EPRI_Guidelines for Controlling Flow Accelerated Corrosion

Guidelines for Controlling Flow-Accelerated Corrosion in Fossil and Combined Cycle Plants

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Technical Report

Guidelines for Controlling FlowAccelerated Corrosion in Fossil and Combined Cycle Plants 1008082

Final Report, March 2005

EPRI Project Manager R. B. Dooley

Electric Power Research Institute • 3412 Hillview Avenue, Palo Alto, California 94304 • PO Box 10412, Palo Alto, California 94303 • USA 800.313.3774 • 650.855.2121 • [email protected] • www.epri.com

DISCLAIMER OF WARRANTIES AND LIMITATION OF LIABILITIES THIS DOCUMENT WAS PREPARED BY THE ORGANIZATION(S) NAMED BELOW AS AN ACCOUNT OF WORK SPONSORED OR COSPONSORED BY THE ELECTRIC POWER RESEARCH INSTITUTE, INC. (EPRI). NEITHER EPRI, ANY MEMBER OF EPRI, ANY COSPONSOR, THE ORGANIZATION(S) BELOW, NOR ANY PERSON ACTING ON BEHALF OF ANY OF THEM: (A) MAKES ANY WARRANTY OR REPRESENTATION WHATSOEVER, EXPRESS OR IMPLIED, (I) WITH RESPECT TO THE USE OF ANY INFORMATION, APPARATUS, METHOD, PROCESS, OR SIMILAR ITEM DISCLOSED IN THIS DOCUMENT, INCLUDING MERCHANTABILITY AND FITNESS FOR A PARTICULAR PURPOSE, OR (II) THAT SUCH USE DOES NOT INFRINGE ON OR INTERFERE WITH PRIVATELY OWNED RIGHTS, INCLUDING ANY PARTY'S INTELLECTUAL PROPERTY, OR (III) THAT THIS DOCUMENT IS SUITABLE TO ANY PARTICULAR USER'S CIRCUMSTANCE; OR (B) ASSUMES RESPONSIBILITY FOR ANY DAMAGES OR OTHER LIABILITY WHATSOEVER (INCLUDING ANY CONSEQUENTIAL DAMAGES, EVEN IF EPRI OR ANY EPRI REPRESENTATIVE HAS BEEN ADVISED OF THE POSSIBILITY OF SUCH DAMAGES) RESULTING FROM YOUR SELECTION OR USE OF THIS DOCUMENT OR ANY INFORMATION, APPARATUS, METHOD, PROCESS, OR SIMILAR ITEM DISCLOSED IN THIS DOCUMENT. ORGANIZATION(S) THAT PREPARED THIS DOCUMENT EPRI

ORDERING INFORMATION Requests for copies of this report should be directed to EPRI Orders and Conferences, 1355 Willow Way, Suite 278, Concord, CA 94520, (800) 313-3774, press 2 or internally x5379, (925) 609-9169, (925) 609-1310 (fax). Electric Power Research Institute and EPRI are registered service marks of the Electric Power Research Institute, Inc. TOGETHER…SHAPING THE FUTURE OF ELECTRICITY is a service mark of the Electric Power Research Institute, Inc. Copyright © 2005 Electric Power Research Institute, Inc. All rights reserved.

CITATIONS This report was prepared by EPRI 3412 Hillview Avenue Palo Alto, CA 94304 Authors R. B. Dooley R. Tilley This report describes research sponsored by EPRI. The report is a corporate document that should be cited in the literature in the following manner: Guidelines for Controlling Flow-Accelerated Corrosion in Fossil and Combined Cycle Plants, EPRI, Palo Alto, CA: 2005. 1008082.

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PRODUCT DESCRIPTION

Feedwater system piping and tubing failures due to flow-accelerated corrosion (FAC) have occurred in conventional fossil plants and economizer/evaporator tubing in Heat Recovery Steam Generators (HRSGs) over at least the last 20 years. Worker fatalities have refocused attention on controlling damage due to FAC. These guidelines, which describe the tasks and approaches required for an effective FAC control program in fossil and combined cycle plants, present a strategy for inspection- and cycle chemistry-based activities. Results & Findings These guidelines integrate information on FAC in fossil and HRSG plants into a comprehensive approach. They describe the organization and activities necessary to implement a successful FAC program. The FAC mechanisms for single-and two-phase flow are described in detail. Cycle chemistry can be optimized to minimize single-phase FAC in conventional fossil plants, and both single-phase and two-phase FAC in HRSG plants. The guidelines describe the management-supported FAC program necessary to manage FAC and link it with an FAC Benchmarking process. Challenges & Objectives The mechanism of FAC is well understood; and the majority of FAC susceptible components and systems, especially those operating in single-phase water, can avoid FAC damage through operation with appropriate cycle chemistry conditions. A subset of susceptible components will require periodic inspection and possible replacement, however. The objective of this study was to consolidate existing information into a comprehensive approach to assist operators in controlling FAC. Applications, Values & Use FAC occurs in about 60% of conventional fossil plants and is the second most important HRSG tube failure mechanism in combined cycle plants. The implementation of the inspection- and cycle chemistry-based approaches will be a cost effective method of increasing personnel safety and plant availability. EPRI Perspective FAC damage can be controlled to avoid severe failures by careful implementation of the activities in the road maps presented in these guidelines. Activities related to cycle chemistry can significantly reduce susceptibility to future FAC damage while inspection-based activities can address damage that has already occurred. It is essential that organizations implement a formal program to control FAC in fossil and HRSG plants and that the EPRI Benchmarking process be used to assess improvements and implementation of FAC activities.

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Approach Since the publication of the initial FAC guideline (EPRI Report TR-108859), EPRI has conducted FAC workshops and been involved in many FAC incidents with many organizations around the world. The EPRI team used this large database to assemble case studies to cover as many fossil and HRSG FAC locations as possible. The team next developed mechanistic understandings of FAC phenomena and used this knowledge to optimize the cycle chemistry and inspection approaches described in these guidelines. Finally, the team developed road maps that describe the tasks and approaches required for an effective FAC control program in both fossil and HRSG plants. Keywords Flow-accelerated Corrosion Feedwater Piping Heat Recovery Steam Generators Cycle Chemistry

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EPRI Licensed Material

ABSTRACT This guideline is the first revision of the document developed in 1997 for conventional fossil plants. It now provides the overall methodologies to control flow-accelerated corrosion (FAC) in fossil plants as well as in combined cycle/HRSG plants. For both, an integrated two-pronged road map approach, involving the inspection based and cycle chemistry based activities, has been developed. A detailed description of the mechanism of single- and two-phase FAC is included, as well as numerous examples of FAC in both types of plant.

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CONTENTS

1 INTRODUCTION TO FAC AND THE FAC GUIDELINES......................................................1-7 1.1 History of FAC Occurrences...........................................................................................1-7 1.2 Background of Developed EPRI Technology for FAC Control .......................................1-7 1.3 Mechanism of FAC in Fossil Plants................................................................................1-7 1.4 Corporate FAC Program Overview ................................................................................1-7 1.5 How Good is My FAC Program? ....................................................................................1-7 1.6 Summary ........................................................................................................................1-7 1.7 References .....................................................................................................................1-7 2 FAC MECHANISM AND EXAMPLES IN CONVENTIONAL AND COMBINED CYCLE PLANTS.....................................................................................................................................2-7 2.1 Mechanisms of FAC .......................................................................................................2-7 2.1.1 Introduction to Single- and Two-Phase Flow and FAC...........................................2-7 2.1.2 Feedwater Chemistry for Fossil and HRSG Plants Controls the Oxide on the Material Surface ...............................................................................................................2-7 2.1.3 Factors Affecting the Growth of Magnetite with AVT(R) which are the Basis for FAC .............................................................................................................................2-7 2.1.4 Factors Affecting the Growth of Ferric Oxide Hydrate (FeOOH) with AVT(O) and OT..............................................................................................................................2-7 2.1.5 Importance of Feedwater Metallurgy for FAC in Fossil Plants ...............................2-7 2.1.6 FAC Influencing Factors .........................................................................................2-7 2.1.7 Two-phase FAC......................................................................................................2-7 2.2 FAC Examples, Morphology and Locations in Conventional Fossil Plants ....................2-7 2.2.1 Single-phase FAC in Conventional Fossil Plants ...................................................2-7 2.2.2 Two-phase FAC in Conventional Plants.................................................................2-7 Deaerators ...................................................................................................................2-7 Low Pressure Heater Shells ........................................................................................2-7 Drain Lines...................................................................................................................2-7

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2.2.3 FAC in Conventional Fossil Plants with Mixed-Metallurgy Feedwater Systems (Heater Tubing Contains Copper Alloys) ...........................................................2-7 2.2.4 Other Locations for FAC in Fossil Plants................................................................2-7 2.2.5 Summary for FAC in Conventional Fossil Plants....................................................2-7 2.3 FAC Examples, Morphology and Locations in Combined Cycle/HRSGs.......................2-7 2.3.1 FAC in HRSG Tubing .............................................................................................2-7 2.3.2 FAC in LP Drums....................................................................................................2-7 2.3.3 Summary for FAC in HRSG Plants.........................................................................2-7 2.4 References .....................................................................................................................2-7 2.4.1 Referenced in Text .................................................................................................2-7 2.4.2 Bibliography on FAC in HRSGs..............................................................................2-7 2.4.3 Bibliography on FAC...............................................................................................2-7 3 OVERVIEW OF FAC PROGRAM FOR FOSSIL AND COMBINED CYCLE/HRSG PLANTS.....................................................................................................................................3-7 3.1 Approach for Conventional Fossil Plants .......................................................................3-7 Step 1 - Develop Corporate Program and Philosophy (Section 1.4) ................................3-7 Step 2 - Develop Comprehensive FAC Program..............................................................3-7 Step 3 - Review Design, Materials and FAC Experience (Section 4) ...............................3-7 Step 4 - Review Cycle Chemistry Experience and Results ..............................................3-7 Step 5 - Identify Susceptible Systems and Lines (Section 4) ...........................................3-7 Step 6 - Perform Initial FAC Analysis (CHECUP™/CHECWORKS™).............................3-7 Step 7 - Perform Initial NDE Inspections ..........................................................................3-7 Step 8 - Material Sampling/Removal ................................................................................3-7 Step 9 - Perform Necessary Repairs/Replacements ........................................................3-7 Step 10 - Subsequent Inspections and Analysis ..............................................................3-7 Step 11 - Optimize Feedwater Chemistry.........................................................................3-7 Step 12 - Safe Unit Operation ..........................................................................................3-7 Step 13 - Longterm Options and Continual Check ...........................................................3-7 3.2 Approach for Combined Cycle/HRSG Plants .................................................................3-7 Step 1 - Specify and Design HRSGs to Avoid FAC..........................................................3-7 Step 2 - Monitoring During Commissioning ......................................................................3-7 Step 3 - Develop Corporate Program and Philosophy .....................................................3-7 Step 4 - NDE Inspections .................................................................................................3-7 Step 5 - Materials Sampling .............................................................................................3-7

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Step 6 - Repair and Replacement ....................................................................................3-7 Step 7 - Subsequent Inspections......................................................................................3-7 Step 8 - Monitoring Iron Levels around the HRSG Cycle .................................................3-7 Steps 9 and 11 - Addressing FAC in the Feedwater by Monitoring and Adjusting the Feedwater Chemistry .................................................................................................3-7 Steps 10 and 11 - Addressing FAC in the Evaporator Circuits by Monitoring and Adjusting the Evaporator Treatment.................................................................................3-7 Step 12 - Continued Operation.........................................................................................3-7 3.3 References .....................................................................................................................3-7 4 IMPLEMENTING THE FAC ROAD MAP ...............................................................................4-7 4.1 Information Gathering.....................................................................................................4-7 4.1.1 Plant Design and Materials.....................................................................................4-7 4.1.2 Operating Experience............................................................................................4-7 4.2 Identify and Prioritize Susceptible Systems and Lines...................................................4-7 4.2.1 Exclusion of Systems From Evaluation ..................................................................4-7 4.2.2 Prioritize Units and Systems For Evaluation ..........................................................4-7 4.2.2.1 Conventional Fossil Units ................................................................................4-7 4.2.2.2 HRSG Units ....................................................................................................4-7 4.3 Initiation of Action Paths.................................................................................................4-7 4.4 Documentation ...............................................................................................................4-7 5 INSPECTION-BASED ACTIVITIES .......................................................................................5-7 5.1 Performing FAC Analysis ...............................................................................................5-7 5.2 Selecting and Scheduling Components For Inspection..................................................5-7 5.2.1 Sample Selection....................................................................................................5-7 5.2.2 Expanded Sample Inspection.................................................................................5-7 5.2.3 Inspection Locations for Lines with Uncertain Operating Conditions .....................5-7 5.2.4 Inspection Locations for Lines that Cannot be Analyzed Using The Selected Predictive Methodology ....................................................................................................5-7 5.3 CHECUP™ Summary ....................................................................................................5-7 5.4 Perform NDE Inspections...............................................................................................5-7 5.4.1 Inspection Techniques............................................................................................5-7 5.4.2 Ultrasonic Testing Inspections................................................................................5-7 5.4.2.1 Grid Coverage ................................................................................................5-7 5.4.2.2 Grid Size .........................................................................................................5-7

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5.4.3 Through-Insulation Inspections ..............................................................................5-7 5.4.4 Measuring Trace Alloy Content ..............................................................................5-7 5.5 Evaluating Inspection Data.............................................................................................5-7 5.5.1 Evaluation Process.................................................................................................5-7 5.5.2 Data Reduction.......................................................................................................5-7 5.5.3 Determining Initial Thickness and Measured Wear ................................................5-7 Band Method...........................................................................................................5-7 Area Method............................................................................................................5-7 Moving Blanket Method...........................................................................................5-7 Point-to-Point Method .............................................................................................5-7 5.6 Identifying and Confirming the Cause of Damage..........................................................5-7 5.7 Evaluating Worn Components........................................................................................5-7 5.7.1 Acceptable Wall Thickness.....................................................................................5-7 5.7.2 Maximum Wear Rate...............................................................................................5-7 5.7.3 Remaining Service Life............................................................................................5-7 5.8 Outage Documentation ..................................................................................................5-7 5.9 Perform Necessary Repairs and Replacements ............................................................5-7 5.9.1 Repairing and Replacing Components...................................................................5-7 5.9.2 Use of FAC Resistant Materials ..............................................................................5-7 5.9.3 System Design Changes ........................................................................................5-7 5.10 References ...................................................................................................................5-7 6 OPTIMIZE FEEDWATER CHEMISTRY IN CONVENTIONAL FOSSIL AND HRSG PLANTS.....................................................................................................................................6-7 6.1 Optimization of All-Ferrous Feedwater Chemistry in Conventional and HRSG Units ......................................................................................................................................6-7 Step 1 - Review Normal or Current Feedwater Treatment ...............................................6-7 Step 2 - Monitoring Baseline on Current Feedwater Treatment .......................................6-7 Step 3 - Evaluate Reducing Agent Requirements ............................................................6-7 Step 4 - Monitoring with New Feedwater Treatment ........................................................6-7 Steps 5 and 6 - Consider Converting to OT .....................................................................6-7 Step 7 - Continue to Optimize the Feedwater Treatment .................................................6-7 Step 8 - Operation and Continuing Monitoring .................................................................6-7 6.2 Optimization of Feedwater Treatment for Conventional Fossil Plants with MixedMetallurgy Systems ...............................................................................................................6-7 Step 1 - Review of Water Chemistry, Operation, and Experience....................................6-7

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Step 2 - Baseline Monitoring ............................................................................................6-7 Step 3 - Water Chemistry Optimization ............................................................................6-7 Step 4 - Design and Material Changes.............................................................................6-7 Step 5 - Operation ............................................................................................................6-7 Step 6 - Monitoring to Compare with Baseline Data.........................................................6-7 Step 7 - Normal Operation and Monitoring.......................................................................6-7 Step 8 - Continual Check of Chemistry ............................................................................6-7 Step 9 - Longterm Plans...................................................................................................6-7 6.3 References .....................................................................................................................6-7 7 PERFORM LONGTERM MONITORING AND INSPECTIONS ..............................................7-7 7.1 Follow-On Inspections....................................................................................................7-7 7.2 Longterm Monitoring ......................................................................................................7-7 7.3 Outage Documentation ..................................................................................................7-7 A BENCHMARKING AN ORGANIZATION’S FAC PROGRAM IN CONVENTIONAL FOSSIL PLANTS...................................................................................................................... A-7 Introduction .......................................................................................................................... A-7 Assessing the FAC Organization of a Utility......................................................................... A-7 A. Corporate Mandate for the Organization’s FAC Program .......................................... A-7 B. Prediction and Inspection of Feedwater Systems in Fossil Plants ............................. A-7 C. Cycle Chemistry Control of All-ferrous Feedwater Systems ...................................... A-7 D. Indicator of Corrosion/FAC in All-ferrous Units (plant or system) .............................. A-7 E. Indicator of Corrosion/FAC in Mixed-metallurgy Units (plant or system).................... A-7 F. Indicator of Two-phase FAC in the LP Heater Shells (plant or system) (see Section 2.2.2) .................................................................................................................. A-7 G. Indicator of FAC in the Heater Drain Lines (single- and two-phase FAC (plant or system) (see Section 2.2.2)......................................................................................... A-7 Assessment of an Organization’s FAC Program.................................................................. A-7 Rating Systems as a Function of Feedwater Metallurgy ...................................................... A-7 Rating System for an Organization with both All-ferrous and Mixed-Metallurgy Feedwater Systems......................................................................................................... A-7 Rating System for an Organization with only All-ferrous Feedwater Systems................. A-7 Rating System for an Organization with only Mixed-Metallurgy Feedwater Systems...... A-7

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B BENCHMARKING AN ORGANIZATION’S HEAT RECOVERY STEAM GENERATOR DEPENDABILITY PROGRAM ......................................................................... B-7 Introduction .......................................................................................................................... B-7 Assessment of an Organization’s HRSG Dependability....................................................... B-7

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LIST OF FIGURES Figure 1-1 Schematic of Typical FAC Locations in an HRSG....................................................1-7 Figure 2-1 Schematic of Magnetite Growth and Morphology under Reducing AVT Conditions ..........................................................................................................................2-7 (8)

Figure 2-2 Corrosion Product Release from Carbon Steel as a Function of pH ......................2-7 Figure 2-3 Solubility of Magnetite as a Function of Temperature at Various Ammonia (9) Concentrations. ................................................................................................................2-7 Figure 2-4 Change in Oxidizing-Reducing Potential (ORP) and Feedwater Iron Levels (Fe) at the Economizer Inlet when Hydrazine (N2H4) was Gradually Reduced on a 600 MW Fossil Drum Unit with an All-Ferrous Feedwater System ....................................2-7 Figure 2-5 Carbon Steel Material in Reducing Feedwater at a Location with Severe FAC. Note very thin Fe3O4 on surface. ........................................................................................2-7 Figure 2-6 Free Corrosion Potential for Carbon Steel as a Function of Oxygen and (10) Temperature ...................................................................................................................2-7 Figure 2-7 Schematic of Oxide Growth and Morphology with AVT(O) and OT..........................2-7 Figure 2-8 Solubility of Ferric Hydrate-Oxides at 0.5 ppm NH4OH (Data extracted from Reference 11) Compared with Fe3O4 Solubility (extracted from Figure 2-3) ......................2-7 Figure 2-9 Metallographic Cross-Section through an Economizer Inlet-Header Tube After Operating under an Oxidizing Feedwater Condition for One Year. The protective oxide formed on the surface should be compared to that under a reducing condition which resulted in FAC (Figure 2-5). ...................................................................................2-7 Figure 2-10 Mechanism of the 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......................................................................................................................2-7 Figure 2-11 FAC on an HP Feedwater Heater Tube Sheet. All HP and LP heater tubing in this unit was stainless steel. The feedwater was AVT(R)...............................................2-7 Figure 2-12 FAC Failure and Damage on an Economizer Inlet Header Tube. All HP and LP heater tubing in this unit was stainless steel. The feedwater was AVT(R). ..................2-7 Figure 2-13 Typical Surface Appearance of FAC. The feedwater water flow was from top to bottom. ...........................................................................................................................2-7 Figure 2-14 Typical Scalloped Appearance of Single-phase FAC as Viewed with a Scanning Electron Microscope...........................................................................................2-7 Figure 2-15 Typical Example of “Tiger-Striping” Appearance of Two-phase FAC .....................2-7 Figure 2-16 Severe Two-phase FAC in a Deaerator Located at a Fluid Entry Position.............2-7 Figure 2-17 Severe Two-phase FAC in a Deaerator Located at a Fluid Entry Position: Note that the Two-phase Damage has been Weld Overlayed Previously .........................2-7

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Figure 2-18 Good Example of Diverse Areas of Two-phase FAC (Black) in an Area which is Generally Protected (Red) Because of the Maintenance of Single-phase Flow....................................................................................................................................2-7 Figure 2-19 Internal and External Views of Two-phase FAC on the Shell of a LP Heater. Note the Typical Wavy Pattern of the Two-phase FAC on the ID. .....................................2-7 Figure 2-20 Metallographic Cross-section through the LP Heater Shell Shown in Figure 2-19. The FAC rate increases towards the right side of the figure. ....................................2-7 Figure 2-21 Further Metallographic Information of Figure 2-20 Showing the Demarcation Between Areas that Have Not Suffered FAC (to the left) and Those Where Severe FAC Has Occurred (towards the right). In the former areas there is a protective oxide (magnetite) and deposition (lower left). In the latter (lower right) there is no protective oxide and the FAC has preferentially attacked the pearlite (dark regions) of the carbon steel..............................................................................................................2-7 Figure 2-22 Two-phase FAC (Black/Shiny) Occurring on the Shell Side of the Lowest LP Heater Shell on a Unit on OT. The red areas are protected by FeOOH in the singlephase areas. ......................................................................................................................2-7 Figure 2-23 Same LP Heater Shell as Shown in Figure 2-22. This one shows the location of the cascading drain from the next highest LP heater (second vertical pipe from the right). Note that the impingement plate is protected (red), indicating that the impinging fluid at this stage is single-phase. .........................................................2-7 Figure 2-24 NDE Survey of the Two-phase FAC Damage on the LP Heater Shell Shown in Figures 2-22 and 2-23 ....................................................................................................2-7 Figure 2-25 Illustrating the Catastrophic Nature of FAC Failures in Drain Lines .......................2-7 Figure 2-26 Example of FAC Damage in a LP Drain Line into the Turbine Exhaust Prior to the Condenser................................................................................................................2-7 Figure 2-27 FAC Damage on Exhaust Hood at Condenser Neck. Note serious previous damage has been repaired by “attaching” plates...............................................................2-7 Figure 2-28 FAC Damage to Turbine Diffuser and Exhaust Ducting at LP Turbine Exhaust of a 450MW Unit with a Drum Boiler. Note the Wavy Appearance Typical of Two-phase FAC. ............................................................................................................2-7 Figure 2-29 Typical Location of FAC in a LP Evaporator of a Triple-pressure HRSG. The FAC usually occurs in association with the dogleg or pant leg as the tubing enters the header. .........................................................................................................................2-7 Figure 2-30 FAC Failure in a LP Evaporator Tube Just Prior to the Header..............................2-7 Figure 2-31 Example of FAC in Vertical LP Evaporator Tubing. a) shows single-phase FAC, b) shows two-phase FAC, and c) and d) show the lack of any protective magnetite on the tube surface. The Arows in d) Point to the Preferential FAC Attack of the Pearlite Colonies in the Carbon Steel ......................................................................2-7 Figure 2-32 Example of FAC in Horizontal LP Evaporator Tube. a) shows region of single-phase FAC at tight 180° bend where flow is from left to right, b) and e) show typical formations of “box-like” and “blistered” magnetite, and c) shows the lack of protective magnetite in the severe FAC areas. ..................................................................2-7 Figure 2-33 Visual and Metallographic Characteristics of Two-phase FAC. Note Wavy Appearance which is Typical in Tubes Damaged by Two-phase FAC...............................2-7 Figure 2-34 Example of FAC on the LP Drum Internals ............................................................2-7

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Figure 2-35 Example of FAC on a Natural Circulation HRSG Drum Separating Device ...........2-7 Figure 3-1 Road Map of Activities for Controlling FAC in Fossil Plants .....................................3-7 Figure 3-2 Road Map of Activities for Controlling FAC in Combined Cycle/HRSG Plants.........3-7 Figure 3-3 Measured Iron Profiles around an HRSG when Operating With and Without a Reducing Agent (Hydrazine). .............................................................................................3-7 Figure 5-1 Sample Input Screen for CHECUP™ FAC Analysis .................................................5-7 Figure 5-2 Sample Output Report from CHECUP™ FAC Analysis ............................................5-7 Figure 5-3 Grid Layout for an Elbow ..........................................................................................5-7 Figure 5-4 Radiographic Technique for FAC .............................................................................5-7 Figure 5-5 Comparison of PEC and UT Results for FAC Damage to Piping .............................5-7 Figure 5-6 Recommended Inspection Coverage in Circumferential Direction for a Feedwater Heater Shell .....................................................................................................5-7 Figure 5-7 Comparison of PEC and UT (pulse echo) Results for a Feedwater Heater Shell – Left Section ............................................................................................................5-7 Figure 5-8 Example of Band Method .........................................................................................5-7 Figure 5-9 Example of Area Method ..........................................................................................5-7 Figure 5-10 Example of Moving Blanket Method .......................................................................5-7 Figure 5-11 Predicted Thickness Profile ....................................................................................5-7 Figure 5-12 Potential for Error When Using Average Wear Rate Based on Inspection Data....................................................................................................................................5-7 Figure 5-13 Potential Error Of Using Wear Rate Based On Inspection Data From Two Inspections .........................................................................................................................5-7 Figure 6-1 Road Map for Optimizing Feedwater Treatment for All-Ferrous Feedwater Systems. ............................................................................................................................6-7 Figure 6-2 Road Map for Optimizing Feedwater Treatment for Mixed Metal Systems (Cu/Fe) to Minimize Feedwater Corrosion Products (Fe and Cu), and FAC of the Carbon Steel Components .................................................................................................6-7

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LIST OF TABLES Table 1-1 Significant FAC Failures in Nuclear Power Plants Since 1989 ..................................1-7 Table 1-2 Survey Results of FAC Incidents in Fossil Plants in 2003 (2000 and 1997). * + Indicates single-phase FAC. Indicates that two-phase FAC predominates. ....................1-7 (4)

Table 1-3 Serious FAC Failures in Fossil Plants from 1982 ....................................................1-7 Table 1-4 HRSG Tube Failure Mechanisms (Compiled from surveys at 2001/2003 International Conferences).................................................................................................1-7 Table 2-1 Factors Influencing FAC in Fossil and HRSG Plants.................................................2-7 Table 2-2 Comparison of Normal Feedwater Cycle Chemistry Limits for AVT and OT as a Function of Feedwater Metallurgy ...................................................................................2-7 Table 2-3 Published Geometric Enhancement Factor Values for Piping Components with Single-phase Flow as Used in Various FAC Models..........................................................2-7 Table 5-1 Maximum Grid Sizes for Standard Pipe Sizes (1 inch = 2.54 cm) .............................5-7 Table 5-2 Performance of Common FAC-Resistant Alloys........................................................5-7 Table B-1 Supplementary Information for Factor C ................................................................. B-7

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1 INTRODUCTION TO FAC AND THE FAC GUIDELINES

Flow-accelerated corrosion (FAC) causes wall thinning (metal loss) of carbon steel piping, tubing and vessels exposed to flowing water (single-phase) or wet steam (two-phase). If undetected, the degraded component can suddenly rupture, releasing high temperature steam and water into neighboring plant areas. The escaping fluids can injure plant workers, sometimes severely, and damage nearby equipment. Over the years, FAC has caused hundreds of piping and equipment failures in all types of fossil, industrial steam, and nuclear power plants, and tube failures in Heat Recovery Steam Generators, HRSGs. Prior to the mid-1980s often the cause of the failure was not known by the plant owner, or if known, was not reported. Additionally, the power industry did not fully understand the conditions under which FAC occurred, where plants should look to find it, or how to best control it when it was found. This changed in 1986. On December 9 of that year, an elbow in the condensate system ruptured at the Surry Nuclear Power Station. The failure caused four fatalities and tens of millions of dollars in repair costs and lost revenue. FAC was found to be the cause of the failure. Because of the deaths involved and the high degree of regulation applied to the nuclear power plants, a comprehensive overall approach was needed. An intensive international cooperative effort was initiated to understand the parameters which affect FAC. The strategy was that understanding FAC would allow the development of technology to help plants find damage before failure occurs, and the measures to control it. The major parties in this cooperation were EPRI, Electricité de France, and Kraftwerk Union, now a part of Siemens. Around the late 1980s, FAC also started to be positively identified in the feedwater systems of conventional fossil plants, and inspection programs were initiated. This took on fresh emphasis following the fatal burst at the Pleasant Prairie Plant in 1995. More recently gas-fired combined cycle/HRSG plants became the new generating source of choice. HRSGs are now operating in a multitude of formats: vertical and horizontal gas paths, vertical and horizontal tubing, single-, double-, and triple-pressure recirculating (drum) systems, and mixed drum and once-through systems. FAC quickly became the number one HRSG tube failure (HTF) problem with most of the failures and damage being concentrated in the low pressure evaporator circuits irrespective of the HRSG format. The LP circuits most often operate at a pressure of around 60–70 psi (0.4–0.5 MPa). FAC has also been observed on the LP drum internal structures such as separators. This introductory section briefly provides the history of FAC in both nuclear and fossil plants and in HRSGs, the background information on the CHEC® series of computer codes developed to address FAC, and the background on the importance of cycle chemistry in fossil plant and HRSG FAC.

1-1

EPRI Licensed Material Introduction to FAC and the FAC Guidelines

1.1 History of FAC Occurrences The technology and information developed since the Surry and Pleasant Prairie failures have greatly reduced the incidence of FAC failures. Nevertheless, instances of severe thinning, leaks, and ruptures are still occurring on a frequent basis. Some of the most significant examples of recent failures in nuclear plants are summarized in Table 1-1. Table 1-1 Significant FAC Failures in Nuclear Power Plants Since 1989 Plant

Date

Location

S. M. de Garona (Spain)

December 1989

Feedwater

Loviisa Unit 1 (Finland)

May 1990

Feedwater

Millstone Unit 3

December 1990

Heater drain

Millstone Unit 2

November 1991

Reheater drain

Almaraz Unit 1 (Spain)

December 1991

Extraction steam

Loviisa Unit 2 (Finland)

February 1993

Feedwater

Sequoyah Unit 2

March 1993

Extraction steam

Fort Calhoun

April 1997

Extraction steam

Mihama Unit 3

August 2004

Feedwater

Failures in fossil and industrial steam plants have not historically been as well documented, because the plants are not as tightly regulated and because FAC has not been properly identified. However, as a result of the fatalities at the Pleasant Prairie fossil plant in 1995 the topic now has a higher priority. Surveys conducted in 2003, 2000 and 1997 provide an indication of the important areas where FAC has been identified in fossil plants (Table 1-2). It can be seen that about 60% of fossil organizations experience FAC; this recognition has increased from about 40% in 1997. The table also indicates that heater drain lines remain the most predominant area. It is also important to note that both single-phase and two-phase FAC is occurring. Table 1-3 provides a summary of recent (from 1982) serious fossil plant failures, resulting in bursts, extensive plant damage, or fatalities, known to be caused by FAC.

1-2

EPRI Licensed Material Introduction to FAC and the FAC Guidelines Table 1-2 Survey Results of FAC Incidents in Fossil Plants in 2003 (2000 and 1997). * Indicates single-phase FAC. + Indicates that two-phase FAC predominates. 60% of Utilities Report FAC (60%, 40%) Locations of FAC Economizer Inlet Tubing*

25% (22%)

Heater Drain Lines*+

52% (32%, 10%)

Piping Around BFP*

25% (16%)

Tubesheet/Tubes in HP Heaters*

11% (12%)

Piping to Economizer Inlet Header*

35% (11%)

Deaerator Shell+

14% (11%)

Shell Side of LP Heaters+

7%

Table 1-3 Serious FAC Failures in Fossil Plants from 1982(4) Plant

Location

Temp.

Feedwater Treatment

A

Elbow downstream of BF booster pump

360° F 182° C

NH3/N2H4/ Carbohydrazide

B

Elbow near EI at RT plug

C

Downstream of boiler stop valve near EI

D-M

EI tubes

pH

Oxygen

Feedwater Heaters

low < 1 ppb

AllStainless

NH3/N2H4

8.80 9.20

low < 1 ppb

AllStainless

456° F 236° C

NH3/N2H4

8.75

very low < 1 ppb

AllStainless

Final Feed Water

NH3/N2H4

9.00 9.40

very low < 1 ppb

AllStainless

1-3


Table 1-3 indicates that there are a number of very important and significant features which are common to these FAC incidents in conventional fossil plants: •

the feedwater failures all occurred in the high pressure portions of the system up to and including the economizer inlet header tubes. This means that the temperature range up to 280-300°C in fossil plants is susceptible to failure. This range is usually considered above the temperature at which maximum FAC occurs in laboratory experiments and at which maximum magnetite solubility occurs.

•

each system (A-M) had stainless steel low and high pressure feedwater heaters.

•

the feedwater in each case was treated with both ammonia and a reducing agent (hydrazine or alternative) which means the feedwater was operating under very reducing conditions (below -300mV redox or ORP potential).

•

the feedwater oxygen levels were very low (< 1 ppb).

•

the heater drains (Table 1-2) are susceptible areas in plants with both all-ferrous and mixed feedwater metallurgies.

The importance of the cycle chemistry will be discussed further in later Sections. The information within Tables 1-2 and 1-3 is used later in the road map in Section 3 to provide initial priorities for inspection. FAC is now recognized as the second most important HRSG Tube Failure (HTF) in HRSGs as indicated in Table 1-4. It has generally been located in the LP evaporator circuits (Figure 1-1), but isolated incidents have occurred in LP and HP economizer or preheater tubing and in the riser/feeder systems. FAC occurs in HRSGs under both single-phase (water) and two-phase (water and steam) flow conditions; it is important to recognize the features of both as different solutions apply. Table 1-4 HRSG Tube Failure Mechanisms (Compiled from surveys at 2001/2003 International Conferences)

1-4

Thermal Fatigue

1

FAC

2

Corrosion Fatigue

3

Under-deposit Corrosion – Hydrogen Damage – Acid Phosphate Corrosion – Caustic Gouging

4

Pitting

5


Figure 1-1 Schematic of Typical FAC Locations in an HRSG

The feedwater systems of modern multi-pressure HRSGs are much simpler than in conventional fossil plants and generally contain no feedwater heaters. This is a major difference from conventional fossil plants in that failure from FAC in the feedwater piping is extremely rare in an HRSG, but the increased corrosion and corrosion product transport are common in these systems where a reducing agent is fed after the condensate pump. This reducing agent flows into the LP evaporator circuit, where the operating temperature and pressure is insufficient to decompose the reducing agent, thus causing severe reducing redox (ORP) potentials, which are the primary conditions (driver) for single-phase FAC. The importance of cycle chemistry in HRSGs is discussed in later sections, and the information is incorporated into the road maps of Section 3.

1.2 Background of Developed EPRI Technology for FAC Control Although there were limited FAC programs in place before the Surry pipe rupture, it was not until after this accident that utilities expanded their inspection programs to reduce the risk of pipe ruptures caused by FAC in susceptible single-phase systems. Since the Surry incident in December 1986, the industry has worked steadily to develop or refine their monitoring programs to prevent the failure of piping due to FAC. To support the nuclear industry effort, EPRI began developing the CHEC® and CHECMATE® computer codes for predicting FAC wear rates in piping containing single- and two-phase flow. These codes were developed specifically to assist the utility industry in planning and implementing inspection programs to prevent FAC failures. The codes could also be used to evaluate the effect of changes in piping design or operating conditions on FAC wear rates. These codes predict the rate of FAC on a component-by-component basis to assist in prioritizing 1-5


inspections to find damage long before a failure might occur. The prioritization of inspections is key to control of FAC as often plants have thousands of possibly susceptible components, and it is not practical to inspect them all. EPRI has continued to develop technology to help utilities control FAC, and in December 1993 (5) released the CHECWORKS™ (Chexal-Horowitz Engineering Corrosion WORKStation) code . In summary, CHECWORKS™ integrated and updated the capability of the previous codes, and was written to take full advantage of the recent advances in computer technology. Additionally, capability was added to help utilities manage related plant data and to automate many of the analysis and reporting tasks conducted during an inspection outage. The rupture of the feedwater line at the Pleasant Prairie fossil plant in 1995 led to many fossil plant owners expanding and refining their FAC inspection programs. In reaction to this EPRI (6) developed CHECUP™ in 1996, to rank the relative rate of wall loss due to FAC at specific piping locations in fossil and co-generation power plants and industrial steam plants. The use of CHECUP™ is described in Section 5 and increases the confidence of plant owners and operators that the most damaged components will be identified, inspected, and repaired or replaced long before a rupture might occur. CHECUP™ also helps manage and interpret associated inspection data. In parallel with those efforts over the last 10 years the EPRI fossil plant cycle chemistry program has focused on optimizing the feedwater treatments to minimize single-phase FAC(7-9). Particular emphasis has been given to reducing the level of iron-based feedwater corrosion products, which are the key on-line indicator of FAC. The fossil plant has more flexibility than a nuclear plant to change the oxidizing-reducing potential in the feedwater, and major efforts have been directed along these lines. Recently three types of feedwater treatment have been delineated(7): classic AVT(R) (with ammonia and a reducing agent), AVT(O) (with only ammonia addition), and OT (with ammonia and oxygen additions). In a conventional fossil plant, it is only possible to address single-phase FAC by cycle chemistry optimization. Two-phase FAC (drain lines, deaerator and shellside of heaters) must be addressed by materials solutions (increasing chromium) as discussed in later sections. The FAC mechanisms which occur in HRSGs have been fully described in EPRI’s HTF (11) Manual. As in conventional plants single-phase FAC can be addressed by ensuring that the feedwater operates on AVT(O) or OT. Two-phase FAC can however be addressed chemically in an HRSG by increasing the LP evaporator pH if not restricted by the HRSG design. The guideline for the cycle chemistry of HRSGs(12) was developed to address both single and twophase FAC. At this time there is not a predictive capability for HRSGs equivalent to CHECWORKS or CHECUP. This current Guideline represents a comprehensive approach which combines the key areas for FAC control: prediction, inspection, and cycle chemistry.

1-6


This Guideline describes the organization and activities necessary to implement a successful FAC program specific to conventional fossil and HRSG power plants and industrial steam plants. Necessary elements of an effective FAC program are identified, and recommendations for implementation are made. The reader should first turn to Section 3, which provides an overview of the necessary activities in the form of road maps (Section 3.1 for conventional fossil plants, and Section 3.2 for HRSGs). The detailed steps are described in the subsequent sections. This document has been written to be of use to all fossil power plants and industrial steam plants including combined cycle/HRSG plants. The Guideline is directed at wall thinning caused by FAC in large-bore piping and in small-bore tubing, such as economizer inlet header tubing and HRSG tubing. This document does not cover other thinning mechanisms, such as cavitation, microbiologically-influenced corrosion (MIC), and erosive wear. It is planned that this document will be periodically updated to reflect the advances made in FAC control; as such this is the first revision of the 1997 Fossil Plant (13) Guidelines for FAC.

1.3 Mechanism of FAC in Fossil Plants. The phenomenon of FAC is well understood(10). It is a process whereby the normally protective magnetite (Fe3O4) layer on carbon steel dissolves in a stream of flowing water (single-phase) or wet steam (two-phase). This process reduces or eliminates the protective oxide (magnetite) layer and leads to a rapid removal of the base material until, in the worst cases, the pipe or tube bursts. The FAC process can become rapid: wall thinning rates as high as 0.120 inch/yr (3 mm/yr) have occurred. In fossil and HRSG plants the rate of metal loss depends on a complex interplay of many parameters including the feedwater chemistry, the material composition, the other materials in the feedwater systems, and the fluid hydrodynamics. Section 2 provides an overview of the key features involved and includes a wide range of single-phase and two-phase examples from conventional and combined cycle HRSG plants. The FAC mechanism is discussed in detail and starts with the basic feedwater chemistries, and then provides a description of the oxides which form under different oxidizing-reducing potentials (redox or ORP). This leads finally to how the hydrodynamic factors influence FAC.

1.4 Corporate FAC Program Overview It is important that a comprehensive set of procedures (or instructions) be developed to define the overall FAC program, identify responsibilities, and control how various tasks are performed. For utilities with multiple plants, it is recommended that the procedures (or instructions) be as common to all plants as is practical. These procedures (or instructions) should be approved plant documents that are updated as necessary to reflect plant and industry requirements. Clearly a corporate FAC program needs to include personnel from various groups in the plant (mechanical maintenance, chemists, technical, and operations) and in head office/research (NDE, metallurgists, feedwater specialists, piping engineers). An overall corporate commitment is essential to an effective FAC program.

1-7


The most successful way of ensuring full participation of the various groups is to develop a corporate philosophy document signed by the upper management, which defines the overall program and responsibilities. Such a document should include, as a minimum, the following elements: •

A corporate commitment to monitor and control FAC.

•

The means to provide adequate financial resources to ensure that all tasks are properly completed.

•

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

•

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

•

Communication requirements between the lead position and other departments that have responsibility for performing support tasks. Formalized sharing of data and information is essential.

•

Ensuring that assigned personnel are properly qualified and trained for their area of technical responsibility and that adequately trained, backup personnel are available.

•

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

•

Minimizing personnel turnover on the program, and providing sufficient transition when turnover does occur to ensure that plant and industry experience is not lost.

•

Ensuring that FAC experiences at other plants are continuously monitored and evaluated.

•

Ensuring that appropriate quality controls are applied. This should include preparing and documenting procedures for tasks to be performed, properly documenting work, and providing for periodic independent reviews of all phases of the FAC program.

•

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

•

A method for evaluating plant performance against longterm goals.

There may be several thousand piping components in a given fossil power plant or combined cycle plant that are susceptible to FAC damage. Without an accurate FAC analysis of the plant, inspection drawings, and a piping database that includes inspection and replacement histories, the only way to prevent leaks and ruptures is to inspect each susceptible component during each outage. This would be a very costly inspection program. A primary objective of the overall FAC program is to identify the most susceptible components, thereby reducing the number of inspections (the size of this sample being a strong function of both the plant susceptibility and the accuracy of the plant model and analysis method used). This limited sample should be chosen to select the components with the greatest susceptibility to FAC. Some plants have used a simplified approach, often involving rating factors for this susceptibility analysis.

1-8


Plants that do not use a systematic, analytically based approach to FAC cannot be confident that all highly susceptible components have been identified and are being monitored to prevent leakage or rupture. Programs that are based purely on engineering judgment will require inspection of an unnecessarily large number of inspection locations during each major outage for piping and tubing systems alone to develop a high level of confidence in the adequacy of the program. Experience has shown that until an adequate analysis of all susceptible systems has been completed, plant personnel cannot be confident that the FAC program is adequate to prevent a consequential failure. For each susceptible segment, an analytical method should be used to predict the FAC wear rate, and the estimated time until it must be reinspected, repaired, or replaced. The analytical model can also be utilized for design studies. These studies are valuable for cost benefit evaluations such as water chemistry changes, materials changes, and design changes, considering various plant constraints for existing and new designs. The rankings of component types can be used as relative rankings to assist in planning and carrying out the initial inspection program of a plant or system. Review and incorporation of industry experience provides a valuable supplement to plant analysis and associated inspections. Utilities have found the following benefits from sharing plant experiences: •

Identifying generic plant problem areas where additional inspections may be warranted.

•

Understanding differences in similar types of components (e.g., FAC wear rates of downstream piping are more severe when control valves made by certain manufacturers are used).

•

Understanding the FAC consequences of using systems off-design (e.g., running bypass lines full time).

•

Sharing information on costs, materials, qualified suppliers, repair or replacement techniques, inspection techniques, new equipment, etc.

EPRI sponsors periodic FAC symposiums to discuss new technologies and to provide an open forum for utility and industrial steam plant personnel to share FAC related experiences. Good NDE inspections (Section 5) are the foundation of an effective FAC program. Wall thickness measurements will establish the extent of wear in a given component, provide data to help evaluate FAC trends, and provide information to refine the predictive model, if the predictive model includes this feature. Thorough inspections are the key to fulfilling these needs. Thorough inspection of a few components is much more beneficial to an FAC program than a cursory inspection of a large number of components. One practice particularly not recommended is recording only the minimum thicknesses ascertained by UT scanning of large-bore components. Rather, a systematic method of collecting data is recommended. This will help to increase repeatability and allow for the trending of results. Complete inspections may require material sampling.

1-9


Cycle chemistry optimization (Section 6) will ensure that FAC is minimized depending on the type of feedwater system (mixed-metallurgy or all-ferrous) and plant (conventional or combined cycle).

1.5 How Good is My FAC Program? Section 1.4 provided an overview of the minimum features of an adequate FAC corporate program. This is initiated with a Corporate Mandate signed by the VP/Director of Operations/Plant Manager. It is activated by on-going cycle chemistry optimization, prediction of damage sites, and repair activities. However, this is often not good enough. Following a major FAC trauma in the world, corporate managers of conventional and HRSG plants ask their staff: “Is our FAC program adequate?” EPRI has developed a Benchmarking Process (Appendix A) for conventional plants to provide the answer. This process ranks the in-house FAC program from “World Class” to “Below Average,” and takes into account whether the plant has all-ferrous or mixed-metallurgy feedwater systems. To achieve “Very Good” or “World Class” status, an organization must be a) using a predictive tool to identify susceptible locations, and b) cognizant that feedwater chemistry in each plant needs to be optimized to minimize feedwater corrosion products. For HRSGs, EPRI has developed a Benchmarking Process to assess overall HRSG performance. Appendix B provides this Benchmarking Process and the reader should note that Factors B, D, E and F address FAC.

1.6 Summary In summary, the mechanism of FAC in fossil plants and combined cycle/HRSG plants is well understood. Unlike nuclear plants, there are a number of variables which can affect the FAC process and which can be changed or controlled to affect the FAC rate. The main ones are the feedwater metallurgy and the feedwater chemistry. It should be clearly understood that the cycle chemistry can be optimized to minimize single-phase FAC in conventional fossil plants, and both single-phase and two-phase FAC in HRSG plants. This guideline brings together all the factors for fossil and HRSG plants into a comprehensive approach, and describes the organization and activities necessary to implement a successful FAC program specific to fossil and HRSG plants, and industrial steam plants. It is believed that the implementation of these procedures will prove to be a cost effective method of increasing personnel safety and plant availability. These procedures also have the potential to reduce forced outages and thus increase the capacity factor, while reducing the cost of plant operations and maintenance. The implementation of all the activities found in this document will greatly reduce the probability of a consequential leak or a rupture occurring.

1-10


The establishment and implementation of a longterm strategy is essential to the success of a plant FAC program. This strategy should focus on reducing FAC wear rates, focusing inspections on the most susceptible locations, and continually checking that the cycle chemistry is optimized for minimum FAC. Monitoring of components is crucial to preventing failures. However, without a concerted effort to reduce FAC wear rates, the number of inspections necessary will increase as the operating hours increase, due to increased wear. In addition, even with selective repair and replacement, the probability of experiencing a consequential leak or rupture may increase as operating hours increase without optimizing the cycle chemistry. The guideline is only directed at wall thinning caused by FAC in large-bore piping and small bore tubing. This document does not cover other thinning mechanisms, such as cavitation, microbiologically-influenced corrosion (MIC), and erosive wear. The reader should first turn to Section 3, which provides the necessary overview of all the activities needed in a successful FAC program in the form of road maps. The detailed steps are described in the subsequent chapters. The FAC mechanisms are described in Section 2 together with numerous examples.

1.7 References 1.

Proceedings: Seventh International Conference on Cycle Chemistry in Fossil Plants, EPRI, Palo Alto, CA: January 2004. 1009194.

2.

Proceedings: Sixth International Conference on Cycle Chemistry in Fossil Plants, EPRI, Palo Alto, CA: April 2003. 1001363.

3.

Proceedings, Fifth International Conference on Cycle Chemistry in Fossil Plants, EPRI, Palo Alto, CA: November 1997. TR-108459.

4.

R. B. Dooley and J. A. Mathews, “The Current State of Cycle Chemistry for Fossil Plants”, Fifth International Conference on Fossil Plant Cycle Chemistry. In Reference 3.

5.

CHECWORKS™ Computer Program Users Guide, EPRI, Palo Alto, CA: August 1994. TR103496.

6.

CHECWORKS™ Fossil Plant Application - CHECUP™ Code, Version 1.0 User Guide, EPRI, Palo Alto, CA: 1998. TR-103198-P5.

7.

Cycle Chemistry Guidelines for Fossil Plants: All-Volatile Treatment, EPRI, Palo Alto, CA: November 2002. 1004187.

8.

Cycle Chemistry Guidelines for Fossil Plants: Phosphate Continuum and Caustic Treatment, EPRI, Palo Alto, CA: January 2004. 1004188.

1-11


9.

Cycle Chemistry Guidelines for Fossil Plants: Oxygenated Treatment, EPRI, Palo Alto, CA: 2005. 1004925.

10. Flow Accelerated Corrosion in Power Plants, EPRI, Palo Alto, CA: July 1998. TR-106611-R1. 11. Heat Recovery Steam Generator Tube Failure Manual, EPRI, Palo Alto, CA: November 2002. 1004503. 12. a) Interim Cycle Chemistry Guidelines for Combined Cycle HRSGs, EPRI, Palo Alto, CA: November 1998. TR-110051. b) The first revision of this guideline will be published at the end of 2005 as: EPRI, Palo Alto, CA. 1010438. 13. Guidelines for Controlling FAC in Fossil Plants, EPRI, Palo Alto, CA: November 1997. TR-108859.

1-12


2 FAC MECHANISM AND EXAMPLES IN CONVENTIONAL AND COMBINED CYCLE PLANTS

The phenomenon of FAC is well understood.(1) It is a process whereby the normally protective magnetite (Fe3O4) layer on carbon steel “dissolves” in a stream of flowing water (single-phase) or wet steam (two-phase). This process reduces or eliminates the oxide layer and leads to a rapid removal of the base material until, in the worst cases, the pipe or tube bursts. The FAC process can become rapid: wall thinning rates as high as 0.120 inch/yr (3 mm/yr) have occurred. The rate of metal loss depends on a complex interplay of many parameters including the feedwater chemistry, the material composition, the other materials in the feedwater systems, and the fluid hydrodynamics. This section provides discussion on the FAC mechanism. For single-phase FAC, this includes a description of the basic feedwater and HRSG evaporator chemistries and relates these to the different oxides that form on the material surfaces under different oxidizing-reducing potentials. This leads finally to how the hydrodynamic factors influence FAC. The key differences between single-phase and two-phase FAC will be highlighted. Finally, numerous examples are provided to illustrate the many facets of FAC in conventional and combined cycle HRSG plants.

2.1 Mechanisms of FAC 2.1.1 Introduction to Single- and Two-Phase Flow and FAC The FAC mechanism involves the dissolution of the oxide on the surface of the component. The oxide on the surface is controlled by the chemistry of the fluid (feedwater or HRSG evaporator water) in contact with the component. Thus understanding the solubility of the two oxides, Fe3O4 and FeOOH, that can form under reducing and oxidizing conditions, is of paramount importance in understanding the FAC mechanism and how to control it. Many factors influence FAC and the overall solubility of these oxides (Table 2-1).

2-1

EPRI Licensed Material FAC Mechanism and Examples in Conventional and Combined Cycle Plants

Table 2-1 Factors Influencing FAC in Fossil and HRSG Plants 1.

Hydrodynamics – Velocity, geometry, steam quality, temperature and mass transfer

2.

Water chemistry (feedwater in conventional and HRSG plants, and LP evaporator in HRSG) – ORP, oxygen and reducing agent – pH

3.

Component material composition – carbon steel – chromium, copper and molybdenum

This section will address each of the factors to provide an understanding of the FAC process. But first it is necessary to outline the overall fluid hydrodynamics for both conventional and HRSG plants in terms of the FAC processes and failure mechanisms. In the main feedwater line of conventional and HRSG plants, the fluid is essentially single-phase water. Here the overriding influence for corrosion and FAC is the feedwater oxidizing-reducing potential (ORP) or redox potential. For the carbon steel materials operating under reducing feedwater chemistry the oxide formed is magnetite (Fe3O4), and its solubility is strongly influenced by the reducing conditions. As shown in Table 1-3 this constitutes the highest probability for FAC in a fossil plant with the highest solubility being around 150°C (302°F) as shown later in this section. Simply changing the feedwater to an oxidizing treatment by eliminating the reducing agent and/or adding oxygen will result in the formation of ferric oxide hydrate (FeOOH). This reduces the solubility of the surface oxide by at least two orders of magnitude in the temperature range up to about 300°C (572°F). Thus FAC, as an active corrosion mechanism, will essentially be turned off. In the drain lines, shell side of heaters and the deaerator of a conventional fossil plant, two-phase flow will be predominant in certain areas of these pressure vessels. In these areas, it is not possible to increase the oxidizing potential and thus materials solutions generally have to be applied: weld overlay and temper bead repair (with chromium containing materials) or straight replacement with chromium containing materials. In HRSG low pressure evaporator circuits, which have both single- and two-phase flow, any single-phase FAC can be controlled, as indicated above, by eliminating the reducing agent in the feedwater so that it does not concentrate in the LP evaporator. To address any two-phase FAC, it is necessary to increase the secondary controlling factor of evaporator pH by increasing the feedwater pH (ammonia) or by adding a solid alkali (tri-sodium phosphate or NaOH) to the LP drum if allowed by the circuitry.

2-2


2.1.2 Feedwater Chemistry for Fossil and HRSG Plants Controls the Oxide on the Material Surface Corrosion and FAC are a balance between the growth of the oxide on the metal surface and its dissolution into the water. Under normal situations these two processes are approximately equal, or their growth reaches an equilibrium situation; in either case an oxide forms on the surface which provides protection. In the abnormal situation with FAC, the dissolution of the oxide into the water is greater than its growth on the metal surface so that the remaining thickness is below that needed to provide protection. In the most severe FAC cases, there is essentially no, or very little, oxide on the surface. This applies to both single- and two-phase FAC. In both, it is always the water phase that is responsible for the dissolution of the oxide. Thus the generation of feedwater corrosion products represents a continuum: from the normal and expected general corrosion to very high rates of FAC. Obviously the focus in fossil and HRSG plants is to reduce FAC as much as possible, which is indicated by a minimum amount of iron in the feedwater. The feedwater chemistry is critical to overall corrosion, FAC and reliability of fossil and HRSG plants. There are three distinctly different feedwater treatments: •

Reducing all-volatile treatment, AVT(R), which uses ammonia and a reducing agent. Here the oxidizing-reducing potential ORP, should be in the range –300 to –350 mV [Ag/AgCl/sat, KCl]. It should be noted that this range of ORP is not always achieved, because ORP is a careful balance between the levels of oxygen and reducing agent, and (5) because ORP is a function of pH, temperature, materials, and the sensor characteristics. Sometimes a reducing ORP can be as high as –80 to –100 mV.

•

Oxidizing all-volatile treatment, AVT(O), where the reducing agent has been eliminated. Here the ORP will be around 0 mV but could be slightly positive or negative.

•

Oxygenated treatment (OT) where oxygen and ammonia are added to the feedwater. Here the ORP can be as high as +100 to +150 mV.

A very achievable iron level for units operating with reducing treatments (AVT(R)) is less than 2 ppb of iron. For units operating with oxidizing treatments (AVT(O)), the iron levels can be around 1 ppb or less. Optimum feedwater chemistry can accomplish both, and EPRI’s new series (2) (3) (3) (4) of Cycle Chemistry Guidelines for AVT, PC, CT and OT contain a section on selecting and optimizing the treatment. These are also outlined in Section 6 of this Guideline. Table 2-2 provides a comparison of the feedwater chemistry limits for AVT and OT as a function of feedwater metallurgy.

2-3


Table 2-2 Comparison of Normal Feedwater Cycle Chemistry Limits for AVT and OT as a Function of Feedwater Metallurgy Parameter

AVT(R) Mixed-Metallurgy

AVT(R) All-Ferrous

AVT(O) All-Ferrous

OT All-Ferrous

9 – 9.3

9.2 – 9.6

9.2 – 9.6

D. 9 – 9.4 O. 8 – 8.5

< 0.2

< 0.2

< 0.2

< 0.15

Fe (ppb) at EI

<5

<2

< 2 (< 1)

< 2 (< 0.5)

Cu (ppb) at EI

<2

< 2*

< 2*

< 2*

O2 (ppb) at EI

< 5 (< 2)

< 5 (< 2)

< 10

D. 30–50 O. 30–150

O2 (ppb) at CPD

< 10

< 10

< 10

< 10

Reducing Agent

Yes

Yes

No

No

ORP (mV) at DAI

–300 to –350+

–300 to –350+

Oxidizing

Oxidizing

pH Cation Conductivity (µS/cm)

Notes: EI - economizer inlet, CPD - condensate pump discharge, DAI - deaerator inlet, D - drum unit, O - once-through unit * - Copper alloys may be present in condenser. + - These ORP values are meant to be indicative of a reducing treatment where a reducing agent is added to the feedwater, after the CPD, and oxygen levels are less than 10 ppb at the CPD. However, ORP is a sensitive function of many variables and may under these conditions be as high as –80 mV.

For HRSG plants with all-ferrous feedwater systems the feedwater chemistry should be AVT(O) to avoid single-phase FAC in the feedwater and LP evaporator circuit. For both fossil and HRSG plants, the basic idea of AVT is to minimize corrosion and FAC by using deaerated high purity water with elevated pH. The pH elevation should be achieved by the addition of ammonia; organic amines are not needed, required or recommended. The actual pH range depends on the cycle metallurgy as indicated in Table 2-2. The use and application of AVT(R) in either type of plant with all-ferrous feedwater systems can result in FAC as described below. In response to the problems of corrosion and FAC, OT and AVT(O) were introduced. The primary difference between these treatments and AVT(R) is that the oxidizing-reducing potential (ORP) will always be oxidizing. It is this basic change that provides the tremendous benefits of reducing corrosion, eliminating active FAC, and minimizing corrosion product transport.

2-4


2.1.3 Factors Affecting the Growth of Magnetite with AVT(R) which are the Basis for FAC With AVT(R), the protective cover layer on the iron based materials (carbon steels) in the condensate and feedwater systems up to about 300 °C (572 °F) consists almost exclusively of magnetite. 3Fe + 4H2O → Fe3O4 + 4H2

(2-1)

This reaction is considered to be the sum of two simultaneous processes: First Process A direct reaction occurs between iron and reducing water to form soluble species and hydroxides. Reducing feedwater is considered to contain less than 10 ppb oxygen and a reducing agent; this will give an ORP in the reducing range as indicated in Table 2-2. When iron corrodes in an aqueous solution, both oxidation and reduction reactions occur at the anodic and cathodic sites respectively. At the anodic site, an oxidation process occurs which involves the dissolution of iron into iron ions and free electrons: Fe → Fe2+ (solution) + 2e–

(2-2)

At the cathodic site, a reduction process occurs which is a gain of electrons. This is hydrogen evolution: 2H+ (solution) + 2e– → H2 (evolved from the surface)

(2-3)

In reducing alkalized water, the cathodic reaction: – – 2H2O + 2e → 2OH + H2

(2-4)

Combining the anodic and cathodic reactions: Fe + 2H2O → Fe(OH)2 + H2

(2-5)

Both ferrous ions and ferrous hydroxide can be obtained according to an equilibrium reaction: 2+ – Fe + 2OH

⇌ Fe(OH)2

(2-6)

Second Process Magnetite forms through the Schikorr reaction: 3Fe(OH)2 → Fe3O4 + H2 + 2H2O

(2-7)

2-5


This reaction has been well described by Sweeton and Baes(6) and by Tremaine and LeBlanc.(7) A schematic showing the growth mechanism and morphology of Fe3O4 under AVT(R) conditions is shown in Figure 2-1. This protective magnetite is usually thin (< 30 µm) and exhibits lots of oxide hydrates and loose (non-protective) magnetite particles in the outer layers.

1

Fe = Fe2+ + 2e– 2 H2O + 2e– = 2 OH– + H2

2

Fe2+ + OH– = Fe(OH)+ 2 Fe(OH)+ + 2 H2O = 2 Fe(OH)2+ + H2

3

Fe(OH)+ + 2 Fe(OH)2+ + 3 OH– = Fe3O4 + 4 H2O

Figure 2-1 Schematic of Magnetite Growth and Morphology under Reducing AVT Conditions

The formation of magnetite (Reaction 2-7) is inhibited by increasing pH, which causes a reduction of the Fe2+ and Fe(OH)+ ion concentrations corresponding to the solubility products of Fe(OH)2 or the dissociation constants of the reactions: + – Fe(OH)2 → Fe(OH) + OH

(2-8)

Fe(OH)2 → Fe2+ + 2OH–

(2-9)

Figure 2-2 illustrates how the corrosion and dissolution of magnetite is reduced by increasing (8) pH.

2-6


Figure 2-2 Corrosion Product Release from Carbon Steel as a Function of pH(8)

Figure 2-3 shows that the solubility of magnetite rises with increasing temperature, then decreases with a steep drop to 300°C (572°F). This results in undesired magnetite deposits in this temperature range. To maintain the solubility of ferrous hydroxide (Fe(OH)2) in the feedwater below or equal to that of magnetite at around 250°C (482°F) and to exclude the possibility of oversaturation, a minimum pH of at least 9.6 should be maintained.(9) A pH of 10 would be even better, but is limited in the cycle if the unit has a copper tubed condenser. The dissolution of magnetite into the reducing feedwater is also a function of potential. As shown in Figure 2-4, decreasing the ORP leads to increasing amounts of iron in the feedwater. This is, of course, the basis of single-phase FAC and the reason why all-ferrous feedwater systems should be operated on AVT(O) (no reducing agent) or OT.

2-7


Figure 2-3 Solubility of Magnetite as a Function of Temperature at Various Ammonia Concentrations.(9)

2-8


Figure 2-4 Change in Oxidizing-Reducing Potential (ORP) and Feedwater Iron Levels (Fe) at the Economizer Inlet when Hydrazine (N2H4) was Gradually Reduced on a 600 MW Fossil Drum Unit with an All-Ferrous Feedwater System

As shown in Figure 2-1, with AVT(R), the steel surface in contact with water is covered by a magnetite layer. It consists of a topotactic and an epitactic part. As shown in the figure, this dense topotactic layer grows directly on the surface of the steel; the more porous epitactic layer forms above the topotactic layer. In the low temperature region, the topotactic part of the magnetite layer is very thin and the Fe2+ ions are easily transported from the steel surface to the oxide/water phase boundary through pores in the magnetite layer. The feedwater pH elevation contributes to the formation of Fe(OH)2, which transforms (in the low temperature region relatively slowly) to magnetite according to the Schikorr reaction (Reaction 2-7). In the feedwater system, thermodynamic solubility equilibrium actually cannot be reached. For this reason, the application of the known magnetite solubility data to real plant cycles is not entirely practical. In most plant cycles, ferrous iron concentrations are comparable to those given in Figure 2-2. In summary the basic single-phase FAC mechanism is intimately linked to the use of reducing treatments. For AVT(R) chemistry, the ORP is typically reducing and may be less than – 300 mV, and the level of feedwater corrosion products will be less than 10 ppb. Most fossil and HRSG plants can easily achieve 5 ppb; this situation is regarded as “normal” and not of major concern from an FAC viewpoint.

2-9


However, for a unit with AVT(R) chemistry and high rates of FAC, the ORP will also be reducing; but because of the local flow hydrodynamics, the total corrosion/dissolution process is faster. In the worst cases, FAC will be so fast that there is only a very thin layer of Fe3O4 on the surface. Figure 2-5 shows such a case. Importantly, the level of feedwater corrosion products can be much more than 10 ppb. Section 2.1.6 discusses how the factors in Table 2-1 affect the FAC process.

Figure 2-5 Carbon Steel Material in Reducing Feedwater at a Location with Severe FAC. Note very thin Fe3O4 on surface.

2.1.4 Factors Affecting the Growth of Ferric Oxide Hydrate (FeOOH) with AVT(O) and OT Elimination of the reducing agent (AVT(O)) and/or addition of oxygen (OT) raises the free corrosion potential of the steel by several hundred millivolts. The increase is especially distinct in the temperature range below 150°C (300°F) (Figure 2-6).

2-10


Figure 2-6 Free Corrosion Potential for Carbon Steel as a Function of Oxygen and Temperature(10)

With these oxidizing treatments, the protective cover layer pores become plugged with ferric 2+ oxide hydrate FeOOH or ferric oxide Fe2O3 (see Figure 2-7). In this way, the Fe ion diffusion from the steel surface through the pores in the protective epitactic cover layer to the oxide/water phase boundary is strongly inhibited. The few ferrous ions leaving the steel are oxidized either in the layer pores or right at the protective layer/water boundary. The following oxidation reactions are assumed:(11) 2 Fe(OH)2 + 1/2 O2 + 2 H+

=

2 Fe(OH)2+ + H2O

(2-10)

2 Fe(OH)2 + 1/2 O2

=

2 FeOOH + H2O

(2-11)

2Fe(OH)2 + 1/2 O2

=

Fe2O3 + 2 H2O

(2-12)

2-11


Figure 2-7 Schematic of Oxide Growth and Morphology with AVT(O) and OT

For this reason, the ferrous ion concentration in the feedwater should be around 1 ppb under AVT(O) conditions and below 1 ppb for OT conditions. Additionally, the ferric ion concentration becomes almost undetectable. As an explanation of this fact, Figure 2-8 shows the calculated solubility of ferric oxide γ-Fe2O3, ferric oxide-hydrate γ-FeOOH, and ferric hydroxide.(11) This figure also shows the solubility field of magnetite plotted from Figure 2-3, and illustrates the much lower solubility of the ferric oxide hydrates that form with oxidizing treatments (AVT(O) and OT).

2-12


Figure 2-8 Solubility of Ferric Hydrate-Oxides at 0.5 ppm NH4OH (Data extracted from Reference 11) Compared with Fe3O4 Solubility (extracted from Figure 2-3)

The corrosion of carbon steel materials in AVT(O) or OT is characterized in the initial phase (steel without protective layer) by the topotactic (inner layer) transformation of individual ferrite grains to magnetite. Here, ferrous ions escape into the fluid boundary layer. A part of these ions is transformed epitactically (outer layer) directly to magnetite. For its formation, the following total reaction is established.(12) 2+ + 3 Fe + 1/2 O2 + 3 H2O = Fe3O4 + 6H

(2-13)

The cover layer morphology is determined by the reactions:(13) + – 2 Fe3O4 + H2O = 3 Fe2O3 + 2H + 2 e

(2-14)

Fe3O4 + 2 H2O = 3 FeOOH + H+ + e–

(2-15)

and

Fe2O3 may occur also as an aging product. The result is a double oxide layer on the steel, consisting of magnetite covered by a layer with a high hematite content as shown on Figure 2-7.

2-13


The corrosion product formation in the passive region is controlled by the diffusion of metal ions through the passive film and is usually very small.(14) The following reaction is given for the formation of hematite:

aging dehydration Fe + 3 OH -> Fe(OH)3 -> Fe2O3.nH2O -> FeOOH -> Fe2O3 3+

–

(2-16)

Even with elevated temperature (up to around 300°C, 572°F), there is formation of the oxide protecting layers which have a very low corrosion product release rate into the flowing water. The major parameter for the adjustment of the desired free corrosion potential above the passivation potential is the transport of the dissolved oxygen to the steel surface. A positive effect is produced by: •

An oxygen level increase (increase of the difference between the oxygen concentration in the core flow and the oxygen concentration at the boundary steel/laminar sublayer).

•

An increase of the flow rate (reduction of the thickness of the laminar sublayer).

•

A temperature elevation (increase of the oxygen diffusion coefficient).

In summary, the oxidizing treatments (AVT(O) and OT) have the ability to deactivate the singlephase FAC mechanism up to about 300°C (572°F). Under these conditions the ORP is greater than zero (Table 2-2); conditions which favor the growth of FeOOH. This formation does two things: i) reduces the overall corrosion rate because the diffusion (or access) of oxygen to the base material is restricted (or reduced), and ii) reduces the solubility of the surface oxide layers (Figure 2-8). Thus from an FAC perspective, this FeOOH layer dissolves much slower (at least two orders of magnitude slower) than magnetite into the flowing feedwater, under exactly the same hydrodynamic conditions that existed previously with AVT(R) chemistry. The overall result is that the measured feedwater corrosion products can be much less than 1 ppb and FAC is minimal. Figure 2-9 shows the protective oxide formed after one year on oxidizing feedwater treatment; this is exactly the same area shown in Figure 2-5, which under reducing feedwater treatment (AVT(R)) had suffered severe FAC and failure. Finally it must be noted that not all feedwater systems in fossil and HRSG plants can run under an oxidizing regime. This is discussed in the next section.

2-14


Figure 2-9 Metallographic Cross-Section through an Economizer Inlet-Header Tube After Operating under an Oxidizing Feedwater Condition for One Year. The protective oxide formed on the surface should be compared to that under a reducing condition which resulted in FAC (Figure 2-5).

2.1.5 Importance of Feedwater Metallurgy for FAC in Fossil Plants The feedwater system in fossil plants can consist of all-ferrous materials (all-ferrous system) or a mixture of copper containing feedwater tubing and ferrous piping (mixed-metallurgy systems). The exact configuration has important ramifications on the choice of feedwater chemistry, and on FAC. There are essentially two types of all-ferrous systems: those containing only carbon steel in the tubing and piping, and those containing stainless steel tubing and carbon steel piping. As can clearly be seen in Table 1-3 most of the serious FAC failures in fossil plants have occurred when all the feedwater heater tubing (both LP and HP) is stainless steel, and the chemistry is AVT(R). This implies that the reducing environment is more severe in the HP feedwater when the tubing is stainless as compared to when the tubing is carbon steel or copper-based. Mixed-metallurgy systems can only use AVT(R) feedwater chemistry(15) which maintains a reducing environment under all operating regimes to protect the copper based tubing (Table 2-2). This means that the carbon steel interconnecting piping and the economizer inlet tubing must also be exposed to the same reducing environment. Review of the extensive EPRI database on FAC and observation of Table 1-3 indicates that no serious FAC failures have occurred in fossil plants with mixed-metallurgy systems; however wall loss associated with FAC has been observed in these plants. This apparent anomaly relates to the fact that the copper alloys and oxides act as a catalyst for the reaction between the reducing agent (hydrazine) and dissolved oxygen in the feedwater. Because serious failures have occurred in nuclear plants with mixed2-15


metallurgy systems, the carbon steel components in mixed-metallurgy feedwater systems must be subjected to the same rigorous FAC programs as for the all-ferrous systems. 2.1.6 FAC Influencing Factors Sections 2.1.3 and 2.1.4 have described how the FAC mechanism is dependent on the solubility of the surfaces oxides. Single-phase FAC essentially occurs with AVT(R) chemistry, where magnetite is the surface oxide; its solubility peaks at around 150°C (300°F) (Figure 2-3). Severe FAC occurs when the dissolution and exfoliation or spalling of magnetite from the surface is greater than its growth on the pressure vessel/tube surface, thus increasing the amount of particulate magnetite in the feedwater or LP HRSG evaporator. This section discusses the factors which accelerate this dissolution process. The FAC mechanism under reducing conditions is further illustrated in Figure 2-10. 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 centerline of the pressure vessel/tube. In this case, the growth of Fe3O4 at the oxide/steel interface matches the dissolution. At higher velocities, the action of the friction between the water and the 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 cannot match the flow-accelerated dissolution, exfoliation and spallation and the oxide thickness reduces and thus becomes less protective. This is FAC. In this case, the levels of iron oxide (particulate) measured in fossil plant and HRSG feedwater systems and in HRSG evaporator circuits are likely to be high, and can be over 15–20 ppb.

Figure 2-10 Mechanism of the 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.

2-16


It should be emphasized here, that while the discussion to this point has continually mentioned that FAC relates to “dissolution” of Fe3O4 from the surface of the oxide layer under reducing conditions, the amount of dissolved Fe3O4 measured in the water, under severe FAC conditions, is not high enough to explain the rate based solely on dissolution. Under the turbulent conditions discussed in the last paragraph, it becomes clear that “particles” of oxide are “dissolved” from the surface (Figure 2-10). This could be described as “exfoliation” or “spallation” as above. High monitored levels of iron, under severe FAC conditions, always consist of over 95% of “particulate” iron. A similar mechanism was recently discussed to explain FAC in a CANDU Nuclear Plant.(22) As shown in Table 2-1, the rate of wall loss (FAC) is affected by the following factors: ORP or redox potential (related to the balance between dissolved oxygen and reducing agent), pH of the water, temperature, velocity, mass transfer, geometry and upstream influences, and alloy composition. Oxidizing-Reducing Potential, ORP (or Redox) is by far the most important factor for singlephase FAC. It is important to note that in fossil and HRSG plants, the ORP is usually reported as a voltage versus that of a Ag/AgCl (sat. KCl) reference electrode. ORP reflects the balance between various conjugate redox systems and must not be confused with the corrosion potential.(5) However, it does provide a useful indicator of the corrosivity of the flowing water. ORP is sensitive to the materials of construction and to the temperature because of the effects of temperature on the redox reactions.(5) ORP also changes with pH, partial pressure of oxygen in the flowing water, mass transport properties and flow rates; thus ORP cannot be compared from unit to unit. Not only does ORP control the surface oxide that forms in feedwater or evaporator water, AVT(R) or AVT(O) (or OT), but as the ORP becomes more reducing the greater is the possibility for FAC (see Figure 2-4). Changing to AVT(O), by eliminating the reducing agent and/or adding oxygen (OT), essentially reduces the possibility of dissolution into the flowing water to very low values, even in areas where FAC was severe with AVT(R). pH of the Water is the second most important factor as it also affects the solubility of the surface Fe3O4 (Figure 2-3). Generally a higher pH will reduce the amount of corrosion and FAC. FAC is directly related to the pH of the fluid in contact with the oxide surface at the “hot” operating temperature, not the cold pH as measured in the feedwater or HRSG evaporator. Temperature is important as it influences several of the fluid properties: the pH of the water or wet steam, the solubility of the oxide layer, the rates of the oxidation and reduction reactions, and the variables related to mass transfer (Reynolds, Schmidt and Sherwood numbers, fluid density and viscosity, steam quality and void fraction). Laboratory data and field experience indicates that FAC tends to peak at temperatures in the range of 150–180°C (300–350°F). Velocity. There is a strong dependence of FAC on flow velocity. This is not simply determined by the bulk fluid velocity but also by the factors which influence the local velocity: surface geometry, flow path geometry and turbulence.

2-17


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. Geometry is the factor which locates where FAC will occur. Certain geometries affect mass transfer due to changes in local velocity and turbulence. FAC does not often occur in straight pipes or tubes, but is more often encountered at points of hydrodynamic disturbance. These include elbows, tight bends, reducer tees, locations downstream of flow control orifices and valves, and even fabrication discontinuities. The geometric enhancement of these features generally increases turbulence. There is extensive literature on geometric factors, and they are discussed later in this guideline (Section 4), especially in the context of using an analytical model (e.g. CHECUP™) to prioritize inspection locations.. Table 2-3 provides a comparison of geometric enhancement factors from various investigators. These factors are related to the velocity/turbulence created by the particular geometry or fitting. Larger values denote a greater propensity for flow disturbance and thus turbulence, which increases the mass transfer coefficients.

2-18


Table 2-3 Published Geometric Enhancement Factor Values for Piping Components with Singlephase Flow as Used in Various FAC Models Geometric Factors for FAC Geometry or Fitting Straight Pipe1 90° Elbow Reducer

ChexalHorowitz(17)

Remy(18)

Woolsey(19)

Kastner(20)

1.0

1.0

1.0

1.0

1.0

5.75 to 13

3.7

2.1

1.7

6.0 to 11

2.5 1.8

3.2 2.5

3.58 to 6.24

(large end) (small end)

Pipe Entry Expander

Keller(16)

4.0 (large end) (small end)

3.0 2.8

3.6

Pipe Expansion Orifice

2.0 4.0 to 6.0

5.0

2.9

3.0 to 4.0

Tee: Flow (run) Combination (branch)

3.74

5.0 5.0

5.7

2.0 to 2.5

Tee: Flow Separation

18.75

5.0 4.0

5.7

(run) (branch)

1. All the geometry factors are based on comparison with straight pipe.

Alloy Composition is important because even trace amounts of chromium (and copper and molybdenum) can significantly reduce the solubility of magnetite, and thus of FAC. An alloy with a nominal chromium content of 1% will have low or negligible FAC, and there is evidence that amounts of chromium as low as 0.1% will significantly reduce FAC. Often organizations use 1.25% Cr alloys for replacement of FAC damaged areas. These alloys are also used in HRSG evaporator circuits susceptible to FAC; however unless the feedwater and evaporator chemistries are changed also, then FAC can continue to occur at other locations not changed to 1.25% Cr or higher. 2.1.7 Two-phase FAC As indicated in Table 1-2, two-phase FAC occurs in conventional fossil plant drain lines, deaerators and on the shell-side of low pressure heaters. In combined cycle/HRSG plants it occurs in low pressure economizer and evaporator circuits. Two-phase FAC can occur whenever a highly turbulent steam-water mixture comes into contact with a carbon steel surface. The ratio of the area occupied by vapor to the total pipe/tube area is the void fraction. The mass transport, and hence the FAC rate, are impacted by changes in void fraction. Void fraction and quality are not equivalent because the steam and water move with different velocities. Steam quality has a significant effect because FAC can only occur if the wall is continuously wet. FAC does not occur in dry steam. If steam quality is greater than zero, only 2-19


the liquid phase produces FAC damage. The two-phase flow regime is characterized by the metal wall (oxide) being wetted by a flowing film of water which moves slower than the bulk twophase mixture. Generally two-phase flow is more turbulent than single-phase, and thus FAC is greater. As discussed in Section 2.1.7, FAC is not purely a “dissolution” phenomenon, but under severe FAC conditions (turbulence), particles of Fe3O4 become the main content of iron in the fluid (Figure 2-10). The same phenomenon happens with two-phase flow and FAC where the “exfoliation” and “spallation” of the Fe3O4 from the surface is influenced both by the dissolution and the surface turbulence. As with single-phase FAC, the two-phase variety is limited to a maximum temperature of around 280–300°C (536–572°F), and is dependent on the solubility of the surface oxide (magnetite) and the mass transfer coefficient (how easily the soluble magnetite can be transported from the surface). To address single-phase FAC, the solubility of the surface oxide can be markedly decreased by increasing the ORP to the oxidizing range by changing from AVT(R) to AVT(O). It can also be decreased by increasing the pH of the liquid. For two-phase FAC, the option of increasing the ORP cannot be applied because the very high partitioning of oxygen to steam means that the oxygen level in the water adjacent to the surface is very low. So the main (chemical) option is to try to increase the pH locally at the saturation temperature at the FAC site on the surface oxide. Ammonia used in fossil and HRSG plant feedwater does not perform well in these two-phase environments as its basicity decreases markedly with temperature and it partitions to steam resulting in lower pH in the water adjacent to the surface. Several amines have better distribution properties but are not acceptable in fossil and HRSG plants because of the thermal degradation, breakdown products and increased cation conductivity levels throughout the fossil and HRSG plants. In conventional plants, the solution must be materials related, where the surface material contains more than 0.5% chromium. A material or overlay with 1.25% Cr or higher is recommended. For HRSG evaporator circuits, the best option appears to be the use of a solid alkali, such as trisodium phosphate or NaOH, providing the HRSG circuitry and attemperation systems allow. Chromium containing alloys can be used at “known” FAC sites, but it must be recognized that this only addresses FAC locally and not the root cause of the problem.

2.2 FAC Examples, Morphology and Locations in Conventional Fossil Plants 2.2.1 Single-phase FAC in Conventional Fossil Plants The predominant locations for single-phase FAC in fossil plants and the most recent and historical rankings are shown in Table 1-2.

2-20


Figure 2-11 shows an example of an HP tube sheet in a feedwater system where all the HP and LP heater tubing was manufactured in stainless steel. This is a good example of the dissolution phenomenon, which is FAC. There is no evidence of any mechanical (erosive) damage. The surface looks like an orange peel. There is also some evidence of FAC damage in the tube holes. Figure 2-12 shows an FAC failure in an economizer inlet header tube. The nipple weld is shown, and the damage starts between 1–2 in (2.5–5 cm) from the header bore. This is obviously an extreme example of FAC. The typical orange peel appearance of single-phase FAC is clearly evident on the inside tube surface. Figure 2-13 shows a close up of the superficial appearance of FAC. Where the FAC is minor or just initiating (towards the lower right of Figure 2-13) a series of pit-like features are evident on the surface. In some cases these have a chevron or horseshoe appearance with the tip pointing in the direction of flow. This chevron appearance is due to small turbulent effects near and on the surface oxide causing dissolution of the oxide because of increased mass transfer. As FAC becomes more severe then these chevrons overlap until, where the FAC is most severe, the surface takes on the continuous scalloped or orange peel appearance. This scalloped appearance usually occurs in areas where significant wall loss has occurred. If these areas are analyzed metallurgically, then there will be very little oxide remaining on the surface (see example in Figure 2-5). Thus when the area is first viewed, if often has the orange color of flash rust if not protected from moisture during the shutdown process. When the oxide is very thin (less than 1 µm or 0.00004 in) the surface often has a metallic appearance due to the almost transparent film of oxide (magnetite). Figure 2-14 shows a higher magnification view of the surface of an active FAC site which shows the microscopic scalloped appearance.

2-21


Figure 2-11 FAC on an HP Feedwater Heater Tube Sheet. All HP and LP heater tubing in this unit was stainless steel. The feedwater was AVT(R).

Figure 2-12 FAC Failure and Damage on an Economizer Inlet Header Tube. All HP and LP heater tubing in this unit was stainless steel. The feedwater was AVT(R).

2-22


Figure 2-13 Typical Surface Appearance of FAC. The feedwater water flow was from top to bottom.

Figure 2-14 Typical Scalloped Appearance of Single-phase FAC as Viewed with a Scanning Electron Microscope

2-23


2.2.2 Two-phase FAC in Conventional Plants As indicated in Table 1-2, the predominant locations for two-phase FAC are drain lines (HP and LP heaters), deaerator and the LP heater shell. Figure 2-15 illustrates one of the typical appearances of two-phase FAC, which shows alternate areas of “fast” and “slow” FAC which is sometimes call tiger striping. The black parts of the surface are the severely corroded regions as there remains only a very thin oxide (magnetite) layer. Sometimes these areas appear black or metallic-like due to the transparent film of magnetite remaining on the surface. Deaerators Usually most of the deaerator is protected. For units operating under reducing feedwater conditions (AVT(R)), this “protected” surface will be grey/black. For units with oxidizing feedwater the “protected” areas will be red. Two-phase FAC occurs in deaerator vessels primarily near to, and associated with, locations where fluids enter the deaerator. These might be the cascading drains or extractions. At each of these locations, there is a difference in temperature/pressure between the entering fluid and the bulk fluid in the deaerator, and thus the fluid flashes upon entry into the deaerator. This provides a local two-phase (turbulent) media, where any oxidizing power of the liquid on the surface is lost because of the partitioning of any oxygen to the steam phase. While these locations are, of course, present on units under reducing conditions (AVT(R)), they are much more visible with units on oxidizing cycles (AVT(O) or OT), as the two-phase FAC appears as black or shiny black discontinuities to the red surface protection. Figures 2-16 and 2-17 show two such typical areas where, in fact, severe FAC has already been previously repaired with weld overlay. Figure 2-18 shows a good example where a number of different lines enter the deaerator. The protected (red) areas are evident, as are the black areas where the twophase FAC occurs. Sometimes these black areas appear shiny black (almost enamel-like).

2-24


Figure 2-15 Typical Example of “Tiger-Striping” Appearance of Two-phase FAC

Figure 2-16 Severe Two-phase FAC in a Deaerator Located at a Fluid Entry Position

2-25


Figure 2-17 Severe Two-phase FAC in a Deaerator Located at a Fluid Entry Position: Note that the Two-phase Damage has been Weld Overlayed Previously

Figure 2-18 Good Example of Diverse Areas of Two-phase FAC (Black) in an Area which is Generally Protected (Red) Because of the Maintenance of Single-phase Flow

2-26


Low Pressure Heater Shells Thinning of feedwater heater shells has been observed in nuclear plants since the 1980s. Many of these incidents required repairs. Over the last eight years additional FAC in heater shells of fossil plants has been reported. Figure 2-19 shows a fossil plant example where a small leak was found. The ID surface shows regions where the FAC was severe surrounding the leak, and also alternating fast/slower damage (wavy appearance) further from the leak. This is a very typical appearance of two-phase FAC. Figure 2-20 shows the location where severe FAC initiates and illustrates the dramatic loss of wall thickness dependent on the FAC rate. Figure 2-21 shows that the surface where FAC occurs has no protective oxide, and also illustrates the clear demarcation with the area where no FAC occurs: here there is protective oxide and also deposition. It should also be noted (lower right) that the FAC preferentially attacks the pearlite regions of the carbon steel. Figure 2-22 shows a dramatic example of two-phase FAC in a LP heater shell. This unit was operated on OT, and the red areas define where there is protection under the single-phase flow. The black shiny areas illustrate where the two-phase flow occurs and cannot maintain the protection because of the missing oxidizing power of the liquid in the two-phase media. These two-phase areas are near to, and associated with, the location where the LP cascading drains enter the heater from the next highest LP heater and flashes. This is shown on Figure 2-23 (second vertical pipe from the right). This emphasizes the need to identify the entry of the drains and also to acquire information on the temperatures and pressures of the entering fluid compared with those in the bulk of the heater. Figure 2-24 shows a nice NDE thickness survey of the shell of this LP heater, illustrating the severe loss of wall thickness in the two-phase areas.

ID

OD

Figure 2-19 Internal and External Views of Two-phase FAC on the Shell of a LP Heater. Note the Typical Wavy Pattern of the Two-phase FAC on the ID.

2-27


Figure 2-20 Metallographic Cross-section through the LP Heater Shell Shown in Figure 2-19. The FAC rate increases towards the right side of the figure.

Up to 0.08” thick deposit

0.00005” thick oxide scale plus occasional ribbons of blistered magnetite

Figure 2-21 Further Metallographic Information of Figure 2-20 Showing the Demarcation Between Areas that Have Not Suffered FAC (to the left) and Those Where Severe FAC Has Occurred (towards the right). In the former areas there is a protective oxide (magnetite) and deposition (lower left). In the latter (lower right) there is no protective oxide and the FAC has preferentially attacked the pearlite (dark regions) of the carbon steel.

2-28


Figure 2-22 Two-phase FAC (Black/Shiny) Occurring on the Shell Side of the Lowest LP Heater Shell on a Unit on OT. The red areas are protected by FeOOH in the single-phase areas.

Figure 2-23 Same LP Heater Shell as Shown in Figure 2-22. This one shows the location of the cascading drain from the next highest LP heater (second vertical pipe from the right). Note that the impingement plate is protected (red), indicating that the impinging fluid at this stage is single-phase.

2-29


Figure 2-24 NDE Survey of the Two-phase FAC Damage on the LP Heater Shell Shown in Figures 2-22 and 2-23

Drain Lines As indicated on Table 1-2, FAC damage in drain lines is the most predominant location in fossil plants, and can be single- or two-phase because of the varying nature of the drainate. An example of a drain line failure is shown in Figure 2-25. This is a catastrophic example. However, most FAC drain line failures are small leaks or pin holes, which are most often quickly repaired by maintenance staff by pad welding, weld overlaying or pipe section replacement with 1.25% chromium material. The last is the preferred repair approach.

Figure 2-25 Illustrating the Catastrophic Nature of FAC Failures in Drain Lines

2-30


Single-phase and two-phase damage have already been illustrated previously in this section. It is important to identify which is occurring and not simply allow the drain line to be repaired by the temporary or palliative processes. Single-phase FAC in drain lines is dependent on the operation of the heater vents. Usually on units operating with a reducing environment (AVT(R)), the heater vents are open. Optimum performance for units on OT requires the vents to be closed. Units operating on AVT(O) operate under both conditions. When the vents are open, any residual oxygen (AVT(O) or AVT(R)) or any added oxygen (OT), and some of the ammonia will exit through the vents due to partitioning. Then there will be insufficient oxidizing power in the drain lines to provide single-phase protection. Closing the vents on OT units (and under special circumstances for AVT(O)), assists in increasing the oxidizing power of the media. Thus operation of the heater vents can be optimized to produce an oxidizing environment in the drain lines, which should address singlephase FAC. Two-phase FAC in drain lines cannot be satisfactorily addressed chemically, so must be identified by prediction or iron monitoring, and subsequent inspection. As indicated above, it is advisable in both cases to replace the susceptible drain line length with a 1.25% Cr or higher alloy. 2.2.3 FAC in Conventional Fossil Plants with Mixed-Metallurgy Feedwater Systems (Heater Tubing Contains Copper Alloys) All the areas discussed in Sections 2.2.1 and 2.2.2 are susceptible in mixed-metallurgy feedwater systems. The major difference for these systems is that to minimize the corrosion of copper alloys, the feedwater chemistry must be AVT(R) and thus requires a reducing agent and low levels of air in-leakage (< 10 ppb oxygen at the condensate extraction pump). This essentially means that the carbon steel interconnecting pipework throughout the feedwater line will be reducing. See discussion in Section 2.1.5. It should, however, be noted (Table 1-3) that no serious catastrophic failures have occurred in mixed-metallurgy feedwater systems, but that FAC is common throughout the feedwater (Table 1-2). 2.2.4 Other Locations for FAC in Fossil Plants FAC has been observed in other locations in fossil plants: •

LP drain lines into the turbine exhaust prior to the condenser (Figure 2-26), and in the condenser neck near to, and associated with, fluid entry (drains) (Figure 2-27).

•

Turbine diffuser and exhaust ducting from the last stage of the LP turbine (Figure 2-28). FAC has also been seen on the casing between the stationary turbine blades, and in very bad cases on the attachments of the stationary blades.(24)

•

Various boiler circulating water pump seal lines.

2-31


Figure 2-26 Example of FAC Damage in a LP Drain Line into the Turbine Exhaust Prior to the Condenser

Figure 2-27 FAC Damage on Exhaust Hood at Condenser Neck. Note serious previous damage has been repaired by “attaching” plates.

2-32


Figure 2-28 FAC Damage to Turbine Diffuser and Exhaust Ducting at LP Turbine Exhaust of a 450MW Unit with a Drum Boiler. Note the Wavy Appearance Typical of Two-phase FAC. Source: Jonas Inc.

2.2.5 Summary for FAC in Conventional Fossil Plants Based on the understanding of the FAC mechanisms (Section 2.1), the various examples of FAC (Section 2.2) and the results of the EPRI Benchmarking Process (Appendix A), the following conclusions can be drawn for control of FAC in fossil plants: •

Single-phase FAC can be controlled by feedwater chemistry. Table 2-2 provides the optimum treatment guidelines for all possible feedwater systems and chemistries.

•

In all-ferrous feedwater systems, use of an oxidizing feedwater treatment (AVT(O) or OT) will minimize corrosion and transport. Reference to the appropriate EPRI cycle chemistry guidelines is required to ensure optimum treatment.

•

In mixed-metallurgy feedwater systems (copper alloys in the feedwater heaters) use of a reducing feedwater treatment is required (AVT(R)) to provide protection to the copper alloys. A careful balance is then required for the interconnecting carbon steel pipework. Again reference to the appropriate EPRI cycle chemistry guideline is required.

•

For both all-ferrous and mixed-metallurgy feedwater systems, the optimum approach can only be obtained by monitoring the iron and copper levels as indicated in Table 2-2.

•

Two-phase FAC will need a materials solution which involves using a 1.25% Cr or higher alloy for weld overlaying or replacement. 2-33


•

Special attention and analysis is required for deaerators and LP heater shells. Inspection is needed and again replacement or overlay is the optimum approach using a 1.25% Cr or higher alloy. Here initial inspection can often be visual to identify the susceptible areas.

•

Drain lines should also be inspected and thinned or failed pipes replace with a 1.25% Cr or higher alloy.

These examples and understanding of the mechanisms leads to the primary inspection priority for fossil plants: •

Units with stainless steel HP and LP heaters

•

Units with stainless steel in HP or LP heaters

•

Units with carbon steel heaters

•

Units with mixed-metallurgy heaters

2.3 FAC Examples, Morphology and Locations in Combined Cycle/HRSGs 2.3.1 FAC in HRSG Tubing The latest statistics for HRSG tube failures are shown in Table 1-4, and indicate that FAC is the second most important failure mechanism. Failures have essentially occurred in LP evaporators and economizers, but a few failures have also occurred in HP economizers. As FAC occurs across the temperature range 70° to around 300°C (160°–570°F) (Figure 2-3) with a maximum near 150°C (300°F), overall the regions of concern are: •

Economizer tubes at inlet headers

•

LP evaporator tubes especially at bends

•

LP drum internals

•

Horizontal LP evaporator tubes at bends

It should, however, be noted that IP evaporator tubes can also move into the susceptible range if a triple-pressure HRSG is operated at reduced pressure. FAC occurs equally in horizontal and vertical gas path units and is also common in LP drums. Figure 2-29 shows a typical location in a horizontal gas path unit, and Figure 2-30 shows an FAC failure. The typical location is associated with the dogleg or pant leg as the tube enters the header. The differences between single- and two-phase FAC have been discussed in Section 2-1. Both types of FAC can occur in the LP evaporator circuits and it is important to recognize exactly which type is occurring. Most of the LP evaporators in triple-pressure HRSGs operate at rather low pressures (60–80 psi, 0.4–0.5 MPa), which means that the fluid is two-phase. However, it is possible to have both single- and two-phase FAC in these circuits. Figure 2-31 and 2-32 illustrate 2-34


examples and show the characteristics. In the cases of single-phase FAC, the damaged surface typically exhibits an orange peel appearance as shown in Figures 2-31a and 2-32a. The other characteristics of single-phase FAC are chevron marks or horseshoes towards the extremities of the damage (slower FAC areas). In cases where two-phase flow is present, the appearance of FAC is more scalloped or wavy-like as indicated in Figure 2-31b and 2-33. This is exactly as seen in conventional plants (see Figure 2-19). In many cases, both types of FAC occur in the same tube region. Single-phase FAC has occurred in circuits where two-phase flow predominates; such areas may be at tight 180° bends. Often in these areas, the re-establishment of two-phase flow after the bend is accompanied by blistered and/or box-like magnetite as clearly shown in Figures 2-32b, d and e about one tube diameter downstream of the single-phase FAC. Another important feature to note is the total lack of any protective oxide (magnetite) on the tube surface in areas of severe FAC (Figures 2-31c and d and 2-32c). As in conventional fossil plants, FAC preferentially attacks the pearlite colonies of the carbon steel (dark areas in Figure 2-31d).

FAC

Economizers LP Evaporator

Feedwater Heater

Figure 2-29 Typical Location of FAC in a LP Evaporator of a Triple-pressure HRSG. The FAC usually occurs in association with the dogleg or pant leg as the tubing enters the header.

2-35


Figure 2-30 FAC Failure in a LP Evaporator Tube Just Prior to the Header

(b)

(a) (d) (c)

Figure 2-31 Example of FAC in Vertical LP Evaporator Tubing. a) shows single-phase FAC, b) shows two-phase FAC, and c) and d) show the lack of any protective magnetite on the tube surface. The Arows in d) Point to the Preferential FAC Attack of the Pearlite Colonies in the Carbon Steel

2-36


(b) (a)

“Box-like” magnetite

(e) (c)

Blistered magnetite (d)

Figure 2-32 Example of FAC in Horizontal LP Evaporator Tube. a) shows region of single-phase FAC at tight 180° bend where flow is from left to right, b) and e) show typical formations of “boxlike” and “blistered” magnetite, and c) shows the lack of protective magnetite in the severe FAC areas.

2-37


Scalloped Regions

Figure 2-33 Visual and Metallographic Characteristics of Two-phase FAC. Note Wavy Appearance which is Typical in Tubes Damaged by Two-phase FAC.

It is rather important to note that the velocities in these HRSG components are generally low (up to 3 ft/sec, 0.9 m/sec) in LP economizers and evaporators. The velocities in the riser tube to the LP drum may be higher. The fact that these velocities are generally low confirms the understanding of the FAC mechanisms (Section 2.1), that they are controlled by the water potential (for single-phase) and by mass transfer. Thus the turbulent flow introduced by the geometry increases the mass transfer. Gabrielli(21) illustrated by computational fluid modelling that the turbulence in a 17° economizer tube bend is approximately twice that in a straight section, and even higher in a 45° bend. 2.3.2 FAC in LP Drums According to the EPRI statistics (Table 1-4), FAC has been observed in the LP drum of about 20% of HRSGs. Two examples are shown in Figures 2-34 and 2-35.

2-38


Figure 2-34 Example of FAC on the LP Drum Internals

Figure 2-35 Example of FAC on a Natural Circulation HRSG Drum Separating Device

2-39


2.3.3 Summary for FAC in HRSG Plants Based on the understanding of the FAC mechanisms (Section 2.1), the various examples of FAC (Section 2.3.2), and the results of EPRI’s HRSG Tube Failure Reduction Program and HRSG Benchmarking Process (Appendix B), the following conclusions can be drawn for control of FAC in HRSGs: •

Single-phase FAC can be controlled by feedwater and evaporator chemistry. –

Most triple-pressure HRSGs contain no feedwater heaters or copper alloys and should run on an oxidizing cycle (AVT(O)). This means that reducing agents should not be added to HRSGs during operation or shutdown.

•

Some two-phase FAC can be addressed by LP evaporator chemistry by adding either trisodium phosphate or NaOH to the LP drum provided that the circuitry allows. Reference to (23) the EPRI HRSG Cycle Chemistry Guidelines is required to ensure optimum treatment.

•

Some two-phase FAC is addressed by a materials solution. If obvious tube locations can be identified then these should be replaced by 1.25% Cr or higher steel. Drum components can similarly be replaced with 1.25% Cr or higher steel or austenitic stainless. An active monitoring program for iron at the feedwater, LP, IP and HP drums will identify whether FAC is active. A level of less than 5 ppb iron is a good level to aim for to ensure FAC is inactive.

•

Inspection of the typical locations is required using a combination of internal visual and ultrasonic thickness techniques.

2.4 References 2.4.1 Referenced in Text 1.

Flow Accelerated Corrosion in Power Plants, EPRI, Palo Alto, CA: July 1998. TR-106611-R1.

2.


3.


4.


5.

R. B. Dooley, D. Macdonald and B. C. Syrett, “ORP—The Real Story for Fossil Plants”, PowerPlant Chemistry, 5(1), pp 5–15: 2003.

6.

F. H. Sweeton and C. F. Baes, J. Chem. Thermo., 2, p 479: 1970.

2-40


7.

P. R. Tremaine and J. C. LeBlanc, J. Solution Chem., 9-6, p 415: 1980.

8.

F. J. Pocock, J. A. Lux and R. V. Siebel, “Control of Iron Pickup in Cycles Utilizing Carbon Steel Heaters”, Proc. Am. Power Conf., 28, Chicago: 1966.

9.

P. Sturla, “Oxidation and Deposition Phenomena in Forced Circulating Boilers and Feedwater Treatment”, Fifth National Feedwater Conf., Prague: 1973. (in French)

10.

U. Rohlfs, Analysis of the Corrosion Characteristics and Protective Layer Growth in Feedwater Heater Tubes of Unalloyed Steel, Ph.D. Thesis, Erlangen-Nürnberg University: 1983. (in German)

11.

P. Sturla, “Iron Oxides in Thermoelectric Cycles: Theoretical Aspects and Their Possible Influence on Service”, 1985 Fossil Plant Water Chemistry Symposium, pp 22-1 to 22-22, EPRI, Palo Alto, CA: 1986. CS-4950.

12.

P. H. Effertz, R. Klose and D. Wiume, “Corrosion Processes and Protective Layer Growth in LP Feedwater”, Der Maschinenschaden 48, pp 208-213: 1975. (in German)

13.

P. H. Effertz, J. Hickling, A. Heinz and G. Mohr (Eds.),”Combined Ammonia/Oxygen Conditioning Water Vapour/Steam Circulation Systems in Power Stations”, AllianzBerichte No. 23: 1985.

14.

F. J. Pocock. Prepared Discussion for the Paper “Chemical Aspects of Magnetite Solubility in Water”, (G. Bohnsack), Proc. of the American Power Conf., 43, Chicago, IL, pp 11441145: 1981.

15.

Guidelines for Copper in Fossil Plants, EPRI, Palo Alto, CA: November 2000. 1000457.

16.

H. Keller, VGB Kraftwerkstechnik, 54, p 292: 1974.

17.

B. Chexal and J. Horowitz, Proceedings of the Fourth Symposium on Environmental Degradation of Materials in Nuclear Power Systems—Water Reactors, Jekyll Island, Georgia: 1989.

18. F. N. Remy, EDF Report, Ref. EC. 90. 83 B: 1991. 19.

I. S. Woolsey, Proceedings of the IAEA Specialist’s Meeting on Corrosion and Erosion Aspects of the Pressure Boundary Components of Light Water Reactors, Vienna, IAEA Report: IWG-RRPC-88-1, Vienna, p 60: 1990.

20.

W. Kastner, M. Erve, N. Henzel and B. Stellwag, Proceedings of the IAEA Specialist’s Meeting on Corrosion and Erosion Aspects of the Pressure Boundary Components of Light Water Reactors, Vienna, IAEA Report: IWG-RRPC-88-1, Vienna, p 49: 1988.

2-41


21. F. Gabrielli, “Flow-Assisted Corrosion Failures/Water Chemistry Aspects”, EPRI Conference on BTF and HTF and Inspections, San Diego, Nov 2004. To be published in 2005 as Proceedings. 22. W. G. Cook and D. H. Lister, “Some Aspects of Electrochemistry and Corrosion Mechanisms Influencing FAC in CANDU Outlet Feeder Pipes”, Intl. Conf. Water Chemistry of Nuclear Reactor Systems, San Francisco, CA: October 2004. 23. a) Interim Cycle Chemistry Guidelines for Combined Cycle HRSGs, EPRI, Palo Alto, CA: November 1998. TR-110051. b) The first revision of this guideline will be published at the end of 2005 as: EPRI, Palo Alto, CA. 1010438. 24. R. Svoboda, Alstom. Private Communication to B. Dooley. January 2005. 2.4.2 Bibliography on FAC in HRSGs •

R. R. Harries and M. J. Willett, “Flow Accelerated Corrosion in HRSGs: Interdependence of Cycle Chemistry and Design”, PowerPlant Chemistry, 3(12), pp 721-727: 2001.

•

A. Bursik, “Chemistry in Cycles with HRSGs”, PowerPlant Chemistry, 2(10), pp 595-599: 2000.

•

R. Svoboda, H. Sandman and F. Gabrielli, “Steam/Water Cycle Chemistry: Current Developments and Challenges in the Future”, PowerPlant Chemistry, 2(2), pp 75-78: 2000.

2.4.3 Bibliography on FAC •

R. B. Dooley and V. K. Chexal, “FAC of Pressure Vessels in Fossil Plants”, Intl. J. of Pressure Vessels and Piping, 77, pp 85-90: 2000.

•

P. Berge and M. Bouchacourt, “Flow-Accelerated Corrosion and Hydrazine”, Eskom International Conference on Process Water Treatment and Power Plant Chemistry, Midrand, South Africa, November 25-28, 1997.

•

V. K. Chexal and J. S. Horowitz, “Chexal-Horowitz FAC Model—Parameters and Influences”, ASME PVP-Vol. B, Book No. H0976B: 1995.

•

I. W. Woolsey, G. J. Bignold, C. H. DeWhalley and K. Garbett, “The Influence of Oxygen and Hydrazine on the Erosion-Corrosion Behaviour and Electrochemical Potentials of Carbon Steel Under Boiler Feedwater Conditions”, Proc. Water Chemistry for Nuclear Reactor Systems, 4, BNES, London: 1986.

2-42


3 OVERVIEW OF FAC PROGRAM FOR FOSSIL AND COMBINED CYCLE/HRSG PLANTS

This section provides an overview of the total program necessary to control FAC in fossil (Section 3-1) and combined cycle/HRSG (Section 3-2) plants.

3.1 Approach for Conventional Fossil Plants The basic structure of the program for conventional fossil plants is shown in Figure 3-1, and consists of a two-pronged parallel approach to the FAC problem: i) “Inspection Based Activities” (Steps 6–10) and ii) “Cycle Chemistry Based Activities” (Step 11). Any comprehensive FAC program for fossil plants cannot afford to only adopt one of the activities of the two-pronged approach. They are critically linked together. The inspection activities together with the application of the CHECUP™/CHECWORKS™ predictive computer codes have the proven capability of identifying those areas susceptible to FAC. The cycle chemistry activities have the proven capability of reducing the generation of feedwater corrosion products (FAC), and reducing and nearly eliminating active single-phase FAC depending on the system metallurgy and the feedwater chemistry adopted. The road map consists of 13 steps which are briefly described in this Section. All the details of the steps are included in the subsequent Sections; the location of these details are delineated within the step descriptions below. Step 1 - Develop Corporate Program and Philosophy (Section 1.4) It is well established within the fossil industry that the key to complex plant problems lies not in only having a complete technical understanding, but ensuring that there is a corporate-wide, coordinated program fully approved and sponsored by the senior management. Such a program should include a broad range of utility personnel such as mechanical maintenance, NDE, chemists and metallurgists. It has to have full cooperation of all the involved departments, ensuring adequate financial and personnel resources, the up-to-date tools, and industry knowledge. The minimum here would include the latest predictive computer codes and the latest guidelines to optimize feedwater chemistry. The type of information that should be included in the Corporate Philosophy statement is discussed in Section 1.4. The management will require an on-going assessment of the organization’s FAC program. This can be accomplished by using the EPRI Benchmarking Process for FAC on a frequent (6 month–1 year) basis (Appendix A).

3-1

EPRI Licensed Material Overview of FAC Program for Fossil and Combined Cycle/HRSG Plants

Figure 3-1 Road Map of Activities for Controlling FAC in Fossil Plants

3-2


Step 2 - Develop Comprehensive FAC Program In this step it is necessary only to fully appreciate that the overall approach to FAC must involve both inspection based and cycle chemistry based activities in parallel and that this should be included in the developed Corporate Philosophy document. Step 3 - Review Design, Materials and FAC Experience (Section 4) This step closely links with the similar review of cycle chemistry in Step 4. Here it is necessary to fully identify and document all the feedwater materials in each one of the fossil plants in the system. All relevant plant design and operations data should be obtained to use in understanding plant susceptibility and in selecting inspection locations. This includes original design information (temperature, pressure, etc.), as-built changes, plant modifications and replacements, historical systems operation, past inspection data, and records of prior leaks and failures. To address the two-phase FAC areas in the deaerator, drain lines and shell side of LP heaters, a complete heat balance of the whole feedwater system will be required. In this way it will be possible to identify the temperatures and pressures of fluid entering these pressure vessels relative to the bulk temperature and pressure within the vessels. It is necessary to clearly delineate all failures and maintenance activities in the feedwater systems, including the deaerator, the economizer inlet header tubing, and all heater drain lines. This analysis should, if possible, include any metallurgical analyses, as often FAC has in the past been identified incorrectly as another mechanism (such as cavitation). The primary inspection priority for fossil plants developed in Section 2.2.5 can be used to assist in the analysis needed in this step. The outcome of this step should be a clear and concise tabulation of definite FAC areas, any possible FAC areas in each plant, and of locations which need to be included in the inspection program (Steps 7 and 10). Obviously single- and two-phase areas must be included. Step 4 - Review Cycle Chemistry Experience and Results In this step, it is necessary to review the cycle chemistry experience of the units and to determine if any of the problems identified in Tables 1-2 and 1-3 as well as those in Section 2.2 have occurred in any of the feedwater systems. It is important to conduct the analysis for both allferrous and mixed-metallurgy feedwater systems. A positive answer indicates possible FAC, and a need to optimize the feedwater treatment (Steps 11a and b). It is also necessary to review the feedwater corrosion product data at the economizer inlet and to determine if the values meet the EPRI limits (Table 2-2). Excessively high values, and an inability to meet these limits on a continued basis again may indicate a significant FAC problem somewhere within the feedwater system. Again it is also necessary within this step to review the current feedwater chemistry as a function of the system metallurgy.

3-3


The details of this step are clearly and comprehensively covered by Step 1 of the road maps in Figures 6-1 and 6-2 of Section 6. The outcome of this step will be an indication of whether, and where, FAC is possible, which feedwater systems may have a priority for inspection and need feedwater chemistry optimization. Step 5 - Identify Susceptible Systems and Lines (Section 4) All systems and lines in the plants should be reviewed against the susceptibility criteria to identify those that need to be included in the inspection program. This is a key step to ensure that a plant program to control FAC is complete. Clearly if the review in Steps 3 and 4 indicates that FAC has occurred, or that there is cycle chemistry evidence (high corrosion products which exceed Table 2-2 limits), then this unit will become a priority. However, if no such evidence is discovered in Steps 3 and 4, then Tables 1-2 and 1-3 indicate those units where serious FAC has occurred in fossil plants and this could be used, together with the information in Section 2.2.5, as a prioritization device. As indicated there, the units most affected in terms of failure appear to be those with stainless steel feedwater heater tubes; however, it must be recognized that FAC wall loss has also been found in mixedmetallurgy fossil units, and serious failures have occurred in nuclear plants with mixedmetallurgy systems; thus these units will also need inspecting. Details on the selection and prioritization process are included in Sections 4 and 5. Step 4 will also provide an indication of the need to optimize feedwater chemistry from both an FAC and corrosion product transfer perspective. The full procedures of this process are contained in Section 6. Step 6 - Perform Initial FAC Analysis (CHECUP™/CHECWORKS™) Procedures and recommendations are provided in Section 5 on how to systematically select locations for inspection. The methods are based on the use of industry experience (Tables 1-2 and 1-3, and Section 2.2) as well as the developed analytical tools (CHECUP™/ CHECWORKS™) that can predict the rates of FAC. Step 7 - Perform Initial NDE Inspections In this step the actual initial plant NDE inspections are performed. The methods and procedures (discussed in detail in Section 5) should accurately and cost-effectively inspect the components for FAC wall loss and related damage. Methods and procedures are also provided on how to evaluate the inspection data (Sections 5), and structurally qualify worn components for continued service.

3-4


Step 8 - Material Sampling/Removal Once any FAC wall loss or damage has been identified, then a sample of the pipe, tube, or component should be taken for metallurgical analysis. This is an important step to ensure: •

the wall loss or damage is FAC, or

•

the wall loss or damage is due to another mechanism such as cavitation, and

•

the wall loss or damage is currently active.

In situations where FAC is currently active, metallurgical analysis will indicate a very thin magnetite layer on the material surface (see example in Figure 2-5). However, in cases where FAC was active in the past then the oxide layer will be of approximately the same thickness as the oxide in areas without any wall loss (see example in Figure 2-9). For cavitation, the appearance within the wall loss region tends to look and feel sharp, as compared to the wavy or orange-peel like surface of FAC. See Section 5 for other types of damage which may be confused with FAC. As was indicated in Section 2.1 and 2.2, it is very important that FAC is characterized as singleor two-phase as different root causes will be responsible. Step 9 - Perform Necessary Repairs/Replacements Where unacceptable damage is found, the affected components need to be repaired or replaced. The use of line or spool piece replacements using FAC resistant materials (1.25% Cr or higher) are specifically recommended. The details are provided in Section 5. Different solutions will need to be applied. Basically single-phase FAC in all-ferrous systems can be addressed by ensuring the feedwater chemistry is oxidizing (AVT(O) or OT). Singlephase FAC in mixed-metallurgy systems will have to be addressed through the monitoring program of Step 11b and will required a careful balance to protect both the carbon steel and copper alloys. Two-phase FAC in fossil plants will need to be addressed using a materials solution involving 1.25% Cr or higher alloys. Drain lines should generally be replaced with piping. Deaerator and LP heater shellsides, depending on the severity, will need either new plate material or weld overlay/temperbead. Step 10 - Subsequent Inspections and Analysis A second inspection of each susceptible area and any additional sites identified during the FAC analysis will be required, and the results inserted into the CHECUP™/CHECWORKS™ codes for repeat analysis. The subsequent inspections will be timed based on the results from Steps 6 and 7, and are designed to confirm the initial results and to obtain data for trending wear. Remaining service life calculation procedures are provided in Section 5. Details of the sample selection procedures for the original and the expanded locations are also included in Section 5. The inspection procedures are provided in Section 5. 3-5


Step 11 - Optimize Feedwater Chemistry Step 4 does not only provide key information that helps to prioritize the systems for inspection, but also recognizes that the feedwater chemistry is not optimized and may be contributing to FAC damage. Step 11 should be conducted in parallel with Steps 6 and 7. Separate approaches need to be followed for all-ferrous (Step 11a) and mixed-metallurgy (Step 11b) feedwater systems. The procedures are provided in Sections 6.1 and 6.2. Step 12 - Safe Unit Operation The results of the “Inspection Based Activities” will be an identification of those areas currently susceptible to FAC and the rate at which FAC will progress if the cycle chemistry and other hydrodynamic factors remain the same. The results of the “Cycle Chemistry Based Activities” will be a feedwater environment that produces minimum feedwater corrosion products in agreement with the EPRI guidelines (Table 2-2). In all-ferrous feedwater systems the optimum treatment (oxidizing) will greatly reduce FAC. In mixed-metallurgy systems, the optimum treatment (reducing) should be developed to greatly reduce any FAC of the carbon steel components, and the corrosion of the copper based tubing. The overall result of the two pronged approach should be a unit where all areas of FAC have been identified, and a feedwater treatment which has minimized the possibility of FAC causing serious damage or failure. Step 13 - Longterm Options and Continual Check No utility can afford to be complacent with FAC and must adopt a policy of continual checking of both the susceptible sites and of the feedwater chemistry. Clearly this continual check must link back to Steps 10 and 11 respectively. Discussion of the continuing inspection activities is provided in Section 7, and of the feedwater chemistry in Section 6. The optimum process to provide a continual check of the organization’s FAC program is to use the EPRI FAC Benchmarking Process (Appendix A).

3.2 Approach for Combined Cycle/HRSG Plants Section 2.3 provided details on FAC failures and damage in HRSGs. EPRI’s overall approach to FAC in HRSGs is outlined in Section 2.3.3, and is extensively covered in a series of documents developed within the HRSG Dependability Program: •

Cycle Chemistry Guidelines for HRSGs(1)

•

HRSG Tube Failure Manual(2)

•

Delivering High Reliability HRSGs(3)

3-6


Figure 3-2 illustrates the approach necessary for controlling FAC in combined cycle/HRSG plants. It should be noted here that some preoperational features are included (Steps 1 and 2) as FAC should be dealt with as a serious potential HTF during the specification and design phases. Monitoring is a key feature needed during commissioning (Step 2). During operation a similar two-pronged parallel approach to FAC, as suggested for conventional plants (Figure 3-1), should be employed. Inspection based activities (Steps 4-7) and cycle chemistry activities (Steps 8-11) are needed. Note that there are no predictive or analysis tools available for HRSGs, but that both types of FAC can be addressed by the cycle chemistry if the installed circuitry allows. EPRI’s HRSG Dependability Program has recently developed all the tools for FAC identification, prediction and assessment, so cross-reference is provided to these documents. Step 1 - Specify and Design HRSGs to Avoid FAC The understanding developed in Table 1-4, showing the predominant FAC areas, and in Section 2.3 providing examples of FAC in HRSGs, has led to a set of guiding principles to avoid FAC in HRSGs during the specification and design phases. EPRI published these in the document (3) Delivering High Reliability HRSGs. The basis was discussed in Section 2.3.3. Thus HRSGs should be specified and designed with the following three key features. •

No facility should be provided to add any reducing agent to the cycle to ensure that singlephase FAC will not take place.

•

Monitoring/sampling points should be installed at the feedwater and for each drum (LP, IP and HP) to ensure that iron can be monitored during commissioning (Step 2) and operation (Step 8).

•

Facility should be provided to enable solid alkali addition to the LP drum in the event that two-phase FAC is identified during the monitoring. This feature probably needs most thought and consideration because it must be associated with designs where the LP drum does not provide feed for the higher pressure cycles or for attemperation.

3-7


Figure 3-2 Road Map of Activities for Controlling FAC in Combined Cycle/HRSG Plants

3-8


Step 2 - Monitoring During Commissioning This is a vital step in the life of an HRSG. But most often it is not accomplished comprehensively. While extensive monitoring is required to confirm the overall cycle chemistry for the HRSG, the primary reason for conducting monitoring at this stage is to check whether FAC has been designed out, is occurring, or is still possible. If the design has not included the use of a reducing agent, then this step identifies possible twophase FAC. If this has not been accomplished during design, then this step addresses single- and two-phase FAC. In either case it is necessary to monitor for total iron at the feedwater and in each drum. The monitoring to be conducted is comprehensively covered in EPRI’s HRSG Cycle Chemistry Guidelines.(1) It involves: •

Varying Operating Conditions - base load, startup, shutdown.

•

Steam Chemistry - cation conductivity, sodium, chloride, silica and sulfate.

•

Feedwater Chemistry - cation conductivity, chloride, corrosion products (Fe, Cu), oxygen, and pH.

•

Evaporator Water (each drum) - cation and specific conductivity and Fe.

•

Operation of Condensate Polishers (if included)

This monitoring takes a “thumb-nail” of the HRSG under typical operating conditions. At this stage in an HRSG’s life, a good level of iron to aim for is around 5 ppb around the cycle. If the iron levels at the feedwater, and in each drum are substantially higher than this, then the organization may want to go straight to Step 8 to address optimizing the treatments. Step 3 - Develop Corporate Program and Philosophy This is the step where most organizations will enter the process because no prior attention has been given to the possibility for FAC in an HRSG in the early phase of life. Some iron monitoring may have been conducted and/or some early FAC damage or failure may have taken place. This step is basically the same as Step 1 for the conventional plants (Figure 3-1). The process starts with a review of the possible failure sites (Table 1-4 and Section 2.3). All relevant plant design and operating data should be obtained; this includes the detailed design of the various LP, IP and HP economizer sections, and the LP evaporator and drum, past inspection and chemical monitoring data. Single- and two-phase flow and FAC should be delineated. The Corporate Philosophy (Mandate) document will need to include the type of information included in Section 1.4. The program should include a broad range of personnel such as mechanical maintenance, NDE, chemists and metallurgists, and should clearly delineate the coordinator of the program. 3-9


The management will require an on-going assessment of the organization’s HRSG FAC program. This can be accomplished by using the EPRI Benchmarking Process for HRSGs on a frequent basis (Appendix B), with particular emphasis on Factors B, D, E and F. Step 4 - NDE Inspections The methods and procedures for NDE in HRSGs are delineated in the HRSG NDE Guideline.(4) Currently the approach involves a combination of visual (including fiber optics) and ultrasonics. Step 5 - Materials Sampling Once there has been an FAC failure or FAC has been identified either by NDE (Step 4) or excessive iron levels (Step 8) during monitoring, then a sample should be removed for analysis. The key need here is to identify whether single- or two-phase FAC has taken place. Maybe both types have occurred in the same tube or section. The identifying tools are provided in Section 2.3. Step 6 - Repair and Replacement As indicated in Section 2.3.3, both types of FAC in the LP evaporator can be addressed by the chemistry as in Steps 9 and 10. However, the tubing should be replaced with 1.25% Cr alloy (T11). FAC in the economizer sections will need replacement with this alloy. Tube repair is (5) addressed in EPRI’s HRSG Materials and Repair Guideline. Step 7 - Subsequent Inspections Once any tube repairs have been made, or the feedwater (Step 9) and/or the evaporator treatment (Step 10) have been addressed, and further analysis still indicates a high level of iron (Step 11), then further chemical analysis (repeat of Step 8) and further NDE (repeat of Step 4) will be required. Step 8 - Monitoring Iron Levels around the HRSG Cycle This step involves similar activities as described in Step 2. Extensive detail is included in EPRI’s HRSG Cycle Chemistry Guideline.(1) For FAC the monitoring needs to concentrate on iron levels around the cycle (feedwater, LP, IP and HP drums). Overall the goal should be to reach less than 5 ppb at each location as a good indicator that FAC is minimized or eliminated. Basically at this phase in an HRSG’s life, there are two cases to consider: a)

If a facility for adding reducing agent to the cycle was not included during the design phase or the reducing agent was removed during commissioning or early operation, or

b)

If a reducing agent is still being added to the feedwater.

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Figure 3-3 shows the differences between these two cases. With a reducing agent being used, it is likely that iron levels are high (greater than 10-20 ppb) in a number of circuits. In some units, the iron levels around the cycle will generally reduce to less than 5 ppb once the reducing agent is eliminated. However, if two-phase FAC is predominant in one circuit, then it is likely that the iron levels will be above 5 ppb. 35

Fe ppb with N2H4 (2 years data)

30

Fe ppb without N2H4 (1 year data) 25

20

15

10

5

0 Cond

BFP Suct

#1 BFP Disch

#1 HP Drum

#1 HP Sat Stm

#1 HP SH Stm

#1 IP Drum

#1 RH Stm

#2 BFP Disch

#2 HP Drum

#2 HP Sat Stm

#2 HP SH

#2 IP Drum

#2 RH Stm

Figure 3-3 Measured Iron Profiles around an HRSG when Operating With and Without a Reducing Agent (Hydrazine).

If the iron levels are generally less than 5 ppb, then the monitoring suggests that the HRSG is currently operating with little prospect for FAC, and the operators can continue normal operation in Step 12. If the iron levels remain generally high, then depending on whether they are high in the feedwater or in one of the drums, the road map approach suggests moving to Step 9 or 10 respectively. Steps 9 and 11 - Addressing FAC in the Feedwater by Monitoring and Adjusting the Feedwater Chemistry If Step 8 indicates feedwater corrosion product levels above the 5-10 ppb level as indicated in the example in Figure 3-3, then analysis is required of the feedwater treatment. This situation usually relates simply to the continued use of a reducing agent injected after the condensate pump in association with good air in-leakage control, which provides less than 10 ppb oxygen at the condensate pump discharge. As thoroughly discussed in Section 2.1, these reducing conditions do not have the ability to minimize corrosion and feedwater corrosion product transfer in the 3-11


feedwater. In this step, a test should be conducted (as described in Section 6.1), where the reducing agent is eliminated in steps or at one time. A repeat of the monitoring conducted in Step 8 will be required, through Step 11, to assess the new feedwater treatment. Occasionally during early operation, high iron levels in the feedwater could relate to inadequate preoperational chemical cleaning, or to no preoperational clean. Steps 10 and 11 - Addressing FAC in the Evaporator Circuits by Monitoring and Adjusting the Evaporator Treatment If Step 8 indicates evaporator corrosion product levels above the 5-10 ppb level as indicated in the example in Figure 3-3, then analysis is required of the applied evaporator chemistries. It is possible that the elimination of the reducing agent in Step 9 will also have a major benefit on the iron levels in the drum, as again is clearly indicated in Figure 3-3. However, in some cases the iron levels may remain high due to two-phase FAC in the evaporator circuits. As discussed in Section 2.3.3, two-phase FAC is not addressed by increasing the oxidizing power of the (evaporator) water. In this case, there is a need to increase the pH of the water droplets/phase in the two-phase mixture. This can be accomplished by the addition of tri-sodium phosphate or NaOH to the LP drum, or by increasing the ammonia levels in the feedwater so that the pH approaches 10. Optimum alleviation of two-phase FAC has been achieved by the former approach. In this step, a test should be conducted of adding a solid alkali to the drum using the monitoring approach conducted in Step 8. It must be noted again here that it is not always possible to add a solid alkali to the LP drum in many HRSGs because this drum feeds the higher pressure circuits and may be used for attemperation of HP or reheat steam. In these cases it will be necessary to activate the inspection and repair route (Steps 4 and 6). Step 12 - Continued Operation Only once the cycle chemistry of the feedwater and evaporator (drum) treatments have been optimized, and the inspection/repair process has been completed can the operator feel that FAC is under control or manageable. The optimum process to provide a continual check of the organization’s HRSG FAC program is to use the EPRI HRSG Benchmarking (Appendix B).

3-12


3.3 References 1. a) Interim Cycle Chemistry Guidelines for Combined Cycle HRSGs, EPRI, Palo Alto, CA: November 1998. TR-110051. b) The first revision of this guideline will be published at the end of 2005 as: EPRI, Palo Alto, CA. 1010438. 2.

Heat Recovery Steam Generator Tube Failure Manual, EPRI, Palo Alto, CA: November 2002. 1004503.

3.

Delivering High Reliability HRSGs, EPRI, Palo Alto, CA: 2003. 1004240.

4.

Interim Guidelines for the Nondestructive Evaluation of HRSGs, EPRI, Palo Alto, CA: 2004. 1004506.

5.

HRSG Material Selection and Repair Guidelines, EPRI, Palo Alto, CA: 2004. 1004875.

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4 IMPLEMENTING THE FAC ROAD MAP

The road maps for managing FAC damage in conventional, fossil steam plants and in heat recovery steam generators (HRSGs) in combined-cycle combustion turbine plants were introduced in the previous section. Each road map presents two major paths of activities required to fully control FAC damage and prevent in-service failures. The inspection-based activities path will be covered in detail in Section 5 and serves two main functions within the overall FAC program: 1) to establish a baseline for FAC damage that may currently exist in a plant that has been operating, and 2) to provide longterm management of FAC damage that may continue to occur in plant components that cannot utilize cycle chemistry processes to prevent FAC. Importantly and as presented in previous sections, the factors contributing to the FAC damage mechanism in conventional fossil and HRSG units are not tied solely to design and materials such that damage over time is inevitable. The critical roles of water chemistry and metallurgy in the corrosion process mean that units may or may not have sustained damage during prior operation. This reality drives the need for baseline assessment of damage within an FAC program. The cycle chemistry-based activities included in Section 6 are directed at preventing FAC damage by stopping the corrosion process and represent the major longterm strategy for managing FAC in both conventional fossil and HRSG units. This section will briefly cover basic activities that will be required for all units as part of a formal program to manage FAC damage. It is emphasized that FAC efforts must be developed on a unit-specific basis because of the complex interaction of metallurgy, chemistry, hydrodynamics, and operations in producing FAC damage. These factors make it unlikely that units of “identical” design actually behave identically with respect to FAC damage.

4.1 Information Gathering An essential first step in implementing the FAC road maps is to gather appropriate unit information to assess susceptibility of unit components to FAC damage. This information will be referenced frequently in the pursuing specific actions in both the inspection and cycle chemistry paths. The following subsections summarize the unit data that will be needed. 4.1.1 Plant Design and Materials It is critical that all available plant design information be obtained for use in identifying potential problem areas and developing a program to control FAC. Typically this information would include:

4-1

EPRI Licensed Material Implementing the FAC Road Map

•

Plant heat balance diagram, along with operating conditions (pressures, temperatures, flow velocities, steam qualities) of major lines and equipment such as feedwater heaters and deaerators. For HRSGs, economizer and evaporator section information needs to be included.

•

Piping and instrumentation diagrams (P&IDs, also known as flow diagrams).

•

Piping isometrics, including as-built changes.

•

Description of plant modifications to FAC susceptible lines and connected equipment (e. g., feedwater heaters, control valve stations, etc.).

•

Records of past repairs and replacements (very important)

•

Piping line lists.

•

Piping and equipment materials.

•

Orifice openings.

•

Discharge coefficients and opening areas of control valves.

•

Locations of any known backing rings or counterbore.

•

Design information of any special or field fabricated components (e. g., field fabricated tees, mitered elbows, etc.).

4.1.2 Operating Experience Relevant plant operating experience should also be obtained to incorporate into the plant FAC program. This might include: •

Records and data concerning prior FAC inspections.

•

Observations from prior inspections or maintenance of in-line equipment (e.g., was any wall loss found in valves opened for maintenance, what did the downstream pipe look like?).

•

Locations of prior leaks and failures, including locations of field repairs.

•

Information from plant operators concerning systems currently being used or historically used differently than designed.

•

Cycle chemistry parameters and changes over time (this information will be reviewed in detail in Section 6).

4.2 Identify and Prioritize Susceptible Systems and Lines The first evaluation task in the unit FAC program is to identify all piping systems, or portions of systems, and vessels that could be susceptible to FAC. FAC is known to occur in piping systems made of carbon and low-alloy steel with flowing water (single-phase) or wet steam (two-phase). All such systems should be considered susceptible to FAC. The unit line list, if available, and the Piping & Instrumentation Diagrams (P&IDs) can be used to ensure that all potentially susceptible systems are included in the program. HRSG units will need to include evaporator 4-2


sections in their FAC program. Note that some lines supplied by an equipment vendor are often not on the unit line list or shown on the P&IDs. Care should be taken to ensure that such susceptible lines are included in the FAC program. Additionally, this evaluation should be periodically reviewed to ensure that it is kept current with unit design changes and ways that systems are being operated. Clearly, each conventional fossil and HRSG unit will have a large number of systems and components that will be susceptible to FAC damage. The critical next step is to prioritize efforts such that any serious damage is detected and addressed as early as possible. 4.2.1 Exclusion of Systems From Evaluation Some susceptible systems, or portions of systems, can be excluded from further evaluation due to their relatively low level of susceptibility. Based on both laboratory and industry experience, the following systems can be safely excluded from further evaluation: •

Systems of stainless steel or low alloy (nominal chromium content equal to or greater than 1.25%) steel piping. This exclusion pertains only to complete piping lines manufactured of FAC-resistant alloy. If some components in a high alloy line are carbon steel (e.g., the valves), then the line should not be excluded. Also, in lines where only certain components or sections of piping have been replaced with an FAC-resistant alloy, the entire line, including the replaced components, should be identified as susceptible and analyzed. Note that high chromium materials do not necessarily protect against other damage mechanisms, especially cavitation and liquid impingement erosion. Thus, if the wear mechanism has not been identified it is not prudent to exclude the replaced components from the inspection program.

•

Superheated steam systems with zero moisture content, regardless of temperature or pressure levels. Drains, however, from superheated steam systems should not be excluded automatically. Experience has shown that some systems designed to operate under superheated conditions may actually be operating with some moisture in off-normal or reduced power level conditions. Care must be exercised not to exclude such systems.

•

Raw water systems, such as service water (high dissolved oxygen content).

•

Single-phase systems with a temperature below 200ºF (93°C) (low temperature). A note of caution is made that, if measurable wall loss is identified in nearby piping operating slightly above 200ºF (93°C), then it is recommended that the system’s exclusion be reconsidered. Importantly, there is no temperature exclusion limit that can be recommended for two-phase systems. Note that other damage mechanisms, such as cavitation, are predominant below 200°F (93°C) and need to be taken into account. This document, however, does not address these other damage mechanisms.

•

Systems with no flow, or those that operate less than 2% of plant operating time (low operating time); or single-phase systems that operate with temperature > 200ºF (93°C) less than 2% of the plant operating time. Note that if the actual operating conditions of the system cannot be confirmed (e.g., potential leaking valve, time of system operation cannot be confirmed), or if the service is especially severe (e.g., flashing flow), that system should not be excluded from evaluation based on operating time alone. A further caution—some lines that operate less than 2% of the time have experienced damage caused by FAC. These lines 4-3


include feedwater recirculation, and steam line drains downstream of traps. Such lines should be excluded only if no wear has been observed and continued operation under existing parameters is assured. It is recommended that a list be developed of the systems excluded from the FAC program. The list should note the basis for the system exclusion. This list should be appropriately documented and periodically reviewed. It has proven useful to have plant operating personnel review the list of excluded systems. Systems should not be excluded from evaluation based on low pressure. Pressure does not affect the level of FAC 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). Also, arbitrary ranges of velocity or other operating conditions should not be used to exclude a system from evaluation. The systems excluded by these criteria will not experience significant FAC damage over the life of the plant. However, it should be noted that such systems could be susceptible to damage from other corrosion or degradation mechanisms. These include cavitation erosion, liquid impingement erosion, intergranular stress corrosion cracking (IGSCC), microbiologicallyinfluenced corrosion (MIC) and solid particle erosion. These mechanisms are not part of an FAC program and should be evaluated separately. 4.2.2 Prioritize Units and Systems For Evaluation Importantly, each conventional fossil or HRSG unit contains a significant number of components susceptible to FAC damage. Expanding the unit-specific level to a fleet of units within an organization further increases the potential scope of work to be performed under an FAC program. It is, therefore, essential to put in place a prioritization plan that focuses resources on the most at-risk systems. The subsections below will provide initial guidance in prioritizing units both from a conventional fossil unit perspective and from an HRSG perspective. Industry experience, as reviewed previously, clearly offers an effective tool for the initial prioritization efforts. 4.2.2.1 Conventional Fossil Units Analysis (summarized in Section 2.2.5) of the serious incidents of FAC (major bursts of pipes and tubes, and fatalities) in conventional fossil power plants and industrial steam plants provides a very clear priority or ranking order of units that are susceptible to FAC damage and should be inspected to establish baseline condition: •

Units with all stainless steel tubing in feedwater heaters, HP and LP.

•

Units with stainless steel tubing in feedwater heaters in either HP or LP trains.

•

Units with carbon steel tubing in feedwater heaters.

•

Units with mixed-metallurgy (copper alloys) tubing in feedwater heaters.

4-4


The feedwater heater drain lines are susceptible locations on all units and currently account for the most frequent occurrences of FAC damage (Table 1-2). This situation is especially true in units with all-ferrous feedwater heaters, if the heaters operate with the vents open then this releases much of the dissolved oxygen content, thus increasing the probability of FAC. The next level of prioritization is to determine the large list of susceptible systems on each unit. All of these systems must be evaluated. However, if time or resources are limited, it may be necessary to prioritize the scheduling of evaluations. The following is a reasonable, first-order listing of priorities: 1. Large-bore piping. 2. Susceptible small-bore piping and tubing with the most significant consequences of failure. (essentially economizer inlet tubing from the economizer inlet header and heater drain lines) 3. The remaining small-bore piping. A failure in a large-bore piping system has potentially more significant consequences to personnel safety and plant availability, and thus these should be given first priority. Analysis and inspection of all susceptible large-bore piping systems is recommended. At a minimum, initial inspections of large-bore systems should be conducted at the next scheduled outage, if they have not yet been performed. For purposes of FAC evaluations, large-bore piping is defined as piping with a nominal diameter of greater than 2.5 inches (63.5mm). Recommendations are provided in Section 5 for inspecting large bore piping. Although the consequences of failure may be less, problems with small-bore piping and tubing in general, and socket-welded fittings in particular, have been experienced. FAC-related leaks and ruptures, some resulting in plant shutdowns, have been reported in small-bore lines. For the purpose of FAC evaluation, small-bore piping and tubing is defined as both butt-welded and socket welded piping and tubing with a nominal diameter of less than or equal to 2.5 inches (63.5mm). The number of inspections performed for small bore piping and tubing is plant dependent. Economics could determine the extent of inspections performed versus wholesale replacement with FAC-resistant materials. Use of EPRI CHECUP software to help prioritize actual inspections by component in FAC susceptible systems will be discussed in Section 5. The objective of this second tier prioritization is to improve the cost-effectiveness of the inspection process and is not intended to replace this unit-by-unit prioritization.

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4.2.2.2 HRSG Units HRSGs do not typically have feedwater heaters, and the prioritization of units for FAC actions does not focus on consideration of feedwater heater tubing metallurgy. More critically for HRSGs, the FAC prioritization should include a review of low pressure evaporator tube failures and the chemistry treatment used for the feedwater as discussed in Section 2. Units currently operating, or previously operated, on all-volatile treatment (AVT) with addition of a reducing agents such as hydrazine should be given priority for FAC assessment.

4.3 Initiation of Action Paths After selection of a unit for FAC assessment, parallel paths are shown on the road maps for conducting both inspection-based and cycle chemistry-based actions. Both paths must be pursued within the FAC program. For units that have operated, FAC failure experience, inspection results, and cycle chemistry data must be collected and evaluated. Detailed information will be provided in Sections 5 and 6. Note that inspection-based actions are intended both to provide a baseline of FAC damage due to prior operation and to identify and manage those systems and components in which FAC control cannot be maintained via optimized cycle chemistry treatment. For conventional fossil plants and HRSGs, cycle chemistry control will be the major focus for longterm control of FAC damage.

4.4 Documentation In the implementation of a formal FAC management program, organizations must establish clear and comprehensive documentation for actions completed and for planned actions. For example, it is recommended that the susceptibility evaluation be fully documented in a unit-specific, calculations package, including the input received from plant operating personnel and identification of lines in the program and identification as to why certain systems and lines are being excluded from the program. As will be discussed in Sections 5 and 6, this susceptibility analysis package will be then linked to results from inspections and to cycle chemistry practices to provide control over FAC damage to components in the unit. Importantly, tracking and documenting cycle chemistry parameters used to show FAC control will be an essential task within the overall documentation effort. This will both demonstrate that the program is complete and allow successor personnel to understand what was done and to form the basis for deciding what program changes may be needed as a result of plant modifications or changes to plant operations.

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5 INSPECTION-BASED ACTIVITIES

This section presents the steps and corresponding actions in the implementation of the inspection-based activities under an FAC program for conventional fossil plants and HRSGs. It is again emphasized that these actions should be pursued in parallel with the cycle chemistry optimization efforts presented in Section 6. Early implementation of appropriate cycle chemistry treatments per Section 6 can prevent FAC damage from occurring. The inspection-based activities are intended to address two major needs within the FAC program: •

Establish a baseline for FAC damage that may already exist in an operating unit, and

•

Provide a life management process ensuring replacement or repair prior to in-service failure for FAC susceptible components for which root cause FAC control via water chemistry or metallurgical upgrade cannot be implemented.

For conventional fossil plants and HRSGs, it is expected that a majority of FAC susceptible components and systems, especially those operating with single-phase water, can avoid FAC damage through operation with appropriate cycle chemistry conditions. There is, however, likely to be a subset of susceptible components that will require periodic inspection and eventual replacement per the actions covered in this section. Components operating under two-phase conditions (wet steam) are a particular set that, per the discussion in Section 2, will likely require specific life management actions.

5.1 Performing FAC Analysis Once the FAC susceptible piping systems and other unit components have been identified, it is recommended that an FAC analysis be performed. The analysis will be focused on identifying highest risk components within susceptible systems and can incorporate past unit FAC damage experience, industry experience, engineering judgment, and computational models. As used in the remainder of this document, the following definitions apply: Predictive Methodology - A predictive methodology uses formulas or relationships to predict the rate of wall thinning in a specific piping component type such as an elbow, tee, or straight run. The predictions need to be based on factors such as the component geometry, material, and flow conditions. An example of a predictive methodology is the Chexal-Horowitz correlation incorporated in the CHECWORKS™ and CHECUP™ codes(1,2,3). A predictive methodology should incorporate the following attributes:

5-1

EPRI Licensed Material Inspection-Based Activities

•

Take into account the geometry, operating time, temperature, velocity, water chemistry, and material content of each component.

•

Address the range of hydrodynamic conditions (i.e., diameter, fitting geometry, temperature, quality, and velocity) expected in a power plant. It is desirable to have the ability to calculate the flow and thermodynamic conditions in lines where only the line geometry and the end conditions are known.

•

Consider the water treatments commonly used in power plants. The water chemistry parameters that should be addressed are the pH range, the concentration of dissolved oxygen, the reducing agent, and the oxidizing/reducing potential.

•

Cover the range of material alloy compositions found in power plants.

•

Use the hydrodynamic, water chemistry, and materials information discussed above to predict the FAC wall loss rate accurately. The model should be validated by comparing its predictions with wall loss measured in power plants.

•

Provide the user with the wall loss rates of components.

•

Provide the capability to use measured wall loss data to improve the accuracy of the plant predictions (if a full featured analysis program such as CHECWORKS™ is used).

•

The developer of the predictive methodology should also periodically review the accuracy of the predictive correlations and refine it as necessary.

Predictive Plant Model - A Predictive Plant Model is a mathematical representation of the power plant's FAC susceptible lines and systems. Typically it utilizes a computer code which incorporates the attributes defined above. The Predictive Plant Model should also be developed on a system-by-system basis using a logical and unique naming convention for each system. Note that predictive models are biased to provide conservative results when used with default parameters. Initial use model results should only be to establish re-inspection intervals. Benchmarking of results with actual unit data may allow refinement of predictive results over time. Analysis Line - An Analysis Line is one or more physical lines of piping that have been analyzed together in the Predictive Plant Model. All results from the FAC analysis must be documented within the FAC program effort. The initial analysis will serve to identify high priority systems and components for inspection and to categorize, in conjunction with the cycle chemistry optimization actions described in Section 6, those systems and components for which longterm FAC control can be achieved via root cause actions. For conventional fossil plants, EPRI developed the CHECUP™ predictive model to assist in single-phase FAC evaluations. This model may also be applied to the feedwater piping in HRSG units. The CHECUP™ model does not analyze two-phase situation in either piping or vessels, such as feedwater heater shells and deaerators, and thus cannot be applied to HRSG economizer or evaporator tubing. The purpose of the CHECUP™ analysis is to predict relative FAC wall loss rates in the large number of “analysis lines” that comprise a typical feedwater system. This analysis provides a consistent, technical basis for prioritizing actual inspections for FAC damage. Only after the actual inspection data is acquired should the remaining service life

5-2


be determined. Note that individual operating units may select any analytical tool that covers the necessary plant design, operating, and water chemistry conditions as described above.

5.2 Selecting and Scheduling Components For Inspection An initial inspection is recommended to determine the actual level of damage that may have been sustained by FAC susceptible systems and components during prior service of the unit, to identify any components with unacceptable damage, to collect data to determine FAC trends, and to benchmark the results from a Predictive Plant Model (CHECUP™ or similar) to more accurately predict future wall loss. In these guidelines, the initial inspection is defined as the first inspection outage at which the inspection locations for a given “Analysis Line”1 were selected based upon a Predictive Plant Model. It is recognized that many organizations have already performed some inspection activities for FAC damage. Under a formal FAC program, this information should be collected and reviewed by the FAC team. Experience has shown that until a comprehensive analysis of all susceptible systems has been completed, a high degree of confidence cannot be established that all highly susceptible locations have been identified and are being controlled or monitored to prevent leakage or rupture. It is recommended that, where feasible, an FAC analysis be performed for each large bore susceptible system using a Predictive Plant Model to help select the inspection locations. The components selected by this process that have not been inspected previously should be inspected at the next scheduled plant outage. Components are selected for the initial inspection by means of a three-step process for each Analysis Line: 1. Select a sample of the most potentially susceptible components from both the ranking analysis and plant and industry experience. (Table 1-2 provides a summary of recent industry experience and Section 2.2.5 provides an initial inspection priority based on feedwater equipment.) 2. Conduct inspections of this sample. If any of these inspections reveal significant FAC wall loss, expand the sample to identify significant loss in other components. 3. As the sample inspections are completed, determine the measured wall loss of each inspected component. Utilize these measured loss rates to calculate the predicted remaining FAC service life for each inspected component. See Subsection 5.7.3 for the method of calculating predicted remaining service life. Additionally, the inspection plan should be modified if necessary to account for the inspection results. Additional details for each of these steps are provided in the subsections that follow.

1

See definition of analysis line in Subsection 5.1.

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5.2.1 Sample Selection The selection of components to be inspected is typically driven by industry and unit experience, engineering judgment, and application of predictive models. The use of predictive models allows consistent comparison between the various lines and their variable conditions within a feedwater piping system. The use of the CHECUP™ software code for this purpose will be summarized in Section 5.3. The following general guidelines are provided for selecting components for the inspection sample of each Analysis Line: 1. Select a sample from the component geometries identified in the wear ranking as having the highest relative wear. To the extent practical, the sample should include components from each geometry type present in the Analysis Line (e.g., elbows, reducers, expanders, tees, valves, orifices, equipment nozzles, piping downstream of other components, etc.). Engineering judgment should be employed to ensure that the most representative sample of the items with the highest probability of damage be examined. For example, if the three highest-ranked components are elbows, and the first tee in the rankings is the sixth highest ranked item, then that tee should be inspected in preference to the third ranked elbow. However, if the highest ranked tee is the hundredth item, it should not replace the third ranked elbow. 2. If previous inspections and remaining life analyses have been performed, select one or more components with the shortest relative remaining service life, if they are not included in the sample of (1) above. 3. A minimum of one component should be selected from each parallel train in a multi-train line. These components should be in similar locations for the purpose of comparing results. It is recommended that this location be one of the highest ranked items in the relative wear ranking. 4. Include components immediately downstream of control valves and orifices. These locations should be included in each train of multi-train lines. Note that locations downstream of control valves and orifices are also often susceptible to damage caused by cavitation or droplet impingement. 5. Include all known and potential FAC problem areas based on past plant experience and past experience in sister plants. 6. Consider all applicable locations known from industry experience to be high-FAC areas in other plants (Table 1-2). 7. Consider components that have been replaced in the past and any components within two diameters downstream of replaced components, or within two diameters upstream if the replaced component was an expander or expanding elbow. Ensure that the piping downstream (upstream in the case of an expander) be included in this consideration. 8. Consider unusual geometries, including field fabricated tees and laterals2 and locations known to have backing rings.

2

Special attention is recommended for field fabricated tees and laterals as they sometimes have protuberances into the flow stream (increasing local turbulence) and they often lack structural reinforcement.

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9. Based on EPRI experience, the size of the sample based on the wall loss ranking should be a minimum of 3 to 5 components per Analysis Line, depending upon the number of components in the Analysis Line, the predicted loss rate, and the line complexity. CAUTION: The recommended sample size of 3–5 components per Analysis Line is based on the demonstrated accuracy of the CHECWORKS™ and CHECUP™ computer codes. If other methods are used to select inspection locations, then the sample size used should be justified. 5.2.2 Expanded Sample Inspection 1. When inspections of the sample selection detect significant FAC damage, the sample size for that Analysis Line should be increased to include the following: a) Any component within two diameters downstream of the component displaying significant damage or within two diameters upstream if that component is an expander or expanding elbow. b) A minimum of the next two most susceptible components from the relative wall loss ranking in the same train as the piping component displaying significant wear. c) Corresponding components in each other train of a multi-train line with a configuration similar to that of the piping component displaying significant wear. 2. When inspections of the expanded sample of (1) above detect additional components with significant FAC wear, the sample should be further expanded to include: a) Any component within two diameters downstream of the component displaying significant wear, or within two diameters upstream if that component is an expander or expanding elbow. b) A minimum of the next two most susceptible components from the relative wear ranking in the same train as the component displaying significant wear. 3. When inspections of the expanded sample of (2) above detect additional components with significant wear, the sample expansion of (2) above should be repeated until no additional components with significant wear are detected. The above selection process should be reviewed with other personnel involved in the implementation of the FAC program. 5.2.3 Inspection Locations for Lines with Uncertain Operating Conditions Certain large bore systems, or portions of systems, such as auxiliary steam and gland steam, may have unknown (e.g. unknown moisture content in two-phase flow, etc.) or widely varying operating conditions which prevent the development of reasonably accurate analytical models. These lines are sometimes called susceptible non-modeled lines. Inspection locations on these lines should be conservatively selected using a combination of engineering judgment, industry experience, and plant experience. 5-5


It is recommended that special consideration be given to the following locations: •

Downstream of orifices

•

Downstream of flow control valves and level control valves

•

Nozzles

•

Tees and laterals, particularly field fabricated tees and laterals

•

Complex geometric locations such as components located within two diameters of each other (e.g., an elbow welded to a tee)

•

Components with backing rings and counterbores

If initial inspections detect significant FAC caused thinning, then the inspection sample should be expanded using the criteria of Subsection 5.2.2 (1) (a) and (c). 5.2.4 Inspection Locations for Lines that Cannot be Analyzed Using The Selected Predictive Methodology Certain predictive methodologies cannot analyze all potential FAC susceptible lines even if operating conditions are known in those lines (e.g. two-phase lines). For these lines the guidance of Subsection 5.2.3 should be followed with the additional recommendation that a minimum of one location in each two-phase line of piping should be selected for inspection.

5.3 CHECUP™ Summary EPRI's CHECUP™ technology was developed specifically for fossil, co-generation, and industrial steam plants to rank the amount of wall loss that may have occurred at various piping locations due to FAC. It can also be used for the feedwater piping of HRSG units, but not for economizer or evaporator tubing. This increases the confidence of plant owners and operators that the most damaged components will be identified, inspected, and repaired or replaced long before a rupture might occur. Importantly, for the large number of piping runs and components that is potentially susceptible to FAC damage, CHECUP™ provides a technical basis for selecting higher FAC risk locations for inspection from among the many possibilities. This provides a cost benefit in reducing the number of inspections required to characterize the level of FAC damage for a specific unit. As was presented in Section 2, the material and chemistry conditions drive the FAC mechanism with the hydrodynamics setting the rate of damage. CHECUP™ provides an analysis basis for the hydrodynamic factors. CHECUP™ predicts the wall loss of single-phase piping segments and components since plant startup. A piping segment is a portion of a line that has the same size, material, and operating conditions. Input data for a segment includes its material, pipe size, operating temperature, flow rate, system identification, dissolved oxygen, water treatment, condensate cold pH, and number of operating hours since plant startup. Provision is made for selecting component types from a library of previously analyzed geometries. A typical input screen for CHECUP™ is shown in Figure 5-1. Output data is the predicted wear of common types of piping components with some parametric variations of uncertainties as shown in Figure 5-2. 5-6


Figure 5-1 Sample Input Screen for CHECUP™ FAC Analysis

Figure 5-2 Sample Output Report from CHECUP™ FAC Analysis

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Key features of CHECUP™ include: •

All data input for a segment on one screen.

•

Ability to quickly evaluate operation at reduced or cycling unit loads.

•

Built-in properties of standard pipe sizes and common piping materials.

•

Built-in correlations of cold pH and water treatment (ammonia, several amines) with hot pH (hot pH impacts the rate of FAC).

•

Sensitivity of results to plant variables- material alloy content (AC), temperature, oxygen content and cold pH is also shown.

•

Results can be easily evaluated to aid in the selection of inspection locations.

It is emphasized that the FAC results from CHECUP™ are intended primarily for prioritizing inspection efforts and are not intended to provide accurate prediction of FAC damage. Actual inspection results are to be used to trend FAC damage and estimate remaining service life. This inspection process is reviewed in the next section.

5.4 Perform NDE Inspections The NDE inspection techniques, FAC analysis procedures and remaining life calculations are included in this Section. The results from these activities are to be reviewed by the FAC team and combined with the results from the cycle chemistry optimization path to establish the unitspecific, longterm strategy for managing FAC. For example, if inspection results confirm that no FAC damage has occurred in a line in which cycle chemistry FAC controls can be initiated or maintained, then this chemistry action becomes the longterm control strategy and further inspection would not be scheduled. The chemistry control strategy must be fully documented in the FAC program, key chemistry parameters must be monitored and recorded, and chemistry data should be periodically reviewed. For components or lines in which chemistry control is not achievable, a periodic inspection process will be undertaken to ensure repair or replacement of FAC damaged components prior to in-service failure. 5.4.1 Inspection Techniques Components can be inspected for FAC damage using a variety of techniques. Key techniques in current use are ultrasonic testing (UT), radiographic testing (RT), visual testing (VT), and pulsed-eddy current testing (PEC).(4,5,6,7) UT provides the most accurate measurement of wall thickness but requires that the inspection be performed during a unit outage with insulation removed from the area to be inspected. RT and PEC can be performed on insulated lines and components but do not provide as accurate data as UT. UT, RT and PEC methods can be used to investigate whether or not wear is present. However, the UT method provides more complete data for measuring the remaining wall thickness. Visual techniques, such as direct observation or use of video camera probes, are often used for examination of very large diameter piping and vessels where inside access is possible. VT should be followed by UT examinations of areas where significant damage is observed or suspected. As noted in Section 2, the morphology of FAC damage in feedwater heaters and deaerators operating under oxidizing chemistry conditions 5-8


can provide an obvious visual indicator in the form of the color of the inside surface. Protected areas will appear red, while damaged areas will appear black. For HRSGs, the same techniques from above may be used on accessible piping and other components. FAC damage (both single- and two-phase) that occurs in the LP evaporator tubing sections presents additional challenges for inspection since access to the tubing is generally very limited. EPRI is currently investigating opportunities for inspecting such sections via inside diameter (ID) access and using visual, UT, and eddy current testing (ECT) techniques.(8) 5.4.2 Ultrasonic Testing Inspections For large-bore piping, the recommended UT inspection process consists of marking 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 thinning, the region between the grid intersection points should also be scanned, or the size of the grid reduced to identify the extent and depth of the thinning. Although scanning the entire component and recording the minimum thickness is not recommended, scanning within grids and recording the minimum found within each grid square is an acceptable alternative to the above method. The inspection data is used for three purposes: 1. To determine whether the component has experienced wear and to identify the location of maximum thinning. 2. To ascertain the extent and depth of the thinning. 3. To evaluate the wear rate and wear pattern to identify any trends, if data from multiple inspections is available. To attain all three of these objectives, it is recommended that the component be inspected using a complete grid with a grid size sufficiently small as not to miss worn areas (see Subsection 5.4.2.2). Although scanning will meet the first two objectives, it will not provide sufficient data to determine component wear rates or to develop sufficient data to perform a detailed stress analysis of a worn component. Further, scanning is of limited use in trending the wear found. High temperature paints, china markers, or other marking devices should be used to identify the grid intersection points where the measurements will be taken. This will ensure that future inspections can be repeated at the same locations. It is good practice to mark at least one location, such as the grid origin, with a low stress stamp or an etching tool. This provides a means of re-establishing the grid if the markings are obscured. Note that approved marking materials should be used when gridding components. Templates may also be used to achieve repeatable measurements.

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When a component is to be replaced with another component made of a non-FAC resistant material, the new component should be appropriately gridded and baseline UT data obtained. This requirement can be waived for the situation where cycle chemistry parameters will be used during future operation to control FAC for the replaced component. The new component should also be examined visually to observe the eccentricity, surface, roughness, local thinning, such as is caused by depressions in the surface, etc. These data should be recorded and will provide a good baseline for determining future component wear. Additionally, if there is any evidence that some of the wear may have been caused by a mechanism other than FAC (e.g., cavitation or droplet impingement), then consideration should also be given to developing an appropriate inspection program to address the suspected phenomenon. The inspection grid should have a unique identification for each measurement location. For compatibility with the CHECUP™ and CHECWORKS™ computer codes, if used, it is recommended that letters be used to designate circumferential locations, and numbers used to designate axial locations on grids. It is also recommended that the origin of the grid be on the upstream side of the component. For small-bore piping and tubing, there are no standardized inspection methods. The most common approaches are: •

Gridding or scanning the downstream piping and expanding to the component if substantial wear is found.

•

Gridding the component and recording the readings.

•

Scanning the component and recording the minimum measured on the entire component or in quadrants.

•

Using RT methods. These methods will be discussed in a Subsection 5.4.3.

5.4.2.1 Grid Coverage Experience has shown that it is very difficult to predict where the maximum wear will occur in a given component. (For the purpose of this section, a component refers to both fittings and straight pipes.) To ensure that the maximum FAC wear can be detected, the UT grid should fully cover the component being inspected. A full-coverage grid also provides a good baseline for future inspections. As wear can spread over time, a partial grid, even if larger than the original wear area, may be too small to ensure that the full extent of the wear can be detected in the future. It is also beneficial to inspect the area on both sides of each pipe-to-component weld. It is desirable to start the grid line on both sides of the weld, as close as possible to the toe of the weld, in order to locate potential thin areas adjacent to the weld. This will help detect the presence of backing rings, or the use of counterbore to match the two inner surfaces. Having data on the connected pipe can also be helpful in evaluating whether variation of wall thickness in the component is FAC wear or fabrication variations. In many cases, the grid in the counterbore region will have to be evaluated separately.

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It is also suggested that when fittings are welded directly to fittings, the weld area on the downstream fitting be inspected. This will provide the same benefits as discussed above. The results of EPRI tests, as well as the evaluation of data from a large number of power plant inspections, show that FAC can also extend into the piping downstream of a component. Consequently, it is recommended that the inspection grid extend from two grid lines upstream of the toe of the upstream weld to a minimum of two grid lines or six inches (15 cm), whichever is greater, beyond the toe of the downstream weld. If there is a straight pipe immediately downstream of the examined component and if the measured wall thickness in the pipe is decreasing in the downstream direction, or if significant wear is present, the inspection grid should be continued downstream until an increasing thickness trend is established. If expanded inspections are performed on the downstream pipe, then the pipe should be separately evaluated for acceptance. Test results also show that in the case of expanders (or diffusers) and expanding elbows, FAC can occur upstream of the component as well. It is recommended that for these components the wall thickness in the upstream pipe be measured. The grid should be extended upstream 2 grid lines or six inches (15 cm), whichever is greater. The grid should be expanded further upstream if necessary. Maximum wear in straight pipe downstream of components typically occurs within two diameters of the connecting weld. Consideration should be given to extending the grid two diameters downstream (or two diameters upstream for expanders and expanding elbows), at least for the first two inspections. This may avoid extra inspection time during the outage to investigate the first two grids and then having to inspect further downstream. Valves, orifices, equipment nozzles, and other like components cannot be inspected completely with UT techniques due to their shape and thickness. They need to be treated differently. Experience has shown that FAC wear in these components can be gauged from wear that may be present in piping located immediately downstream. It is therefore recommended that for these components the inspection grid be placed on the downstream pipe for a distance of two diameters downstream of the connecting weld, and, if possible, one or two grids in the component itself. If significant wear is detected in the downstream pipe, the component should also be examined. This approach for valves, orifices and equipment nozzles is only applicable if the piping downstream is manufactured of material with equal or higher susceptibility (equal or lower chromium content), and has not been repaired or replaced. A combination of UT, RT and/or visual techniques are typically utilized to inspect valves, orifices and equipment nozzles. 5.4.2.2 Grid Size To be compatible with the EPRI computer codes, if used, grid lines must be either perpendicular or parallel to the flow. For elbows, the lines perpendicular to the flow (inspection bands) are radial lines focusing on the center of curvature. This results in the same number of grid intersection points on both the intrados and the extrados of an elbow. The suggested grid layout is shown in Figure 5-3.

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Figure 5-3 Grid Layout for an Elbow

It is important that the grid size (maximum distance along the component surface between grid lines) be small enough to ensure that the thinned region can be identified. Experience and plant data have shown that the grid size should be such that the maximum distance between grid lines is no greater than πD/12, where D is the nominal outside diameter. The grid size need not be smaller than 1 inch (2.5 cm), and should not be larger than 6 inches (15 cm). The following table illustrates the maximum grid sizes for standard pipe sizes. The user should select convenient grid sizes equal to or smaller than those tabulated for the pipe sizes of interest. The grid size below is sufficient to detect the presence of wear, but may not be small enough to determine the extent and maximum depth of that wear. Therefore, where inspections reveal FAC wall thinning, the grid size should be reduced to a size sufficient to map the depth and extent of the thinned area. A grid size of one half the maximum size should be sufficient for mapping.

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Table 5-1 Maximum Grid Sizes for Standard Pipe Sizes (1 inch = 2.54 cm) Pipe Size (inch) 2 3 4 6 8 10 12 14 16 18 20 24 >24

Outside Diameter (inch) 2.375 3.500 4.500 6.625 8.625 10.750 12.750 14.000 16.000 18.000 20.000 24.000 -----

Maximum Grid Size (inch) 1.00 1.00 1.17 1.73 2.25 2.81 3.33 3.67 4.19 4.71 5.23 6.00 6.00

Because of the importance of grid layout in the inspection process and in the interpretation of the obtained data, it is important that the grid layouts used be well thought out and not be changed arbitrarily. This will provide the best possible value from the data sets obtained. 5.4.3 Through-Insulation Inspections As noted previously, two inspection techniques – RT and PEC - allow through-insulation assessment of FAC damage.(5,6,7) Although neither technique will provide the same level of accuracy as UT measurements, this through-insulation capability allows organizations to obtain data during plant operation and, importantly, better prepare for inspection effort during unit maintenance outages. Additionally, RT provides a technique to get some level of wall loss information in situations involving complex geometry where UT cannot be applied. Figure 5-4 illustrates both through-wall and tangential applications of RT. As can be seen in this figure, sources for inaccuracies in wall thickness values arise from the corrections required to, for example, account for the radiographic beam passing through two walls in the through-wall case and account for the variable metal path in the tangential case. Spatial distortion occurs at the edge of the film relative to the centerline and introduces inaccuracies in thickness measurements. Tangential radiography is more successful in estimating wall thickness.

5-13


Figure 5-4 Radiographic Technique for FAC

Newer RT performed with reusable phosphor plates rather than traditional film offers the advantages of higher sensitivity that requires lower radioactive source strength for equivalent film image quality and of a direct transfer of the radiographic image to electronic media. This, in turn, allows application of computer-based, image enhancement tools to improve data interpretation. Pulsed eddy current (PEC) technology has been used in recent years to perform through(6,7,9) The technique does not offer the same spatial resolution as provided insulation inspections. by UT measurements. This is illustrated in Figure 5-5 which compares wall thickness maps from both PEC and UT tests done on feedwater piping. The PEC process averages over a larger inspection spot size than in the case of UT. Accordingly, PEC does not provide a reliable methodology to determine the maximum wall loss, and thickness results should not be used in establishing re-inspection intervals without an increase in safety factor.

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20.0-25.0 35.0-40.0

Axial position

O

15 14 13 12 11 10 9 8 7 6 5 4 3 2 1

M

K

I

G

E

C

A

Circumferential position 15.0-20.0 30.0-35.0

C-Scan UT-Results Hayden Sample

Axial position

O

15 14 13 12 11 10 9 8 7 6 5 4 3 2 1

M

K

I

G

E

C

A

C-Scan Incotest-Results Hayden Sample

C ircumfe re ntial position 25.0-30.0 40.0-45.0

15.0-20.0 30.0-35.0

20.0-25.0 35.0-40.0

25.0-30.0 40.0-45.0

Figure 5-5 Comparison of PEC and UT Results for FAC Damage to Piping

In addition to piping applications, PEC has been applied to FAC damage assessment for feedwater heater shells.(9) This application is attractive due to the large areas to be evaluated and to the fact that RT cannot be easily applied as a through-insulation technique. Figure 5-6 summarizes the recommended inspection area for the two-phase FAC damage that has been reported in feedwater heaters (and reviewed in Section 2). EPRI results in assessing this technique show that it matches UT wear patterns if the area extent is large, that it provided reliable detection in cases where wall loss exceeded 20% and circumferential extent was greater than 10 inches (25.4 cm), that it was not reliable for FAC damage with relatively small area extent. Figure 5-7 provides a comparison of PEC and UT results.

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Figure 5-6 Recommended Inspection Coverage in Circumferential Direction for a Feedwater Heater Shell

Pulsed Eddy Current

Pulse Echo UT

Figure 5-7 Comparison of PEC and UT (pulse echo) Results for a Feedwater Heater Shell – Left Section

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5.4.4 Measuring Trace Alloy Content It has been previously presented in Section 2 that the presence of small amounts of chromium, and to a lesser extent copper and molybdenum, will dramatically reduce the rate at which FAC occurs. Currently, the technology exists to measure the trace alloy content of components. If the alloy content were measured, these measurements could then be factored into the Predictive Plant Model to improve the accuracy of predictions and to ensure that the inspection program is directed at the fittings most likely to fail. These measurements are particularly useful in cases where the measured wear is substantially less than the predicted wear. This will help in both understanding the reason for the differences as well as improving the accuracy of a Predictive Plant Model. Note that material libraries built into computer codes such as CHECWORKS™ and CHECUP™, normally use minimum specified values for the alloy content. If alloy measurements are used, the analyst must confirm that the measurements are accurate enough to ensure that the predictions remain conservative.

5.5 Evaluating Inspection Data Once the inspection data has been acquired, the next task is to evaluate the data for accuracy and to then assess the impact of any detected damage on remaining life of the component. Again, it is emphasized that in situations where little or no damage is found, attention must then be given to longterm, root cause control via cycle chemistry parameters. 5.5.1 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 is complicated by several factors, including the following: •

Unknown initial wall thickness (if baseline data was not taken).

•

Variation of as-built thickness along the axis and around the circumference of the component.

•

Inaccuracies in NDE measurements.

•

The possible presence of pipe to component misalignment, backing rings, or the use of counterbore to match two surfaces.

•

Data recording errors or data transfer errors.

•

Obstructions that prevent complete gridding (e.g., a welded attachment).

The challenge is to minimize the effect of these problems by applying uniform evaluation methods and utilizing engineering judgment.

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The large amount of inspection data can present a substantial data management problem. To manage the data, it is recommended that a scheme be utilized to organize and maintain the data logger files. A database should be used to store past inspection data and contain provisions to accommodate future inspection data. The database will provide an efficient means of organizing and accessing the data. The evaluation process consists of reviewing the inspection data for accuracy, determining the total wear, and determining the wear rate for each inspected component. These processes are described below. 5.5.2 Data Reduction The inspection data should be carefully reviewed to identify any data that is judged to be in error. Erroneous data points should preferably be re-inspected, or if necessary, eliminated to obtain valid readings. High and low readings should be compared to adjacent readings to evaluate their validity. One high or low reading in an area of consistent thickness may indicate an erroneous reading. Finally, depending on the component type, the variation in thickness attributable to manufacturing variations should be separated from the FAC wear. Reviewing data from the attached upstream and downstream pipe can be helpful. Elbows, tees, reducers and expanders are examples of components in which there is significant variation in thickness due to the manufacturing process. The presence of backing rings and counterbore should be noted so that these effects can be excluded. 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. 5.5.3 Determining Initial Thickness and Measured Wear Wear evaluations fall into two categories. The first category includes those components for which baseline (pre-service) thickness data are available. The second category includes those components for which no baseline data exists. The method used for calculating the component maximum wear (the maximum depth of wall thinning since the component was installed or repaired) will be different for the second case as the initial thickness is unknown. There are four methods commonly used for determining the wear of piping components from UT inspection data3. The methods are: •

Band Method

•

Area Method

3

Validity of the methods to determine wear and estimate the component’s initial thickness is based on grid sizes and configurations consistent with that recommended in Subsection 5.4.

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•

Moving Blanket Method

•

Point to Point Method

Three of the methods (band, area and blanket) also estimate the components initial thickness and can be used to evaluate components with single outage inspection data. All the methods are predicated on the theory that the wear caused by FAC is typically found in a localized area or region. Also, application of these approaches is invoked for the case where on-going FAC damage is anticipated because root cause control actions (chemistry or material upgrade) cannot/is not implemented. The methods are described below: Band Method

The Band Method is predicated on the assumption that wear caused by FAC is localized. As such, the thickness variations observed around circumferential bands is an indication of the wear experienced by the component. By successively evaluating these circumferential bands, the component wear is determined by the maximum variation observed from all such bands. The band method divides a component into circumferential bands of one grid width each. Each band is in a plane perpendicular to the direction of the flow. Figure 5-8 shows a cross sectional view of a circumferential band on a component with a localized wear region.

t max

t min Figure 5-8 Example of Band Method

The initial thickness of each band is assumed to be the larger of the nominal thickness or the maximum thickness found in the band (tmax). The band wear is the initial thickness minus the minimum thickness found in the band (tmin). For each band:

tinit

= larger of tnom or tmax

Wear = tinit - tmin The component maximum wear is the largest of the individual band wear values. The component initial thickness is then the initial thickness from the band of maximum wear. The use of the nominal wall thickness in the above calculations addresses the possibility that an entire band may have thinned uniformly, which may have caused most or all of the thickness to be under the nominal wall thickness. 5-19


The band method is based on the assumption of a uniform initial thickness of the band (e.g., no manufacturing variation). Any such manufacturing variation is reflected in the calculated wear. An appropriate method should thus be used to determine the measured wear of components suspected to have manufacturing variations (e.g., elbows). Further information is contained in the (2) CHECUP™ user guide. Area Method

The Area Method is an expansion of the Band method in which a local rectangular region, identified as the wear region, is evaluated for wear. It is based on the assumption that the entire wear area, and a thickness representative of the initial thickness, is encompassed within the rectangular region. More than one area can be defined for a given component. The initial thickness of each area is assumed to be the larger of the nominal thickness or the maximum thickness found in the area. The area wear is the initial thickness minus the minimum thickness found in the area. An example of the Area Method is shown in Figure 5-9. A, 1

G, 1 B, 2

E, 2

B, 5

E, 5

A, 6

G, 6

Figure 5-9 Example of Area Method

For each area:

tinit

= larger of tnom or tmax

Wear = tinit - tmin The component maximum wear is the largest of the individual area wear values. The component initial thickness is then the initial thickness from the area of maximum wear. The use of nominal wall thickness in the above calculations addresses the possibility that an entire area may have thinned uniformly, which may have caused most or all of the thickness to be under the nominal wall thickness. Moving Blanket Method

The Moving Blanket Method is a refinement of the Area Method. It automates the process of identifying the region of maximum wear and attempts to minimize the effect of measurement errors. The Moving Blanket Method was developed by reviewing extensive amounts of 5-20


component data to identify a method that would provide realistic, yet somewhat conservative estimates of initial thickness and wear. The method that was developed consists of placing a predetermined wear area or “blanket” of certain dimensions over the grid data. See Figure 5-10. The data that is within each blanket is evaluated to estimate both the initial thickness and the wear. The blanket is then moved to another location on the component and the process is repeated. The process continues until all possible locations on the component have been covered. Initial Blanket Location A, 1

Maximum Wear Blanket Location

G, 1

A, 1 B, 2

G, 1

D, 2

B, 2

D, 2

B, 4

D, 4

Primary Move

B, 5

D, 5

A, 6

G, 6

Secondary Move

A, 6

G, 6

Figure 5-10 Example of Moving Blanket Method

Point-to-Point Method

The Point-to-Point Method can be used when data taken at the same grid locations exists from two or more outages (or baseline data plus data from one or more outages). In such a case, it is possible to obtain a difference in thickness readings at each of the grid locations. In summary, the wear at each grid location is the thickness taken at the earlier inspection minus the thickness taken at the later inspection. The largest of the grid wear values is the component maximum wear between the two outages. The Point-to-Point Method does not estimate the initial component thickness.

5.6 Identifying and Confirming the Cause of Damage Wherever significant damage (or a leak or failure) has been found, it is highly recommended to look at the surface morphology and to perform a metallographic analysis to confirm the mechanism is FAC. Section 2 provides an extensive review of actual FAC damage. It is, however, most important to note that the plant areas susceptible to FAC can also be damaged by other mechanisms, which include cavitation and droplet impingement (sometimes called liquid impact erosion). Cavitation in piping and valve components occurs when water near the saturation point experiences a large pressure drop such as at a throttled control valve or orifice. The pressure drops below saturation, and bubbles are formed. Further downstream, when the pressure recovers, the bubbles collapse, causing large pressure spikes on nearby surfaces. The result can be significant wall loss of the material surfaces. Damage tends to look and feel quite sharp.

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Droplet impingement occurs in high velocity two-phase conditions when water droplets entrained in the steam strike and damage piping and equipment surfaces. As with cavitation, damage tends to look and feel quite sharp. It is important to identify the mechanism and to determine what caused the damage so that appropriate measures can be taken to find the extent of the damage and to control it. These guidelines do not pertain to mechanisms other than FAC.

5.7 Evaluating Worn Components Safe operation of piping and other components is predicated on the wall thickness being sufficient to contain the pressure stresses and prevent leak or rupture. The material in this subsection reviews the calculation basis for continued service. 5.7.1 Acceptable Wall Thickness Once significant damage has been found, and FAC has been determined to be the cause, then it should be evaluated to determine its acceptability for continued service. 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 = FAC wear rate at location of tp T = Time until next inspection SF = Safety Factor

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Although the wear rate and the amount of wear vary throughout a component, calculation of location-by-location values is beyond the ability of current available computer software. Currently, it is recommended that the component maximum wear rate be assumed to occur throughout the component, giving a predicted future thickness profile as shown in Figure 5-11. Note that this approach is conservative, as the amount of wear is overstated at all locations other than the point of maximum wear. See Subsection 5.7.2 for a method to determine the component maximum wear rate. Exterior Surface

Current Thickness Profile

Predicted Thickness Profile

Predicted Wear

Current Interior Surface

Figure 5-11 Predicted Thickness Profile

For susceptible components that have not been inspected, the predicted thickness should be used to calculate the lifetime of the component. The component nominal wall thickness should be utilized as the initial thickness unless another value can be justified. A reasonable safety factor should be applied to the predicted wear rates to account for inaccuracies in the FAC wear rate calculations. This can also provide a mechanism by which the analyst may apply engineering judgment in setting the interval for re-inspection. As the plant program matures and several outages of good inspection data are collected, the safety factor can be changed based on the use of actual inspection data. The minimum acceptable wall thickness for each component should be calculated. Component (10) acceptance criteria are typically based on the ANSI B31.1 construction code of record for the plant or the local international code. It is recommended that the calculation of taccpt be performed by an engineer with experience in piping stress analysis. 5.7.2 Maximum Wear Rate The Predictive Plant Model should be used to predict the future maximum wear rate for every component analyzed, whether inspected or not. For those components that have been inspected, two methods have been used to determine the wear rate directly from the inspection data.

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With the first method, 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. However, this method may cause several potential inaccuracies: 1. This method assumes that operating conditions that affect FAC wear rate (e.g., feedwater chemistry, plant power level) have not changed since plant startup or are well documented. If changes did occur or these conditions are not well documented and assumptions must be made, the current wear rate could be considerably different than the average wear rate. 2. The method cannot accommodate potential future changes in operating conditions.

Component Thickness

Figure 5-12 shows the potential for error when using an average wear rate based on inspection data and changing operating conditions for determining component lifetimes.

Chemistry Period 1 t init

Initial Wear Rate

Chemistry Period 2

Prediction

Current Wear Rate

Average Wear Rate t accpt

Time of Inspection

Plant Operating Time Figure 5-12 Potential for Error When Using Average Wear Rate Based on Inspection Data

A second method can be utilized if data from more than one inspection is available. The measured thickness at the point of maximum wear from the current outage is subtracted from the value measured at the previous outage. This difference is then divided by the time interval to obtain the average wear rate. This method is known as the point-to-point method. It has the advantage of being mechanical; the maximum wear is simply the maximum difference between two sets of readings at the same location. Note that the user does not have to estimate initial thickness of the component in order to calculate the measured wear. The difficulties in using the point-to-point method occur in cases where the wear between the outages is small. Two large numbers (wall thickness) are subtracted to obtain a small number (wear since previous outage) and then divided by another relatively small number (interval between outages) to determine the wear rate. UT measurement inaccuracies could cause significant calculation error with this method. This is illustrated in Figure 5-13. However, in most cases where inspection data from

5-24


several inspection outages is available, the point-to-point method will provide more accurate determinations of wear than other methods.

Component Thickness

Previous Outage Range of UT Inaccuracy

Current Outage

UT Reading

Future Outage

Assumed Wear Rate

Potential Range of Actual Wear Rate

Plant Operating Time Figure 5-13 Potential Error Of Using Wear Rate Based On Inspection Data From Two Inspections

5.7.3 Remaining Service Life It is recommended to determine the remaining service life of each component where FAC is active or has been active, where, Tlife = remaining service life Tlife =

cu rrent thickness − m inim u m accep table thickness cu rrent w ear rate × safety factor

Tlife =

t c − t accpt R × SF

5-25


For those components that have been inspected, it is recommended that actual measured values be used for tc. For components not inspected, tc can be predicted utilizing predicted wear rates, tc

= tinit - “predicted wear” = tinit - (T x R x SF)

where, T R SF

= component service time to date = average wear rate over time T = safety factor

If the predicted remaining service life is shorter than the amount of time until the next inspection, there are three options for disposition of the component: 1. Shorten the inspection interval. 2. Perform a detailed stress analysis to obtain a more accurate value of the acceptable thickness. 3. Repair or replace the component.

5.8 Outage Documentation The results of the major decisions and results of the outage inspections should be documented, and appropriate records should be maintained. It is recommended that a report be prepared for each inspection outage. This report should identify the components inspected and justify the basis for their selection, (i.e., predictive ranking, industry experience, engineering judgment), the results of those inspections, and an evaluation and disposition of worn components. The plant database of inspection and replacement history should be updated after every outage.

5.9 Perform Necessary Repairs and Replacements Where unacceptable damage has been found (as determined by the structural evaluations of Subsection 5.7.1), it is necessary to repair or replace the affected components. One mitigating approach that is sometimes used is to replace only those fittings that have experienced significant wear. This approach is satisfactory if the wear is very localized. This is the case in which the wear is concentrated downstream of a flow control valve or an orifice. In most cases, though, the wear is widespread throughout a susceptible line or system. Unless changes to cycle chemistry can be implemented to control FAC damage, it is only a matter of time until upstream or downstream fittings will also need to be replaced. This fitting-by-fitting replacement approach is less expensive in the short term, but is generally not cost effective over the long term. Plants using this selected replacement technique have also experienced unexpected failures in components scheduled for future replacement. It is recommended that when making repairs, strong consideration be given to replacing the entire line or spool piece with a resistant material 5-26


(Cr content > 1.25%). Again, unless changes to cycle chemistry can be implemented to control FAC damage, replacement/repair with carbon steel will result in repeat FAC damage. 5.9.1 Repairing and Replacing Components The following items should be considered in making replacement decisions: •

The cost and availability of replacement fittings.

•

The need for skills and procedures to weld alloy steels and clad material to carbon steel, or apply weld overlays or use the temper bead technique.

•

The pre-and post-weld heat treatments required for welding chrome-molybdenum fittings. This heat treatment may affect the outage schedule.

•

The piping stress analysis required if a large portion of a carbon steel line is replaced with stainless steel.

•

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

If repair is decided upon, the weld buildup technique is commonly used for the temporary repair of piping. Interior weld buildup is generally preferred to exterior buildup for the following reasons: •

Interior weld repair results in a smoother internal surface.

•

By using interior weld repair, the resulting, smoother internal surface reduces the difficulty of making future UT inspections.

•

An exterior weld buildup tends to result in a more complex state of stress.

Temporary clamping devices or furmanite boxes are often used to make temporary repairs to low pressure piping. However, permanent repairs should be made at the first opportunity in the event that the damage is growing and may cause the component to lose structural integrity (i. e., completely rupture). If repair or replacement of a component is necessary, it is recommended that the plant owner develop a strategy so that the wear process does not continue. This essentially means not repairing/replacing with carbon steel material. However, there are cases in which use of like-forlike (i.e., non-FAC resistant) material is appropriate. These cases include: •

The plant has optimized the feedwater chemistry (Sections 2 and 6) or the line will experience less damaging operating conditions (e.g., a higher steam quality) such that the replacement is projected to last the remaining life of the plant.

•

Procurement of a resistant material would delay plant restart. In this case, consideration should be given to upgrading the replacement with a resistant material at the next outage.

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•

The remaining life of the plant is such that a like-for-like replacement will perform satisfactorily.

•

Life cycle costs and risk considerations associated with like-for-like replacement, including associated inspection costs, do not support change to FAC resistant material.

5.9.2 Use of FAC Resistant Materials It has been widely demonstrated that materials containing chromium are resistant to FAC damage. Lesser improvements come from molybdenum and copper. Replacing carbon steel piping with chrome-molybdenum alloy (SA335, Grade P11 or P22) (1.25 or 2.25% Cr alloys) or stainless steel (normally a 304 alloy) should alleviate FAC damage for the life of the plant. The benefit can also be achieved by coating the piping surface with a high-alloy layer (flame spraying or weld overlay) or using a clad pipe with a high-chromium or stainless steel inner layer surrounded by a carbon steel outer layer. In all cases replacement should be with a minimum of a 1.25% Cr alloy. Recent EPRI work has reviewed the use of weld overlay for repair of FAC damage to deaerators(11). This review notes the need for further weld procedure development to allow use of chromium levels greater than 1.25% without performing post weld heat treatment. EPRI work is ongoing. In the specific case of two-phase FAC damage to both conventional fossil plant components and to HRSG components, use of FAC resistant materials will likely provide the most cost-effective, longterm control of FAC damage since cycle chemistry control options are limited as discussed in Sections 2 and 6. Table 5-2 presents the degree of improvement associated with common piping alloys, as predicted by CHECUP™, which is based on the data of Ducreux(12). This data is generally considered the definitive work in the area of the influence of material composition on FAC wear rate. It is clear from the values shown in the table that FAC can be effectively eliminated through material improvement. Table 5-2 Performance of Common FAC-Resistant Alloys Nominal Composition (Chrome & Moly only)

Ratecarbon/Ratealloy _________________

P11

1.25% Cr, 0.50% Mo

34

P22

2.25% Cr, 1.00% Mo

65

304

18% Cr

>250

Material

Material changes can be used to replace an entire system or to repair an especially troublesome area. However, material replacement may not reduce the wear rate if the damage is caused by a mechanism other than FAC. This is the case, for instance, if the damage is caused by cavitation or liquid impingement.

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5.9.3 System Design Changes When repairing a section or line of piping damaged by FAC, some consideration can also be given to design changes, particularly when a like-for-like replacement is made. However, design changes generally result in only small reductions to the rate of FAC damage. For example, reducing the flow velocity by changing the diameter of a piping system from 12 to 14 inches (3035 cm) will only reduce the FAC rate by about 20%. One instance, however, where design change can be effective occurs in increasing the pipe diameter to reduce the velocity in control valve stations. Valve stations are typically designed to accommodate the flow capacity of the control valves. This typically results in a reduced diameter of about 60% of the line size and a consequent increase in the fluid velocity. This locally increased velocity has often caused damage downstream of the valve. Redesigning the valve station to reduce the local velocity and turbulence can greatly reduce the rate of FAC damage.

5.10 References 1. CHECWORKS™ Computer Program Users Guide, TR-103496, EPRI, Palo Alto, CA: August 1994. 2. CHECWORKS™ Fossil Plant Application - CHECUP™ Code, Version 1.0 User Guide, EPRI, Palo Alto, CA: 1998. TR-103198-P5. 3. CHECUPweb Version 1.0 a web application on the EPRI Solutions production server, EPRI, Palo Alto, CA: 2004. 1008127 4. NDE of Ferritic Piping for Erosion/Corrosion, NP-5410, Electric Power Research Institute, September 1987. 5. FAC Wear Rate Assessment Through Insulation, EPRI, EPRI NDE Center, Charlotte, NC: 2000. 1000114. 6. On-Line Flow-Accelerated Corrosion Assessment of Large Diameter Piping Through Insulation with Radiographic Techniques, EPRI, Palo Alto, CA and Florida Power & Light, Juno Beach, FL: 2004. 1009594. 7. Assessment of the Pulsed Eddy Current Technique: Detecting Flow-Accelerated Corrosion in Feedwater Piping, EPRI, Palo Alto, CA: 1997. TR-109146. 8. Interim Guidelines for the Nondestructive Examination of Heat Recovery Steam Generators, EPRI, Palo Alto, CA: 2004. 1004506. 9. In-service Feedwater Heater Condition Assessment Using the Pulsed Eddy Current NDE Technology, EPRI, Palo Alto, CA: 2001. 1006372.

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10. American National Standard Code for Pressure Piping, “Power Piping”, ANSI B31.1. 11. Repair of Deaerators, EPRI, Palo Alto, CA: 2004, 1008069. 12. J. Ducreux, “Theoretical and Experimental Investigation of the Effect of Chemical Composition of Steels on Their Erosion-Corrosion Resistance”, presented at the Specialists Meeting on the Corrosion-Erosion of Steels in High-Temperature Water and Wet Steam, Les Renardieres, France, May 1982.

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6 OPTIMIZE FEEDWATER CHEMISTRY IN CONVENTIONAL FOSSIL AND HRSG PLANTS

For conventional fossil plants as indicated in Section 3 (Figure 3-1), it is suggested that a utility address both the “Inspection Based Activities” and optimize the feedwater chemistry in a parallel path set of activities in developing an overall approach to FAC. The importance of feedwater chemistry in the mechanism of FAC, and its interface with the different materials (all-ferrous or mixed-metallurgy) under reducing and oxidizing conditions was discussed in Section 2. Changes in feedwater treatment can significantly reduce the rate of single-phase FAC, and in some cases (such as with OT in all-ferrous systems) can almost eliminate it. Similarly in HRSGs, optimizing the cycle chemistry can significantly assist in controlling FAC. As discussed in Sections 2 and 3, the cycle chemistry can be optimized in: a) the feedwater to control single-phase FAC (Step 9 on Figure 3-2), and b) the evaporator to control both singleand two-phase FAC (Step 10 in Figure 3-2). Chemistry changes are an attractive solution for FAC as they affect the damage mechanisms globally. It is also recognized that the cycle chemistry is very important to the overall availability of other parts of the fossil and HRSG plants, as the corrosion products generated flow around the cycle and deposit in the higher heat transfer areas. These locations can act as the initiating centers for other damage mechanisms. EPRI has a series of guidelines for fossil plant cycle chemistry(1,2,3) and for HRSGs.(4) The feedwater guideline limits are shown in Table 2-2. This Section addresses the selection and optimization of feedwater treatment and is an extracted compilation from the latest guideline documents with particular emphasis for FAC control and minimization. Optimization of the evaporator chemistry for HRSGs is discussed in Step 10 of the road map for controlling FAC in HRSGs (Section 3.2).

6.1 Optimization of All-Ferrous Feedwater Chemistry in Conventional and HRSG Units Figure 6-1 shows a road map for optimizing the feedwater treatment in all-ferrous systems. The primary purposes of this important activity are to minimize corrosion product transport, eliminate any possibility for single-phase FAC, and thus to reduce the accumulation of corrosion product deposition on the boiler waterwalls. The methodology described here is equally applicable for both drum and once-through conventional fossil units and for HRSG units with all-ferrous feedwater systems.

6-1

EPRI Licensed Material Optimize Feedwater Chemistry in conventional Fossil and HRSG Plants

Step 1 - Review Normal or Current Feedwater Treatment This step involves a review of the current feedwater treatment, which is probably AVT(R) with a reducing agent. If there are no current problems then continue to use the current treatment. Such a review would indicate that the operating experience has been good, that minimal chemical control problems have been experienced, that no BTF or HTF in the waterwalls or evaporators relating to waterside problems have occurred in the last five years, that no turbine deposition or blade failure problems have occurred, and that the feedwater is operating in the optimum fashion with minimum levels of feedwater corrosion products (less than 2 ppb at the economizer inlet). In such cases of good experience, no changes need to be made. However, it is suggested that the road map is reviewed as there may be considerable economic savings to be gained by converting to AVT(O) or OT, and it should be remembered that single-phase FAC is always possible with reducing feedwater chemistry (AVT(R)) (Section 2). If the review indicates problems, then some baseline monitoring is required (Step 2). Step 2 - Monitoring Baseline on Current Feedwater Treatment This step involves a complete base-line monitoring to quantify the current chemical parameters and, in Step 3, to determine whether continued use of a reducing agent and AVT(R) or a change to AVT(O) should be contemplated. This program would utilize the installed chemistry monitoring system, which involves the core (1–4) level of instrumentation. The monitoring program should pay particular attention to the adequacy of the makeup and chemical feed systems, condenser tightness, air in-leakage, and corrosion product transport.

6-2


Figure 6-1 Road Map for Optimizing Feedwater Treatment for All-Ferrous Feedwater Systems.

6-3


This monitoring involves taking a “thumb-print” of the unit under “typical operating conditions” to identify under controlled conditions exactly how the unit chemistry is behaving. It may involve a review of the operating chemistry logs, but this often is not satisfactory and it is preferable to undertake a monitoring campaign. Before this campaign is initiated, it is important to review the utility’s chemistry monitoring capability and reliability. This should include Quality Assurance (QA) and Quality Control (QC) of existing and normally utilized analytical chemistry monitoring and analysis methodology and equipment. The monitoring campaign should include: •

Varying Operating Conditions—base load, startup and shutdown

•

Steam Chemistry—cation conductivity, sodium, chloride, silica and sulfate

•

Feedwater Chemistry—cation conductivity, chloride, corrosion products (Fe, Cu), oxygen and pH.

•

Operation of Condensate Polishers (if included)

If this step indicates a low level of feedwater corrosion product transport (such as Fe <2 ppb) and acceptable feedwater purity from a dissolved solids standpoint with the control chemistry meeting the guideline values provided in the EPRI Guidelines,(1–4) then an organization might consider to continue with the current AVT(R) feedwater chemistry. Further confirmation, for conventional fossil plants, of optimum feedwater chemistry will be that waterwall deposition rates have historically been much less than 1 mg/cm2/1000 hours (about 1 g/ft2/1000 hours), that the interval between chemical cleans has historically been longer than every 10 years, and that there has been no indication of FAC in the feedwater, feedwater steamside, deaerator, or feedwater heater drain lines. For HRSG plants, confirmation would be low levels (< 5 ppb) of iron around the cycle. Step 3 - Evaluate Reducing Agent Requirements This step is a subset of Step 2 and should involve a series of tests to minimize the generation and transport of feedwater corrosion products. Many utilities with all-ferrous systems have found that, with proper air in-leakage control (dissolved oxygen at the CPD of less than 10 ppb), the reducing agent (such as hydrazine) can be eliminated without jeopardizing chemistry control on the unit and move to AVT(O). Thus in Step 3, a series of tests could be performed to evaluate the need for a reducing agent and, if needed, to determine the proper reducing agent level. The tests should utilize the monitoring system instrumentation (used in Step 2) while reducing or eliminating the reducing agent dosage. Particular note should be made of dissolved oxygen levels and the level of corrosion products generated during each test. Table 2-2 should be referenced for typical parameter ranges. Particular attention should be paid to the fact that there can be a long time between changes in the feedwater chemistry and corrosion product transport, so careful planning is needed for accurate extended tests.

6-4


Step 4 - Monitoring with New Feedwater Treatment Step 4 involves a period of normal operation with the new feedwater treatment, which occasionally requires repetition of monitoring in Step 2 to confirm that running with reduced or zero reducing agent provides the optimum feedwater treatment. This might involve a reduced monitoring effort which just looks at feedwater oxygen and corrosion products at the economizer inlet, in parallel with the cycle “core” parameters(1–4), which should be normally continuously recorded and alarmed. In units with all-ferrous feedwater systems, but with copper based condenser tubing, there is a possibility of copper corrosion particularly in the air removal section of the condenser. If increased copper transport is measured at the CPD, then considerations should be given to a reduction in cycle pH from 9.2–9.6 to 9.0–9.3 as needed to reduce copper levels to those present during baseline monitoring. Of course such an increase in copper dissolution will not be a result of the AVT(R) to AVT (O) change, but the pH reduction was probably needed when operating in the AVT(R) mode. Steps 5 and 6 - Consider Converting to OT Once the baseline monitoring (Step 2) and a period of normal operation has been undertaken then the question can be raised about whether the unit could run on oxygenated treatment (Step 5). For conventional fossil plants, the reader is referenced to Sections 8 and 2.7 of the OT Guidelines(3) for guidance on OT conversion and for frequently asked questions on OT which provides step-by-step guidance on whether a unit is suitable for OT and how to convert units to OT (Step 6) in a sequential fashion. It should be noted that conversion to OT will take a number of weeks (more for drum units) and must include passivation of the heater drains and optimizing of vent operation on the heaters and deaerators. Step 7 - Continue to Optimize the Feedwater Treatment This step continues the efforts described in Steps 3 and 4. Step 8 - Operation and Continuing Monitoring When Step 7 results are satisfactory, indicating trouble-free water chemistry and operation, then normal operational monitoring resumes. However, there should be periodic reviews of water chemistry and equipment scale and corrosion problems, and chemical transport studies should be performed every two to three years to ensure that equipment aging and other changes do not result in problems. The water chemistry and operating manuals should be updated to reflect the changes resulting from the optimization. The feedwater treatment used on each unit, whether this is AVT(R), AVT(O) or OT, should be continually checked to ensure it is always the optimum treatment. 6-5


6.2 Optimization of Feedwater Treatment for Conventional Fossil Plants with Mixed-Metallurgy Systems Figure 6-2 shows a road map for optimizing the feedwater treatment in conventional fossil plants with mixed-metallurgy feedwater systems, and for ensuring that FAC will be minimized on the carbon steel components. For mixed-metallurgy systems, the optimum pH control (9.0-9.3) (Table 2-2)(1,2) is a compromise of the optimum corrosion protection for each metal. The brief outline of the steps below are from an FAC perspective, but it is important that the reader references the EPRI Guidelines(1,2) to get the full unit perspective for mixed-metallurgy units. Step 1 - Review of Water Chemistry, Operation, and Experience This step involves a review of the past and current feedwater treatments to assess whether FAC is, or maybe will be a future, problem and also to determine if the feedwater treatment can be optimized to minimize the level of feedwater corrosion products. If there have been no problems in the unit, no evidence of any FAC damage or failure (Tables 1-2 and 1-3), and the level of feedwater corrosion products at the economizer inlet are in agreement with the EPRI guideline limits for mixed-metallurgy units (Table 2-2), then continue the current treatment. However, it is suggested that the road map is reviewed as there may be considerable economic savings to be gained. Also in mixed-metallurgy systems both the iron and copper corrosion products have to be optimized as the latter contributes seriously to copper fouling of the HP turbine.(5)

6-6


Step 1 Review design and materials experience. Review current treatment, sampling and monitoring. No problems, BUT possible economic savings

Step 2

No current problems Continue use of current treatment Low level of corrosion products

Baseline monitoring

Implementation Step 3

Step 4

Water chemistry optimization (pH, ammonia/amine, reducing agent)

Step 5

Design and materials changes

Monitoring to compare with baseline

Step 6

Step 9

Operation

Step 7

Long-term plans

Normal operation and monitoring

Step 8 Continual check of chemistry

Figure 6-2 Road Map for Optimizing Feedwater Treatment for Mixed Metal Systems (Cu/Fe) to Minimize Feedwater Corrosion Products (Fe and Cu), and FAC of the Carbon Steel Components

Step 2 - Baseline Monitoring Baseline monitoring is a step which determines cycle chemical characteristics such as oxygen control, and transport of corrosion products. The monitoring involves taking a “thumb-print” of the unit under “typical operating conditions” to identify under controlled conditions exactly how the unit chemistry is behaving, and whether the feedwater chemistry is contributing to FAC of the carbon steel components. The monitoring campaign should include: –

Varying Operating Conditions - base load, startup, shutdown, etc.

–

Steam Chemistry - cation conductivity, sodium, chloride, silica and sulfate

6-7


–

Feedwater Chemistry - cation conductivity, chloride, corrosion products (Fe, Cu), oxygen, pH, oxidizing-reducing potential (ORP)

–

Drain lines - oxygen, ORP, and corrosion products

–

Operation of Condensate Polishers

During the tests for optimum pH and ammonia concentrations for mixed-metallurgy systems, it is extremely important that both iron and copper feedwater corrosion are monitored. If this step indicates a low level of feedwater corrosion products (such as Fe < 5 ppb and Cu < 2 ppb), and acceptable feedwater purity meeting the guideline limits (Table 2-2), then it is suggested to continue with the current chemistry as future single-phase FAC damage is not likely to be a serious problem. This does not preclude FAC having taken place with previous feedwater treatments. Step 3 - Water Chemistry Optimization If Step 2 has identified a problem with corrosion and/or FAC, then a careful series of feedwater optimization changes may improve the situation. Feedwater chemistry optimization usually consists of reducing air in-leakage, minimization of ammonia concentration and determining the optimum reducing agent dosage. All efforts must be directed along two paths: to minimize copper corrosion, and control corrosion and FAC of the carbon steel components. In fossil plants, there is little room for application of alternate reducing agents and volatile amines because of the problems with their thermal decomposition and generation of organic acids and CO2. Thus in most units with copper alloys in the feedwater system, hydrazine is the only reducing agent recommended. In this step, a series of tests should be performed to determine the proper reducing agent levels. The tests will utilize the monitoring parameters in Step 2, with particular emphasis on dissolved oxygen, ORP, and feedwater corrosion products. ORP (measured at the deaerator inlet) is particularly important with mixed-metallurgy units as a reducing environment is required for the (5) copper containing alloys . Step 4 - Design and Material Changes See Section 5. Step 5 - Operation As indicated in Section 2, once design deficiencies, improper materials or operating features are identified as the root causes of any FAC problems, these deficiencies need to be corrected. A follow-up chemistry monitoring campaign will need to be conducted (Step 6) to ensure low feedwater corrosion products and a low probability of FAC.

6-8


Step 6 - Monitoring to Compare with Baseline Data This step is aimed at verifying the effectiveness of the implemented solutions to water chemistry, corrosion and FAC problems. Step 7 - Normal Operation and Monitoring When Step 6 results are satisfactory, indicating long-time, trouble-free water chemistry and operation, normal operational monitoring resumes. The major criterion of an optimized feedwater treatment with minimum FAC is that the core parameters are within the normal guideline limits (Table 2-2). Step 8 - Continual Check of Chemistry The continual check on the optimized treatment (Step 8) and the core parameters will determine whether fine tuning is necessary (Repeat of Steps 3 and 6). Step 9 - Longterm Plans Based on the effectiveness of the solutions of water chemistry and corrosion problems implemented in a specific unit and on the equipment life predictions (i.e., feedwater heater and condenser tube deterioration) longterm plans can be formulated. This can include planning for ultimate replacement of copper alloys, retrofit of condensate polishers, nitrogen sparging and blanketing of the storage tanks used to fill the system during startup, etc. Industry experience shows that the maximum reduction of corrosion product transport in fossil power plant cycles can only be obtained by eliminating chemical control compromises caused by the use of mixed metal feedwater systems. Experience has also shown that the installation of a full-flow condensate polishing system with a startup cleanup system provides optimized corrosion product transport control.

6-9


6.3 References 1.


2.


3.


4.

a) Interim Cycle Chemistry Guidelines for Combined Cycle HRSGs, EPRI, Palo Alto, CA: November 1998. TR-110051. b) The first revision of this guideline will be published at the end of 2005 as: EPRI, Palo Alto, CA. 1010438.

5.

6-10

Guidelines for Copper in Fossil Plants, EPRI, Palo Alto, CA: November 2000. 1000457.


7 PERFORM LONGTERM MONITORING AND INSPECTIONS

It is most important that all plants conduct longterm monitoring and inspections of lines susceptible to FAC, and continually check that the feedwater chemistry meets the guideline limits of Table 2-2. This will provide a higher degree of assurance as to continued plant safety and operational integrity than will one time inspections. The recommended frequency and extent of future inspections will depend on the extent of damage found in the initial inspections, along with plant actions to reduce susceptibility such as optimizing the feedwater chemistry in conventional and HRSG plants, as well as the evaporator chemistry in HRSG plants. Follow-on inspections on an annual basis are suggested as follows: •

On all susceptible lines of plants that have not optimized their feedwater chemistry,

•

On all lines that have very little structural margins, and

•

On all lines that are found to have moderate to aggressive operating conditions.

Longterm monitoring (i. e., fewer inspections and inspections more widely spaced in time) can be performed in the following case: •

On lines of plants that have optimized their feedwater chemistry according to the procedures in Section 6, and were found to have reasonable amounts of structural margins.

In case of doubt, it is recommended that follow-on inspections be performed until it is clearly established that the line can be put into a longterm monitoring program.

7.1 Follow-On Inspections Follow-on inspections should be conducted for each line of plants that have not optimized their chemistry, were found to have little structural margin, or have aggressive operating conditions. The purpose of the inspections are to: 1. Confirm the results of the first inspection. 2. Obtain data for trending wear for use in predicting remaining service life. This is done by inspecting some of the previously inspected, highly-ranked components. 3. Consider inspecting those components with a short relative remaining service life to confirm that all components are suitable for continued service.

7-1

EPRI Licensed Material Perform Longterm Monitoring and Inspections

The timing of the follow-on inspections should be conservatively selected considering results from the previous inspections, predictions of the Predictive Plant Model, structural margins, presence of any known aggravating conditions (e.g., leaking, flashing, or cycling valves), potential consequences of failure, and plant and industry experience. For example, lines with high wear rates or low structural margins should be reinspected at the next outage. It is recommended that the following components be included in a second inspection for each Analysis Line (definition of Analysis Line was provided in Section 5): 1. A minimum of three components from the initial inspection having the most FAC wear. This will help confirm predictions made by the Predictive Plant Model and verify the inspection and data acquisition systems used. 2. Consider inspecting a representative sample of components for which the updated Predictive Plant Model shows a remaining service life of less than the amount of time until the next scheduled inspection (if the Predictive Plant Model offers this feature). This situation can occur in both previously inspected components as well as non-inspected components. See Section 5 for calculations of predicted remaining service life. The sample should represent factors such as component type, location, upstream influences, train where located, size, operating conditions, etc. For example, results of an inspection of one elbow closely located on the same train with two other elbows (e.g., same predicted wear rate and remaining service life) could serve to represent all three elbows. However, three otherwise identical elbows located on different trains should not be qualified by one inspection. 3. Consideration should also be given to inspecting problem areas that have been experienced at other power plants since the initial inspection. Inspections following the second inspection should be scheduled as necessary to monitor plant susceptibility and to inspect wearing components prior to the end of their predicted service life. For each Analysis Line, the interval until the next inspection outage should be based on the results of the prior inspection and any changes in plant design, operating conditions, and water chemistry since then. Industry experience with problem areas in other plants should also be considered. It is recommended that the next inspection for each component be scheduled for no later than the normally scheduled outage preceding the end of the predicted FAC service life of the component plus an appropriate safety factor. At that outage, it is recommended that the following components, at minimum, be included for inspection: 1. Consider inspecting a representative sample of components for which the remaining service life is less than the amount of time until the next scheduled inspection outage, with an appropriate safety factor. The sample should represent factors such as component type, location, upstream influences, train where located, size, operating conditions, etc. For example, results of an inspection of one elbow closely located on the same train with two other elbows (e.g., same predicted wear rate and remaining service life) could serve to represent all three elbows. However, three

7-2


otherwise identical elbows located on different trains should not be qualified by one inspection. 2. A minimum of the highest-wear component found in the previous inspection, if it has not already been replaced. In addition, the following components should be considered for inspection: 1. Straight pipe and other components within two diameters downstream of any component replaced in the previous inspection, or two diameters upstream if the replaced component was an expander or expanding elbow. 2. Susceptible piping components immediately downstream of control valves and orifices that showed wear from previous outage inspections for trending of the measured wear. 3. Areas that have experienced problems at other plants since the previous inspection. 4. Components on lines with two-phase flow conditions. 5. To confirm predictions, consideration should also be given to periodically inspecting previously repaired and replaced components, unless the replacement components are fabricated of a FAC-resistant material. It is recommended that the user monitor plant design and operational changes between scheduled inspection outages and update the susceptibility analysis (see Section 5) and the FAC analysis as appropriate. If inspection results are unexpected and inconsistent with predictions, the reasons for those inconsistencies should be investigated. An updated FAC analysis should be performed, and additional inspections conducted and material determinations made as appropriate. The above process for follow-on inspections should be repeated for the life of the plant.

7.2 Longterm Monitoring Longterm monitoring can be performed for lines with significant structural margins and nonaggressive operating conditions of plants that have optimized their feedwater chemistry. It is recommended that some locations on these lines be inspected every few years to ensure that unexpected damage has not occurred and significant structural margins still remain. The following locations should be considered for these inspections: 1. A minimum of the highest-wear component found in the previous inspection, if it has not already been replaced. 2. Susceptible piping components immediately downstream of control valves and orifices that showed wear from a previous outage. 3. Any line with two-phase flow conditions 4. Areas that have experienced problems at other plants since the previous inspection. 5. The sample should represent factors such as component type, location, upstream influences, train where located, size, operating conditions, etc. 7-3


7.3 Outage Documentation It is recommended that the results of the outage inspections be documented in a calculations package, and checked if possible by an independent engineer. This would include the inspection results and the evaluation as to acceptability of component wear.

7-4


A BENCHMARKING AN ORGANIZATION’S FAC PROGRAM IN CONVENTIONAL FOSSIL PLANTS

Introduction The following is a Benchmarking Process to assess an organization’s or a plant’s fossil FAC Program

Assessing the FAC Organization of a Utility The attached form can be a self-assessment or completed by EPRI during an FAC course or plant/system review. It involves seven “results oriented”, “FAC influenced” factors. Each of the factors is capable of being assessed quantitatively, and, as a whole, represent an indicator (results) by which organizations can compare their FAC programs with other organizations in the world. Each factor relates to the optimum FAC Program developed by EPRI and published in these Fossil Plant FAC Guidelines. It is suggested that an organization or plant make the initial assessment with data from the last three years of information. Improvements/changes could then be assessed on an annual basis. The Benchmarking Process will work when applied either to a single unit/plant or across a utility system. The following factors are assessed: A. Corporate Mandate for the Organization’s FAC Program As suggested in the EPRI FAC Guideline (Section 1.4), the optimum FAC program requires a Corporate Mandate signed by the VP or Plant Manager responsible for the fossil plants in the system or units in the plant. This important factor enquires whether an organization/plant has such a Mandate, which indicates how the organization/plant will adopt the optimum FAC program. B. Prediction and Inspection of Feedwater Systems in Fossil Plants This important factor relates to the percentage of units (plant or system) where a predictive analysis (such as EPRI’s CHECUP or CHECKWORKS) (see Section 5.1) has been conducted, and where those predicted susceptible areas have been inspected. This factor has two parts: a) focuses on the most FAC prone systems in fossil plants in feedwater systems that have allferrous feedwater heaters (here it should be noted that those systems with stainless steel feedwater heater tubing in both the LP and HP feedwater heaters have the highest priority. Section 2.2.5), and b) those with mixed-metallurgy feedwater systems (copper alloy tubing in LP A-1

EPRI Licensed Material Benchmarking an Organization’s FAC Program in Conventional Fossil Plants

and/or HP). An important note here is that the weighting factor is different for all-ferrous and mixed-metallurgy units. C. Cycle Chemistry Control of All-ferrous Feedwater Systems This factor also addresses the most important areas in a Fossil Plant for those systems with allferrous feedwater systems (here again it should be noted that those systems with stainless steel feedwater heater tubing in both the LP and HP feedwater heaters have the highest priority. Section 2.2.5). The factor relates to the percentage of these units, that are operating with an oxidizing feedwater chemistry (AVT(O) or OT) and thus indicating that single-phase FAC should not be an active corrosion mechanism. D. Indicator of Corrosion/FAC in All-ferrous Units (plant or system) The factor relates to the level of iron corrosion products at the economizer inlet as this is a major indicator of a serious corrosion or FAC problem. This factor can be assessed across a system or for a plant/unit. E. Indicator of Corrosion/FAC in Mixed-metallurgy Units (plant or system) The factor relates to the level of iron corrosion products at the economizer inlet as this is a major indicator of a serious corrosion or FAC problem. This factor can be assessed across a system or for a plant/unit. F. Indicator of Two-phase FAC in the LP Heater Shells (plant or system) (see Section 2.2.2) This factor addresses whether an organization has assessed the FAC susceptibility in the heater shell areas (particularly the LP heater shells, with the lowest LP heater being most prone). This can be assessed across a system or for a plant/unit. Assessment here requires at least a visual inspection. G. Indicator of FAC in the Heater Drain Lines (single- and two-phase FAC (plant or system) (see Section 2.2.2) This factor addresses whether an organization has assessed the FAC susceptibility in the drain lines. Particularly emphasis here is on the drain lines from the lowest HP and LP heaters to the deaerator and condenser respectively. This can be assessed across a system or for a plant/unit. Assessment here requires a NDE inspection.

A-2


Assessment of an Organization’s FAC Program

Weighting 3

Factor A.

Points

Total

Corporate FAC Mandate Do you have a Corporate/Plant FAC Mandate o o

Yes No

0 2 Sub-total (Points x Weighting)

3

B.

Predictions and Inspections of FAC Prone Areas Percentage of units (plant or system) that have had a predictive capability applied and have had follow-up NDE inspections at all predicted critical locations a) Units with all-ferrous feedwater systems o 100 % of units o 70 - 99 % o 50 - 69 % o < 50% o No all-ferrous units

0 1 2 3 0

Sub-total (Points x Weighting) 2.

b) Units with mixed-metallurgy feedwater systems 100 % of units 0 50 - 99 % 1 < 49% 2 No mixed-metallurgy units 0

o o o o

Sub-total (Points x Weighting)

A-3


Weighting 3

Factor C.

Points

Total

Cycle Chemistry Control of All-Ferrous Feedwater Systems What is percentage of units with all-ferrous feedwater systems that operate with either AVT(O) or OT o o o o o

100 % of units 70 - 99 % 50 - 69 % < 50% No all-ferrous units

0 1 2 3 0

Sub-total (Points x Weighting) 2

D.

Corrosion/FAC in Units with All-Ferrous Feedwater Systems What is percentage of units with all-ferrous feedwater systems that have iron levels at the economizer inlet consistently less than 2 ppb during normal operation o o o o o

100 % of units 70 - 99 % 50 - 69 % < 50% No all-ferrous units

0 1 2 3 0


E.

Corrosion/FAC in Units with Mixed-Metallurgy Feedwater Systems What is percentage of units with mixed-metallurgy feedwater systems that have iron levels at the economizer inlet consistently less than 5 ppb during normal operation o o o o

100 % of units 50 - 99 % < 49% No mixed-metallurgy units Sub-total (Points x Weighting)

A-4

0 1 2 0


Weighting 1

Factor F.

Points

Total

Corrosion/FAC in LP Heater Shells What is percentage of units (all-ferrous and mixed-metallurgy) where the LP heater shell has been at least visually inspected (fiber optics or physically) o o o

100 % of units 50 - 99 % < 49%

0 1 2


G.

Corrosion/FAC in Drain Lines What is percentage of units (all-ferrous and mixed-metallurgy) where the heater drain lines have been inspected using NDE o o o

100 % of units 50 - 99 % < 49%

0 1 2

Sub-total (Points x Weighting) Total

A-5


Rating Systems as a Function of Feedwater Metallurgy

Rating System for an Organization with both All-ferrous and MixedMetallurgy Feedwater Systems Excellent/World Class Very good Good Average Below Average

<7 8-12 13-19 20-32 > 33

Rating System for an Organization with only All-ferrous Feedwater Systems Excellent/World Class Very good Good Average Below Average

≤6 7-12 13-18 19-29 > 30

Rating System for an Organization with only Mixed-Metallurgy Feedwater Systems Excellent/World Class Good Average Below Average

A-6

≤6 7-10 11-14 > 15


B BENCHMARKING AN ORGANIZATION’S HEAT RECOVERY STEAM GENERATOR DEPENDABILITY PROGRAM

Introduction EPRI’s Heat Recovery Steam Generator (HRSG) Tube Failure Reduction Program/Cycle Chemistry Improvement Program (HTFRP/CCIP) is conducted at organization’s combined cycle plants. Alternatively it can be conducted at a central location so that staff members from a number of plants can attend. The HTFRP/CCIP provides information on: •

HRSG tube failures (HTF) – mechanisms and root causes

•

Cycle chemistry influenced HTF

•

Thermal transient/cycling influenced HTF including FAC

•

How to optimize the cycle chemistry in the feedwater and evaporator circuits to avoid HTF

•

How to identify the locations where thermally driven HTF could occur

•

How to monitor thermal transients.

Overall the program is designed to help an organization avoid HTF and to identify the precursors to damage and HTF. Organizations frequently ask how good or bad is their overall HRSG dependability program on a world ranking. To answer these questions, EPRI developed the HRSG Dependability Benchmarking Process. Much thought has been given to the Benchmarking topic, and the current assessment approach was developed during the initial 20 HTFRP/CCIP workshops conducted with members of EPRI’s HRSG Dependability Program. It will provide an assessment for an organization of its overall approach to HRSG reliability. The Benchmarking process is to assess overall HRSG Dependability. The FAC factors are B, C, D, E, and F.

B-1

EPRI Licensed Material Benchmarking an Organization’s Heat Recovery Steam Generator Dependability Program

Assessment of an Organization’s HRSG Dependability Weighting 3

Factor

Points

A. Total number of HTF over the last three years

0 1-2 3-5 5-10 >10

0 1 2 3 4 Sub-total (Points x Weighting)

3

B. Number of chemically influenced HTF over last three years (Flow-accelerated corrosion, corrosion fatigue, hydrogen damage, acid phosphate corrosion, caustic gouging, pitting)

0 1-2 3-5 5-10 >10

0 1 2 3 4 Sub-total (Points x Weighting)

3

C. Cycle Chemistry Instrumentation and Control. What percentage of the EPRI Core level do you have? See Table B-1 for Core Level.

100% 90-99% 70-89% <70%

0 1 2 3


D. Is reducing agent used in the feedwater (during Operation and/or shutdown)?

Yes No


B-2

Total


Weighting 2

Factor

Points

Total

E. What is level of iron in feedwater (generally during steady operation)?

<5 ppb 5-10 ppb 11-20 ppb >20 ppb Don’t know

0 1 2 3 3


F. What is level of iron in LP Drum (generally during steady operation)?

<5 ppb 5-10 ppb 11-20 ppb >20 ppb Don’t know

0 1 2 3 3


G. Has temperature monitoring been conducted on LP Economizer, Superheater and Reheater during Startup, Shutdown and Operation to identify damaging thermal transients (using specially installed thermocouples)

Yes, all three Yes, on two Yes, on one No

0 1 2 3


H. Do you have written Action Plans to address Root causes of HTF or potential HTF?

Yes No


B-3


Weighting 1

Factor I.

Points

Do you have written Action Plans to address damaged tubing or potential damage tubing?

Yes No

0 1 Sub-total (Points x Weighting) Total

Rating System World Class Very Good Above Average Average Program Below Average Program Poor

B-4

<5 6-10 11-25 26-40 41-45 46-55

Total


Table B-1 Supplementary Information for Factor C

“Core” Monitoring Parameters (Minimum level of instruments for all plants/units) (all instruments should be on-line and continuously monitored) Parameters Cation Conductivity

Measurement Locations Condensate Pump Discharge Condensate Polisher Effluent (if installed) Feedwater (or economizer inlet) Drum Blowdown (each drum) Main steam or reheat steam

Specific Conductivity

Makeup Drum Blowdown (each drum)

pH

Drum Blowdown (each drum)

Dissolved Oxygen

Condensate Pump Discharge Feedwater (or economizer inlet) Drum Downcomer (Drum unit on OT)

Sodium

Main steam or reheat steam

Phosphate

Drum Blowdown (each drum using a phosphate treatment)

Silica

Makeup

B-5

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Programs:

1008082

Boiler Life and Availability Improvement Boiler and Turbine Steam and Cycle Chemistry Heat Recovery Steam Generator (HRSG) Dependability © 2005 Electric Power Research Institute (EPRI), Inc. All rights reserved. Electric Power Research Institute and EPRI are registered service marks of the Electric Power Research Institute, Inc. TOGETHER...SHAPING THE FUTURE OF ELECTRICITY is a service mark of the Electric Power Research Institute, Inc. Printed on recycled paper in the United States of America

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EPRI_Guidelines for Controlling Flow Accelerated Corrosion

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