Member Question Repository

Revision 4

Reactor Pressure Vessel (RPV) Integrity

Supervision of RPV Irradiation Embrittlement During License Extension

1. Implementation of Coordinated Reactor Vessel Surveillance Program (CRVSP)

Q: What is the status of CRVSP implementation in industry, and the feasibility in coordinating and linking irradiation surveillance tubes for similar RPV units (same manufacturer, model, and comparable performance)? Has there been any consideration for lifespan extension beyond 80 years, such as to 100 years?

A: MRP-326, Revision 0 has been implemented by plants identified in the original submission of the report (See NRC ML12040A314 and ML12040A315). As of 2020, 16 out of 30 CRVSP capsules are tested or planned to be tested. There are 14 remaining CRVSP capsules. Half of these are not planned to be tested (i.e., due to plant shutdown) or will be delayed beyond 2025.

Additional information can be found in this publicly available presentation: ML21288A145.

2. Implementation of Pressurized Water Reactor [PWR] Supplemental Surveillance Program (PSSP)

Q: Is there a brief introduction to the sample reassembly technique and the manufacturing process of radioactive surveillance tubes used in the PSSP?

A: The PSSP surveillance capsules were both fabricated in 2015 and inserted into Farley 1 and Shearon Harris Unit 2 in 2016 and 2018, respectively. Farley 1 Capsule P is scheduled to be withdrawn in Spring 2027; Shearon Harris Capsule P is scheduled for Fall 2028.

Additional information can be found in this publicly available presentation, specifically on slide 9: ML21288A145. An ASME Code PVP paper was published in 2017 with further information, PVP2017-65307. (Available for purchase here)

The ASTM standard for Charpy specimen reconstitution is ASTM E1253-13, “Standard Guide for Reconstitution of Irradiated Charpy-Sized Specimens.” (Available for purchase here)

3. Utilization of Ex-core Neutron Detectors

Q: What is the installation status and replacement cycle of Ex-core Neutron Detectors (EVND)? Are there any plans for regular reliability inspections of EVND after installation? Are EVNDs installed at nozzle locations?

A: EVND is one method to monitor fluence after all in-core surveillance capsules have been removed. Some plants also use EVND when plant capsules are remaining in the vessel for confirmatory calculations. The ASTM standard for EVND is ASTM E2956-14, “Standard Guide for Monitoring the Neutron Exposure of LWR Reactor Pressure Vessels.” (Available for purchase here)

Additional information is also available in U.S. NRC Regulatory Guide (RG) 1.190 (ML010890301).

EVND systems have been installed at most plant sites in the U.S., as well as at many international sites. There is no regulatory standard in the U.S. for frequency of withdrawal and analysis of EVND. Either a range of cycles run or effective full power years (EFPY) accumulated is utilized; however, specific questions related to EVND systems, and the frequency of withdrawal and analysis should be directed to the original equipment manufacturer (OEM) or nuclear steam supply system (NSSS) vendors. Standard EVND systems provide multiple measurements around the core-midplane octant, as well as a single measurement at the top and bottom of the active core.

4. Usage of Shielding Components

Q: For nuclear power plants with high cumulative neutron fluence towards the end of their lifespan, shielding components can be employed to reduce neutron fluence and mitigate RPV irradiation embrittlement. What is the overall implementation status of shielding components in U.S. nuclear power plants? What is the shielding coefficient based on a 80-year lifespan? How effective is the reduction in peak neutron fluence in the RPV compared to before the implementation?

A: Installation of shielding components in U.S. nuclear plants has always been rare. EPRI is aware of a few plants that have had shielding assemblies in the past, but all have been removed over the past 10-15 years due to the emergence of other technologies or regulatory options that allow plants to remain in compliance with fracture toughness requirements, such as use of the Alternate Pressurized Thermal Shock (PTS) Rule (10 CFR 50.61a), or the use of Master Curve (“new” technology).

One such plant that previously used Peripheral Power Suppression Assemblies (PPSAs) is described in ML16251A153. The Subsequent License Renewal (SLR) Time-Limited Aging Analysis (TLAA) evaluations for this plant are documented in (ML20329A264).

Specific questions related to the effective reduction in peak neutron fluence, or the shielding coefficients of plant-specific components should be directed to the OEM or NSSS vendors.

Fracture Toughness Allowance of Ferritic Steel

1. Acceptance Criteria for Defects in Ferritic Steel

Q: The defect acceptance criteria in ASME Section XI are based on a hypothetical defect of ¼-thickness (1/4T) and safety factors under normal operating conditions, which are not applicable to accident conditions. How should the acceptance criteria for defects in ferritic steel under accident conditions be considered? Can the allowable reference surface defect size under accident conditions be qualitatively determined by combining the limiting crack size under accident conditions (surface reference defect) with a safety factor?

A: The standard flaw size for heatup and cooldown pressure-temperature (P-T) limit curves under normal and faulted operation (Levels A and B) is 1/4T (MRP-450, Revision 1). Other transients, such as for upset or emergency operation (Levels C and D) can use a 1/10T flaw or 1 inch (minimum) (MRP-450, Revision 1). Specific assessments can take advantage of the minimum analyzed NDE flaw detectability, which is typically set at 0.5 inch (ML20024E573).

2. Margin of RT_NDT Measurement

Q: RT_NDT is not a direct measurement of fracture toughness. In practice, when the initial RT_NDT prefers measured values, deviations are not considered. However, there may be deviations in T_NDT (such as 5℃). What is the technical basis for not considering deviations in RT_NDT measurements? Compared with RT_T0, qualitatively explain the sufficient margin?

A: The margin for RT_NDT is set in the U.S. by the provisions of RG1.99R2 (consistent with the methodology of 10 CFR 50.61, the PTS Rule). The margin is calculated as follows:

Margin = 2√(σ_I² + σ_∆²)

• σ_I is the standard deviation for the initial RT_NDT. If a measured value of initial RT_NDT for the material in question is available, σ_I is to be estimated from the precision of the test method (and it is normally taken to be 0°F or 0°C). If not, and if generic mean values for the class of material are used, σ_I is the standard deviation obtained from the set of data used to establish the mean.
• The standard deviation for ∆RT_NDT, σ_∆, is 28°F (16°C) for welds and 17°F (9°C) for base metal, except that σ_∆ need not exceed one-half the mean value of ∆RT_NDT.
• If credible surveillance data are available, σ_∆ may be cut in half.

If the fluence values are calculated in accordance with RG 1.190 (linked above), the σ_∆ term is then considered adequate for deviations in RT_NDT measurements in the irradiated condition.

RT_T0 is equal to T₀ + 35°F (MRP-462). Although the addition of 35°F provides the equivalent of a 5% lower bound toughness curve, additional margins may still be added to account for other uncertainties in the determination of this value, or to account for irradiation. A consistent two times the square root of the sum of the squares of the various uncertainties is considered adequate. Also see the PWROG report that dispositioned RPV nozzles, PWROG-15109-NP-A (discussed below, ML20024E573, Section 3.1) for more information and an example.

3. Neutron Fluence Values

Q: When calculating P-T limits and PTS analysis, French plants use the peak fast neutron fluence on the inner surface, which is considered overly conservative. For fracture mechanics calculations, it is more reasonable to use the neutron fluence at the location of the hypothetical defect. When U.S. industry establish the neutron fluence for the P-T limit curve, using the 1/4T fast neutron fluence is more reasonable. Is it necessary to consider the uncertainty of fast neutron fluence? Why does U.S. industry use the neutron fluence on the inner wall for PTS (RT_NDT) calculations instead of the neutron fluence at the location of the hypothetical defect? Why is there a difference in the selection of neutron fluence between the P-T curve and PTS? Can the neutron fluence at the location of the hypothetical defect be selected for detailed PTS fracture mechanics analysis?

A: U.S. NRC Regulatory Guide 1.190 (ML010890301) governs the calculation of neutron fluence in the U.S. If the measured fluence values from capsule dosimetry and/or ex-vessel neutron dosimetry are within plus or minus 20% of the model calculated values, then the calculated fluence values are confirmed and can be used as-is. As noted above, the σ_∆ term is then considered adequate for deviations in RT_NDT measurements in the irradiated condition.

The definition of fluence to be used for PTS evaluations is given in the Definitions section of the PTS Rule, 10 CFR 50.61 (link above) as:

EOL Fluence means the best-estimate neutron fluence projected for a specific vessel beltline material at the clad-base-metal interface on the inside surface of the vessel at the location where the material receives the highest fluence on the expiration date of the operating license.

Flaws closer to the inside surface of the RPV contribute more to PTS risk than those embedded within the vessel itself. Furthermore, use of the surface fluence at the clad-base-metal interface is considered conservative.

P-T limit curves are governed by ASME Code Section XI as well as 10 CFR 50 Appendix G. A fluence at the limit of the assumed flaw, in this case 1/4T and 3/4T is acceptable for use. The fluence attenuation formula from RG 1.99, Revision 2 (link above) for a cylindrical shell RPV is used to calculate fluence values at these flaw locations.

4. LTOP (Low Temperature Overpressure Protection)

Q: During the low-temperature operation of the reactor coolant system, transients in mass and heat input can lead to overpressure in the reactor coolant system. Severe transient analysis includes accidental actuation of the safety injection system and the accidental shutdown and restart of the reactor coolant pumps. Under these two transients, the initial average temperature of reactor coolant pump (RCP) is approximately 70℃, where the allowable pressure limit of the RCP system is relatively high. The setpoint of the relief valves in the residual heat removal system has the capability to prevent overpressure in both the residual heat removal system and the reactor coolant system. Is it necessary to consider transients with lower initial temperatures, such as severe transients with an initial average temperature of the RCP around 20℃ or 30℃? Is there a possibility that the P-T pressure limit of the RCP system under these conditions could be lower than the setpoint of the relief valves? Are there any cases in U.S. plants where the setpoint of the relief valves in the residual heat removal system has been adjusted?

A: LTOP systems (also, sometimes called Cold Overpressure Mitigation Systems, COMS) have been installed on most U.S. PWRs. Additional information is contained in ASME Code Case N-641, as well as vendor specific methods to develop and protect the ASME Code, Appendix G limits, such as WCAP-14040, Revision 4 for Westinghouse Plants (ML050120209) or BAW-10046, Rev. 4 for B&W plants (ML012850156).

Further details on the process used to determine LTOP system setpoints, the LTOP system itself, and RCP paraments should be directed to the OEM or NSSS vendors.

5. P-T Curve and PTS Analysis for RPV Nozzles at the End of Service Life

Q: At the end of the service life, the peak fast neutron fluence on the inner surface of the nozzles may exceed 10¹⁷ n/cm². Stress concentrations exist at the nozzles, resulting in smaller allowable defects. Do the P-T curves of U.S. plants consider both the cylinder and nozzle locations? Is the defect at the nozzle considered in the PTS analysis?

A: The PWROG published a report dispositioning P-T limits for RPV nozzles generically for the U.S. fleet and used this flaw size – See PWROG-15109-NP-A, Revision 0, (ML20024E573). This report was the culmination of a multi-year effort to evaluate P-T limit curves for the traditional, cylindrical shell beltline and the RPV nozzles. This NRC-approved report concluded that RPV inlet and outlet nozzles are not limiting in comparison to RPV beltline cylindrical shell P-T limit curves, if the neutron fluence at the nozzle corner remains below 4.28 x 10¹⁷ n/cm² (This specific fluence value is described in detailed in Section 4.3 of the NRC SE and Section 3.4 of the report itself). If this value is exceeded, plant-specific analyses would need to be undertaken to determine the potential impact to existing P-T limit curves due to RPV nozzles. However, the same methodologies utilized in PWROG-15109-NP-A, Revision 0 can be used to determine if the nozzles become limiting on a plant-specific basis into extended operation, and if so, a composite curve of the nozzle results and cylindrical shell beltline, as a plant moves into long-term operation (LTO), can be generated. An additional, approved plant-specific example of the comparison between cylindrical shell P-T limits and RPV nozzles is included in ML15061A277, which has also been approved by the NRC.

EPRI is following with a report analyzing RPV nozzles for unanticipated event conditions, in accordance with ASME Code Section XI, Appendix E. This report, MRP-489, will be published by the end of 2024.

The U.S. NRC requires that all RPV materials that exceed a fluence threshold of 1 x 10¹⁷ n/cm², including RPV nozzles (NRC RIS 2014-11, ML14149A165) be analyzed for PTS under 10 CFR 50.61. However, no additional evaluations other than determination of an RT_PTS value are required. See example in Section 4.2 of a Subsequent License Renewal Application (ML18291A828).

6. Basis for Selecting Heating and Cooling Rates of the Primary Loop (100℉/h, 80℉/h, 60℉/h, 50℉/h, 40℉/h, 25℉/h)

Q: Under normal operating conditions, the pressurized water reactor plants in the United States have multiple options for heating and cooling rates of the primary loop, including 100℉/h, 80℉/h, 60℉/h, 50℉/h, 40℉/h, and 25℉/h. What is the basis for selecting these rates, except for 100℉/h? The primary loop has a large water capacity, resulting in a slow overall temperature change. Does 100℉/h refer to the average cooling rate within one hour? Is the short-term fluctuation (locally high cooling rates) taken into account? French plants typically adopt heating and cooling rates of 0℃/h, 14℃/h, 28℃/h, and 55℃/h for the primary loop. It is easier to remember after modifying 55℃/h to 56℃/h. When converting Fahrenheit to metric system, which one should we take for 100℉/h, 55.6℃/h or 56℃/h?

A: The maximum heatup or cooldown rate under normal operating conditions is 100℉/h. The steady-state, or 0℉/h, rate is also the limiting cooldown parameter at higher temperature and provides the theoretical maximum P/T points at lower temperatures (MRP-450, Revision 1). Thus, these are the only two rates that are required. Otherwise, utilities can select interim rates for their own operability convenience. Nominal heatup and cooldown rates are steady-state, 20, 40, 60, 100 ℉/h (MRP-450, Revision 1). Most plants in the U.S. incorporate these exact rates (ML23087A250). ML17326A389 contains an example of a plant that uses different rates.

Per MRP-450, Revision 1, hourly rate of change in heating or cooling a reactor pressure vessel (RPV) is not well defined in Section XI Appendix G. Hourly rate of change has been interpreted as the average rate over a moving one-hour time frame. EPRI has an open project, MRP-490, to evaluate the effect of changing the temperature rate during heatup and cooldown transients to assure ASME Code margins of safety continue to be maintained. U.S. plants have felt compelled to perform Appendix E evaluations for barely exceeding the average rate instantaneously over the moving one-hour time frame for brief instances in the past. MRP-490 will be published in 2025.

Finally, since 100℉/h is the maximum, it is recommended to use 55.6℃/h, and round down, if needed.

Nondestructive Evaluation

Stress corrosion cracking (SCC) detection and sizing on the reactor primary auxiliary piping

1. Administration of PDI-UT-2 qualification

Q: How does EPRI systematically consider SCC testing requirements when administrating the qualification of PDI-UT-2?

A: IGSCC qualification is a specific PDI test that is administered in conjunction with qualifying to EPRI generic procedures PDI-UT-2 or EPRI-PIPE-MPA-1; or vendors may choose to use their own procedure. The candidate that wishes to be qualified for IGSCC examinations would be given specific IGSCC blind test specimens during the PDI qualification. EPRI has also administered IGSCC qualifications and required annual training for EPRI members in Europe. These qualifications and annual training sessions are administered by EPRI in accordance with their country’s specific regulations.

Please see NRC website for qualification requirements for wrought austenitic piping welds with flaws including IGSCC: ML13144A107

2. Mockup flaws

Q: What are the specific requirements for SCC flaws when designing flaws in open test and the blind test mockups? Considerations include the number of pipe specifications, the number of SCC cracks, flaw location (weld and base material), flaw size (length and height), whether SCC flaw should be inside diameter (ID) connected, etc. Are the number of flaws, flaw locations and flaw size for SCC related to the pipe specification?

A: ASME Section XI, Appendix VIII sets the requirements for flaw sizes and distributions. All flaws are inside diameter (ID) initiated. All qualifications are performed with blind test specimens. EPRI does have open / practice IGSCC specimens that vendors can practice on before they take their blind test. The qualification specimens include actual IGSCC flaws located within the HAZ of pipe sections which were removed from operating nuclear power plants and supplied to EPRI.

Please see NRC website for IGSCC flaw requirements for PDI qualifications: ML13144A107

3. IGSCC PD test acceptance criteria

Q: What are the test acceptance criteria of IGSCC open test (process / equipment) and blind test (process / equipment / personnel data analysis)? Are there any special requirements and concerns compared with the requirements specified in ASME XI, Appendix VIII?

A: There are no open tests, only blind tests for qualification of personnel and procedures. The requirements and procedures for administering the PDI qualifications come from ASME Section XI, Appendix VIII, as supplemented by U.S. NRC requirements documented within 10CFR50.55a, and EPRI developed administrative PDI program procedures.

Please see NRC website for IGSCC PD test acceptance criteria: ML13144A107

4. UT technology for IGSCC

Q: For the detection of flaws like IGSCC of EDF Nuclear Power Plants (NPPs), is it necessary to use focused phased array UT technology (such as FMC-TFM or PWI-TFM) to detect the early initiation SCC in the repaired weld (when the crack height is less than 2mm)? How does EPRI use the conventional UT inspection technology to solve the issue of detection and sizing of early initiation SCC in the repaired weld during the administrative process of PDI?

A: Currently, there are no PDI IGSCC qualified FMC-TFM or PWI procedures or equipment. Reliability for detecting flaws less than 2 mm has not been demonstrated. UT techniques implemented to detect flaw initiation at less than 2 mm tend to give additional false flaw indications due to the sensitivity of the techniques. EPRI has both conventional and PAUT qualified procedures for IGSCC detection and length sizing. EPRI blind IGSCC test specimens have a range of flaw sizes 5% - 30% per Section XI, Appendix VIII, Supplement 2 requirements. Based on 5% of the test specimen thickness, some of the flaws used in qualification and testing are ~3 mm in height. The EPRI procedures, both PAUT and conventional UT, reliably detect flaws down to this size range. This also includes both automated (encoded) and manual (non-encoded) examinations.

5. PWSCC crack inspection in reactor vessel head penetrations and J-Groove welds

Q: According to ASME Code and Code Case N729-6 requirements, ultrasonic and eddy current inspections are required for PWR reactor vessel head penetrations and J-Groove welds. How are PWSCC cracks in Inconel 690 material for PDI produced? If PWSCC cracks cannot be produced in Inconel 690 material, how does EPRI deal with it?

A: PWSCC flaws are not used in the EPRI RPV Upper Head Qualification program for a few reasons. Some of the reasons are that it is hard to control:

1. Initiation and placement
2. Growing of extra flaws that may initiate in the same localized region
3. Flaw depth
4. Flaw orientation

EPRI has conducted research to develop flaw fabrication processes to simulate PWSCC. EPRI demonstration test specimens implement simulated PWSCC, which are fabricated by using shaped EDM notches that are then compressed though a process called Hot Isostatic Pressing (HIP). This process compresses, or tightens, the notch such that the notch walls collapse and almost come into contact, and in some cases parts of the notch walls do wind up coming into contact, which simulates a crack like structure and ultrasonic response. EPRI has documented technical justifications for using simulated PWSCC by comparing UT data of flaw responses from actual flaws found in operating units and the simulated flaws in the EPRI test specimens.

6. Calculation principle of UT examination coverage for butt weld of primary auxiliary pipeline

Q: According to MRP-139 guidelines for inspection and evaluation of butt welds of primary system pipes, will only coverage area of UT inspection greater than 90% be considered fully accessible?

A: It is not the intent to allow for a minimum of 90% coverage when more scan area is accessible. This means that every reasonable attempt shall be made to obtain maximum coverage, even if 90% has already been met. (See discussion and examples below).

7. UT probe angle impact on calculation of coverage area

Q: During UT inspection of butt welds of primary auxiliary pipeline, UT probes with multiple angles (such as 40°，60°，75° are used. Similarly, when using a phased array UT probe, a wide range of scanning angles, e.g., 40°- 70° are used. Is the minimum angle probe (such as 40° of conventional UT) or the lower limit of scanning angle range of phased array probe (such as 40°) used to calculate the coverage area?

A: The answer to this question all depends on what the requirements are for effective coverage. If the requirement is that the exam volume needs to be interrogated by two separate examination angles (e.g., both a low angle, 45 degrees, and a high angle, 60 degrees), then the calculation for coverage is based on the most limiting angle.

Hypothetical Example (1) for the requirement of two examination angle coverage: If the 45-degree probe achieves 93% and the 60-degree probe achieves 76%, then maximum coverage would need to be stated as 76%.

Hypothetical Example (2) for the requirement of single examination angle coverage: If the 45-degree probe achieves 93% and the 60-degree probe achieves 76%, then maximum coverage can be claimed as 93%.

Also, see discussion and examples below.

8. Determination of UT coverage area

Q: When the minimum angle conventional UT probe or the lower limit of scanning angle range of phased array probe is considered, the coverage area can reach 90%. However, when the maximum angle probe (such as 75°) or the upper limit angle of scanning angle range of phased array probe (such as 70°）is considered, the coverage area does not meet 90%. How is this case evaluated? Is there a need to supplement with additional volumetric inspection methods?

A: The responses above are applicable, along with the discussion and examples below. Typically, US utilities do not use supplement NDT to increase coverage for inaccessible welds or limited weld coverage. The utilities typically exercise the “Relief Request” process established by the US NRC. This process allows for the utility to present a technical justification and mitigation plan to the US NRC for consideration. The US NRC will evaluate the submittal for relief of the limited inspection, potentially respond to the utility asking for more information or clarification, then provide their response of acceptance, acceptance with some conditions imposed, or denial of the submittal for relief. The links below are two examples of US utility’s requests for relief due to limited weld accessibility and coverage:

ML11234A185

ML12145A170

In addition to “relief request,” ASME code cases (e.g., N-711) also provides an alternative approach to determine the acceptability of the examination even if it is less than, or different than ASME XI’s guidance.

Discussion and Example of Coverage Calculations

Calculations are performed considering 360° of the pipe weld to be equal to 100% of the circumference. If you show that your UT effectively covered the exam volume specified by your requirements, and you are able to pass sound through the exam volume in all the required sound path directions (typically done by using CAD to show exam volume profile with axial and circumferential interrogation angles plotted); then the calculation is relatively simple. You would just have to determine degrees of circumference were inaccessible and subtract that percentage from 100%. Example: If you were limited to 330° of effective UT coverage for the entire volume, from all required interrogation angles and directions, then you would simply divide 330/360 = 0.91666667 (i.e. 92%).

The case presented below is a little more complex, but by no means covers all cases, and considers the examination of a similar metal weld subject to the use of the EPRI qualified procedure PDI-UT-2 “PDI Generic Procedure for the Ultrasonic Examination of Austenitic Pipe Welds.”

Examination Volume Requirements

The required examination volume shall be, as a minimum, the lower 1/3 weld volume and base material for a distance of 1/4 inch from each weld toe, as described in Figure 1. Alternative examination volumes may be applicable, if required by the utility specific Inservice Inspection (ISI) program.

UT Beam Coverage

Examinations shall be performed from both sides of the weld with the beam directed essentially perpendicular and parallel to the weld. Where dual side access is not possible, the examination shall be performed to the maximum extent practical. The example below shows how coverage is calculated based on the requirements of this specific procedure. While it shows sound passing through to the opposite side of the weld, the procedure only allows you to claim coverage up to weld centerline. So, the 45° probe angle scanning perpendicular to the weld has limited coverage of the exam volume based on not being able to scan far enough to cover the green shaded area. In this case, another scan angle (maybe a 60° or 70° UT angle beam) would be used to cover the missed area. The 45° probe angle used to scan parallel to the weld provides no coverage of the exam volume profile when placed exactly parallel to the weld, but the procedure allows for manual beam skewing; so, the probe is physically skewed inward toward the weld centerline (up to 45°) to cover as much of the exam volume profile as possible. In this case, the maximum skewing does allow for interrogation up to and beyond weld centerline, but again, we can only claim coverage up to the weld centerline from the same side as scanning is being performed.

The example shows the exam volume profile in terms of sq. cm. because it is a 2D representation of the volume that needs to be interrogated by UT. The true 3D volume would be calculated by sweeping that profile in the 3rd dimension around the pipe circumference.

The calculation of exam volume coverage is a combination of how much of the exam volume profile is interrogated with UT scans performed in both the perpendicular and parallel scan directions (4 scan directions) combined with the number of degrees around the pipe circumference can be achieved. This will determine total effective coverage.

VERY IMPORTANT STATEMENT: It is not the intent to allow for a minimum of 90% coverage when more scan area is accessible. This means that every reasonable attempt shall be made to obtain maximum coverage, even if 90% has already been met.

In summary, all cases of calculating inaccessible or missed examination coverage are unique to the inspection and examination requirements. There is no one method that provides answer to all the various scenarios when it comes to calculating coverage.

Reactor Internals

1. Internals design changes

Q: For the second and second-generation improved PWR units (M310 and CPR1000) and the third-generation PWR units (EPR), what design changes have the French (Framatome) made to the reactor internals on the basis of Westinghouse's original design?

A: EPRI is not aware of specific details of design changes between Westinghouse original design and French designs made by Framatome. The details are proprietary. However, some other international PWR utility owners including French (Framatome) designs have begun to implement the MRP-227 inspection guidance related to license renewal and life extension. Qinshan unit 1 has performed some of these exams as well.

2. French experience

Q: For M310, CPR1000 and EPR units, is there any similar situation in the United States for the design change part of reactor internals made by French (Framatome) based on the original design of Westinghouse, and what are the specific inspection suggestions for the design change part made by France (Framatome)?

According to the feedback of operating experience, what are the specific recommendations for the inspection of reactor internals for the second and second generation improved PWR units designed by Westinghouse? With the operation of two M310 units of CGNPC entering the end of design life and extension life in the future, is it necessary to refine the inspection items of reactor internals in the ISI program? To what level should the ISI program be refined (to components and even to parts level)? Can you provide a sample of in-service inspection program for Westinghouse design units?

A: As described below and in ML23324A422, all EPRI members in the USA and many international utility members have incorporated internals inspection into its ISI program.

Periodic inspections of the internals are performed as part of the existing MPS3 inservice inspection (ISI) program, which meets the requirements of American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code, Section XI. Until the beginning of the period of extended operation (PEO), the ISI program provided the primary inspection requirements to ensure that the integrity is maintained for the components comprising the reactor internals. In many instances the ISI program remains adequate for management of aging effects and is therefore referenced by this Aging Management Program (AMP) document. The additional examinations beyond the requirements of ASME Section XI are governed by this AMP. The technical requirements for such augmented examinations are further specified in EPRI inspection standard, MRP-228.

The inspection recommendation for long-term operation (LTO) and license renewal are contained in the EPRI MRP-227, Revision 1-A report, which has been approved by Nuclear Regulatory Commission (NRC) in the United States. This report is free to anyone in the public. Please see EPRI website: https://www.epri.com/research/products/000000003002017168

MRP-228 is the companion document that contains the NDE inspection standard and procedure/technique requirements.

WCAP-17096-NP-A, Revision 3 is another companion document that contains the engineering acceptance evaluation methodology and flaw evaluation calculation requirements, which has also been approved by the US NRC. This report is free to anyone in the public, too. Please see NRC website: ML23248A258

Below links are an example of ISI program and aging management program for internals. ML12082A009 ML092750338

3. Internals inspection

Q: For the inspection of reactor internals designed by Westinghouse, what are the inspection equipment currently used? Does it fully cover the inspection needs for failure feedback and degradation assessment of reactor internals? Are there any special requirements and concerns?

A: Multiple inspection vendors in the United States have successfully performed inspections for Westinghouse-design PWRs, since 2011; including Westinghouse, Framatome, and Structural Integrity Associates. The inspection vendors must meet the requirements associated with MRP-228 when performing inspections.

CASS Flaw Tolerance Evaluation

1. Application of Defect Tolerance

Q: How are the acceptance criteria considered for the base metal of Z3CN20-9M with low thermal aging sensitivity in US nuclear power plants?

A: Thermal embrittlement screening criteria in NUREG-2191, Vol. 2, XI.M12 is used. For static-cast low-molybdenum (i.e., ≤ 0.5 wt.%) steels with ferrite content less than 20% and all centrifugal-cast low-molybdenum steels, thermal aging embrittlement is not significant, (i.e., screens out).

• NUREG-2191, Vol. 2 “Generic Aging Lessons Learned for Subsequent License Renewal (GALL-SLR) Report”.

Flaw acceptance criteria in ASME Code, Section XI, Non-mandatory Appendix C can be used to determine the allowable flaw size for flaw tolerance evaluation of CASS piping. For CF3, CF8, or equivalent chemical composition cast product with ferrite content ≤ 14%, limit load approach in C-5000 is used. For CF3, CF8, or equivalent chemical composition cast product with ferrite content > 14%, elastic-plastic fracture mechanics (EPFM) approach (based on Z-factor) in C-6000 is used. The technical basis for the flaw acceptance criteria is provided in PVP2017-66100.

Q: How is the acceptance criterion determined for the weld of Z3CN20-9M without molybdenum elements using manual arc welding?

A: Typically, for flux welds, EPFM approach (based on Z-factor) in C-6000 is used to determine the allowable flaw size for flaw tolerance evaluation.

Q: How is the acceptance criterion determined for the weld of TIG (316L) containing molybdenum elements?

A: Typically, for non-flux welds, limit load approach in C-5000 is used to determine the allowable flaw size for flaw tolerance evaluation.

Q: What is the NRC's position on the application of probabilistic fracture mechanics to defect tolerance in the primary pipeline?

A: US NRC uses probabilistic fracture mechanics as part of their Risk-informed Decision Making (RIDM) – see ML24172A306.

As stated in Regulatory Guide 1.147, Rev. 21, US NRC has conditionally approved ASME Code Case N-838. The condition is related to the applicable range of delta ferrite content of the CASS material – i.e., Code Case N-838 shall not be used to evaluate flaws in CASS piping where the delta ferrite content exceeds 25 percent.

• Regulatory Guide 1.147, Rev. 21 “Inservice Inspection Code Case Acceptability, ASME Section XI, Division 1”.

Although not directly related to CASS flaw tolerance evaluations, US NRC has recently published a Technical Letter Report (LR-RES/DE/REB-2021-09) where they used xLPR code to perform probabilistic leak-before-break (LBB) evaluation for primary coolant loop piping. This report provides a detailed description of PFM calculations performed by US NRC.

• TLR-RES/DE/REB-2021-09 “Probabilistic Leak-Before-Break Evaluation of Westinghouse Four-Loop Pressurized-Water Reactor Primary Coolant Loop Piping using the Extremely Low Probability of Rupture Code”.

2. Inputs for Probabilistic Fracture Mechanics

Q: Which input parameters use a probabilistic model, and which are deterministic? Are they adjustable?

A: This will depend on the available data and may rely on expert judgment. For example, inputs in MRP-479 were categorized as follows:

Deterministic (constant) – geometry, operating conditions, load transients, initial flaw geometry

Probabilistic (random) – fracture toughness, tensile properties, ferrite content, fatigue crack growth rate coefficient

• MRP-479 “Materials Reliability Program: Probabilistic Fracture Mechanics Evaluation of PWR Cast Austenitic Stainless Steel Piping Components”.

Q: Z3CN20-9M and welds without molybdenum (manual arc welding) have lower thermal aging sensitivity than CF3M and CF8M. Is it necessary to separately distinguish between CF3 and CF8 when US power plants conduct their analyses?

A: Identical analysis method is used for CF3 and CF8 (or equivalent chemical composition cast product).

Q: What is the applicability of the EPRI database to the A NPP (Z3CN20-9M)?

A: This can be assessed by comparing the tensile and fracture toughness properties of Z3CN20-9M to those in the EPRI database. EPRI can make an assessment if the utility can provide the material property data – i.e., tensile properties including stress-strain curves and fracture toughness including J-R curves.

3. Analysis Model: Software Theory (e.g., Monte Carlo Algorithm, Sampling Methods)

Q: A brief introduction to the defect tolerance model for the primary pipeline in the US, and the applicability of the EPRI analysis model to French-type units?

A: Examples of PFM based flaw tolerance calculations (including software descriptions) for CASS piping can be found in MRP-479 and MRP-362, Rev. 1.

• MRP-479 “Materials Reliability Program: Probabilistic Fracture Mechanics Evaluation of PWR Cast Austenitic Stainless Steel Piping Components”.

• MRP-362, Rev. 1. “Materials Reliability Program: Technical Basis for ASME Section XI Code Case N-838—Flaw Tolerance Evaluation of Cast Austenitic Stainless Steel (CASS) Piping Components”.

General methodology (including models) should be applicable to French-type units. However, the input distribution (especially for material property inputs) may require some verification based on the available data for the French-type units.

4. Application of 1/4T Tolerance Defect

Q: Can EPRI conduct a verification calculation of the defect tolerance for cast austenitic stainless steel based on a NPP which has been in service for approximately 30 years?

A: Yes, both deterministic and probabilistic calculations can be performed. The utility would need to provide the input designs required for the calculations.

Reactor Pressure Vessel (RPV) Bottom Mounted Nozzle (BMN) Aging Management

RPV BMN Inspection, Monitoring, and Maintenance Methods

1. Inspection Methods, Monitoring Frequencies, and Maintenance Experiences

Q: What are the inspection methods, monitoring frequencies, and maintenance experiences or contingency plans for addressing defects discovered in reactor pressure vessel bottom mounted instrument (BMI) penetrations made of Inconel 600 material?

A: Note: MRP adopted the NSSS-vendor neutral “bottom mounted nozzle” or “BMN” terminology used herein but BMN and BMI are completely interchangeable terms.

Inspection Methods and Monitoring Frequencies

The following summary addresses inspection methods and monitoring frequencies, and is entirely based on the following publicly available sources:

References (Publicly Available)

1. MRP-206 - Inspection and Evaluation Guidelines for Reactor Vessel Bottom-Mounted Nozzles in U.S. PWR (1016594)
2. MRP-167 - Safety Evaluation for Boric Acid Wastage of PWR Reactor Vessel Bottom Heads Due to Bottom-Mounted Nozzle Leakage (1016591)
3. MRP-308 – Boric Acid Corrosion Testing: Implications and Assessment of Test Results (1022853)
4. ASME Code Case N-722, Revision 1
5. 10CFR 50.55a, Codes and Standards

Background

The overall goal of augmented BMN inspection and evaluation requirements is to ensure a low frequency of damage to the nuclear fuel core due to the potential for cracking of BMNs by PWSCC. The safety assessment documented in MRP-206 rigorously evaluated the range of BMN failure modes and effects and identified the dominant potential safety concerns associated with PWSCC of the BMNs or their J-groove attachment welds as:

• Nozzle ejection due to circumferential cracks located in the nozzle below the bottom of the J-groove weld
• Structurally significant loss of reactor vessel lower head material due to excessive boric acid wastage resulting from leakage and concentration of the borated reactor coolant

MRP-206 also evaluates the relative merits, limitations, and contributions of available inspection methods in lowering the risk of leakage and catastrophic penetration failure. Specific inspection programs employing these methods at defined frequencies are then evaluated for their effectiveness in timely detection of cracking or leakage to satisfy the low core damage frequency criterion. These results can then inform licensees and their regulators when making decisions balancing risk management against practical implementation considerations such as schedule impacts and cost.

Discussion

Augmented inspection activities may be appropriate when their use can identify whether adverse aging effects are occurring in an unanticipated manner or in a way that could challenge the intended function of the reactor coolant pressure boundary, particularly during the next period of operation. Considerations should include not only the availability of a viable inspection technique but also its capability to provide additional actionable information to licensees and regulators.

The rationale for the sufficiency of the visual examination for BMN aging management relies primarily on the ability of the BMN configuration to operate with robust safety margins for a fuel cycle with minor leakage up to that detectable via normal plant on-line leakage monitoring. Of course, knowledge of part-through-wall cracks developing in the tube wall would allow for pre-emptive repair. However, volumetric exams presently cannot effectively interrogate the weld to detect cracks wholly contained within the weld and consequently volumetric exams alone cannot fully establish the condition of all the susceptible material. Although the visual exam is predicated on first allowing a leak to develop, this examination method comprehensively assesses the entire BMN pressure boundary configuration for evidence of leakage. Therefore, while a BMN tube wall volumetric exam is certainly informative, it is neither conclusive nor sufficient to establish the overall health of a BMN installation.

The MRP-206 safety assessment includes a failure modes and effects analysis (FMEA), deterministic structural integrity evaluations of the resulting credible failure modes, and risk assessments of practical examination plans. The credible failure modes determined from the FMEA identified three basic conditions for subsequent evaluation:

• Through wall axial or circumferential cracks and the associated leakage
• Partial or complete ejection of a single tube
• Simultaneous leakage from multiple tubes

Cracking that is completely within the weld metal, even if 360ᵒ around the nozzle, will not lead to ejection since the portion of the weld that remains attached to the outside surface of the tube wall will not be able to pass through the tight annular fit. There would be a risk of ejection for the case of lack-of-fusion between the J-groove weld and outside surface of the nozzle over most of the weld circumference. However, the tolerable extent of lack-of-fusion which still maintains structural integrity is similar to the acceptable extent of through wall circumferential cracking documented in MRP-206. Such significant lack of fusion is unlikely to have gone undetected during original fabrication.

Given these conditions of interest, a deterministic structural integrity evaluation of a single BMN tube was performed postulating surface flaws in the base metal, modeling growth of those surface flaws due to service conditions, and determining elapsed time between the flaws just beginning to leak and when subsequent failure of the nozzle would occur. These analyses confirmed that periodic visual or volumetric examinations of the BMNs will successfully reduce the potential for failure of a single BMN tube and thereby can ensure the structural integrity of the BMNs and reactor vessel lower head for the remaining life of the plant. However, since cracking of the j-groove weld/weld buttering was determined not a credible scenario for nozzle ejection, weld cracking, leakage, and any subsequent low alloy steel wastage was not considered in this part of the evaluation.

Risk assessments were performed to compare various inspection programs for the BMNs to manage the potential for cracking by PWSCC and to adequately preserve the structural integrity of the reactor coolant system. This assessment considered the consequences of a single BMN failure due to cracking and subsequent crack growth to net section failure (NSF) of an inside or outside diameter circumferential surface flaw in the BMN base metal below the J-groove weld, and of multiple such BMN failures. The probabilistic analyses confirm that the overall risk of BMN failure is extremely low and support the deterministic conclusion that periodic examinations of the BMNs will successfully minimize the risk of nozzle ejection.

Similarly, the consequences of BMN cracking that result in leakage and subsequent reactor vessel lower head wastage were also evaluated. Both deterministic and probabilistic analyses demonstrated robust safety margins assuming implementation of any one of the several evaluated inspection programs exhibiting comparable outcomes, including “visual-only” exams performed in accordance with ASME Code Case N-722. Additionally, MRP-308 and other supporting reports present results from an extensive MRP-sponsored research and testing program that included prototypical CRDM and BMN tests which confirmed that the assumptions made in the development of MRP-167 regarding rates and conditions for boric acid corrosion wastage were appropriate. This body of work further supports the conclusion that structurally significant wastage in a crevice or confined environment adjacent to a BMN cannot develop without positively revealing its presence through the existing periodic visual examination requirements of Code Case N-722 as mandated within US regulations.

While leakage through the reactor coolant pressure boundary at any level is unacceptable, such leakage does not automatically imply a loss of either structural integrity or of safety function. Leakage is a leading indicator of potentially serious material degradation, but its primary engineering significance is in the context of a rapidly propagating failure. However, as described above, MRP-206 and its supporting documents thoroughly address the relevant BMN failure modes due to both PWSCC and boric acid corrosion wastage and still support the visual-only exam program. Furthermore, if rapidly propagating failure was a realistic concern, the risk-reduction contribution of a one-time volumetric exam at an arbitrarily established time of implementation would clearly provide limited benefit.

Finally, industry has thoughtfully considered the recent domestic and international operating experience with BMNs and other locations operating at cold-leg temperatures. The facts of these occurrences taken either individually or collectively have not invalidated the fundamental assumptions, analyses, or conclusions of the relevant MRP technical basis documents that establish the basis for the visual-only BMN inspection program over the entire life of the plant. Current BMN degradation management regulatory requirements as generically applicable to the US PWR fleet through 80 years of operation only require the recurring rigorous bare metal visual exams implemented under 10CFR 50.55a and ASME Code Case N-722.

A secondary but important additional consideration when evaluating the value added by undertaking a one-time or recurring volumetric exam is to define appropriate examination requirements that must be met by the combination of examination equipment, procedures, and personnel. At its simplest, the key decisions revolve around whether “demonstration” requirements are sufficient, or “qualification” requirements are necessary to satisfy the intended purpose of the exam. The distinction between “demonstrated” and “qualified” involve many associated details and nuances that can substantially impact planning, reliability of the results, and associated costs.

As is typical for an NDE “demonstration” program, the licensee is responsible to determine if the results from a given inspection vender are acceptable for use at their site. If there is no regulatory requirement for a demonstration to be, or remain, a blind test, feedback may be provided on what the vendor should do to improve. This sometimes will include giving the truth information about the flaw locations and sizes to the vendor after the test so that they can improve their process and thereby improve their exam results.

In contrast, a “qualification” test has a firm pass/fail criteria, the test is blind, and the feedback that can be given (beyond “you passed” or “you failed”) is normally very limited in order to maintain the security of the “truth” regarding what is contained within the test samples. Also, there may be strict requirements for the flawed and unflawed grading unit populations, flaw sizes and orientations, etc. Although requirements for demonstration versus qualification for BMN examinations in the US fleet as well as across the international PWR fleet may vary, many effective and informative BMN volumetric exams have been performed.

Conclusion

The information provided above describes relevant research findings to support a licensee decision making process. In summation, the following points should be reviewed and considered in the determination of the need for and benefit obtained from a volumetric BMN examination:

• The volumetric exam provides thorough interrogation of the nozzle base metal material, but does not provide information on the weld integrity
• MRP-206 rigorously evaluated the range of BMN failure modes and effects and identified the dominant potential safety concerns associated with PWSCC of the BMNs or their J-groove attachment welds
• MRP-308 and other supporting reports present results from an extensive MRP-sponsored low alloy steel wastage research and testing program that included prototypical CRDM and BMN tests
• MRP-167 assumptions concerning boric acid wastage corrosion rates have been confirmed through further testing (MRP-308)
• Operating experience supports the conclusion from MRP-206 that visual examinations identify low-level leakage prior to the development of lower head structural integrity concerns
• Although volumetric examinations alone are insufficient to ensure safety for BMNs, they may still add value as part of a thoughtful asset management strategy for the plant.

BMN Maintenance Experiences and Repair Options for Addressing Defects

The worldwide commercial PWR fleet experience with BMN NDE indications is rather limited and there is even less experience leaving an indication in service without repair. The most common repair technique employed thus far has been the half-nozzle with exterior weld pad.

Repair techniques which have been employed or may be applicable to the BMN configuration include:

1. Half nozzle repair
2. Exterior weld pad
3. Inner Diameter Temperbead
4. MNSA (Mechanical Nozzle Seal Assembly).
5. Abandon and plug the location

Publicly available information on these repair techniques and associated industry experience can be found under the following links:

1. Half nozzle repair overview, ANS 2004-10-2
   • South Texas Project, Unit 1:
     • Summary of ASME code calculation for repair BMI with a half-nozzle design, ML031900204
     • Bottom Mounted Instrument Penetration Tube Condition Update meeting, 2003, ML031920229
     • Summary of Exit Meeting for Special Inspection of Bottom Mounted Instrumentation Nozzle Leakage in South Texas Project, Unit 1 (NRC Inspection Report 05000498/2003008), ML032120244
   • Arizona Public Service, Palo Verde Unit 3:
     • Palo Verde Unit 3 Bottom-Mounted Instrument (BMI) Relief Request 52 Pre-submittal Meeting: Half nozzle repair Long-term evaluation, ML14098A183
     • Palo Verde Unit 3 BMI Nozzle Repair - Section XI Analysis for Restart, ML13317A072
2. Mechanical Nozzle Seal Assembly (MNSA): ML032600770
3. Abandonment and plugging: EdF resolution of BMN indications at Gravelines Unit 1 (Inspection & Repair at Gravelines 1 (ndt.net))

RPV BMN Mitigation Methods and Strategies

1. BMN Mitigation Methods

Q: What are the implementation plans of SCC mitigation solutions for BMI penetrations in US power plants, including surface shot peening treatments, water chemistry management, and other relevant practices?

A: Stress Corrosion Cracking (SCC) requires the confluence of a susceptible material, a chemical environment conducive to cracking, and sufficiently high tensile stresses on the material in contact with the coolant. Mitigation is intended to extend the life of components by altering one or more of these conditions necessary for SCC to occur. The mitigation techniques generally considered viable for BMNs are Zinc addition and various peening methods.

Laboratory studies and field experience show that zinc addition to pressurized water reactor (PWR) primary coolant can play a role in reducing the probability of crack initiation of PWSCC of Alloy 600 components and reduce in-plant radiation fields, as shown in EPRI report 1009568 and various other publicly available EPRI Reports. However, it appears the factor of improvement in rate of initiation is modest at best.

Peening has been demonstrated to be a much more effective PWSCC mitigation method. The technical basis for PWSCC mitigation by peening is documented in MRP-267 Materials Reliability Program: Technical Basis for Primary Water Stress Corrosion Cracking Mitigation by Surface Treatments, and is publicly available at the following link: 1020481.

The basis for inspection relief within the US PWR fleet is documented in MRP-335 Materials Reliability Program: Topical Report for Primary Water Stress Corrosion Cracking Mitigation by Surface Stress Improvement (MRP-335, Revision 3-A), is also publicly available at the following link: 3002009241. Notably though, since the only current inspection requirement in the US for BMNs is a bare metal visual exam, licensees of US PWRs do not get any inspection relief from BMN peening. Therefore, for US PWRs the decision whether to peen or not is entirely based on asset management.

2. BMN Mitigation Strategies

Q: When should these mitigation measures be implemented? What tracking and inspection measures are recommended to monitor their effectiveness? How can the implementation results be verified?

A: There is no single answer detailing the optimum implementation timing for any PWSCC mitigation as every plant will have its own unique set of operational, economic, and materials-related factors to consider. PWSCC is an age-related degradation mechanism, meaning that the risk of consequential degradation increases with time, but predicting when cracks will initiate in a specific component is not possible.

Some considerations that may impact mitigation strategies include:

1. Plant life and plans for license renewal,
2. Typical outage length and synergies with other significant outage activities (for example, 10-year ISI or steam generator replacements),
3. Replacement power costs,
4. Knowledge of specific materials susceptibilities,
5. Financial, radiation dose, and schedule impacts of required inspections and any repair contingencies
6. Risk tolerance for inspection findings leading to emergent repairs when performing inspections,
7. Regulatory drivers
8. Plant asset management.

Specifically for BMNs, the available mitigation options are very limited, act only at or near the wetted surface of the component, and are only effective at preventing PWSCC initiation. Therefore, mitigation implementation is most beneficial before cracks at engineering scale have initiated, making an argument for implementation relatively early in plant life.

Mitigation implementation verification for peening through appropriate process controls and other measures is addressed in MRP-267 and MRP-335 along with guidance for associated component inspections. Rather than monitoring for mitigation effectiveness over time, the focus should be on implementing an appropriate post-peening mitigation PWSCC inspection plan. Clearly the goal of any mitigation campaign is to eliminate future cracks but for wetted surface mitigation methods, pre-existing cracks may continue to grow.

RPV BMN Mitigation NRC Requirements

1. NRC Requirements

Q: What are the requirements of the Nuclear Regulatory Commission (NRC) regarding SCC mitigation solutions for BMI penetrations?

A: For the US PWR fleet, the only required BMN inspection is a recurring bare metal visual exam, generally every other refueling outage, and there is no inspection relief available for peening or other mitigation. Therefore, asset management is the basis for BMN mitigation implementation within the US fleet. With no inspection relief involved, the US NRC has no direct involvement in either the decision to mitigate BMNs or in the implementation process. However, the licensee can maximize the benefit from the mitigation implementation by following the same guidance reflected in reports such as MRP-335 and MRP-267 as they would for other mitigation locations that might more directly involve the US NRC.

Steam Generator Inspection, Assessment, and Management

Steam Generator Tube Leakage

1. Steam Generator Tube Leakage Online and Offline Detection Methods and Accuracy

Q: What are the main detection methods of the SG tube leakage in US power plants? What is the accuracy with which leaks are found in these methods？ What are the advantages and disadvantages of each inspection method?

A: The basis for leak detection in the US is detection of radioactive species from the primary system being detected on the secondary side. The detection methods in the US are designed such that an operator can respond to rapidly escalating leakage in a timely manner. This can best be accomplished if continuous rapidly updated data are used to provide a basis for operator actions. Therefore, the leakage monitoring program emphasizes the uses of Radiation Monitoring System (RMS) to detect radioactivity in the secondary plant. The RMS provides continuous on-line monitoring capability to plant operators for detection of primary-to-secondary leakage.

Routine plant sampling (grab sampling) is also an integral component of the leakage monitoring program. The plant sampling program may be implemented to verify the performance of the RMS, verify alarms, confirm leakage estimates, and provide early detection of levels or changes in radioactivity in the secondary system that are either below the sensitivity of the RMS or are not able to be sensed by the particular type of detector.

It is important to compare multiple primary-to-secondary leakage calculations to ensure the validity of the method used. This is addressed in NRC Information Notice 94-43. Not comparing leakage calculated with different methods when attempting to resolve discrepancies has led to nonconservative leakage estimates being used to make operational decisions.

The most common RMSs include instrumentation for monitoring of the following:

• Condenser Off-Gas: used to identify the presence of non-condensable radioactive gases removed from steam condensate
• Steam Generator Blowdown: used to identify non-volatile radioactive species in the steam generator bulk water
• Main Steam: used to detect primarily radioactive N-16, carried from the steam generator via the main steam

To identify the presence of primary-to-secondary leakage and to permit its calculation, routine grab samples may be collected from:

• Primary Reactor Coolant: used to quantify the source term
• Steam Generator Blowdown: used to detect non-volatile radioactive species in liquid
• Condenser Off-Gas: used to detect noble gas and other volatile species removed from steam condensate
• Condensed Main Steam: used to detect noble gas and other volatile species carried over with main steam
• Condensate: used to detect tritium, iodine and other soluble species carried with the steam from the steam generator into the secondary side
• Blowdown Filters and Ion Exchanger Columns (or ion exchange materials used for chemistry sampling that receive continuous flow): used to detect particulates and ionic species from liquid streams

Detection capabilities and measurement uncertainties are dynamic, as opposed to fixed, parameters. The specific values may vary with plant operating status and/or history. Detection capability and measurement uncertainties are a function of the following parameters:

• Source Term: Source term is the activity that exists in the primary system. Larger source terms enhance the leakage detection capability and lower the uncertainty due to improved counting statistics.

• Primary-to-Secondary Leakage: The leakage determines the rate at which activity is released into the secondary system. For a given source term, higher leakage leads to higher activity in the secondary side and lower relative uncertainty due to improved counting statistics.

• Sample Transport Time: The sample transport time includes time for mixing as well as transport to the radiation monitor. The location of the leakage can impact transport time as well as mixing within the steam generator. Active leakage in a free span region will provide significantly different data than leakage from a region with less communication with the steam generator water (e.g., a leaking tube plug or deep tubesheet crevice leakage). Transport time becomes very important for radionuclides with short half-lives and when comparing readings from different secondary system isotopes.

• Properties of the Radionuclide Measured: The properties of the isotope being measured by the detection system that affect its sensitivity include solubility in water (partition coefficients), chemical interactions (plate out), hideout, half-life (decay), parent/daughter ingrowth (species from transformation), and decay scheme (type of radiation emitted).

• Detector Efficiency: Detector efficiency refers to the response of the detector used to measure a particular radionuclide as a function of the type and energy of the radiation measured. In the case of gross channel analyzers, such as those commonly found in plant RMS monitors, the systematic errors associated with the monitor readings caused by the specific radionuclide energy response can be significant unless a correction is made for the specific isotopic mix.

• Detection Sensitivity: Detection sensitivity is the ability of the detection system to distinguish between signal and noise response. All monitors and laboratory instrumentation have a lower limit of detection (LLD) based on the system design parameters, the type of detector, and the background radiation level. Sensitivity can be enhanced by ensuring the sample is not diluted by other liquid/gas streams.

The parameters listed above are interrelated and dependent on the expected operating conditions.

Under certain plant operating conditions (e.g., startup, shutdown, etc.), the source term and detection capability of the instrumentation may not be sufficient to provide indication of leakage or changes in leakage at established action levels. Under these conditions, it may be necessary to implement frequent grab sampling in order to attain the required sensitivities.

Radiation monitors available in most plants are located in steam generator blowdown, condenser off-gas, and main steam lines. In addition to these, some facilities have also installed N-16 monitors that supplement the main steam line monitors required by NRC’s Regulatory Guide 1.97. Each type of monitor is discussed in greater detail below.

Steam Generator Blowdown Radiation Monitors

The blowdown monitors typically used are liquid monitors in an off-line sampling configuration. A sodium iodide detector is the most common type used. The monitor is operated in a gross counting mode. The monitors detect soluble gamma emitters in steam generator blowdown.

The monitors are typically relied on to provide qualitative information on primary-to-secondary leakage. Due to their sensitivity, they are responsive to small changes in activity. When no radioactivity is present or at concentrations less than the sensitivity of the monitor, setpoints are typically set at some multiple of background that prevents spurious alarms but still provides early warning of increasing radioactivity. Once detectable activity is present, leakage calculated based on a quantitative grab sample method can be correlated directly to monitor readings. In this instance, the assumption would be made that if the leakage doubles, the monitor reading would be expected to double. This assumption is subject to significant errors as discussed below. Caution is warranted with respect to acting solely on the blowdown monitor readings without confirmation from another monitor or grab sample. Operational actions, such as a power decrease, can initiate hideout return and cause steam generator activity to increase without a corresponding increase in leakage.

Limitations associated with using these monitors for performing quantitative leakage assessment include:

• Hideout: If radionuclides are deposited in steam generator crevices or hide out within oxides and sludge prior to reaching the monitor, the blowdown leakage calculation will underestimate the actual leakage. As noted above, hideout return can lead to a false indication of increasing leakage during power reduction.

• Dependency on Radionuclide Mix: Due to operation in gross count mode, the monitor response correlation to leak rate is dependent on the specific assumed radionuclide mix sampled. If the radionuclide mix changes, errors in monitor readings can result. For example, during a reactor downpower, if a significant amount of hideout return occurs, the radionuclide mix of the sampled stream will be altered. In addition, erroneously high readings will be indicated with no change in leakage. Therefore, alarms on these monitors need to be verified using an independent pathway (typically main steam N-16 monitors or the condenser off-gas monitor).

• Response Times: Another problem that has occurred with these monitors is slow response times due to relatively low sample flows through long sample lines. In fact, if a steam generator tube rupture were to occur, there is a possibility that containment isolation could be actuated by a safety system prior to the blowdown sample reaching the monitor. If containment isolation isolates the monitor sample lines before sufficient flow has reached the monitor, the monitor may never respond to the steam generator tube rupture (SGTR) event. It is important that monitor response time be examined. Response time can sometimes be decreased without making design modifications by increasing sample flow. Additionally, the response time of blowdown monitoring is also delayed (with respect to quantification) by the significant secondary side volume. Calculations that account for the transient buildup of activity in the steam generators following initiation of a leak can be used to derive a leak rate. However, such calculations are generally not incorporated into plant online monitoring systems, delaying the availability of a quantitative measurement of leakage.

• Background Radiation Levels: If high background contamination levels exist in the secondary system (due to a prior leak or a large active leak), the sensitivity of the monitor to detect changes in activity will be reduced due to higher background readings.

• Fuel Defects: In the event of a fuel leak or an increase in a fuel leak in the presence of active primary-to-secondary leakage, the monitors will reflect higher primary-to-secondary leakage. Depending on the level of the fuel defects, this may drive the primary-to-secondary leakage as indicated by the monitor into higher action levels. Therefore, it is important to ensure the change in the indicated primary-to-secondary leakage is correlated against the failed fuel radiation monitor (if available) or new reactor coolant samples.

Condenser Air Removal Radiation Monitors

The typical condenser air removal radiation monitors measures radioactive non-condensable gases discharged from the condenser. The monitors are sensitive to gaseous activity. There are several sampling configurations available: off-line, in-line (or in-duct), and adjacent-to-line. The detectors commonly used are Geiger-Muller (GM) detectors or organic (beta) scintillation detectors, operated in a gross counting mode. The organic scintillation detectors respond to beta emission from the gaseous activity discharged from the condenser. Since these monitors are operated in a gross counting mode, the detector response correlations to leak rate depend on the radionuclide mix of the sampled stream. GM detectors are sensitive to both the beta and gamma emissions (if used in an in-line or off-line configuration) and gamma emissions (if used in an adjacent-to-line configuration) from radioactive gases in the condenser off-gas. The energy response of the GM tubes depends on the window thickness and material used. In some applications, the monitors may perform a dual role.

The monitors may function as both a process monitor and effluent radiation monitor. Like other monitors, there are limitations associated with using condenser air removal monitors for evaluating primary-to-secondary leakage. These limitations include:

• Dependency on Radionuclide Mix: The energy response characteristics of the associated detectors operating in a gross counting mode may affect the accuracy of calculated leakage and should be considered. In order to provide accurate readings, monitor response should be corrected for the specific isotopic mix of the sample stream. The radionuclide energy response can either be calculated or, if activity is present, directly correlated to monitor readings by comparing grab sample data to monitor readings obtained during sampling.

• Dependency on Condenser Gas Flow Rate: Accurate measurement of process flow may also affect the accuracy of calculated leakage. In order to calculate leakage, the process flow past the monitor must be known. Because the process stream consists of a moisture saturated vapor that can contain water droplets, the effect of this sample steam needs to be considered on the instrumentation used to measure process flow. In addition, for utilities that do not have process flow instrumentation, the accuracy of the leakage estimates would be limited by the accuracy of the assumed process flow. Therefore, estimates of process flow should be confirmed by measurement or ensured to be conservative.

Limitations notwithstanding, the condenser air removal monitors provide the most accurate estimate of primary-to-secondary leakage for many leak scenarios. Readings from these monitors can be used to give a rapid assessment of leakage to operators. Although these monitors provide reliable leakage information, when looking for rapid increases in leakage, the sample transport time from the condenser to the monitor should be evaluated. Typically, those condenser systems that operate with vacuum pumps have low flow rates (on the order of a few cubic feet per minute) and large diameter exhaust lines (to accommodate the high flow rates typically encountered when initially pulling vacuum). If the monitor is not located near the condenser, transport time could be significant. Although the monitor would respond to leakage increases, the response might not be observed until sometime after the event occurs, e.g., 5 or more minutes.

If no activity is present in the process stream or if it is less than the sensitivity of the monitor, alert/alarm setpoints for these monitors should be set as low as possible without causing spurious alarms in order to provide early indication of primary-to-secondary leakage. If the energy response characteristics of the monitor are known (usually this information is available from primary calibration data), the setpoint can be set to correspond to a leakage action level by using actual RCS activity. If the monitor is used in effluent applications, the setpoints used to relate monitor readings to off-site dose may not provide early alarm indication of changing leakage.

Main Steam Line Monitors

N-16 Main Steam Line Monitors

These monitors are typically mounted on the main steam lines in an adjacent-to-line configuration. A large volume sodium iodide detector is typically used which detects and is windowed to respond primarily to the high energy gamma from N-16 decay. The effectiveness of leakage monitoring via N-16 detectors can vary depending on the leak scenario. However, these monitors can be very effective for most leak scenarios that will lead to rupture. Because N-16 has a 7 second half-life, sample transport time to the monitor becomes significant. In most calculations, the sample holdup time in the steam generator becomes the limiting factor. Small errors in the estimate of the hold up times in the generator can result in significant errors when calculating leakage based on N-16 monitor response. Therefore, N-16 monitor response to leakage is normally determined empirically by correlating indicated monitor response to known leakage calculated using grab sampling. This correlation is only specific to the particular leak and may not be transferable to leaks occurring at different locations in the generator.

Some of the advantages and challenges of N-16 monitors are:

• Limited Detection Capability at Low Power: Depending on monitor design, N-16 monitors may be useful at less than 40% power. In most cases the validity of power correction is bounded on the lower end at approximately 20% power. Primary N-16 activity concentration decreases approximately linearly with power. Steam generator and main steam line mass transport times increase significantly as power decreases. Therefore, monitor response can be significantly modified due to N-16 decay and the use of N-16 monitors at low power should be evaluated and its limitations understood by plant personnel. Depending on monitor design, N-16 monitors can be used below 20% load by using local electronic meters that read out in CPM.

• Accurate Decay Time Corrections: Due to the high flow velocity in the steam lines, the transport time from the generator to the radiation monitor is typically very short. Thus, the monitors respond almost instantaneously to increases in leakage. However, the half-life of N-16 is short and there can be considerable error associated with estimating leakage, unless the monitor readings are correlated to leakage calculated using grab sampling.

• Assistance in Leakage Location Evaluation: An N-16 monitor can also provide diagnostic information. For example, if grab sampling at the condenser exhaust indicates significant leakage, but there is no N-16 activity detected, the leak may be the result of a leaking tube plug or sleeve or by a crack in a deep tubesheet crevice (i.e., a leak scenario with significant holdup time in the steam generator). This observation could also indicate that the source of the activity in the condenser exhaust is from a source other than primary-to-secondary leakage.

• Detector “Cross Talk”: Detector “cross talk” can cause problems related to using N-16 monitors. Cross talk is simply the response of one steam line monitor detecting high-energy gamma radiation emitted from an adjacent steam line. For steam lines that are in close proximity to one another, a significant response (on the order of 10 to 25% for two-foot diameter steam lines that are seven feet apart) can be observed on a steam line monitor that may be monitoring an unaffected generator. This can present difficulties to operators when attempting to assess an affected generator or if tracking leaks that occur in more than one generator. Cross talk may also be used to confirm the adjacent N-16 monitor’s indication. Cross talk may be minimized by relocating portable N-16 monitors preferentially across the steam line in question to yield better results.

• Once monitor readings are correlated with leakage calculated using grab sample data, the monitor readings can provide a direct measurement of leakage. An increase in monitor readings would suggest that the leakage increased by the same factor. However, it is possible for the leakage to increase without any response on the N-16 monitor. For example, if a new leak develops that has a significantly different transport time than the leak causing the initial response. Therefore, N-16 leakage estimates should be periodically compared to leakage calculated using chemistry grab sample data to ensure that the correlation remains valid. With no detectable activity, alert/alarm setpoints should be set as low as possible to alert operators to potential changes in leakage while minimizing spurious alarms. If detectable activity is present in the steam line, the monitor reading can be correlated to the calculated leakage based on grab sample analysis. The alarm setpoint on the monitor can then be set to correspond to a leakage action level.

Non N-16 Main Steam Line Monitors

The main steam line monitors discussed in this section are installed at most facilities as required by NRC’s Regulatory Guide 1.97 and not intended to be used for low-level primary-to-secondary leakage but relied on for design basis accidents. Due to the high pressure and temperature of the process stream, these monitors are typically installed in an adjacent-to-line configuration. The detectors used are either ion chambers, GM tubes, or in some applications, sodium iodide detectors. The monitors respond to the gamma rays emitted from the radioactive gases and vapors being carried through the steam lines. The accuracy and range requirements for these monitors are specified by Regulatory Guide 1.97. and ion chamber monitors typically read out in gamma dose rates. Calculations are necessary to estimate the actual activity in the main steam lines.

The major limitation of these monitors is that they are not sensitive to small changes in leakage. Because these monitors measure activity through a steel pipe that is about an inch thick, the sensitivity to isotopes with low-energy gamma rays (such as Xe-133 with an 80 keV photon) is minimal. These monitors would only respond if there were sufficiently high RCS source terms. As a result, these monitors cannot be used for low-level leakage detection and are limited to post-accident assessment of significant releases. However, these monitors will exhibit a response to N-16, but typically only at levels corresponding to leakage in the gallons per minute range. Because of the N-16 response, these monitors can provide a clear indication of a SGTR if the rupture occurs while the unit is at power. However, once the reactor trips the readings will typically return to background levels.

Because of the low sensitivity of these monitors under normal failed fuel conditions and low-level leakage, they typically do not provide useful trend information. Alarm setpoints are typically set at three times background. In most facilities with such monitors, the setpoint is determined by the plant Technical Specifications.

Portable Instrumentation

Some utilities use a portable system to detect N-16 in the steam lines. The system consists of a portable multiple-channel analyzer (MCA)/amplifier/power supply coupled to a sodium iodide detector. The instrumentation can be used as a diagnostic tool to identify the affected generator and possibly obtain information concerning the cause of the leak.

A few utilities use area monitors attached to the side of piping, ion exchangers, or flash tanks to provide a qualitative indication of changing leakage. In addition, some facilities have incorporated into their station operating procedures instructions on how to perform surveys on ion exchange columns on in-line analyzers in the laboratory to provide a rapid method for confirming increasing radioactive contamination or assessing the affected steam generator. The information obtained from portable survey instrumentation and/or area monitors can provide a qualitative indication of changing leakage. Readings should be correlated by observing readings on another monitored pathway. Finally, if significant activity is present in the secondary system from either an earlier tube leak or an active leak, the information obtained may be masked because of the reduced sensitivity of the monitoring instrumentation caused by high background.

2. Online Steam Generator Tube Leakage US Operating Experience

Q: Have US power plants with Alloy 690 tubes run with a leak (maintain a small leakage until the next outage)? For operation with leakage, please describe the specific leakage assessment method and the control strategy of the unit at different leakage levels.

A: The only leakage that has been reported in the US with Alloy 690TT tubed SGs has been caused by foreign objects and the leakage increases quickly. Past OE from Alloy 600MA tubing does include plants with less than 5 gpd leakage operating and not shutting down for the small amount of leakage.

If leakage is above the SGMP Primary to Secondary Leakage limits, plants are required in the US to shut down. Secondary hydro tests are used to detect the leaking tube if it is not obvious when the plant is shut down and the cameras are installed in the SG bowl. For leakage less than this amount, increased monitoring is required.

3. Response Once a SG Tube Leak is Identified

Feedback from abroad indicates that defects in the heat transfer tubes of steam generators can lead to leakage of primary loop coolant into the secondary loop system. We would like to hear from EPRI experts about the emergency response procedures and treatment plans following such leaks.

Q: Should the unit be shut down immediately after discovering a leak, or should shut down be based on monitoring according to specific leakage standards?

A: Unit is shut down according to standards.

Q: What non-destructive testing methods should be used to locate the leak after shutting down the unit? Should eddy current inspection of the heat transfer tubes, helium leak detection, or secondary side water pressure testing be used?

A: In the US, secondary side hydro test is typically used. There is no reporting of helium leak testing in the US. Eddy current can be used also, but more expensive and time consuming.

Q: How many tubes should be inspected? Should all heat transfer tubes be inspected, or should inspection stop once the leaking tube is identified?

A: If the unit is just shut down to identify the leakage, when the leaking tube or tubes are identified and plugged and no threat for other damage, no other inspections are required.

Q: If the detection methods used fail to find the leak or suspected heat transfer tube, are there other detection methods for precise localization?

A: Eddy current would be the only other way. But the secondary hydro has been used successfully.

Q: What are the precautions and prerequisites for the leak detection process? Could you share any successful or unsuccessful cases of leak detection?

A: EPRI doesn’t have the procedures for performing the secondary hydro tests. But it has been used successfully in the US.

4. Addressing Secondary Side Contamination due to a SG Tube Leak

Q: What is the level of contamination of the secondary loop system/equipment in the event of a SG tube leak? Are there specific guidelines for preventing the spread of pollution and decontamination?

A: In all cases, the level of contamination is highly dependent on a number of variables but some thoughts below:

SGMP does not have guidance for the planning of secondary side contaminant clean up. Stations with long-term primary-to-secondary leakage have reported during station visits or during industry meetings that they posted the secondary sample sinks as contamination areas where smears indicated the presence of low-level contamination. These areas include SG sample panel, Secondary sample panel area, and, in particular, SG cation resin column monitoring was increased to establish an activity (dose rate) buildup for more than low-level SG leakage.

Secondary side tritium will increase noting that tritium is completely soluble/dissolved in the water, therefore is not expected to concentrate in sludge or other areas. The biggest challenge with tritium is that secondary side tritium may be an issue associated with secondary discharge pathways (turbine building sumps, low level steam leakage with releases to the atmosphere, etc.

Secondary liquid effluent pathways typically have activity concentration limits, including tritium, and are continuously monitored with tritium performed by compositing the sample and analyzing for tritium. Depending on the leakage, activity changes may or may not be observed due to the significant amount of secondary side leakage and makeup. Tritium will move around the secondary circuit mixing with liquid and steam environments. Unfortunately, there is very little that staff can do to minimize this mixing.

Staff should evaluate cross-connections to minimize cross-contamination of the other unit. Common areas for the plants that have experienced long-term primary-to-secondary leakage and some of the contamination and waste challenges include: SG deposits, which provide a location for primary side deposits to precipitate and be retained. Increased activity or activity higher than previous baseline work may be observed during SG maintenance activities. SG deposits may indicate the presence of low-level contamination with longer-lived activated corrosion products. SG secondary side sludge typically has low levels Co-58/60 and others in it even with no detectable leakage. These levels may increase if actual leakage is detected.

The presence of primary-to-secondary leakage does not necessarily indicate a higher activity buildup, but the longer the leakage condition exists or the higher the leakage, the greater the chance the deposit activity is higher and additional radiation protection measures may be required.

• Turbine building sumps and the sump effluent pathway to the environment.
• Hotwell and return to condensate storage tanks
• Condenser off gas system – this include the gaseous decay products that are particulate and deposit on surfaces.
• Condensate and secondary resins / filters – programmatic reviews of the secondary resin and waste disposal
• Sumps which are typically non-radioactive may become radioactive. Station Offsite Dose Calculation Manuals should be consulted on additional monitoring of sumps and other liquid pathways may be required.
• Secondary side effluent permitting (liquid and gaseous) will have to account for other radionuclides other than just tritium. This is likely something that is not commonly done in plants who have not experienced PSL so it is critical that effluent pathways account for these additional radionuclides
• Waste Challenge (potential) - Be aware that the disposal class of the resin may change due to the presence of increased levels of activity.
• For regenerable resins (e.g., condensate polishing resin), be aware of the increased level of radionuclides in the waste regenerant chemicals which would have to be dealt with and resin rinse water would also have to be appropriately managed due to the presence of radionuclides
• Depending in the plant specific offsite dose calculation manual - The ODCM may allow for the plant to create temporary storage of low activity fluid within certain limits. We did this in tankers and tanks at STP. They have to be appropriately marked and monitored as radioactive. These are good if the plant has time to let them decay.

Other thoughts: EPRI Radiation Safety is preparing the development of a Radiation Protection Challenges with Primary-to-Secondary Leakage Wiki page, but unfortunately it is in the early phases. Some of the known Radiation Protection considerations:

• Secondary effluents – understanding the effluent pathways to ensure adequate monitoring is in place. Depending on the country limits, these effluents may require routing to other areas for collection within the plant liquid processing systems for discharge (long-term units with SG leakage)
• Secondary side
  • Increase the frequency of secondary sample panel monitoring including smears and dose rates (cation columns).
  • Work planning – evaluate the potential for increased contamination and possibly airborne challenges if opening the secondary side early in the outage.
  • For units with fuel cladding defects, though it would not normally be expected, but the rapid cooldown and fission product release, iodine and xenon may be an issue and planning should account for additional time, review of system venting activities (monitoring for airborne activity concentrations, etc.) and engineering controls. Ensure that worker planning considers the initial openings of the SGs and turbines following a primary-to-secondary leakage event and the increases awareness of higher than expected SG sludge deposits and how to handle.
• Sample sinks – an updated monitoring program should be considered. In same vases, units that have long-term primary-to-secondary leakage even when the SG were replaced, these units still maintain the secondary sample sink area posted due to the longer lived radionuclides (Co-60) and the buildup of activity in the sample sink drains.
• Secondary chemistry instrumentation can now become contaminated. Might want to evaluate which instruments are actually used. E.g., Dionex columns could get jacked up, chemicals used in online sodium/hydrazine PIs may become contaminated (mixed waste).
• Weekly corrosion product filters for FW iron sampling may now become contaminated

Q: How is the pollution problem in the secondary loop solved and how should the contaminated water in the secondary loop be treated?

A: Ion exchange systems are the best way to clean-up soluble radionuclides and some particulates and are likely the best way to remove them. If the plant chooses to maintain them in service, monitor the effluent of the resin beds for activity to ensure they do not reach saturation and exhaust on these radionuclides.

Temporary TOC filters may be good for some particulate removal. This should be evaluated against the cost of the filters and disposal. Temporary membrane filters would also be good (like the BARS unit for silica removal in the primary). But again, this would have to be evaluated.

The limits for secondary loops are dependent on the station and country. From some plants, the only limit that is in place is associated with secondary side tritium to quickly note that a primary-to-secondary leak existed, but it is an administrative limit.

Effluent limits are defined in the station Offsite Dose Calculation Manual.

Secondary side cleanup systems (condensate polishers, etc.) will remove soluble (ionic) activity, but not gases or tritium, and filters may remove some of the insoluble species.

• Discharges to low level waste ponds are designed during permitting that allow for low-level activity. This is normally captured in the Offsite Dose Calculation Manual with limits.
• Temporary systems can be connected to the secondary circuit or these low-level waste pond to remove activity but should be balanced with the cost to risk analyses.

SG Integrity Evaluations and Assessments

1. Long Term Operation Experience

Q: After the implementation of steam generator integrity evaluation methods, please discuss the situation and relevant data on the long-term safe operation of the unit, the change of outage time, and the reduction of equipment faults and defects. Please describe the major defects arising from steam generators in U.S. power plants after the implementation of the integrity assessment method.

A: US plants that have implemented TSTF-577 and have tube integrity assessments that support long operating intervals between inspections have operated up to 8 years between inspections. This has saved money, dose, and outage time. Most of the replacement SGs with Alloy 690 tubing have low levels of support-to-tube wear and are able to justify these long operating times and their SG inspections include automated data analysis which help to shorten inspection time. Some US SGs with Alloy 690TT tubing have excessive wear which necessitates inspections each outage, but again, with auto analysis, they too have shortened their inspection time.

2. Risks and Challenges

Q: What are the main risks and challenges of steam generators in the United States after implementation of integrity assessments?

A: Some designs are susceptible to excessive tube-to-support wear and foreign object wear.

SG Primary and Secondary Side Foreign Objects

1. SG Secondary Side Foreign Objects

Q: During each outage, we will conduct video inspection of the cleanliness of the secondary side tube sheets of the steam generators. However, metal or non-metal foreign objects of varying sizes are inevitably found during each outage, and there have been no instances where these objects could not be removed. We would like to hear from EPRI experts about their experience in evaluating the impact of these foreign objects on the integrity of the heat transfer tubes. Please provide guidance on the handling of foreign objects discovered in the secondary side of the steam generator and the methods and procedures for assessing the reliability of the heat transfer tubes.

A: EPRI SGMP has issued a white paper with a section on Managing Foreign Material in the SG Tube Bundle (3002030563). It is common in the US for plants to identify foreign objects during secondary side visual inspections. When the part is in a high flow region of the bundle, every effort is made to retrieve the part. If the part cannot be removed, tubes are plugged and stabilized, and these areas are inspected in future outages. When foreign object wear is detected, it is treated like all other wear and plugged if 40% through wall or greater and evaluated for tube integrity.

2. Primary Side Experience in Assessment and Handling of Mechanical Damage in US Power Plants

Q: For mechanical damage caused by foreign objects, such as in the primary side water chamber overlay welding layer of the SG or the seal welds of the SG heat transfer tubes, foreign objects may cause multiple damages. Under normal water environment, the possibility of SCC occurring in mechanically damaged areas caused by foreign objects is low. Are there any cases of mechanical damage to the SG water chamber overlay welding layer or heat transfer tube seal welds in US power plants? How does EPRI assess such cases?

A: Yes, there is operating experience in the US where objects have entered the primary bowl and damaged the tubesheet welds. There is international operating experience were objects damaged the 82/182 divider plate welds. For the 82/182 weld material, the international plant reported SCC. SGMP does not have guidance for actions to take after such an event. It is very rare and actions would be specific to the event. Most of the time, no repair has been needed. One possible issue could be if the tubesheet weld is damaged to the point where eddy current probes couldn’t be inserted. In this case, the eddy current vendors have tooling to fix this.

SG Secondary Side Sludge Accumulation

1. SG Secondary Side Sludge Inspection, Monitoring, and Removal

Q: What are the inspection and monitoring methods for sludge accumulation in the high-level support structures, and what are the acceptance criteria? What are the methods for removing deposited sludge, and what are the criteria for initiating the removal process? What are the verification methods and removal cycles for sludge removal?

A: This question is also covered in an SGMP White Paper (3002030563). Eddy current can be used to estimate the areas of deposits in the bundle and a qualitative thickness. Visual inspections have been used by inserting a camera. Sludge lancing is used at the top of the tubesheet to reduce accumulation of deposits. Chemical cleaning is used for the rest of the bundle.

Record of Revisions

Number	Date	Description of Changes
0	7/11/2024	Original release
1	9/12/2024	Added NDE and Vessel Internals technical content
2	10/01/2024	Added CASS content
3	12/06/2024	Added BMN content
4	1/15/2025	Added SGMP content

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