high risk in terms of rupture (as confirmed by wall thickness calculations) follow up DRT can be performed as an on-load screening tool for determining future wall thinning.

DRT has limitations in terms of piping diameter and pipe wall thickness – typically a maximum of a 200 mm (8”) pipe with a 10 mm wall thickness can be tested using an Iridium 192 source.

The Eskom standard 240-92944687: Standard for Performing Digital Radiography for Screening of FAC and Erosive Attack in Fossil Fired Power Plants clearly defines the associated “Roles and Responsibilities” as well as the DRT process and details the limitations of DRT within Eskom’s Generation Plants. The standard includes requirements for the following:

Principles to consider during testing

Process and steps to follow for DRT

Minimum criteria for acceptable DRT images

Minimum criteria for acceptable DRT reports

Technique sheet and setup parameter requirements

Guide for component type versus number of DRT shots required

Advisory notes for the DRT contractor – Work Packages

Enquiry and Tender Considerations

DRT NDT - Contractor’s responsibilities

Safety

D.1.2 Quantification - Ultrasonic Testing Inspections (UT)

D.1.2.1 Introduction

The in-depth considerations and discussion of UT theory, applications, specific techniques, etc. are beyond the scope of this guideline document. For the purpose of performing UT inspection specifically for quantification of FAC and other wall thinning mechanisms, refer to sections D.2.1 and D.3.

As a general description, ultrasonic examination can be defined as the introduction of high-frequency sound waves, generally in the low-megahertz (MHz) range of 0.5–25 MHz, into a component, part, or






Revision: 2

Page: 61 of 83

structure for the purpose of determining some characteristic of the material from which the component, part, or structure is made.

In the context of FAC or wall thinning quantification the specific material characteristic required during inspection is dimensional measurement i.e. thickness.

A prerequisite to UT is surface cleaning/preparation i.e. surface debris/scale removal. The level of surface preparation depends on the extent and type of surface oxidation and/or scaling. It is advisable that the inspection company access and provide recommendations with respect to surface cleanliness requirements before tender award or as a minimum at the “Kick Off” meeting. Although one of the most popular surface preparation techniques is grit or sand blasting it should be considered a last resort. Abrasive grit blasting is problematic in plant areas such as the turbine plant due to the inherent problems of dust and grit containment, safety considerations etc. If at all possible surface preparation of piping and components in preparation for UT should be performed by local cleaning with wire brushes or light grinders. The cleaning is to be performed by appropriately trained/qualified personnel to prevent undesirable material removal.

Ultrasonic examination, as used for thickness measurement, is analogous to active sonar. A short-duration ultrasonic pulse is generated in the component by a transmitter. Immediately thereafter, the ultrasonic instrumentation is switched to a “listening” mode. Any detected return signal is indicative of the presence of a “reflector” that has redirected the propagating wave in the direction of the receiver.

D.1.2.2 Ultrasonic Data Display Formats

The A-scan display is the traditional time/amplitude display used for ultrasonic information presentation. When the pulse is applied to the transducer, a vertical spike is produced by the initial pulse at the left of the screen. Any similar vertical spike at other positions along the time base indicates the presence of a reflector, and the position along the horizontal axis indicates its position relative to transducer(s) in terms of propagation time.

The A-scan presentation of amplitude versus time (depth) on a display screen (shown in Error! eference source not found.) is the most common display found in manual, conventional ultrasonic examination. The screen time base is typically calibrated to limit the extent of the display to the depth range of interest. Similarly, instrument sensitivity is adjusted to produce a measurable response from the smallest flaw of interest. The operator typically moves the transducer(s) over the component by hand, observing the A-scan display for any “indication” that appears on the screen. Positions (both spatial in the scan and depth) are determined and recorded manually in the form of a grid (table) as described in D.2.1. For FAC inspection in Eskom fossil plant this is the prescribed method of UT information display.






Revision: 2

Page: 62 of 83

Figure 13: A-Scan Display Format

Figure 14: B-Scan, C-Scan and D-scan Conventions

The B-scan presentation is a profile (cross-sectional) view of the test specimen. In the B-scan, the time-of-flight (travel time) of the sound energy is displayed along the vertical axis and the linear position of the transducer is displayed along the horizontal axis. From the B-scan, the depth of the reflector and its approximate linear dimensions in the scan direction can be determined. The B-scan is typically produced by establishing a trigger gate on the A-scan. Whenever the signal intensity is great enough to trigger the gate, a point is produced on the B-scan. The gate is triggered by the sound reflecting from the backwall of the specimen and by smaller reflectors within the material

C-Scan

B-Scan

D-Scan






Revision: 2

Page: 63 of 83

Figure 15: B-Scan Display Format

The C-scan presentation provides a plan-type view of the location and size of test specimen features. The plane of the image is parallel to the scan pattern of the transducer. C-scan presentations are produced with an automated data acquisition system, such as a computer controlled immersion scanning system. Typically, a data collection gate is established on the A-scan and the amplitude or the time-of-flight of the signal is recorded at regular intervals as the transducer is scanned over the test piece. The relative signal amplitude or the time-of-flight is displayed as a shade of grey or a colour for each of the positions where data was recorded. The C-scan presentation provides an image of the features that reflect and scatter the sound within and on the surfaces of the test piece.

Index Axis

Scan Axis

Figure 16: C-Scan Display Format






Revision: 2

Page: 64 of 83

In Eskom fossil plant FAC inspections the C-scan display is considered a supplemental display. Other common display formats found in use involve automated or semi-automated data acquisition and processing. The transducer is moved over the surface of the part in a precise fashion, recording response amplitude as a function of transducer position throughout the scan.

Regardless of the particular system being used it shall be capable of producing the A-scan display (grid/table). The UT Inspection Report shall detail the data in the form of the grid pattern applying the convention and requirements detailed in D.2.1and D.3.

D meter presentation only employing a digital numeric display could be problematic in terms of a producing incorrect thickness measurements when wall thicknesses approach 3mm and less due to the so called “thickness doubling” effect, but in fact can be any multiple of actual remaining thickness.

As a general rule of thumb if both surfaces of the test item cannot be directly viewed during measurement and there is the possibility that remaining wall thickness approach 3mm and less then complimentary A-Scan should be undertaken.

D.1.3 Positive Material Identification (PMI)

As discussed in C.1.2 and C.1.4 it may become necessary to confirm material composition where doubt exists with respect to nominal chromium content. The following describes the basics of PMI.

PMI field techniques sort and identify material by actual chemical analysis of the component at one or more locations. Although in situ chemical analysis techniques do not typically analyse for all elements present in a material, they are usually comprehensive enough to identify unknown materials and provide certain compositional data with a reasonable degree of accuracy. In most cases these techniques are based on X-ray fluorescence spectroscopy (XRF). Optical Emission Spectroscopy (OES) is a field technique providing similar element capabilities to laboratory based wet chemical analysis techniques. The technology provides immediate results, without the need of removing filings.

In XRF an X-ray beam impinging on the surface of an unknown material causes the surface atoms of specific chemical elements in the material to emit fluorescent X-rays. The fluorescent X-rays have unique energy levels and wavelengths that are characteristic of the specific chemical elements in the unknown material. These characteristic X-rays are passed through detectors to measure either the energy level or the wavelengths.

Typically, the measurements are analysed by a microprocessor that compares the percentages of the chemical elements present in the unknown material to pre-programmed compositions of specific alloys. The instrument then identifies the alloy if the measured composition matches a pre-programmed alloy and displays the percentages of the measured elements.

Most instruments used in this method of alloy identification are very portable for field applications and provide quantitative analysis results in an efficient and timely manner. In addition, a range of instruments exists. The selection of which one to use depends on time constraints, number of elements to be analysed, and precision required from the measurements. In general, the accuracy of measurements is dependent on the specific instrument and the surface conditions at the test location.

Typically, some degree of surface preparation is required for the effective use of these instruments. Specifically, a test location must be selected that is representative of the bulk of the component, because the fluorescent X-rays are obtained from only a comparatively thin layer of the material. Also, the test area should be sufficiently large for the particular instrument.

Surface curvature and irregularities should be minimized, and all extraneous surface materials (scale, oxide, deposits, coatings, paints, oils, or greases) must be removed. Additionally, the surface finish must be controlled by grinding unless the test location is a finished or machined surface.






Revision: 2

Page: 65 of 83

D.1.3.1 Optical Emission Spectroscopy

This technology was introduced in the late 1990’s.

The machine is quite bulky and is not suited for use at heights. It can easily be bumped or damaged, which will affect the calibration.

With this instrument the sample atoms are exited but by means of a spark (shielded by argon gas). The spark emits light which is then converted into a spectral pattern. By measuring the peaks in this spectrum a qualitative and quantitative report is produced.

Special techniques are required to prepare the sample. Analysis depends heavily on the preparation.

This machine is often the preferred machine for site analysis due to the capability of analysing the carbon content of steel.

Although the spark does leave a small mark it is regarded as a non-destructive alternative to the removal of filings (slightly destructive).

It is at least 4 to 5 times the cost of XRF, but can save time when compared to wet chemical analysis.

It is recommended that in cases where “high chromium” results have been obtained by PMI that these should be forwarded to the appropriate RT&D/PEIC materials specialist/metallurgist for review and acceptance.

D.2 Quantifying FAC Damage/Wear & Data Evaluation

D.2.1 Performing Inspections

Piping components and vessels can be inspected to detect FAC damage using DRT (within previously discussed limitations), UT or if assessable visual observation. Both DRT and visual methods can be used to determine whether or not wear is present. DRT provides a quantitative measure of wall thinning and can generally be regarded as suitable for decision-making. However, in the case of visual inspections and possibly DRT i.e. marginal result etc. once damage or wear is detected then the extent of wall thinning needs to be quantified by UT. Visual methods are preferred in detecting more localised wall loss mechanisms such as erosive attack. As previously mentioned once damage is observed then quantification needs to be conducted using UT.

For piping >50mm, it is mandatory that the UT inspection process includes marking of a grid pattern on the component and using the appropriate transducer and data acquisition equipment to take wall-thickness readings at the grid intersection points. If the readings indicate significant wall thinning a mini grid (described below) needs to be inspected to identify the extent and depth of wall thinning. The intention of the inspection is to provide wall thickness data for three purposes:

1. To determine whether the component has experienced wear and to identify the location of maximum wall thinning within the component.

2. To ascertain the extent and depth of the wall thinning.

3. In the case of multiple previous inspection data to evaluate the wear pattern and to identify any trends.

Complete scanning of the entire component without the use of a grid pattern and simply recording the minimum thickness is not recommended. It is recommended that the component (a component refers to both fittings and straight pipes) be inspected using a complete grid with a grid size sufficient to detect worn areas.

The recommendation for a grid pattern on components in the case of large-bore piping is as follows:






Revision: 2

Page: 66 of 83

Keep grid lines perpendicular and parallel to flow. Cover the component completely. Include the upstream and downstream pipe. Extend the grid past the bend/component by three complete grids upstream of the component and up to two diameters (±7 grids) downstream. For T pieces, all three legs will be 7 grids in all planes.

Place grid lines on both sides of the weld as close as possible to the toe of the weld in order to detect backing rings, the use of counterbore to match the two inner surfaces, or the localized wear that is sometimes found adjacent to welds. When analysing the results special attention must be given to the grid markings closet to the weld as match boring can render a good component being classified as “worn”.

The grid size selection shall be equal to or smaller than the “Maximum Grid Size” as recommended by EPRI in Error! Reference source not found. – Maximum Grid Sizes for Standard Pipe Sizes. he “Maximum Grid Size” refers to the maximum spacing distance on the extrados pipe surface. Where inspections reveal wall thinning the grid size should then be further reduced to one half the selected sizes described above.

For small-bore piping < 2 inch (<50mm) there are no standardised inspection methods. The most common recommended approaches are:

Due to the small diameter gridding is not practical using the approach for larger piping as described above i.e. (π multiplied with OD)/12. In the case of small bore piping it is recommended that grid lines be drawn on quadrants and then scanning along these quadrants.

DRT is ideally suited for the inspection of small-bore piping and should be considered in preference to UT.

Figure 17: Maximum Grid Sizes for Standard Pipe Sizes

It is recommended that the convention described below be used to ensure consistency and repeatability in future inspections.

Pipe Size

(inch)

Pipe Size

(mm)

Outside

Diameter

(inch)

Outside

Diameter

(mm)

Maximum Grid Size

(inch)

Maximum Grid Size

(mm)

2 51 2.38 60 * Quadrant X 1.00 * Quadrant X 25

3 76 3.50 89 1.00 X 1.00 25 X 25

4 102 4.50 114 1.17 X 1.17 30 X 30

6 152 6.63 168 1.73 X 1.73 44 X 44

8 203 8.63 219 2.25 X 2.25 57 X 57

10 254 10.75 273 2.81 X 2.81 71 X 71

12 305 12.75 324 3.33 X 3.33 85 X 85

14 356 14.00 356 3.67 X 3.67 93 X 93

16 406 16.00 406 4.19 X 4.19 106 X 106

18 457 18.00 457 4.71 X 4.71 120 X 120

20 508 20.00 508 5.23 X 5.23 133 X 133

24 610 24.00 610 6.00 X 6.00 152 X 152

>24 -------- -------- -------- 6.00 X 6.00 152 X 152

* Refer to approach for small-bore piping






Revision: 2

Page: 67 of 83

Figure 18: Grid Pattern marking convention






Revision: 2

Page: 68 of 83

The component to be numbered/labelled as follows:

The basis of the convention is the “right-hand rule” where the thumb points in the direction of flow.

The reference or start point for numbering/labelling is always on the upstream side of the component and the first or reference point is situated on the extrados plane (as above indicated by 1A) – this regardless of component orientation.

The grid lines (perpendicular to flow) from the reference point are labelled 1, 2, 3, etc.

Grid lines next to welds as indicated in Figure 18 (Grids 4 and 13).

The grid lines (parallel to flow) from the reference are numbered A - L in the direction of the fingers OR always clockwise when looking downstream. The measurements are then tabulated in the format described below in Figure 19.

For T pieces measurements should firstly proceed along the main branch (straight through) and then along the T branch. Reports shall reflect these as separate piping entities on the same report.






Revision: 2

Page: 69 of 83

Figure 19: Tabular form for recording measurements

High-temperature paints or china markers may be used to identify the grid intersection points where the measurements will be taken. Generally these markings are not permanent and will most likely be obscured or non-existent at the future inspection.

It is mandatory that the grid be marked with a low stress stamp prior to the start of the inspection, mark grid A1.

Orifices, valves, flow nozzles, and other like components cannot be inspected completely with UT due to their shape and thickness. (i.e. non-parallel surfaces). It is recommended that the internals be inspected by visual examinations.

D.2.2 Data Evaluation Process

The purpose of evaluating the inspection data is to determine the location, extent, and amount of total wear for each inspected component. The evaluation process may be complicated by the following:

The original installed wall thickness is unknown or there is doubt.

Variation in thickness along the axis and around the circumference of the component i.e. bends.

Possibility of pipe to component misalignment, backing rings or counterbores.

Inaccuracies in UT measurements.

As a first step the inspection data should be carefully reviewed to identify any data that is judged to be obviously questionable. It is advisable that this be performed during the inspection by the appropriate system engineer. High and low readings should be compared to adjacent readings to evaluate their validity. Isolated high or low reading in an area of consistent thickness may indicate an error.

Once the data set is acceptable, any wear region on the component should be identified. The location of a potential wear region should be compared with the component orientation, flow direction, and attached piping. The variation in thickness within this region should be compared to the adjacent region to confirm the existence of wear. If data from previous inspections are available, they should be compared with the current measurements, and wear trends/patterns should be identified.

The following sections are intended to provide insight into approaches for determining initial installed thickness if unknown, estimated wear or thinning, acceptable wall thickness, estimating future wear rates and remaining service life. It is beyond the scope of this guideline to discuss the in-depth details of






Revision: 2

Page: 70 of 83

these aspects. If required the reader should consult the literature source and approach the appropriate technical specialist in RT&D/PEIC.

D.2.3 Determining Initial Thickness and Measured Wear

Because of the localised nature of most forms of erosive attack, the amount of wear degradation may be estimated by:

Wear due to erosive attack = Tnom – Tmin

Where:

Tnom = Nominal thickness / installed thickness

Tmin = Minimum measured thickness

When the wear pattern indicates more widespread degradation as in the case of FAC damage, the inspection data evaluation methods commonly used in analysing FAC data should be used (EPRI, Final Report 1008082: EPRI Guidelines for Controlling Flow-Accelerated Corrosion in Fossil and Combined Cycle Plants, Dr. B. Dooley, March 2005).

The referenced literature describes three methods (using UT data from gridding) to estimate the components initial thickness and also evaluate components with single outage inspection data. The three methods (band, area and blanket) use the data as presented in a grid pattern. The theory of these methods is based on the principal that FAC damage is not uniform throughout a component but is found in a localised region.

D.2.4 Determining Acceptable Wall Thickness

A component can be considered suitable for continued service if the predicted wall thickness, tp, at the time of the next inspection is greater than or equal to the minimum acceptable wall thickness, taccpt.

tp ≥ taccpt

where,

tp = Predicted remaining wall thickness at a given location on the component

taccpt = Minimum acceptable wall thickness at location of tp

Note that tp can be rewritten in terms of the current thickness, tc, as:

tp = tc - .predicted wear.

Or

tp = tc - R x T x SF

where,

tc = Current wall thickness at location of tp

R = Erosive wear rate at location of tp (mm/year)

T = Time until next inspection

SF = Safety Factor

A reasonable safety factor should be applied to the predicted wear rates to account for inaccuracies in the FAC wear calculations or to allow for wear that may be non-linear with time as in the case of erosion attack. The non-linear nature of some of the wear mechanisms has been discussed in Appendix B.






Revision: 2

Page: 71 of 83

It is mandatory that the calculation of taccpt and application of a safety factor be performed according to the relevant plant construction coding by the appropriate piping/metallurgical specialist with the necessary experience in piping stress analysis.

D.2.5 Determining Maximum Wear Rate

In the case of only a single inspection the component maximum wear is divided by the period of service to obtain the average wear rate over the component lifetime. This past rate is then assumed to continue into the future. This method may cause several potential inaccuracies. This method assumes that operating conditions that affect erosive wear rate, (i.e. velocity, plant power level) or FAC (cycle chemistry, etc) have not changed since plant start-up. If changes did occur, the current wear rate could be considerably different than the average wear rate.

Furthermore the method cannot accommodate potential future changes in operating conditions. Except for SPE, the erosive mechanisms are considered to be non-linear with time. Thus, any linear rate should be used with caution and with an appropriate safety factor.

In situations where data from more than one inspection is available, point-to-point methods and other variant methods can be utilised. Wear from the current outage is subtracted from the value measured at the previous outage and the difference then divided by the time interval to obtain the average wear rate.

D.2.6 Determining Remaining Service Life

In determining the remaining service life of a component it is recommended that the following approach be used.

Tlife = remaining service life

Tlife = current thickness - minimum acceptable thickness

current wear rate * SF

Tlife = tc - taccpt

R x SF

If the predicted remaining service life is shorter than the amount of time until the next inspection opportunity then there are three options:

1. Shorten the inspection interval.

2. Perform a detailed stress analysis to obtain a more accurate value of the acceptable thickness as per the requirements in D.2.4.

3. Repair or replace the component.

D.3 UT Procurement Specification & Technical Checklist

D.3.1 Personnel Qualifications

Operators who wish to perform wall thickness (WT) inspections on Eskom plant require as a minimum one of the following:

1. To be qualified and certified UT level 1/2 in accordance with ISO 9712 or ASNI/ASNT CP 189, ASNT ACCP.

2. ISO 9712 WT Certification. Written confirmation from the designated company Level 3 that the operators have been trained to calibrate the applicable equipment and to perform WT under the agreed conditions.






Revision: 2

Page: 72 of 83

D.3.2 Prerequisites

1. Testing surfaces shall be free of weld spatter, scale, rust, etc. which could otherwise impair the transmission of ultrasound. Use an approved process (e.g. power wire brushing) to bring unsatisfactory test surfaces into an acceptable condition.

2. Use only high temperature transducers when performing thickness measurements on components with temperatures ranging from 50°C up to 260°C as allowed by the applicable technique sheet. No wall thickness measurements shall be performed on components with temperatures greater than 260°C.

3. On completion of ultrasonic thickness measurements remove all traces of couplant from the test surface.

4. Temporary obstructions on/to the test surface (e.g. pipe clamps, adjacent pipe insulation) shall be removed prior to thickness measurements.

5. Wall thickness measurements on items where the thickness, or expected thickness, is ≤ 3 mm shall be subject to special precautions as discussed in D.1.2.2 and D.3.4 (Probe Selection)

6. Ambiguous wall thickness reading shall be compared using A-Scan equipment.

D.3.3 Equipment

When inspecting components with a diameter > 2” and wall thickness > 3 mm the following equipment is recommended:

UT measurements:

D.3.3.1 Measuring device:

Digital Numeric/Digital A-scan Thickness Meters

The instrument shall be capable of transmitting and receiving synchronised sound energy in the 1-10 MHz range and be capable of displaying thickness measurement to the first decimal place (1/10)

Digital Wall thickness meter Digital Wall thickness meter with A-scan display






Revision: 2

Page: 73 of 83

Figure 20: Wall Thickness Measuring Devices

D.3.3.2 Transducers

5 mm ≤ Ø ≥20mm

Single or twin crystals

1 - 25 MHz

D.3.3.3 Additional Equipment Required

Calibration block: A step wedge of similar material as the component covering the range of expected thickness.

Figure 21: Additional Equipment Required for Wall Thickness Measurement

UT machine with A-Scan display






Revision: 2

Page: 74 of 83

D.3.4 Probe Selection

Probe Diameter, Configuration and Frequency Selection

1Nominal Pipe Size

( inch)

Pipe Diameter

( mm)

2Maximum Crystal

Diameter Probe Crystal Configuration

2 to 3½ 73 to 102 5 mm

Single or Twin 4 to 5 114 to 141 10 mm

6 to 24 168 to 610 15 mm

>24 >610 20 mm

NOTE:

1Nominal pipe sizes as per ASME B36.10

2Active crystal diameter. If twin crystal, then it is the diameter of the combined crystals.

3Thicknesses measurements close to or less than 3mm found by a Probe Frequency of 4 – 10

MHz shall be retested with higher Probe Frequency equipment i.e. 10MHz – 25MHz to confirm the

initial measurement. Regardless of the Probe Frequency, in all cases, only equipment with AScan

presentation capabilities shall be acceptable for FAC remaining wall thickness quantification.

Table 6: Probe Selection Criteria

D.3.5 Performing Wall Thickness Measurements

Recommendations in terms of grid pattern size and marking convention is described in D.2.1.

D.3.5.1 Pre checks

1. Ensure that probe wear face is smooth and even.

2. Measure temperature of calibration block and record.

3. Take measurements on calibration block covering the range and record.

4. Measure the temperature of the component and record.

D.3.5.2 Technique

1. When obtaining measurements, the reading on the digital readout shall be allowed to stabilise before recording the thickness.

2. If the readings indicate significant wall thinning then the size of the grid needs to be reduced as described in D.2.1.

3. If there is any difference greater than 0,1 mm between the initial calibration and post calibration readings, then all data sheets pertinent to that calibration shall be marked void, and the inspection shall be repeated.






Revision: 2

Page: 75 of 83

D.3.6 Post Measurement Activities

D.3.6.1 Post Checks

1. Measure temperature of the component and record.

2. Take measurements on calibration block covering the range and record.

3. Measure the temperature of the calibration block and record.

D.3.6.2 Reporting

A standard company report sheet will be completed which as a minimum will detail the following.

1. Date of inspection, power station, unit.

2. Component identification – unique number per component and inspection intervention.

3. Operator - name, signature and date.

4. Supervisor (UT Level 2) - name, signature and date.

5. Company procedure number.

6. Details of measuring equipment – make, model and serial number/s.

7. Details of probe – make, twin/single, frequency, serial number.

8. Pre and post temperature of component.

9. Pre and post temperature of calibration block.

10. Calibration block details – serial number, material, thickness range, calibration number and date.

11. Pre and post calibration readings.

12. List of all limitations.

13. Component grid drawing as per Figure 17 – 18.

14. Dimensional measurement of component (Circumference or OD) as follows:

Bend – Outside diameter and/or circumference.

Reducer - Outside diameter and/or circumference of both the small end and large end.

Tee - Outside diameter and/or circumference of both main pipe and branch.

15. Table of results – as defined in Figure 20.

D.4 Advisory Notes for FAC NDT Contractor – Work Packages

In addition to the SOW template detailing components and locations for inspection it is recommended that a “Works Package” also be included as part of the NDT Inspection companies tender enquiry document. The intention of the “Work Package” is to provide the necessary technical documentation and information to ensure the prospective contractor is suitably informed to provide the required inspection as well as to address related contracting commercial considerations.

The “Works Package” should include the following:

Provision of or reference to applicable procedures and applicable Eskom standards including Corporate FAC Policy, Guideline, Site Specific Policy and Eskom NDT Standards 240-83539994 (Alternative No: 32-631) and 240-8354008 (Alternative No: 32-632).

Isometrics, plant drawings, photographs, sketches, etc.






Revision: 2

Page: 76 of 83

The excel based software SOW template detailing the exact components to be inspected during the outage for the Contractor to complete the minimum thickness for each component with daily feedback to the system engineer.

Results of prior inspections should not be made available to contractors – this provides a means to ensure unbiased results and reporting.

Scaffolding requirements

Insulation removal instructions

Anticipated or planned interfaces with other activities during the outage

Instructions for removal of surface oxides and scale in preparation for UT

Gridding requirements: extent and sizes, type of marking

Hard stamping instructions

Suspect areas to be brought to the attention of the FAC team representative immediately.

Screening criteria for inspection results and action levels (when to highlight risk areas), when acceptable to re-insulate.

Report, inspection sheet, electronic data format requirements

The tender enquiry document should request the following returnables to be evaluated as part of the technical evaluation:

Anticipated duration for inspection SOW and resource schedule

Programme

Personnel qualifications and certification as defined in D.3.1

Upon tender award it is strongly recommended that the contractor attend a “Kick-off” meeting with respective members of the site FAC team. On contract completion an exit or “Close-out” meeting is recommended.






Revision: 2

Page: 77 of 83

APPENDIX E: CLOSING OF HEATER VENTS AND MONITORING OF HEATER DRAIN LINES

E.1 Position Regarding Closing of Heater Vents

E.2 FAC in Heaters Classified as a Repeat Situation

E.3 Rationale for Closing of Heater Vents

E.4 Dealing with Non-Condensable Gases and Other OEM Concerns

E.5 Executing a Heater Performance Test to Determine Impact of Closing Heater Vents

E.6 Guidelines Regarding Heater Venting Procedure

E.7 Operational Experience

E.8 Position Regarding Monitoring of Heater Drain Lines

E.9 Rationale for Monitoring of Heater Drain Lines

E.10 Implementation of Monitoring Equipment and Procedures

E.11 References






Revision: 2

Page: 78 of 83

E.1 Position Regarding Closing of Heater Vents

Eskom’s position is that Generation stations on OT and AVT(O) will convert their operating procedures to operate with HP heater vents closed during normal operation in order to reduce single- and two-phase FAC in heater shells, heater normal drain lines and heater emergency drain lines. Generation stations on AVT(R) will continue to operate with the HP and LP heater vents opened at all times.

Due to the LP heaters operating at lower pressures and, in some cases, under vacuum, consultation must be sought from Condensate and Feed Heating Plant Specialist prior to making a decision about closing of LP heater vents.

E.2 FAC in Heaters Classified as a Repeat Situation

A Cycle Chemistry Improvement Review conducted by Dr Barry Dooley in September 2009 confirmed that FAC in heater cascading drain lines is an increasing safety concern in Eskom. Generation has experienced a significant number of FAC failures in heater drain lines in the last few years. In addition to those, significant single-phase and two-phase FAC damage has also been identified in heater shells and heater drain lines resulting in FAC in heaters being classified as a priority repeat situation.

Figure 22: Examples of two-phase FAC Failures in Heater Drain Lines of Eskom Power Stations

In addition to the other measures to address FAC, such as conducting comprehensive inspections and the replacement of materials, one of the actions to address single-phase FAC in heater shells and heater drain lines is to operate with heater vents closed during normal operation.

E.3 Rationale for Closing of Heater Vents

When the HP heater vents are open, any residual oxygen, any added oxygen and some ammonia will exit through the vents due to partitioning. This results in insufficient oxidising power in the heater shells and drain lines to provide protection against FAC.

Oxygen is a gas and prefers the steam phase rather than remaining in the liquid phase. To maintain sufficient oxygen in the water phase, and provide sufficient oxidising power against single-phase FAC,






Revision: 2

Page: 79 of 83

the oxygen partial pressure in the heater shell and drain lines is increased by closing the heater vents during normal operation. The closing of heater vents also allows a higher concentration of ammonia to remain in the two-phase water droplets in flashing steam in the heaters and reduces FAC.

Thus, for these reasons, HP heater vents should be closed during normal operation in order to reduce single- and two-phase FAC in heater shells, heater normal drain lines and heater emergency drain lines.

E.4 Dealing with Non-Condensable Gases and Other OEM Concerns

Some heater OEM’s may be concerned that the closing of heater vents will result in the build-up of non-condensable gases in the heaters, affecting the performance of the heaters and exposing heater to corrosive effects of stagnant gases.

The performance concerns are addressed as follows. The risk of significant build-up of non-condensable gases is greatly reduced by the Air In-Leakage Reduction Program implemented at stations, and by the control of condensate dissolved oxygen below 20ppb.

Stations may however decide to carry out a controlled performance test to determine impact of closing of vents on performance of heaters.

Stations may also continue to track selected physical parameters on heaters to determine when/if venting is required over time to prevent the build-up of non-condensable gases.

The corrosion concerns are addressed as follows. Corrosion is expected to be reduced when closing heater vents due to the increased oxidising power of oxygen and ammonia. A Repeat Situation Action for all stations is to monitor the corrosion product in the heater drain lines and thereby verify that corrosion is reduced.

E.5 Executing a Heater Performance Test to Determine Impact of Closing Heater Vents

In order to satisfy the requirements of OEM with respect to the impact of closing of vents on the performance of heaters, a controlled performance test can be conducted.

The steps are as follows:

- Check that heater vents can be closed and ensure that heater vents valves are not passing when closed.

- Monitor physical and chemistry parameters on heaters with heater vents open to establish a baseline (temperatures, pressures, levels, corrosion product, dissolved oxygen, pH, etc.).

- Close heater vents and monitor the same physical and chemistry parameters for set period of time.

- Perform periodic venting (“burping”), as/if required.

- Analyse results of test and update procedure to operate with vents closed during normal operation based on the results of the test.

The physical parameters that can be used in the controlled performance test to determine whether the closing of the vents has any effect on the performance of the heaters are as follows:

Feedwater Heater Temperature Rise (TR) - This is the amount of temperature that the condensate/feedwater picks up as it travels through the heater. It is measured as: TR = feedwater outlet temp – feedwater inlet temperature. If the heater becomes bound with non-condensable gases because the vents are closed, this value will decrease.

Feedwater Heater Terminal Temperature Difference (TTD) - This value is defined as the saturated steam temperature (Tsat) in the heater shell (can be measured or derived from shell pressure measurement) minus the heater feedwater outlet temperature TFW(out). It is measured as: TTD = Tsat – TFW(out), where TTD indicates the heat transfer capability of the heater. If the heater






Revision: 2

Page: 80 of 83

becomes bound with non-condensable gases because the vents are closed, this value will increase.

Feedwater Heater Drain Cooler Approach Temperature (DCA) - This value is the difference between the drain outlet temperature (TDrains) and the feedwater inlet temperature (TFW(in)) for heaters fitted with drain cooling sections. It is measured as: DCA = TDrains – TFW(in). This is mainly a heater level parameter. Generally the DCA increases as a result of lower distillate levels.

These physical parameters can be tracked on an ongoing basis to determine if/when venting is required.

The chemistry parameters that can be used to monitor the benefit of closing of heater vents are as follows:

Corrosion Product - Fe (ppb) - This measurement gives an indication of the extent of corrosion taking place in the heaters and heater drain lines. This value is expected to decrease with closing of the vents.

Dissolved Oxygen - DO (ppb) - This measurement gives an indication of the oxygen content in the heaters and therefore the oxidising power against FAC. This value is expected to increase with closing of the vents.

pH - This measurement gives an indication of the ammonia content in the heaters and therefore the oxidising power against FAC. This value is expected to increase with closing of the vents.

E.6 Guidelines Regarding Heater Venting Procedure

Changing from operating with heater vents normally closed to operating with vents normally open is a modification and therefore the site modification process must be followed to update operating procedures, philosophy etc. The modification process must consider whether automation of these vents is required.

Here are some guidelines with respect to the venting procedures that may be implemented at the stations:

Heater Vents during Normal Operation – During this mode, all heater start-up and running vents are closed. Operating will open the heater running vents once a week for approximately five minutes to coincide with other equipment change-overs, or Operating will open heater running vents as dictated by heater physical parameters such as Feedwater Heater Temperature Rise.

Heater Vents during Unit Trip or Shutdown - In the event of a unit trip or shutdown, Operating will open the heater running and start-up vents as needed.

Heater Vents during Unit Start-Up - Operating will close the heater start-up vents and the heater running vents after stable running conditions have been reached on the heaters and after steady-state chemistry specifications have been reached.

Heater Vents during Change in Heater Status - In the event of a heater being taken out of service, Operating will open the heater running and start-up vents as needed. In the event of heater returning to service, Operating will keep the heater running and start-up vents open until stable running conditions have been reached on the heater. Thereafter, all heater start-up and running vents will be closed.

E.7 Operational Experience

Structural Integrity provided the following feedback based on over 20 years of experience in this field:

In Italy, experience has confirmed that restriction of the heater vents was necessary to passivate heater drain lines

Japan has conducted detailed monitoring on early supercritical units in 1990’s which confirmed that it was necessary to operate with heater vents closed in order to reduce iron levels

Results of survey of other utilities conducted by Eskom in October 2009 show that:






Revision: 2

Page: 81 of 83

- In US, Tri-State Craig Station Unit 3, closed vents in 1999 and has since noted no changes in performance of heaters.

- In Australia, Tarong and Tarong North operate with all vents closed. They have conducted extensive monitoring of physical parameters and have had no negative indications in last 10 years.

Results of tests conducted at Tutuka power station in 2010 and 2011 have shown that when closing the heater vents there is no deterioration in the performance of the heater and that there is an increase in the oxidising potential of the water in the shell and heater drain lines. Below is the trend indicating the consequence of operation, specifically on 14 October 2011.

Figure 23: Increased dissolved oxygen in LP Heater drain line after closing vents of LP Heater

E.8 Position Regarding Monitoring of Heater Drain Lines

Eskom’s position is that all Generation stations will perform corrosion product monitoring on their LP and HP heater drain lines in order to determine the extent of FAC in the heater shells and drain lines.

This requirement is in line with the requirements of the internationally recognised technical guidance document for volatile treatments for the steam-water circuits of fossil plants as published by the International Association for the Properties of Water and Steam (IAPWS).

E.9 Rationale for Monitoring of Heater Drain Lines

FAC has been detected in heater shells and drain lines of both LP and HP systems to some extent at all stations. A sample conditioning system with corrosion product monitor is therefore required to monitor the extent of FAC in these systems on load. The data will be used to make decisions about chemistry control, operation of heaters and material selection in order to mitigate the risk of FAC.

E. 10 Implementation of Monitoring Equipment and Procedures

Each power station is required to install a sample point in the lowest cascading drain lines of the LP heaters and the HP heaters. This sampling point will comprise of an isokinetic probe to ensure representative sampling of corrosion products in the drain lines. The sample point will be placed as far down in the lowest cascading drain line as possible in order to account for as much of the system as possible. The sampling arrangement will be such that other measurements such as pH and dissolved oxygen can also be performed.

Figure 24 and Figure 25 present the two options for corrosion product monitoring equipment. The one option is to have a mobile sample conditioning and monitoring system. The other is to have a fixed






Revision: 2

Page: 82 of 83

sample conditioning system and a mobile monitoring system. Further detailed information regarding these two options can be obtained from the documents listed in the references.

Figure 24: Mobile Sample Conditioning and Monitoring System for Corrosion Product Monitoring on Heater Drain Lines

Figure 25: Fixed Sample Conditioning System & Mobile Trolley for Corrosion Product Monitoring on Heater Drain Lines






Revision: 2

Page: 83 of 83

Initially monitoring will be done weekly in order to establish a baseline. Thereafter, the results will be reviewed and monitoring is expected to be reduced to once every 6 months. This may vary from station to station based on extent of FAC in heaters and drain lines, which is in turn based on materials of construction, on chemistry regime applied and on operation of heater vents.

It is important to note that as far as possible the sample point should be kept open, even when not sampling, in order to maintain a continuous and consistent flow through the sample line and thereby ensure a representative sample.

The corrosion product will be captured by means of an on-line corrosion product sampler with flow integrator and 0.45μm Millipore membrane filter. The analytical results will be recorded in the Laboratory Information Management System (LIMS).

E.11 References

- B Dooley, “Operation of Feedwater Vents when Operating with Oxygenated Treatment”, Practice Note, 16 October 2009

- Guidelines for Controlling Flow-Accelerated Corrosion in Fossil and Combined Cycle Plants, EPRI, Palo Alto, CA: 2005, 1008082

- T Gilchrist, “Springerville Generating Station Unit 3 Oxygenated Treatment Operating Procedures”, Tri-State, US, 1999

- E-mail communication with Tom Gilchrist from Tri-State, US, October 2009

- E-mail communication with Des McInnes from Tarong, Australia, October 2009

- Eric Maughan, Mobile Sample Conditioning System and Corrosion Product Sampler for Drain Lines of Low and High Pressure Feedwater Heaters in Power Plant, 3 December 2009

- Dheneshree Lalla, Works Information for PU3 Corrosion Product Sampler Project, 18 January 2010

- IAPWS Technical Guidance Document: Volatile treatments for the steam-water circuits of fossil and combined cycle/HRSG power plants, July 2010

guideline technology guideline for detection and 240 ... · pdf filefrom high pressure heater...

Documents