L-2023-075, Response to Request for Additional Information (RAI) Regarding Exemption Request, License Amendment Request and Revised Response in Support of a Risk-Informed Resolution of Generic Letter 2004-02

Response to Request for Additional Information (RAI) Regarding Exemption Request, License Amendment Request and Revised Response in Support of a Risk-Informed Resolution of Generic Letter 2004-02

ML23163A022
Person / Time
Site:	Point Beach
Issue date:	06/09/2023
From:	Strand D Point Beach
To:	Office of Nuclear Reactor Regulation, Document Control Desk
References
L-2023-075
Download: ML23163A022 (1)

Text

NEXTera ENERGY~

~

BEACH U. S. Nuclear Regulatory Commission Attn: Document Control Desk Washington DC 20555-0001 June 9, 2023 RE:

Point Beach Nuclear Plant, Units 1 and 2 Docket Nos. 50-266 and 50-301 Renewed Facility Operating Licenses DPR-24 and DPR-27 L-2023-075 10 CFR 50.12 10 CFR 50.90 GL 2004-02 Response to Request for Additional Information (RAJ) Regarding Exemption Request, License Amendment Request and Revised Response in Support of a Risk-Informed Resolution of Generic Letter 2004-02

References:

1.

NextEra Energy letter L-2022-121, Exemption Request, License Amendment Request and Revised Response in Support of a Risk-informed Resolution of Generic Letter 2004-02, July 29, 2022 (ADAMS Accession No. ML22210A086)

2.

NRC Generic Letter 2004-02, Potential Impact of Debris Blockage on Emergency Recirculation During Design Basis Accidents at Pressurized-Water Reactors, September 13, 2004

3.

NRR electronic memorandum dated May 1, 2023, FINAL RAJ, - Point Beach 1 & 2 - License Amendment Request Regarding Risk-Informed Approach to Address GSl-191 (EPID L-2022-LLA-0106) (ADAMS Accession No. ML23122A013)

In Reference 1, NextEra Energy Point Beach, LLC (NextEra) submitted pursuant to 10 CFR 50.12, a request for an exemption from the requirements of 10 CFR 50.46(a)(1) for Point Beach Nuclear Plant Units 1 and 2 (Point Beach), respectively. The proposed exemption would allow the use of risk-informed methods to evaluate the long term core cooling (L TCC) effects of debris generation resulting from a postulated loss of cooling accident (LOCA), as described in Generic Letter (GL) 2004-02 (Reference 2). The submittal also included pursuant to 10 CFR 50.90, a license amendment request for Point Beach Renewed Facility Operating Licenses DPR-24 and DPR-27 which revises the licensing basis described in the Point Beach Updated Final Safety Analysis Report (UFSAR) to include a risk-informed method of evaluating the effects of LOCA generated debris on LTCC. Additionally, the submittal included NextEra's revised response to GL 2004-02 for Point Beach based on a risk-informed approach to the safety issues described therein.

In Reference 3, the NRC requested additional information deemed necessary to complete its review.

The enclosure to this letter contains Enercon Project Report NEE-591-REPT-0002, which provides NextEra's response to the request for additional information (RAJ) of Reference 3. The report additionally identifies where applicable, superseding changes to the original submittal (Reference 1 ). Attachments 1, 2 and 3 to the enclosure provide the three Point Beach plant procedures requested in Reference 3.

The supplements included in this RAJ response provide additional information that clarifies the application, do not expand the scope of the application as originally noticed, and should not change the NRC staffs original proposed no significant hazards consideration determination as published in the Federal Register.

This letter contains no new regulatory commitments.

Point Beach Nuclear Plant, Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2023-075 Page 2 of 2 Should you have any questions regarding this submission, please contact Mr. Kenneth Mack, Fleet Licensing Manager, at 561-904-3635.

I declare under penalty of perjury that the foregoing is true and correct.

Executed on the~ day of June 2023.

Sincerely, Dianne Strand General Manager, Regulatory Affairs cc:

USNRC Regional Administrator, Region Ill Project Manager, USNRC, Point Beach Nuclear Plant Resident Inspector, USNRC, Point Beach Nuclear Plant Public Service Commission of Wisconsin Enclosure Attachments (3):

1.

Point Beach Nuclear Plant Procedure, NP 7.7.31, Revision 9, Alloy 600 Management Program

2.

Point Beach Nuclear Plant Procedure, 01-55, Revision 35, Primary Leak Rate Calculation

3.

Point Beach Nuclear Plant Procedure, NP 7.7.22, Revision 6, Service Water Inspection Program

Point Beach Nuclear Plant, Units 1 and 2 L-2023-075 Docket Nos. 50-266 and 50-301 Enclosure Point Beach Units 1 and 2 GSI-191 License Amendment Request Submittal RAI Responses (Enercon Project Report NEE-591-REPT-0002)

(31 pages follow)

0 ENERCON PROJECT REPORT COVER SHEET Excellence-Every project Every day.

Point Beach Units 1 and 2 GSl-191 PROJECT NEE-591-REPT-0002

Title:

License Amendment Request Submittal REPORT NO.

RAI Responses REV.

0 NextEra Energy Point Beach Project Client:

Identifier:

NEE$PB-00133 Item Cover Sheet Items Yes No 1

Does this Project Report contain any open assumptions, including

~

preliminary information, that require confirmation? (If YES, identify the assumptions.)

2 Does this Project Report supersede an existing Project Report? (If

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YES, identify the approved Project Report.)

Superseded Project Report No.

Scope of Revision:

Initial Issue Revision Impact on Results:

NA D Safety-Related D Augmented Quality 1:8'.1 Non-safety Related D Safety Class D Safety Significant D General Services D Production Support Page 1 of 31 QF-047, Rev. 0

ENERCON PROJECT REPORT COVER SHEET Excellence-Every project. Every day (Print Name and Sign)

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Digitally signed by Haifeng Li Reason: Signe t~~~e Stair per Prepared: NCSG-RAl-2, 3 delegation of a Date: 2023.06. 15 14:56:37-04'00' i2 /dJJ_

Digitally signe j by Drew Rodich Date: 2023.0.05 16:44:44-04'00' Prepared: STSB-RAl-1-3, 6, 8, 10, 13 Date:

Reviewed: STSB-RAl-4, 5, 7, 9, NCSG-RAl-1, NPHP-RAl-1-4 Prepared: STSB-RAl-4, 5

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Digitally si llif Haifeng Li Date: 202.

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Bach Date: 2023.06.05 11 :38:46 9-M Reviewed: STSB-RAl-1-3, APLB-RAl-1, ESEB-RAAPBl-1, NCSG-RAl-2, 3 i4-1JLi Digital y signed by Timothy D. Sande Date: 2 D23.06.05 11 :23:15 -06'00' Prepared: STSB-RAl-11, 12, APLB-RAl-1 Date:

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Digitally signed by Alec Clark Approver:

Date: 2023.06.05 17:08:06 Date:

-04'00' Note 1: For Non-safety Related, DOE General Services, or DOE Production Support Project Reports, design verification can be substituted by review.

Page 2 of 31 QF-047, Rev. 0

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Point Beach Units 1 and 2 GSl-191 PROJECT NEE-591-REPT-0002

Title:

License Amendment Request REPORT NO.

Submittal RAI Responses REV.

0 PROJECT REPORT REVISION STATUS REVISION DATE DESCRIPTION 0

See Cover Page Initial Issue APPENDIX/ATTACHMENT REVISION STATUS APPENDIX NO.OF REVISION ATTACHMENT NO.OF REVISION NO.

PAGES NO.

NO.

PAGES NO.

None None Page 3 of 31 QF-047, Rev. 0

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Point Beach Units 1 and 2 GSl-191 PROJECT NEE-591-REPT-0002

Title:

License Amendment Request Submittal REPORT NO.

RAI Responses REV.

0

1.0 Purpose and Scope

............................................................................................ 5 2.0 Summary of Results and Conclusions............................................................. 5 3.0 References.......................................................................................................... 5 4.0 Assumption......................................................................................................... 5 5.0 Design Inputs...................................................................................................... 5 6.0 Detailed Discussion........................................................................................... 5 7.0 Computer Software.......................................................................................... 31 Page 4 of 31 QF-047, Rev. 0

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1.0 Purpose and Scope

The purpose of this report is to document responses to requests for additional information (RAls) issued by the Nuclear Regulatory Commission (NRC) on the Exemption Request and License Amendment Request (LAR) for a risk-informed resolution of GSl-191 for Point Beach Units 1 and 2 (Reference 3.2). The RAls are documented in Reference 3.1.

2.0 Summary of Results and Conclusions The individual RAI responses are described in Section 6.

3.0 References 3.1 Email from Scott Wall to Eric Schultz, "FINAL RAI - Point Beach 1 & 2 -

License Amendment Request Regarding Risk-Informed Approach to Address GSl-191 (EPID L-2022-LLA-0106)", May 1, 2023, (ADAMS Accession No. ML23122A013).

3.2 NextEra Energy Point Beach, LLC letter L-2022-121, "Exemption Request, License Amendment Request and Revised Response in Support of a Risk-informed Resolution of Generic Letter 2004-02", July 29, 2022, (ADAMS Accession No.ML2221A086).

4.0 Assumption No assumptions were required for the development of the RAI responses.

5.0 Design Inputs No design input was required since this report does not document any independent analysis. The reference(s) used for the basis of each RAI response are cited with the response text (see Section 6).

6.0 Detailed Discussion The responses to each RAI are described below.

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Technical Specifications Branch (STSB) Questions STSB-RAl-1 (Audit Question STSB-1)

Page E1-10 discusses the request for exemption. The reference to Title 10 of the Code of Federal Regulations (10 CFR), Section 50.46(a)(2)(ii) may require additional explanation. The referenced regulation is required for the short-term analysis, but not the long-term analysis.

NextEra Response:

The reference to 10 CFR 50.46(a)(2)(ii) was a typo and should have referenced 10 CFR 50.46(a)(1).

Page E1-10 of the original submittal (Reference 3.2) is affected by this response.

STSB-RAl-2 (Audit Question STSB-3)

Define what is meant by "first isolation valve" throughout the submittal.

NextEra Response:

The Class 1 boundary for the RCS includes two isolation valves in series (e.g., check valves, or valves that are normally closed) that isolate the RCS from other systems. The first isolation valve is the first valve on the RCS side. This valve would have to fail open in order for breaks in downstream piping to cause a LOCA.

The original submittal (Reference 3.2) is not affected by this response.

STSB-RAl-3 (Audit Question STSB-4)

Figure 3.a.1-1 does not show any postulated breaks on the reactor nozzles or elsewhere on the main reactor coolant system (RCS) loops near the reactor. It is also not clear whether any breaks were postulated on the safety injection tank (SIT) or emergency core cooling system (ECCS) injection lines. Verify that all welds that are within the first isolation valve are considered as potential break locations.

NextEra Response:

It was confirmed that all welds within the first isolation valve were included in the debris generation analysis. However, some of the break locations were inadvertently omitted from Figure 3.a.1-1. The figure below depicting the Unit 1 breaks replaces Figure 3.a.1-1 in the original submittal (Reference 3.2).

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STSB-RAl-4 (Audit Question STSB-13)

Discuss Table 3.e.6-26, "Definition of Debris Groups." Describe the quantities included in the last 3 rows (include densities, volumes, and masses), and reasons for coating particulates to be aggregated with chips and latent particulates. Describe how the debris types are related and compared to debris types used in strainer testing (dirt, silica, chips, and pressure washed chips). Refer to Table 3.f.5-1 at the test scale, and Table A.8-1, "PBNP Sump Strainer Debris Limits."

NextEra Response:

The plant debris types included in each of the debris groups in the last 3 rows of Table 3.e.6-26 are listed in the table. The debris groups defined in Table 3.e.6-26 were consistently used when presenting and comparing the plant strainer debris loads (see Table 3.e.6-27 through Table 3.e.6-30 for example Page 7 of 31 QF-047, Rev. 0

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breaks) and head loss testing debris loads (see Table 3.f.10-1). The same debris groups were also used when presenting the plant strainer debris limits at test scale (see Table 3.f.5-1).

As noted on Page E3-78 of the submittal, the following materials were used during head loss testing to represent different plant particulate debris types.

PCI dirt and dust mix was used as a surrogate for latent particulate debris during head loss testing.

Silica flour was used as a surrogate for coatings particulate debris, resulting from failed qualified and unqualified coatings, and the particulate portion of the actively delaminating qualified (ADQ) epoxy coatings.

Pressure washed paint chips and raw paint chips were used as surrogates for flat fine chip and flat small chip portions of ADQ epoxy coatings, respectively.

The quantifies for these debris groups vary from break to break. The variation is due primarily to the quantities of qualified coatings, which depend on break size, orientation, and location.

Particulate debris contributes to debris bed head loss by filling up the voids within a fiber bed. For the PBN conditions, coatings particulate debris, with its characteristic size of 10 µm, has more impact on debris head loss compared to other particulate debris types with greater characteristic sizes (e.g.,

coating chips and latent particulate). For this reason, coatings particulate was set as a separate debris group. This means that in order for a head loss test to bound a break, its tested coatings particulate debris quantity must be greater than that of the break. This is, however, unnecessary for coating chips debris. If, compared with a given break, a test has a smaller tested coating chips quantity but higher combined quantity for coating chips and coating particulate, the test is still applicable for this break because the deficiency in the tested coating chips load can be compensated by the excess in the tested coatings particulate load with respect to head loss impact. Therefore, the combined coatings particulate and chips was set as a debris group. The same is applicable for the latent particulate debris.

It should also be noted that the quantities of coating chips and latent particulate debris are much less than that of the coatings particulate.

The original submittal (Reference 3.2) is not affected by this response.

STSB-RAl-5 (Audit Question STSB-18)

Discuss how temperature scaling is implemented for the headlosses applied in NARWHAL.

NextEra Response:

The methodology used for temperature and strainer approach velocity scaling in the PBN risk quantification is the same as that in the Vogtle GL 2004-02 submittal (ML181938165). The scaling was performed on the conventional and chemical debris head losses separately. The discussion and example in this response will focus on the process for conventional debris head loss, which was similarly applied to the chemical debris head loss.

Debris head loss was determined for every postulated break over each time step. The Response to

3. f.10 explained the process of identifying an applicable head loss test for a given combination of debris loads. The peak head loss of the selected test (as shown in Table 3. f.10-1) was measured at a certain strainer approach velocity and water temperature (see Table 3.f.4-9), which may be different from the Page 8 of 31 QF-047, Rev. 0

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actual strainer operating conditions in the NARWHAL analysis. The differences between testing and plant operating conditions (i.e., strainer approach velocity and water temperature) were accounted for by multiplying the peak head loss of the selected test by the head loss scaling factor XHL, which is calculated for each break and time step.

As shown in the Response to 3.f.10, XHL depends on parameters derived from the selected head loss test (i.e., a, b, LJ.PHL) and those at the plant operating conditions for the given time step: strainer approach velocity (Vstrainer), water viscosity (µ), and water density (p). An example is given below for determining the conventional debris head loss for the 23" partial break (225°) at Weld ISi RC-36-MRCL-All-02_ZOI for Unit 1 at the end of the 30-day period.

1.

The FDL-1 head loss test was shown to be applicable for determining the conventional debris head loss for this break. The FDL-1 test has a peak conventional head loss of 2.640 ft at the testing conditions (see Table 3.f.10-1 ).

2.

The conventional debris head loss scaling factor XHL was calculated based on the following inputs:

a.

Parameters from the selected head loss test FDL-1 (see Table 3.f.10-4)

Parameter Value Unit a

1306103.95 b

2718.22 APHL 2.59 ft ft

b.

Parameters based on plant strainer flow rate and sump temperature at the given time step Parameter Value Unit Strainer flow rate 2100 gpm Net strainer surface area 1754.6 ft2 Strainer aooroach velocity Vstrainer 0.002667 ft/s Plant sump temperature 102.36 OF Parameter Value Unit Plant sump water density (p) 62.1432 lb/ft3 Plant sump water viscosity (µ)

0.0004479 lbm/ft-s

3.

Using the above inputs and the formula given in the Response to 3.f.10, the correction factor (XHL) is calculated to be 1.0661.

4.

Multiplying the peak conventional debris head loss of the FDL-1 test (2.640 ft) by the value of XHL results in the conventional debris head loss of 2.815 ft for the given break and the time step.

The original submittal (Reference 3.2) is not affected by this response.

STSB-RAl-6 (Audit Question STSB-19)

Discuss how the scaling factors discussed starting on page E3-97 are developed and implemented.

What temperature is used to determine the viscosity and density in the equation?

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Were all of the data in Table 3. f.10-3 corrected to the same temperature for the analysis?

How are data points like the first and last used when developing the correlation? The first point is a higher headloss than the last, but its flow is lower and temperature higher than the last point.

This is not expected. The value just above Table 3. f.10-4 is listed at 2.59 ft, but the value is actually 2.64 ft in Table 3.f.10-1.

The sentence just above Table 3. f.10-4 refers to Table 3. f. 10-10. Should it refer to Table 3.f.10-4 instead?

NextEra Response:

1.

The scaling factor was calculated for each time step. The viscosity and density are calculated at the sump temperature for each time step. The plant sump temperature for a given time step is obtained from a time-temperature lookup table in NARWHAL. The time dependent sump temperature data used is plotted in Figure 3.g.1-1.

2.

The data in Table 3.f.10-3 was not corrected to any plant conditions. Table 3.f.10-3 shows the flow sweep data collected during the FDL-1 head loss test after all conventional debris has been added to the test tank and head loss stabilized. Similar data was also obtained for the other head loss tests but was not tabulated in the submittal. The data in Table 3.f.10-3 was only used to determine the parameters a, b, llPHL for the FDL-1 test. These parameters are required for scaling the peak conventional head loss of the FDL-1 test (see Table 3.f.10-1) from its testing conditions to plant conditions of interest in NARWHAL. The process of calculating the parameters a, b, llPHL was demonstrated on Pages E3-98 and E3-99 of the submittal using the FDL-1 test as an example. It should be noted that, as shown in Table 3.f.10-3, the test temperature was held as constant as reasonably achievable during the flow sweep. This was true for all tests.

3.

As noted above, the flow sweep data in Table 3.f.10-3 was recorded during the FDL-1 test after all conventional debris has been added to the test tank and head loss stabilized. As shown in Figure 3. f.10- 1, all the data points in the table were used to derive a curve fit, which was then used to determine the parameters a and b (see Page E3-99). In other words, the data in the table was only used to derive these parameters for head loss scaling.

The first and last data points in Table 3.f.10-3 were recorded at the beginning and end of the flow sweep during the FDL-1 test. The slight difference between the two head losses (2.59 ft vs. 2.56 ft) could be due to a number of factors, such as measurement uncertainties, slight variations in test conditions and debris bed characteristics.

As noted above, the head loss of 2.59 ft was recorded at the beginning of the flow sweep, which was performed after the strainer head loss had stabilized. As a result, this head loss represents a long-term stabilized debris head loss and was only used to determine the scaling factor. In contrast, the head loss value of 2.64 ft in Table 3.f.10-1 was the maximum conventional debris head loss recorded during the FDL-1 test. For conservatism, this peak head loss value was adjusted from the testing conditions to plant conditions when determining the conventional debris head loss for a given break.

4.

The reviewer is correct that the reference to Table 3.f.10-10 on page E3-99 should have been Table 3.f.10-4.

The original submittal (Reference 3.2) is not affected by this response.

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STSB-RAl-7 (Audit Question STSB-21)

Confirm that the minimum SI curve is conservative compared to the maximum safety injection (SI) curve for the purpose of determining margin to flashing and crediting some containment accident pressure (CAP) to suppress flashing (page E3-102). On page E3-107 it is stated that the minimum SI curve results in a higher temperature, so it is conservative. However, there is time dependency with respect to sump temperature and containment pressure for various containment response cases that should be considered.

For example, the maximum SI curve should reduce containment pressure faster than a minimum SI case.

The sump temperature generally lags the containment pressure, so there may be times that the maximum case has less subcooling.

NextEra Response:

The base case NARWHAL model credits 2 psi of containment accident pressure for the first 200 minutes after initiation of the accident to mitigate flashing failure. This approach is acceptable as justified below.

The evaluation of flashing failure uses a very conservative approach:

The flashing evaluation is performed at the top of the strainer, where the pressure is the lowest.

For the first 200 minutes after the accident, the containment pressure is assumed to be equal to the saturation pressure at the sump temperature plus 2 psi if the sump temperature is above 212°F and equal to 16.7 psia (14.7 psia + 2 psi) otherwise. After 200 minutes, the containment pressure is assumed to be equal to the saturation pressure at the sump temperature if the sump temperature is above 212°F and equal to 14.7 psia otherwise.

The sump temperature curve came from the analysis of a double-ended pump suction (DEPS) break with minimum safety injection. The inputs for this analysis were biased to maximize sump temperature and resulted in a lower containment pressure than the other cases analyzed. Even with the 2 psi of containment accident pressure credited, the containment pressures used in NARWHAL are at least 6 psi lower than those from the containment analysis. As shown in Figure 3.f.14-1, the minimum margin occurs at the start of recirculation, after which the margin increases to over 10 psi within 14 minutes and continues to increase after that. This margin is judged to be in excess of any difference in the resulting containment pressures between the minimum and maximum safety injection (SI) cases. Note that containment accident pressure was only used for the evaluation of flashing and was not credited for degasification or the pump NPSH evaluation.

The original submittal (Reference 3.2) is not affected by this response.

STSB-RAl-8 (Audit Question STSB-22)

For the flashing evaluation discussed in section 3.f.14, discuss whether clean strainer headloss included in the differential pressure.

NextEra Response:

NARWHAL uses the total strainer head loss, including clean strainer head loss and debris head loss, for the flashing evaluation.

The original submittal (Reference 3.2) is not affected by this response.

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STSB-RAl-9 (Audit Question STSB-26)

Clarify whether the strainers consist of 11 or 14 strainer modules. See pages E3-129 and 131 as well as the layout drawings.

NextEra Response:

The strainers consist of 14 modules. Originally, each strainer train at PBN1 and PBN2 consisted of 11 strainer modules connected to the respective train's sump outlet pipe. The installations were performed during the spring 2006 and 2007 refueling outages. An additional 3 modules were added to each train in the Fall 2008 and Fall 2009 outages.

The original submittal (Reference 3.2) is not affected by this response.

STSB-RAl-10 (Audit Question STSB-27)

For Item 7 on page E3-168, explain the statement that the fiber transported by the RHR pump reaches the reactor. The staff is under the impression that the RHR pump also feeds the containment spray (CS) pump so that some of the fiber transported by the RHR pump would be returned to the sump. For a zero CSS case, which is shown to be limiting in Table 3.n.1-2, the statement would be true.

NextEra Response:

The statement is modified as follows.

"During recirculation, the fiber transported by RHR pump flow that is not supplied to the CS pump reaches the reactor."

As noted on Page E3-168, when the CS pump is in recirculation mode, the fiber carried by the flow supplied to the CS pump is returned to the sump.

The original submittal (Reference 3.2) is revised by this response as discussed above.

STSB-RAl-11 (Audit Question STSB-30 rev 1)

Table 1-1 on page E4-66 provides strainer debris limits for various debris types. Discuss whether these limits are for single or dual train operation. It appears that the particulate debris types are based on single train operation. This is not clear for the fibrous debris types. Should limits for chemical precipitates be included in the table? Discuss the basis for the acceptability of these values if they are not all for single train operation.

Describe how the quantity of other chemical contributors (especially aluminum) in containment are tracked.

Describe what actions would be taken if previously unidentified material is discovered or the quantity of material exceeds that assumed in the risk-informed analysis.

NextEra Response:

As described in the text above Table 1-1, "the limits for these debris categories are based on the debris loads on one strainer resulting from the strainer head loss testing and analysis." These limits are independent of the number of trains in operation. If one train is in operation, all transported debris would accumulate on that strainer and the debris quantity would be compared against these limits. If two trains are in operation, the debris would be split between the two strainers and the debris load on each strainer would be compared against the same limits.

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Similar limits could be defined for chemical precipitates. However, the evaluation of chemical debris is somewhat different than other debris types because chemical precipitation quantities are calculated based on the quantity of other debris (e.g., fiberglass), containment conditions (e.g., pH and temperature), and the exposed surface area of aluminum in containment. Therefore, it is easier to track quantities and margins for input parameters such as the quantity of aluminum in containment rather than the margin associated with the quantity of sodium aluminum silicate generated.

Containment walkdowns were performed to identify the quantity and location of aluminum inside containment. The results were initially documented in Engineering Evaluations 2007-0001 (Unit 1) and 2007-0009 (Unit 2). These were subsequently superseded by Calculations 2018-0007 (Unit 1) and 2018-0008 (Unit 2). The results are incorporated into the FSAR. The calculations include margin for contingencies and provided input to the Chemical Effects analyses. Procedure NP 7.2.28, Containment Debris Control Program, contains guidance to ensure that appropriate sump performance design basis documents are updated as necessary to maintain configuration control and evaluate any reduction in design margin. Note that this procedure will be revised as needed to align with the risk-informed approach for the GL 2004-02 response upon NRC's approval of the licensing amendment request.

If previously unidentified aluminum is discovered or the quantity of aluminum exceeds that assumed in the risk-informed analysis, the process described on page E4-68 of the submittal would be followed, similar to the other debris types.

The original submittal (Reference 3.2) is not affected by this response.

STSB-RAl-12 (Audit Question STSB-31)

Similar to the question regarding single and dual train operation for table 1-1, discuss the assumption for Tables 1-2 and 1-3 on page E4-67.

NextEra Response:

The debris limits in Tables 1-2 and 1-3 are copied directly from Table 1-1 (see response to STSB-RAl-11 ). As described in the text above these tables, the margin is the difference between the debris limit and the current plant quantity, and the current plant quantity is the maximum debris quantity that would transport to a single strainer for either:

1.

Breaks less than or equal to 12 inches for two train operation, or

2.

Breaks less than or equal to 8 inches for singe train operation.

The basis for selecting these break sizes is described on Page E4-65. If all breaks larger than 12 inches fail for two train operation scenarios and all breaks larger than 8 inches fail for single train operation scenarios, the overall risk associated with these failures would be less than 1 E-06 yr*1 (i.e., within RG 1.17 4 Region 111) as long as no smaller breaks fail. These tables essentially define the operating margin for each reported debris type to ensure the plant remains within RG 1.174 Region Ill. The two figures below illustrate the derivation of the debris margin for Cal-Sil as an example.

Figure 1 shows the quantity of Cal-Sil debris transported to one strainer for single train operation (blue points) and two train operation (orange points). The dashed red line indicates the tested Cal-Sil debris quantity, which represents the debris limit for Cal-Sil. The solid lines in blue and orange indicate the subset of breaks to be considered for operability (solid blue line: s 8-inch breaks for single train operation; solid orange line: s 12-inch breaks for two train operation). Figure 2 shows a zoomed in version of Figure 1, focusing on the break size ranges that are used for deriving the debris margin. The max Cal-Sil debris load on one strainer for s 8-inch breaks with single train operation and for s 12-inch Page 13 of 31 QF-047, Rev. 0

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breaks with two train operation are noted on Figure 2. As stated above, the greater value of the two was used to calculate the debris margin for Cal-Sil, which is represented by the vertical dash-dotted line in Figure 2.

The original submittal (Reference 3.2) is not affected by this response.

700 600 E 500

§.

Cl)

C -~

ci) 400 Cl)

C 0

C 0

-~ 300

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• Unit 1 Single Train Operation

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= -*

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0 5

10 I

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,1 II 15 20 Break Size (in)

I I

i I I I

• I I

• I

~

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• I

=

25 30 35 Figure 1: Cal-Sil debris limit and debris loads for single and two train operation Page 14 of 31 QF-047, Rev. 0

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500 -

450 400 PROJECT REPORT NEE-591-REPT-002 Debris Loads for Single-Train Operation Debris Loads for Two-Train Operation Available Margins

---

i ------------------------------

E

e 350

41)

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~ 300 ci5

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C:

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0

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0 Max Cal-Sil load on one strainer for up to 8" breaks and single train operation 2

4 6

8 Break Size (in)

Max Cal-Sil load on one strainer for up to 12" breaks and two train operation 10 12 Figure 2: Illustration of Cal-Sil debris margin for breaks ::5 12 inches (two train operation) and ::5 8 inches (one train operation)

STSB-RAl-13 (Audit Question STSB-34)

Provide details on the empirical fiber penetration and shedding model so that the NRC staff can perform confirmatory calculations for the in-vessel fiber analysis. Include equations for fiber penetration and shedding, parameters, water flow rates, pool volume initial fiber amounts, and information on dependence of results on time stepping. Provide a description of how the bounding input fiber mass used in the calculations was determined.

NextEra Response:

The calculation steps described on Pages E3-168 and E3-169 of the submittal (Reference 3.2) provide the process necessary for performing a confirmatory calculation. The initial fiber load, pump flow rates, pump lineup, and pool volume inputs are shown on Page E3-170 of the submittal.

The equations for calculating the fiber penetration fractions are shown below. The prompt fiber penetration fraction (F) can be calculated with the following series of equations.

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-M' BFinf=M M' = (2CF X Z X M)

-(BF XM)

The fiber shedding fraction (S) can be calculated with the following set of equations.

Where:

F

= Fiber prompt penetration fraction S

= Fiber shedding penetration fraction q

= Quantity of debris on the strainer at test scale t

= Shedding time or time since start of recirculation The coefficients associated with these equations are shown in the table below.

Coefficient Value Units AF 5.23253E-01

[g/g]

BF 4.31653E-03

[1/g]

CF 1.16881 E-06

[1/g2]

DF 9.991038E-01 Bs1 1.201 S0E-05

[g/(g*s)]

Bs2 8.26372E-04

[1/g]

bs1 5.25979E-02

[1/s]

bs2 2.43008E-06

[1/g]

Note that the strainer debris load q is at test scale. The scaling factor of the fiber penetration test should be used and is the ratio of the test strainer area (95.13 ft2) to the plant strainer area (1,904.6 ft2).

Page 16 of 31 QF-047, Rev. 0

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For the cases with CS operation, the delay in the start of CS recirculation was considered. The analysis used the timing of the minimum safeguard case shown in the table below due to its greater delay in the start of CS recirculation. This conservatively adds more fiber to the reactor at the beginning of recirculation when the strainer is less covered by debris, and the strainer bypass fraction is the highest.

A duration of 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> was used for the CS recirculation.

No. of RHR pumps RHR Switchover to CS Recirculation Recirculation Begins (sec)

Starts (sec)

Minimum Safeguard 3,397.73 9,200 The time steps used in the analysis are as follows:

Time after start of Time Step Size (sec) recirculation (hrs)

Oto 1.5 1

1.5 to 5 10

>5 60 Note that the initial fiber load of 550 lbm presented on Page E3-170 bounds the worst-case transportable fiber load for PBN Units 1 and 2 presented in Tables 3.e.6-27 and 3.e.6-29. The fiber quantities in these tables are presented in LDFG-equivalent volumes.

The LDFG-equivalent volume is calculated by dividing the actual mass of the fiber debris (output from BADGER) by the LDFG density of 2.4 lbm/ft3* For example, 10 lbm of mineral wool which has an actual density of 8 lbm/ft3 (Table 3.c.1-1) would have an actual volume of 1.25 ft3* This same mass of mineral wool would have an LDFG-equivalent volume of 4.17 ft3*

When converting an LDFG-equivalent volume to mass, the LDFG density must be used. Taking the worst fiber break in Table 3.e.6-27 as an example, the total mass of transportable fiber is 341. 7 lb

[(119.68 + 22. 70) ft3 x 2.4 lb/ft3]. Similarly, for Unit 2, the maximum total mass of transportable fiber of a given break is 502.4 lb [(121.60 + 87.72) ft3 x 2.4 lb/ft3], see Table 3.e.6-29.

The original submittal (Reference 3.2) is not affected by this response.

Probabilistic Risk Assessment Licensing Branch B (APLB) Questions APLB-RAl-1 (Audit Question APLB-3 rev 1)

On page E4-38 the submittal states that the risk contribution of primary LOCAs and SSBls are not aggregated because it does not provide a realistic picture of risk. Provide an argument to conclude that the risk of SSBls is significantly smaller than the risk of primary side breaks. The argument could be quantitative and/or qualitative and use information from previous Generic Letter 2004-02 submittals.

NextEra Response:

The evaluation of SSBls was performed in a bounding manner where strainer failure was very conservatively assumed to occur for all SSBls that require ECCS recirculation. In reality, the strainer would not be expected to fail for most SSBls since the ZOI for a secondary side break would be smaller than an equivalent size break on the primary side (resulting in less debris generation). Also, the flow Page 17 of 31 QF-047, Rev. 0

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rate through the strainer for a secondary side break would be much lower (i.e., a relatively low flow rate to support feed and bleed or makeup for a stuck open PORV). This lower flow rate would potentially reduce transport to the strainer and significantly reduce head loss for any debris that accumulates on the strainer.

Since the SSBls were evaluated using a bounding approach (assuming the strainer would fail for all SSBls that require ECCS recirculation), the values are overly conservative. Therefore, it is not meaningful to combine them with the primary LOCA results to estimate an overall risk impact from the effects of debris.

The STP risk-informed GSl-191 pilot project screened secondary side breaks from further consideration based on their very low risk contribution (see ML17038A223). Similarly, the Calvert Cliffs risk-informed GSl-191 submittal concluded that secondary side breaks can be screened out based on very low risk values determined from a bounding analysis (see ML19158A075).

The Vogtle risk-informed GSl-191 submittal provided a more realistic evaluation of secondary side breaks that was consistent with the general methodology used for primary side breaks (i.e., a generally conservative approach rather than a bounding approach). The Vogtle assessment concluded that the 8CDF contribution from secondary side breaks (1.39E-09) is less than an order of magnitude smaller than the contribution of analyzed primary side breaks (2.32E-08) (see ML181938165).

A detailed assessment of secondary side breaks has not been performed for Point Beach. However, as discussed above, there are several reasons why the risk associated with strainer performance for secondary side breaks would be significantly lower than the risk associated with primary side breaks.

A detailed assessment of secondary side breaks for Point Beach would be expected to show results similar to Vogtle. Therefore, the conclusion that the bounding 8CDF and 8LERF values for secondary side breaks do not need to be aggregated with the more realistic 8CDF and 8LERF values for primary side breaks is reasonable and consistent with previous risk-informed GSl-191 submittals where secondary side breaks were screened out based on a bounding assessment (and the results were not aggregated).

The original submittal (Reference 3.2) is not affected by this response.

APLB-RAl-2 (Audit Question APLB-4 rev 1)

Provide a traceable reference of the LOCA break frequencies in Table 3-1 of Enclosure 4.

NextEra Response:

The LOCA break exceedance frequencies in Table 3-1 of Enclosure 4 for break sizes 0.375 in., 2 in and 6 in. were quantified by converting the small, medium, and large LOCA frequencies present in the Point Beach PRA model of record into a "per calendar year basis using 0.934 as a capacity factor.

This capacity factor value bounds the modeled value of both Point Beach units.

The PWR LOCA frequencies present in the Point Beach PRA model of record are sourced from the SPAR Initiating Events 2015 Detailed Data Sheets. This data, including the Bayesian Update from the NUREG-1829 values, is presented in:

https:llnrcoe.inl.gov/publicdocs/AvgPerfllnitiatingEventDataSheets2015.pdf The 31-inch break size exceedance frequency, 7.50E-08 events per calendar year, was taken directly from NUREG-1829, Table 7.19 ("40 years fleet average operation" section) because the exceedance frequency for this size range was not included in the 2015 Parameter Estimation Update.

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The calculation of the LOCA initiating event frequencies on a per calendar year basis is demonstrated below:

Mean Frequency LOCAType Break (per reactor critical year)

Mean Frequency Size from Initiating Events 2015 (per calendar year)

Detailed Data Sheets Large LOCA Bin.and 5.91E-06

_ 1 0.934 rcy

_1 PWR greater1 5.91E-06 rcy x l l

d

= 5.SZE-06 cy ca en aryear Medium LOCA 2 in. to 6 1.50E-04 0.934rcy PWR in.

1.S0E-04 rcy-1 x l l

d

= 1.40E-04 cy-1 ca en aryear Small LOCA 3/8 in. to 4.01E-04 0.934rcy PWR 2 in.

4.0lE-04 rcy-1 x l l

d

= 3.75E-04 cy-1 ca en aryear The calculation of the exceedance frequencies is demonstrated below:

Break Size (in.)

Exceedance Frequency 0.375 XFBreak Size.: 0.375 in. = f 3/4 in.:S Break Size< 2 in. + f2 in.:S Break Size< 6 in. + fBreak Size.: 6 in.

XFBreak size.: o.375 in. = 3.75E-04 cy-1 + 1.40E-04 cy-1 + 5.SZE-06 cy-1 = S.Z0E-04 cy-1 XFBreak Size.: 2 in. = f2 in. :S Break Size< 6 in. + fBreak Size.: 6 in.

2 XFBreak Size.: 2 in. = 1.40E-04 cy-1 + 5.SZE-06 cy-1 = 1.46E-04 cy-1 6

XFBreak Size.: 6 in. = 5.SZE-06 cy-1 31 XFBreak Size.: 31 in. = 7.S0E-08 cy-1 The original submittal (Reference 3.2) is not affected by this response.

Structural, Civil, Geotech Engineering Branch (ESEB) Questions ESEB-RAl-1 (Audit Question ESEB-2)

On page E3-134, the total debris load per module is stated to be 100 lbm per module. The NRC staff takes this to imply that the assumed total strainer debris amount for the structural analysis is 1400 lbm since each strainer train has 14 modules. On page E3-67 and 68 (Tables 3.e.6-28 and 30) the worst debris quantities that don't fail any acceptance criteria are tabulated. It appears that these debris amounts would result in a total debris load of more than 1400 lb.

Clarify if 1400 lbm is the limiting debris load on the strainer. If it is not the limiting debris load, update the 1 Per the SPAR Initiating Events 2015 Detailed Data Sheets, the NUREG-1829 Table 7.19 LOCA frequency associated with break sizes greater than 31 inches was included in the reported large LOCA frequency (typically defined as a break size between 6 inches and 31 inches) due to the frequency being "so small as to be negligible."

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structural analysis to account for the limiting debris load, or explain why it is unnecessary to update the analysis. Update the associated response in item 3.k to address any changes in the structural analysis.

Update any other responses or evaluations that may be impacted by the change in the structural analysis.

NextEra Response:

The structural evaluation of the sump strainers was performed using a combination of manual calculations and finite element analyses. This evaluation used a design weight of debris per strainer module of 100 lbs. This value was obtained by rounding up a debris weight per strainer module of 77 lb, which was estimated as follows:

1. A theoretical mixed debris bed density was determined using the total volume of fibrous debris and the total mass of both fiber and particulate debris.

2.

The total available interstitial volume between strainer disks that is available to collect debris for a single strainer module was determined. The available volume between the top of the strainer module and the water surface was also considered.

3.

The total volume available to collect debris for one strainer module was then multiplied by the mixed debris bed density to arrive at the 77 lb of debris weight for one strainer module.

NextEra is in agreement with the NRC reviewer's observation that the debris loads shown in Tables 3.e.6-28 and 3.e.6-30 exceed the analyzed 1400 lb debris mass in the strainer structural evaluation.

NextEra has reevaluated the strainer using an increased debris load of 3,500 lbm on one strainer, which bounds the maximum transported debris mass for all breaks for Unit 1 (2,972 lbm) and Unit 2 (3,271 lbm). The evaluation reduced the differential pressure of the strainer from 11.5 ft to 7 ft and demonstrated acceptable results. NextEra has revised the risk quantification using the updated strainer differential pressure, and the conclusion of the risk quantification was not impacted. Refer to the Response to NCSG-RAl-1 for the updated risk quantification results.

The total mass of debris transported to a strainer was calculated for each break by summing the masses of various debris types: fiber fines (including latent fiber), mineral wool, Cal-Sil, qualified epoxy and IOZ coating particulate, unqualified IOZ, epoxy, and alkyd coating particulate, the particulate portion of actively delaminating qualified (ADQ) epoxy coating, ADQ epoxy coating chips, dirt/dust and chemical debris.

A qualitative analysis was performed to consider the effect of changing debris weight and strainer differential pressure. The lateral and vertical load distribution were recalculated considering the increased debris weight to estimate its effects on the qualification of the strainer in a qualitative manner.

The hydrodynamic masses were included by adding inertia to various strainer members. The bounding percent increase for the vertical and horizontal hydrodynamic loads (overall debris mass load used in the finite element model) is approximately 18%. The components of the strainer whose interaction ratios would likely get above the unity (i.e., 1.0) due to 18% increase in hydrodynamic loads were reviewed in detail (IR of 0.85 and above). Those components are External Radial Stiffener (including debris stops), Tension rods, Seismic Stiffeners, Perforated Plate (DP Case), Alternate Detail End Cover Assembly Welds, Angle Iron Mounting Tracks, and Expansion Anchors to Floor.

1. The Perforated Plate (DP Case) interaction ratios were recalculated by using the updated values for the pressure acting on the perforated plate on the end disk. The pressure acting on the perforated plate on the end disk is affected by both the increase in debris weight and decrease in the differential pressure drop. The new Interaction Ratios are 0.61 and 0.517 for OBE and SSE respectively. Therefore, the Perforated Plate remains qualified.

2.

Alternate Detail End Cover Assembly Welds interaction ratios are governed by the Weld of 4x3 7/8 Tube Steel to 3x3 Tube Steel interaction ratios. The Weld of 4x3 7 /8 Tube Steel to 3x3 Tube Steel Page 20 of 31 QF-047, Rev. 0

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qualification is not affected by the increase in debris weight. The decrease in differential pressure drop will reduce the interaction ratios and therefore, the Weld of 4x3 7/8 Tube Steel to 3x3 Tube Steel and the Alternate Detail End Cover Assembly Welds remain qualified.

3.

External Radial Stiffener (including debris stops), Tension rods, Seismic Stiffeners, Angle Iron Mounting Tracks and Expansion Anchors to Floor are qualified based on the output from the GTSRUDL analysis. As observed from the qualification calculation of strainer components considering the combined effect of the increased hydrodynamic mass and decreased strainer pressure drop, it was concluded that the forces used in the qualification calculation would not increase. Considering that the hydrodynamic loads are only a fraction of the pressure drop load, the increases in the total hydrodynamic masses and the potential increases in seismic accelerations corresponding to the dominant modes due to the shift in frequencies would not exceed the gains obtained due to 40% reduction in the pressure drop. Therefore, the strainer components remain qualified.

Page E3-92, Response to 3.f.7, "Strainer Structural Margin Limits", of the original submittal (Reference 3.2) is updated to state, "The structural design differential pressure for the PBN strainers is 7.0 ft."

Corrosion and Steam Generator Branch (NCSG) Questions NCSG-RAl-1 (Audit Question NCSG-2 rev 1)

Page E3-171 states that plant specific inputs, including containment spray times, were selected to maximize the generated amount of precipitates. The maximum spray pH (10.5) was used to determine the aluminum release.

(a) Discuss the spray duration used in the aluminum generation NARWHAL calculations relative to the operating procedures for securing containment spray.

(b) Discuss the spray pH as a function of time relative to the 10.5 pH value assumed in the base case calculation.

On February 14, 2023, a teleconference call was held between the NRC staff and NextEra staff as part of a regulatory audit. Items (c) and (d) below, pertain to discussions conducted during this call:

(c) The response to Item (a) states that parametric uncertainty cases were performed with maximum refueling water storage tank (RWST) injection, safety injection (SI), residual heat removal (RHR), and containment spray (CS) pump flow rates for injection from the RWST, with minimum and maximum initial RWST mass. Please evaluate the effects of a CS pump trip relative to the duration of CS injection phase, spray pH, and if there are any additional scenarios or pump configurations affecting precipitate amounts that would change the risk quantification.

(d) The response to Item (b) states that an error to the inputs to the NARWHAL analysis was discovered.

The CS injection phase pH (10.5) was applied up to 23.8 minutes after the start of the accident, when the RHR pumps switch to recirculation. The base case holds the pH constant at 10.5 for 64.1 minutes, until the CS recirculation begins. Please provide the results from a sensitivity case to evaluate the effect of longer periods of higher pH injection to precipitate amounts and to the total risk.

NextEra Response:

The NARWHAL software analysis accounts for spray mode/duration with respect to time. The spray durations are modeled in NARWHAL based on the Emergency Operating Procedures (EOPs). The Containment Spray (CS) pumps are aligned with the Refueling Water Storage Tank (RWST) for CS injection until the RWST water level reaches the low-low level setpoint, and the suction of the CS pumps Page 21 of 31 QF-047, Rev. 0

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are then aligned with the discharge of the Residual Heat Removal (RHR) pumps to start CS recirculation. The CS pumps are secured 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> after the start of CS recirculation. The RWST inventory is delivered to the sump as a function of the pump flow rates during the injection phase.

(a) In the base case models, the duration of the CS injection was calculated using the design Safety Injection (SI), RHR, and CS pump flow rates for injection from the RWST with a minimum initial RWST mass (minimum containment pool volume). During the injection phase, no pump failures were assumed. It was determined that the RHR and CS switchover time from injection to recirculation was 23.8 minutes and 64.1 minutes after start of the accident, respectively. As noted above, CS operates in the recirculation mode for 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. Therefore, CS is terminated 184.1 minutes after start of the accident.

Parametric uncertainty cases were performed with maximum RWST injection SI, RHR, and CS pump flow rates for injection from the RWST with a minimum and maximum initial RWST mass.

The results showed that varying the pool volume inputs had little impact on the risk quantification results.

(b) The maximum containment spray pH during the CS injection phase is 10.5. After CS recirculation begins, the containment spray pH is the same as the containment sump pool pH. Therefore, the CS injection phase spray pH of 10.5 is held constant for 64.1 minutes after the start of the accident for the base case. The spray pH switches to the maximum sump pool pH of 9.5 for the 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> of CS recirculation.

When developing this response, an error in the inputs to the NARWHAL analysis was discovered.

The CS injection phase pH (10.5) was applied up to 23.8 minutes after start of the accident when the RHR pumps switch to recirculation, rather than 64.1 minutes as discussed above. For the base case, this results in a 40.3-minute duration (64.1 minute - 23.8 minute) where the containment sprays are at the lower containment sump pool pH of 9.5 instead of the higher CS injection phase pH of 10.5. NextEra revised the evaluation to correct the error, as seen in the Response to Part (d) of this RAI.

(c) A single pump or single train failure during the injection phase increases the duration of the spray injection, during which the unsubmerged aluminum in the containment could be exposed to the higher spray water pH of 10.5, resulting in higher chemical debris loads. A single train failure has the most impact on the duration of the injection phase. Therefore, a sensitivity run was performed for each unit with the single train failure occurring at the initiation of the accident (vs. at the start of recirculation in the Base Case). The Unit 1 sensitivity case resulted in a acDF of 2.299E-08 yr1 (vs. 2.280E-08 yr1 in the Base Case). The Unit 2 sensitivity case resulted in a acDF of 4.020E-08 yr1 (vs. 3.944E-08 yr1 in the Base Case). Note that these results are based on the NARWHAL models in the revised risk quantification after correcting the error in spray pH, as noted in the Response to Part (d) below.

(d) NextEra revised the risk quantification to correct the error in spray pH and to incorporate the reduced strainer differential pressure (see the Response to ESEB-RAl-1 ). The revision used a conservatively high spray pH profile by applying the maximum spray pH of 10.5 up to 184 minutes after the accident, instead of 64.1 minutes after the accident. With these changes, the revised calculation showed a base case aCDF of 2.280E-08 yr1 (vs. 2.201 E-08 yr1 before correcting the error) for Unit 1, and 3.944E-08 yr1 (vs. 3.673E-08 yr1 before correcting the error) for Unit 2.

The following updates to the submittal (Reference 3.2) associated with the revised risk quantification calculation are identified.

Page E3-173 Page 22 of 31 QF-047, Rev. 0

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Table 3.o.2.3-1: PBN pH Values for NARWHAL Base Case Desian Input pH Injection and Recirculation Spray pH Used to Determine Chemical 10.5 Release Rates Sump pH Used to Determine Chemical Release Rates 9.5 Sump pH Used to Determine Aluminum Solubility 8.25 Page E4-35 For both units, the smallest break that resulted in a failure is a 10-inch partial break due to exceeding the chemical debris limit.

Table 5-1: PBN Unit 1 Base Case CFPs Equipment Lineup SBLOCA MBLOCA LBLOCA All pumps available 1 Containment Spray (CS) pump failure 0

0 2.983E-03 2 CS trains failure Single train failure 1 RHR pump failure 0

0 8.658E-02 1 RHR pump + 2 CS pump failures Page E4-36 Table65-2: PBN Unit 2 Base Case CFPs Equipment Lineup SBLOCA MBLOCA LBLOCA All pumps available 1 CS pump failure 0

0 5.409E-03 2 CS trains failure Single train failure 1 RHR pump failure 0

0 1.320E-01 1 RHR pump + 2 CS pump failures Page E4-36 Table 5-4: PBN Units 1 and 2 Primary Loop LOCAs Risk Quantification Results ACDF (yr1)

ALERF (yr1)

Unit 1 2.280E-08 5.311 E-11 Unit2 3.944E-08 9.189E-11 Page E4-42 Table 6-2: Results of Parametric Uncertainty Evaluation for Unit 1 Case Description 6CDF (yr1) 1 Minimum water volume 7.860E-08 2

Maximum water volume 7.872E-08 Page 23 of 31 QF-047, Rev. 0

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Table 6-3: Results of Parametric Uncertainty Evaluation for Unit 2 Case Description 6CDF (yr-1) 1 Minimum water volume 1.359E-07 2

Maximum water volume 1.371E-07 As shown in the tables above, the parametric uncertainty cases have higher fiCDF values than the base cases (2.280E-08 yr1 for Unit 1 and 3.944E-08 yr1 for Unit 2).

Page E4-44 Table 6-5: Results of Unit 2 Model Uncertainty Quantification Model in Base Case Model Uncertainty Case 6CDF Change in 6CDF from Base Case Continuum Break Model DEGB-Only Model 2.372E-07 1.977E-07 Top-Down Allocation of Top-Down Allocation of NUREG-LOCA Frequencies from 1829 Arithmetic Mean LOCA 5.584E-07 5.190E-07 PBN PRA Model Frequencies LBLOCA Size Range Bias 1 (6-10, 10-15, and 15-31 in) 5.077E-08 1.134E-08 Discretization (6-15, 15-Bias 2 (6-20, 20-27, and 27-31 in) 8.653E-08 4.709E-08 25, and 25-31 inches) 2 minutes 3.949E-08 5.108E-11 3 minutes 3.949E-08 5.108E-11 Time Step Size 4 minutes 3.969E-08 2.554E-10 5 minutes 3.969E-08 2.554E-10 15 minutes 3.673E-08

-2.709E-09 Page 24 of 31 QF-047, Rev. 0

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Model Uncertainty Case Figure 6-1: Comparison of Unit 2 Model Uncertainty Cases to Base Case NCSG-RAl-2 (Audit Question NCSG-3)

Table 3.o.2.3-1 provides the sump and recirculation spray pH (9.5) used to determine aluminum release rates and the sump pH (8.25) used to determine aluminum solubility. Page E3-173 states that the impact by sump pH was shown in two parametric sensitivity cases using a lower pH range (8.25 decreasing to 7) and a higher pH range (10 decreasing to 8.75). These sensitivity cases showed insignificant effect on the risk quantification results.

(a) Describe how the pH is lowered as a function of time to account for acids generated by radiolysis, as applied in the solubility equation. Is the pH adjustment for radiolysis treated the same way for all breaks?

(b) Table 3.o.2.7.ii-2 provides a summary of precipitate quantities and precipitation temperatures from bounding hand calculations. This table shows the precipitation temperatures for the lower pH scenario (8.25 decreasing to 7) are approximately 40-50°F higher than for the NARWHAL base case pH (9.5 decreasing to 8.25). Please discuss why (e.g., sufficient NPSH margin) the higher precipitation temperatures have no significant effect on the risk quantification.

(c) Was Equation 3.o.2.9-1 used for the parametric sensitivity using the higher pH range (10 decreasing to 8.75)? The NRC staff notes that the WCAP-17788-P Volume 5 precipitation boundary function was determined to be more appropriate for determining aluminum solubility at higher pH values. This is Page 25 of 31 QF-047, Rev. 0

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shown in proprietary Figure RAl-5.12-12 in Attachment 1 to L TR-SEE-17-62 dated May 23, 2017 (ML17293A220).

NextEra Response:

(a) The containment sump pool and recirculation spray pH are not lowered as a function of time.

Conservative pH values for release and solubility were combined to bound the net effect of the radiolysis acids. In the base case, the containment sump pool and recirculation spray pH is constant at 9.5 for the entire event for the purpose of determining chemical release rates.

Concurrently, the base case pH is constant at 8.25 for the purpose of determining aluminum solubility. This treatment is used for all breaks. Additionally, the methodology is the same for the parametric sensitivity cases with pH values changed as indicated.

(b) The maximum aluminum precipitation temperatures determined from bounding hand calculations range from 101 °F to 160.2°F. As shown on page E3-118 of the submittal, the RHR pump NPSH margin for both units ranges from 3.61 to 4.83 ft from 242°F to 212°F, but then increases rapidly to ~12 ft at 200°F and ~28 ft at 160°F. Additionally, precipitation is "forced" to occur at 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> following initiation of the accident even if the solubility limit is not exceeded. At 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, the containment sump pool temperature is 152.8°F. Page E3-118 shows NPSH margin at this temperature to be at least 25 ft. Therefore, precipitation will occur at a temperature at which NPSH margin is near its maximum. In terms of the internal NARWHAL calculations, this effectively limits the range of potential precipitation temperatures to a narrow window of 152.8°F to 160.2°F, further diminishing the effect of precipitation temperature variability on risk quantification.

(c) The ANL function, equation 3.o.2.9-1, was used for all cases. As discussed above for the base case, the high pH parametric sensitivity case models the containment sump pool pH of 10 decreasing to 8.75 by using both pH values in a conservative manner. The higher pH of 10 is used for determining chemical release rates, and the lower pH of 8. 75 is used to determine the aluminum solubility. Per page G-48 of WCAP-17788-NP, Vol. 5, Rev. 1, the WCAP solubility function is more conservative at pH values above 9.6 and the ANL solubility function is more conservative at pH values between 7.1 and 8.6. Both functions converge to the same values at a pH of 7. Since the precipitate solubility is evaluated at pH 8. 75, it is conservative to use the ANL function.

The original submittal (Reference 3.2) is not affected by this response.

NCSG-RAl-3 (Audit Question NCSG-4 rev 1)

(a) Describe the aluminum release rate (relative to metallic aluminum) from aluminum-based coatings, including breaks in the reactor compartment.

On February 14, 2023, a teleconference call was held between the NRC staff and NextEra staff as part of a regulatory audit. Item (b) below, pertains to discussions conducted during this call:

(b) The response to Item (a) states that the aluminum coating debris surface area is calculated by NARWHAL for each break using a surface to mass ratio of 120 ft2/lbm (feet squared per pound mass). Provide the results of a sensitivity study for the effects of aluminum coating debris surface area on the risk quantification.

NextEra Response:

(a) The calculated masses of aluminum from aluminum coatings are input into NARWHAL as a generated debris type for the applicable pressurizer breaks and reactor cavity breaks. The Page 26 of 31 QF-047, Rev. 0

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aluminum coatings debris surface area is calculated by NARWHAL for each break using a surface area to mass ratio of 120 ft2/lbm. This ratio was calculated using Point Beach specific aluminum coating mass and surface area inventories. Using the mass and surface area, NARWHAL applies the same release rate methodology used for submerged, mass limited, aluminum metals.

Note that Safety Margin 13 on page E5-15 incorrectly states that the aluminum contained in the failed coatings is instantly released into the sump pool. This assumption was used in the bounding hand calculation but was not used in the NARWHAL risk quantification calculation. Therefore, Safety Margin 13, as written, is not applicable to the design basis analysis.

(b) A sensitivity study was run in NARWHAL and documented in the revised risk quantification. In the sensitivity case, the surface area to mass ratio of 120 ft2/lbm used in the base case was increased by a factor of 10 to 1200 ft2/lbm. The 8CDF increased to 2.288E-08 yr1 (vs. 2.280E-08 yr1 in the base case) for Unit 1. The 8CDF increased to 3.969E-08 yr1 (vs. 3.944E-08 yr1 in the base case) for Unit 2. Therefore, the 8CDF is insensitive to this variable.

Original submittal (Reference 3.2) page E5-15 Safety Margin 13 should not be considered a conservatism credited as safety margin.

Piping and Head Penetrations Branch (NPHP) Questions NPHP-RAl-1 (Audit Question NPHP-1)

The submittal stated that a program plan was developed to manage the risk of Primary Water Stress Corrosion Cracking (PWSCC) degradation in Alloy 600 components and Alloy 82/182 welds. Clarify whether any of the welds/components been mitigated with Alloy 52/152 inlays/onlays. If mitigation used another technique, identify the technique. Provide a list of the components and welds that have been mitigated with 52/152 welds. Provide a list of components that have been manufactured/fabricated with Alloy 600 base material, and piping that is welded with Alloy 82/182 welds. In addition, provide the ASME Examination category of the welds (i.e.,Section XI Examination Category 8-F, etc.).

NextEra Response:

The reactor coolant system piping is constructed of austenitic stainless steel. Piping is A376 Type 316, fittings areA351 CF8M, and nozzles areA182 F316. Welding was performed in accordance with USAS 831.1. ER316L or E316L filler was used for 316L base metal. ER316 or E316 filler was used for 316 base material.

Point Beach procedure NP 7.7.31, Alloy 600 Management Program, describes the overall programmatic requirements that Point Beach Nuclear Plant (PBNP) follows for the development, control, and implementation of an Alloy 600 Management Program for PBNP Units 1 and 2.

Welds/components that have been mitigated with Alloy 52/152 inlays/onlays are summarized in the following table.

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Component Strategy RV Heads Replaced with Alloy 690 materials and alloy 52/152 filler material. Continued monitoring per ASME Code Case N-729 RV Lower BMls Continued monitoring per ASME Code Case N-722 U2 SG Hot and Cold Leg Inlaid with alloy 52/152 during manufacture. Continued nozzle safe-end welds monitoring per N-722 and N-770. Approval of relief request 2-RR-11 allowed for extended inspection frequency due to inlay.

U 1 SG Bowl Drain Alloy 82/182 weld and alloy 600 nozzles replaced with Alloy 690 nozzle and alloy 52 weld.

Alloy 600/82/182 locations are described in attachment C of NP 7.7.31. Inspection of susceptible locations is discussed on page 4 of attachment C.

The original submittal (Reference 3.2) is not affected by this response.

NPHP-RAl-2 (Audit Question NPHP-2)

The submittal states that the RCS leak detection program is capable of early identification of RCS leakage to allow time for appropriate operator action to identify and address RCS leakage. Provide a description of how the leak detection system complies with Regulatory Guide 1.45, Revision 1, "Guidance on Monitoring and Responding to Reactor Coolant System Leakage" (ML073200271 ).

NextEra Response:

Identified and unidentified RCS leakage is determined using Point Beach procedure 01-55, Primary Leak Rate Calculation, which is based upon the following industry guidance developed to meet the recommendations in Regulatory Guide 1.45, Revision 1.

WCAP-16423-NP, Pressurized Water Reactor Owner's Group Standard Process and Methods for Calculating RCS Leak Rate for Pressurized Water Reactors, Revision 0, dated September 2006, and PWROG Letter OG-07-387, Recommendations for Implementation of Guidelines for PWROG RCS Leak Rate Programs with Respect to NEl-03-08 (PA-OSC-0189 and PA-OSC-0218),

dated August 27, 2007.

Point Beach procedure Ol-55 is used to quantify leakage rate as follows:

Total leakage rate is determined based on average reactor coolant system (RCS) temperature (Tav9), pressurizer level, volume control tank (VCT) level, make-up volume and divert volume.

Identified leakage rate is determined using pressure relief tank (PRT) level, reactor coolant drain tank (RCDT) level, steam generator tube leakage and other known and documented RCS leakage.

Non-pressure boundary leakage is determined by summing charging pump seal leakage and other known non-pressure boundary leakage.

Unidentified leakage is then the total leakage rate less identified and non-pressure boundary leakage.

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Accuracy is improved by ensuring that level indications are taken at least 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> apart, and by maintaining steady RCS conditions.

In addition to quantifying RCS leakage, PBN has several other ways of detecting leakage. Radiation monitors inside containment include:

1(2)-RE-102 Containment Low Range Area monitors 10-1mR/hr 1(2)-RE-107 Seal Table Area monitors 10-1mR/hr 1(2)-RE-126, 1/2-RE-127, 1/2-RE-128, Containment High Range Area monitors 1 R/hr 1 (2)-RE-211 Containment Air Particulate Monitor 1(2)-RE-212 Containment Noble Gas Monitor The beta scintillation detectors used to detect activity in both the particulate and noble gas sampler assembly chambers are identical. These detectors are lead shielded to mitigate detection of area gamma radiation. The particulate monitor is capable of detecting particulate activity in concentrations as low as 10-s µCi/cc, with a range of 1 o-s to 10-3 µCi/cc. The noble gas monitor will sense gaseous activity in the range of 1 Q-7 to 10-1 µCi/cc.

The humidity detection instrumentation offers another means of detection of leakage into the containment. Although this instrumentation has not nearly the sensitivity of the air particulate monitor, it has the characteristics of being sensitive to vapor originating from all sources within the containment, including the reactor coolant, main steam, and feedwater systems. Plots of containment air dewpoint variations above a baseline maximum established by the cooling water temperature to the air coolers should be sensitive to incremental leakage equivalent to 2 to 10 gpm. The sensitivity of this method depends on cooling water temperature, containment air temperature variation, and containment air recirculation rate.

Containment sump A collects condensation from the containment cooling coils. Should a leak occur, the condensation rate will increase above the previous steady state due to the increased vapor content of the fan cooler air intake. The time required for the new equilibrium rate to be reached varies with the initial containment conditions, service water temperature and the conditions of the reactor coolant at the leak location. The condensate measuring system meets the leak before break performance requirement of detecting RCS leakage of 1 gpm in 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. Readout of the condensate measuring device level channel is provided in the control room. A high level alarm is provided to alert the operator to significant increases in the condensate flow rate.

The Component Cooling Liquid Monitor continuously monitors the component cooling system for activity indicative of a leak of reactor coolant from either the reactor coolant system or the recirculation or residual heat removal system. A high activity alarm would be annunciated at the unit Auxiliary Safety Instrumentation Panel (ASIP) as well as the radiation monitoring system control terminals. The range of th is monitor is 1 Q-5 to 1 o0 µCi/cc.

The Condenser Air Ejector Gas Monitor samples the discharge from the air ejector exhaust header of the condensers for gaseous radiation which is indicative of a primary-to-secondary system leak. The detector output is transmitted to the radiation monitoring system control terminal in the control room.

High activity alarm indications are displayed on the ASIP annunciator in addition to the radiation monitoring system control terminals. The range of this monitor is 10-7 to 10-2 µCi/cc.

The Steam Generator Liquid Sample Line Monitor observes the liquid phase of the secondary side of the steam generator for radiation. Secondary side radiation indicates a primary-to-secondary system Page 29 of 31 QF-047, Rev. 0

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leak and provides backup information to that of the condenser air ejector gas monitor. Samples from the bottom blowdown lines of each of the two steam generators are mixed to a common header and the common sample is continuously monitored by a scintillation counter and holdup tank assembly.

Upon indication of a high radiation level, each steam generator is manually sampled in order to determine the source. This sampling sequence is achieved by manually selecting the desired unit to be monitored and allotting sufficient time for sample equilibrium to be established (approximately 1 min.).

A high radiation alarm is located near the detector. The range of this monitor is 10-7 to 10-2 µCi/cc.

The containment fan cooler service water monitor checks the containment fan service water discharge lines for radiation indicative of a leak from the containment atmosphere into the service water. Upon indication of a high radiation level, each heat exchanger is individually sampled to determine which unit is leaking. This sampling sequence is achieved by manually selecting the desired unit to be monitored and allotting sufficient time for sample equilibrium to be established (approximately 1 minute). The range of this monitor is 1 o-7 to 10-2 µCi/cc.

The original submittal (Reference 3.2) is not affected by this response.

NPHP-RAl-3 (Audit Question NPHP-3)

The LAR states that the ISi program plan addresses examination and tests required by ASME Section XI and licensee augmented ISi commitments. Identify other inspections (i.e., walkdowns etc.) that are performed outside of the requirements of Section XI.

NextEra Response:

In addition to the ASME section XI required inspections, station staff perform containment closure walkdowns and inspections (CL-20 series), system engineer walkdowns, and periodic containment entries at power. The service water inspection program (NP 7.7.22) performs additional internal inspections of service water piping that is opened for repair or maintenance. Identified and unidentified RCS leakage is also monitored on a daily basis (01-55).

The original submittal (Reference 3.2) is not affected by this response.

NPHP-RAl-4 (Audit Question NPHP-4)

The LAR states that a program plan was developed to manage the risk of PWSCC degradation in Alloy 600 components and Alloy 82/182 welds. The submittal further states that the plan is in accordance with ASME Code Cases N-722-2 and N-770-2 and identifies all Alloy 600/82/182 locations and ranks the locations based on their risks of developing PWSCC. Additionally, the plan provides inspection requirements, and presents mitigation/replacement options. Provide the program plan for NRC review.

NextEra Response:

Point Beach procedure NP 7.7.31, Alloy 600 Management Program describes the overall programmatic requirements that Point Beach will follow for the development, control, and implementation of an Alloy 600 Management Program for Point Beach Units 1 and 2.

The original submittal (Reference 3.2) is not affected by this response.

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7.0 Computer Software No software was used for this report.

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Point Beach Nuclear Plant, Units 1 and 2 L-2023-075 Docket Nos. 50-266 and 50-301 Enclosure Point Beach Nuclear Plant Procedure, NP 7.7.22, Revision 9 Service Water and Fire Protection Program (21 pages follow)

NP 7.7.22 SERVICE WATER AND FIRE PROTECTION INSPECTION PROGRAM DOCUMENT TYPE: Administrative REVISION: 9 APPROVAL AUTHORITY: Department Manager PROCEDURE OWNER (title): Group Head OWNER GROUP: System Engineering

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL SERVICE WATER AND FIRE PROTECTION INSPECTION PROGRAM NP 7.7.22 Revision 9 Page 2 of 21 INFORMATION USE TABLE OF CONTENTS SECTION TITLE PAGE 1.0 PURPOSE.......................................................................................................................3 2.0 DISCUSSION.................................................................................................................3 3.0 RESPONSIBILITIES.....................................................................................................4 4.0 PROCEDURE.................................................................................................................7 4.1 Method of Examinations.................................................................................................7 4.2 Radiographic Inspection.................................................................................................7 4.3 Ultrasonic Testing...........................................................................................................9 4.4 Guided Wave Ultrasonic Inspection...............................................................................9 4.5 Visual Inspection9 4.6 Selection of Examination Locations...............................................................................9 4.7 Frequency of Examinations...........................................................................................12 4.8 Pipe Blockage Acceptance Criteria and Corrective Actions........................................12 4.9 Pipe Wall Thinning Acceptance Criteria and Corrective Actions.................................13 4.10 Degraded Component Characterization and System Failure Analysis..........................17 4.11 Augmented Inspection...................................................................................................17 4.12 Inspection Report Documentation.................................................................................18 4.13 Annual Report................................................................................................................19 4.14 Database.........................................................................................................................19

5.0 REFERENCES

..............................................................................................................20 6.0 BASES...........................................................................................................................21

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL SERVICE WATER AND FIRE PROTECTION INSPECTION PROGRAM NP 7.7.22 Revision 9 Page 3 of 21 INFORMATION USE 1.0 PURPOSE The Service Water and Fire Protection Inspection Program defines the examinations to be performed on safety-related and non-safety related piping within the Service Water (SW) and Fire Protection (FP) Systems. The primary purpose of this program is to perform periodic examinations to detect pipe wall thinning and internal blockage from silting and corrosion products. These results are then evaluated and Corrective Actions initiated to maintain reliability and operability of components and systems served by the SW and FP systems.

This procedure is credited as one of the implementing documents to meet PBNPs commitment to Generic Letter 89-13, "Service Water System Problems Affecting Safety-Related Equipment, Action Item III, which requires establishing a routine inspection and maintenance program for open-cycle SW system piping and components such that corrosion, erosion, protective coating failure, silting, and bio-fouling cannot degrade the performance of the safety-related systems supplied by SW. This procedure aids in verification that the SW system will perform its design basis heat removal requirements, ensuring that sufficient water flow is maintained. Additional examinations of SW system piping outside the scope of GL 89-13 may also be performed in an effort to minimize component failures. (B-5)

This procedure is one of the implementing documents used to meet a commitment to the NRC to manage the effects of aging for SCCs within the scope of License Renewal (LR) as described in NP 7.7.25, PBNP Renewed License Program. This procedure is credited as an implementing document in the Open Cycle Cooling (Service) Water System Surveillance Program and the Fire Protection Program Basis Documents for license renewal. (B-1, B-2, B-3, B-4) 2.0 DISCUSSION 2.1 This procedure implements the Service Water In-Service Inspection Program (SWP).

The SWP should be referenced for supplemental and historical information related to this implementing procedure.

2.2 Safety-Related SW system piping essential to the safe operation of the plant is examined.

Inspections of the Safety Related SW piping is required in order to meet NRC Generic Letter 89-13 commitments (B-5). Fire Protection (FP) System piping does not require inspection to meet the GL 89 13 Program Document (B-5). It can be noted that the safety related SW piping includes supply piping to the fire hose reels in containment and the sprinklers in the G01 and G02 EDG rooms.

2.3 Although not required by GL 89-13, Non-Safety Related SW piping important to power generation may also be examined to ensure reliable plant operation. Equipment and components such as heat exchangers, pumps and valves are inspected and tested under other programs.

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL SERVICE WATER AND FIRE PROTECTION INSPECTION PROGRAM NP 7.7.22 Revision 9 Page 4 of 21 INFORMATION USE 2.4 Inspection of FP system piping is required in order to meet commitments to the NRC to manage the effects of aging for SCCs within the scope of License Renewal (B-2, B-3).

LR-AMP-010-FP, Fire Protection Program Basis Document for License Renewal, states that Procedure NP 7.7.22, Service Water and Fire Protection Inspection Program is used to inspect a representative sample of fire protection system pipe segments for loss of material (wall thinning).

2.5 Portions of the SW system piping are ASME Section XI Class 3 as defined by the ISI Classification Boundary Drawings (CBDs). The SWP inspections are required to fulfill GL 89-13 Program and License Renewal Aging Management Commitments. The SWP inspections are not code required inspections and are not intended to fulfill ASME Section XI inspection requirements. ASME Section XI required inspections are controlled by other programs and procedures.

3.0 RESPONSIBILITIES 3.1 Site System Engineering Manager 3.1.1 The System Engineering Manager has the overall responsibility of ensuring this procedure is implemented. This includes ensuring adequate personnel and budgetary resources are allocated in order to effectively implement the procedure.

3.1.2 The site System Engineering Manager will share information of significant Operating Experience (OE) to all Program Owners.

3.2 Site Maintenance Programs Manager The Site Maintenance Program manager is responsible for ensuring adequate personnel and resources are available to perform NDE inspections related to the SWP.

3.3 Service Water (SW) System Engineer 3.3.1 The SW System Engineer is responsible for the administration and maintaining the SWP. Program maintenance includes updates to procedures, inspection drawings/sketches and supporting documents as necessary.

3.3.2 Identify piping components to be included in each years SWP inspection scope and ensure that the inspection work orders containing specific examination locations are generated and scheduled each calendar year.

a. Work order packages shall, at a minimum, contain the following information:

1.

Location map(s)

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL SERVICE WATER AND FIRE PROTECTION INSPECTION PROGRAM NP 7.7.22 Revision 9 Page 5 of 21 INFORMATION USE

2.

Inspection location photographs

3.

System Drawings

4.

Completed form NDE 1.0 documenting requested inspection parameters.

3.3.3 Accompany NDE personnel on system walkdowns as needed.

3.3.4 Provide the inspection scope to Design Engineering personnel so Code required minimum wall calculations can be completed in advance of the actual inspection work week(s).

3.3.5 Provide input on the operational risk of identifying pipe wall thinning below minimum required wall thickness to the station and assist in high risk challenge board discussions and contingency planning as necessary.

3.3.6 Review or coordinate review of the results of each inspection.

3.3.7 Initiate Action Requests (ARs) and Work Requests (W/Rs) to evaluate, repair or replace degraded components as necessary. Note that repairs of ASME Section XI Class 3 components in the SW system shall be performed in accordance with the ASME Section XI Repair and Replacement Program.

3.3.8 Determine priorities of work orders (WOs) initiated due to the SW and FP inspections by color coding the WOs under WO disposition in the System Health Report ER Dashboard application.

3.3.9 Perform Maintenance Rule and Causal Evaluations when required due to ARs generated due to SW and FP inspection findings.

3.3.10 Issues annual reports documenting the past years examination WO numbers, examination locations, examination results, Action Requests (ARs) and Work Requests (W/Rs) initiated, corrective actions completed and other noteworthy information related to the SW ISI program such as focus areas for future inspections.

3.4 NDE Personnel 3.4.1 NDE Level III

a. Assist SW System Engineer in determining correct NDE method to use in specific inspection locations as requested.

b. Ensure approved procedures and forms exist to facilitate performance and documentation of inspections in support of the SWP.

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL SERVICE WATER AND FIRE PROTECTION INSPECTION PROGRAM NP 7.7.22 Revision 9 Page 6 of 21 INFORMATION USE

c. Ensure NDE certifications of personnel performing SWP inspections meet the requirements of NDE-3, Written Practice for Qualification and Certification of NDE Personnel.

3.4.2 Site Maintenance Programs

a. Walkdown inspection locations with the SW System Engineer, as necessary, to ensure desired inspection scope can be completed.

b. Utilizing qualified personnel, complete NDE inspections at the locations described in the WO using applicable approved NDE procedures and forms.

c. Document inspection results on the applicable NDE forms and review results with SW System Engineer as necessary.

3.5 Design Engineering 3.5.1 Perform Code required minimum wall thickness calculations (or owners acceptance reviews of calculations completed by contractors) for planned inspection locations. These calculations should be prepared in advance of the work week with milestone completion dates for engineering products as defined in WM-AA-203, Online Scheduling Process.

3.5.2 Prepare operability evaluations as necessary in support of identified wall thinning or through wall leakage. Utilize ASME Code Cases N-597-2, Requirements for Analytical Evaluation of Pipe Wall thinning and N-513-2, Evaluation Criteria for Temporary Acceptance of Flaws in Moderate Energy Class 2 or 3 Section XI Piping, when applicable.

3.5.3 Perform flow analysis to evaluate inspection findings on pipe blockage when requested.

3.6 All Involved Personnel At any time if a non-conforming condition or a condition Adverse to Quality (CAQ) is identified, then a CAP Action Request must be initiated per PI-AA-104-1000, Corrective Action. Non-conforming conditions are, as a minimum, those conditions where the acceptance criteria are not met.

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL SERVICE WATER AND FIRE PROTECTION INSPECTION PROGRAM NP 7.7.22 Revision 9 Page 7 of 21 INFORMATION USE 4.0 PROCEDURE 4.1 Method of Examinations 4.1.1 The SWP uses Non Destructive Examination (NDE) methods to inspect for system degradation due to corrosion, erosion, cavitation, and flow blockage.

Tangential Radiography (RT) and Ultrasonic Thickness (UT) scanning are the most frequently used NDE techniques incorporated in the SWP. Other NDE methods such as visual (VT) and Guided Wave Ultrasonics (GWUT) may be used when appropriate.

4.1.2 RT has typically been used as the primary method for initial inspection over other NDE techniques for a variety of reasons. These include the ability to inspect insulated piping for internal and external wall thinning along with being able to view internal blockage due to corrosion product buildup and/or silting. A shortcoming of RT is that only the tangential pipe walls can be used for estimating wall thinning.

4.1.3 In order to obtain more detailed wall thickness information to assess the health of a piping section, or when substantial wall thinning is identified by RT or is otherwise suspected, UT scanning is typically utilized.

4.2 Radiographic Inspection 4.2.1 Utilizing this technique, a scale representation of the pipe cross section is captured on a radiographic film or phosphor plate if a digital radiograph system is being used. The radiograph is then examined for wall thinning, corrosion product nodules, and sediment. The radiograph and subsequent evaluation are completed and documented in accordance with the applicable approved NDE procedure.

4.2.2 The radiographic image is evaluated as follows:

a. Wall thinning is examined. The thinnest section (normally at the deepest pit) is located and measured. This value is then used as the minimum measured wall thickness to compare to acceptance criteria.

b. The amount of blockage due to corrosion product nodules and sediment is reviewed if any is present. The total cross sectional blockage is estimated by close objective examination of the radiograph. The amount of hard blockage (due to corrosion product nodules) and soft blockage due to silt/sediment is ascertained.

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c. Additional dimensional information on any identified nodules and sediment may be obtained. This information can be entered into the For Information Only Access Database described in Appendix B of the SWP in order to obtain automatically calculated conservative blockage percentages. Information that is entered into the Access database includes the following:

Nodule diameter (assumed circular)

Height of the largest nodule (measured perpendicular to the pipe cross section from the original inside wall)

Circumferential nodule count (the number of nodules within a band, projected perpendicular to the diameter of the largest nodule)

Sediment height (measured perpendicular to the pipe cross section at the point of greatest sediment. The sediment depth is measured from the lower original inside wall.)

Dimensioned Sketch of a Radiograph

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL SERVICE WATER AND FIRE PROTECTION INSPECTION PROGRAM NP 7.7.22 Revision 9 Page 9 of 21 INFORMATION USE 4.3 Ultrasonic Testing 4.3.1 Ultrasonic Testing (UT) can provide wall thickness measurements of the entire pipe section if desired. UT inspection requires insulation removal and moderate pipe cleaning. UT inspections are to be performed per approved NDE procedures.

4.3.2 UT scanning can provide very detailed wall thickness readings, however in the case of MIC pitting standard UT probe measurements may not always identify the deepest pit due to pitting geometry and non-parallel surfaces.

More sophisticated dual phased array UT scanning equipment may need to be used if higher accuracy is warranted.

4.3.3 UT scanning may also be used for the determination of sediment levels in piping. Sediment depth is measured perpendicular to the pipe cross section at the point of greatest sediment. The sediment depth is measured from the lower original inside wall. Cross sectional pipe blockage due to sediment may be modeled as described in Appendix B of the SWP.

4.4 Guided Wave Ultrasonic Inspection (GWUT)

Guided Waves are ultrasonic waves guided by the confines of a structure, such as the inner and outer wall of piping. GWUT can travel significant distances within components and can examine large volumes quickly. GW technology is extremely complex and therefore will only be used as a screening technology. Additional UT inspections of defects for quantitative pipe thickness measurements will be completed based on the combined recommendation of vendor and site personnel interpretation of data.

4.5 Visual Inspection Visual inspections can be completed when access to the internal piping is available and on the external pipe surface if insulation is removed (or not normally present). Pitting depths can be examined visually and measured by the use of a depth (pit) gage. If corrosion is present, moderate cleaning to remove the corrosion is required.

4.6 Selection of Examination Locations 4.6.1 The SW System Engineer selects examination locations based upon the following criteria and with input from the SW and FP system engineers.

a. Previously inspected areas attaining 50% (or greater) wall loss shall be re-inspected on an as needed basis based on estimates of remaining service life to reach code required minimum wall thickness. Determination of the inspection frequency should be documented in the AR initiated for the condition.

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL SERVICE WATER AND FIRE PROTECTION INSPECTION PROGRAM NP 7.7.22 Revision 9 Page 10 of 21 INFORMATION USE

b. Previously inspected areas in which remaining wall thickness is >50% but less than 87.5% are to have follow up inspections as determined necessary in any associated AR or as considered necessary by the SW System Engineer.

c. Areas attaining 50% (or greater) cross sectional blockage due to corrosion nodules (i.e. non-flushable blockage) that are not in a dead leg piping section shall be re-inspected on an as needed basis (or with refueling outage frequency if more appropriate) until repaired, replaced or evaluated to be acceptable as-is. Determination of the inspection frequency should be documented in the AR initiated for the condition.

d. Re-inspection of piping with blockage <50% is scheduled as determined necessary in any associated AR or as considered necessary by the SW FP System Engineer.

e. Areas in which there are operational concerns due to suspected flow blockage (that cannot be flushed away) shall be inspected at the next reasonable opportunity.

f. Additional first time or repetitive inspections shall be chosen based on SW System Engineering input. These inspection locations are selected with emphasis on selecting locations in the most important (i.e. highest risk) piping sections of the system at the following problem areas:

Microbiologically Influenced Corrosion (MIC) and Nodule Buildup Examples:

(a)

Stagnant lines (b) Intermittent flow lines where nutrients are periodically introduced.

(c)

Low flow lines.

Sedimentation Examples:

(a)

Horizontal low flow lines.

(b)

Stagnant dead legs off main flow stream.

(c)

Bypass lines, alternate and cross-connecting lines.

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL SERVICE WATER AND FIRE PROTECTION INSPECTION PROGRAM NP 7.7.22 Revision 9 Page 11 of 21 INFORMATION USE Cavitation/Erosion Damage Examples:

(a)

Downstream of throttle valves and orifices (valve body and downstream piping)

(b)

Areas where there is a significant differential pressure (c)

Areas of high velocity (d)

Steam Generator (SG) Blowdown to SW return header Exterior Corrosion Examples:

(a)

Underneath insulation where water collects (b)

Low points where external moisture is evident from valve packing, condensation, etc.

4.6.2 Examined Areas of Pipe Sections

a. The SW System Engineer, with input from the NDE group, will indicate the desired orientation of the RT shot or desired grid for UT scanning for each inspection location.

b. When horizontal piping is being examined it is best practice to capture the bottom wall in the RT and in the UT scanning grid. This is due to possible debris settlement which can lead to under-deposit corrosion and MIC pitting.

c. If the initial UT scanning grid will not encompass the entire circumference of the piping, which is sometime done on large piping to reduce scanning time, multiple rows of grid should be applied at the bottom of the piping to best ascertain overall condition. For example, on 12 in. and larger piping three rows of 2 in. square grids could be applied at the bottom of the pipe while only one row of 2 in. square grids would be applied at the top and sides of the pipe.

d. If the initial RT or UT scan identifies concerns, then additional inspection of the pipe may be performed as needed in order to evaluate the piping and determine corrective actions.

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL SERVICE WATER AND FIRE PROTECTION INSPECTION PROGRAM NP 7.7.22 Revision 9 Page 12 of 21 INFORMATION USE 4.7 Frequency of Examinations 4.7.1 SW and FP piping inspection packages are to be generated and completed annually. A Work Order (WO) Preventive Maintenance (PM) callup (PMRQ 60765-01) titled SW Radiography and UT exists and is scheduled using frequency code 1YH, which allows 6 months of grace period on either side of its due date. Therefore, the PMs targeted due date remains the same every year instead of basing it on the Work Order closeout date. It is the responsibility of the SW System Engineer to ensure that work orders re generated by NDE and performed each calendar year.

4.7.2 Selection criteria of Section 4.6 shall be used along with engineering judgment for the selection of examination locations and NDE technique.

4.7.3 Repeated or augmented examinations shall be performed based on previous inspection findings, Corrective Actions taken and the criteria of Section 4.11.

4.7.4 Plant operating conditions and system/component availability dictate the actual schedule for each inspection in order to minimize overall plant risk.

Work week challenge boards and plant safety monitor input are typically used when determining the inspection schedule. As an example, if the pipe section to be examined would require a Unit outage to repair or replace, the inspection could be scheduled just prior to or during the Unit outage.

4.8 Pipe Blockage Acceptance Criteria and Corrective Actions 4.8.1 Piping with < 10% blockage is accepted as-is.

4.8.2 Piping with blockage >10% but < 50% is reviewed to determine if there will be sufficient flow (or open area in the case of instrument sensing lines) to critical components. This review can be documented on the NDE inspection form by the engineering reviewer with consultation with the system engineer and design engineering flow analysis personnel if needed. If flow instrumentation is available and/or periodic testing is performed the flows and/or test results can be used in the evaluation. If there are concerns that the blockage may impact system function, an Action Request (AR) shall be initiated to determine Corrective Actions. Re-inspection will occur as described in Section 4.6.

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL SERVICE WATER AND FIRE PROTECTION INSPECTION PROGRAM NP 7.7.22 Revision 9 Page 13 of 21 INFORMATION USE 4.8.3 An Action Request (AR) shall be initiated for piping sections found with

>50% blockage. The AR shall include impacts on critical components with input from the system engineer and design engineering flow analysis personnel as needed. If flow instrumentation is available and/or periodic testing is performed the flows and/or test results should be reviewed and incorporated into the AR description to define the significance of the condition. If the blockage is due to silt/sedimentation, flushing should be considered. If the blockage is due to corrosion nodules (i.e. non-flushable blockage), mechanical cleaning or replacement of the piping sections would be required to resolve the condition. Re-inspection will occur as described in Section 4.6.

4.8.4 Note that the For Information Access Database described in Appendix B of the Service Water In-Service Inspection Program (SWP) automatically calculates blockage. Calculated blockage assumes all nodules are as large as the largest nodule, which may lead to overly conservative unrealistic results.

This calculated value can be used as a conservative informational value.

However, actual blockage may be more accurately estimated by reviewing the radiograph and making an objective estimate of actual blockage. For areas in which significant blockage appears to exist, further review by the system engineer should be obtained. The function of the line and impacts on required design flows need to be considered in assessing the significance of the findings. An Action request (AR) must be initiated if appropriate.

4.9 Pipe Wall Thinning Acceptance Criteria and Corrective Actions 4.9.1 Process of evaluating pipe wall thinning and the acceptance criteria for varying degrees of wall degradation.

a. When measured wall thickness (Twall) > 0.875 nominal wall thickness (Tnom), the pipe is accepted as-is. This is based on manufacturing tolerances for piping allowing an under tolerance of 12.5% of nominal wall thickness as stated in EPRI NP-5911M, Acceptance Criteria for Structural Evaluation of Erosion-Corrosion Thinning in Carbon Steel Piping. Re-inspection is not required unless there are specific concerns related to this inspection location.

b. When measured wall thickness (Twall) is less than 87.5% Tnom, an Action Request (AR) shall be initiated. The measured wall thickness must then be compared to the construction code required minimum wall thickness (Tmin) as calculated in Section 4.9.2 Re-inspection of piping with wall thickness < 87.5% is performed in accordance with Section 4.6.

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL SERVICE WATER AND FIRE PROTECTION INSPECTION PROGRAM NP 7.7.22 Revision 9 Page 14 of 21 INFORMATION USE

c. If the measured wall thickness (Twall) is less than the construction code required minimum wall thickness (Tmin) or when the predicted pipe wall thickness (based on wear rate determined in Section 4.9.3 following the next operating cycle is less than Tmin or when a through wall flaw exists, an Operability Determination or Functionality Assessment per EN-AA-203-1001 is required if the piping will remain in service. It may be possible to support continued service of the subject piping section by calculating the local allowable wall thickness Taloc or by completing piping stress analysis for a through wall flaw as described in Section 4.9.2.

d. If a through-wall flaw exists on an ASME Section XI portion of the SW system, a Code repair is required. If a Code repair is not immediately practical, a temporary Non-Code repair may be performed but requires Nuclear Regulatory Commission (NRC) approval. A temporary Non-Code repair is performed utilizing the guidance and requirements in:

1.

NRC Generic Letter 90-05, Guidance for Performing Temporary Non-Code Repair of ASME Code Class 1, 2, and 3 Piping.

2.

ASME Code Case N-513, Evaluation Criteria for Temporary Acceptance of Flaws in Moderate Energy Class 2 or Piping Section XI, Division 1.

3.

NRC Regulatory Guide RG 1.147, Inservice Inspection Code Case Acceptability, ASME Section XI, Division 1 shall be referenced for the latest approved revision of ASME Code Case N-513 and any conditions placed upon the code case.

4.

NEI White Paper, Treatment of Operational Leakage from ASME Class 2 and 3 components Rev 1, October 2006.

5.

NP 7.2.5, Repair/Replacement Program

6.

EN-AA-203-1001, Operability Determinations & Functionality Assessments

7.

EN-AA-205-1102, Temporary Configuration Changes

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL SERVICE WATER AND FIRE PROTECTION INSPECTION PROGRAM NP 7.7.22 Revision 9 Page 15 of 21 INFORMATION USE 4.9.2 Calculation of Minimum Allowed Wall Thickness

a. The construction code (e.g. B31.1) required minimum allowed wall thickness (Tmin) is calculated conservatively assuming that the entire piping cross section is thinned to the Tmin value. Minimum required wall thickness is calculated for both hoop stress and bending stress to determine the governing stress. Tmin is then the larger value of the calculated minimum required wall thicknesses.

b. In the event the measured minimum wall thickness Twall is below the construction code require minimum allowed wall thickness Tmin, a local allowable wall thickness Taloc can be calculated to support continued service under an Operability Determination or Functionality Assessment per EN-AA-203-1001. For ASME Section XI piping, Taloc is calculated in accordance with ASME Code Case N-597-2, Requirements for Analytical Evaluation of Pipe Wall Thinning, or other NRC approved code cases.

c. In order to support an Operability Determination for ASME Section XI piping when a through wall flaw exists, piping stress analysis can be completed using ASME Code Case N-513, Evaluation Criteria for Temporary Acceptance of Flaws in Moderate Energy Class 2 or Piping Section XI, Division 1. Use of Regulatory Guide RG 1.147, Inservice Inspection Code Case Acceptability, ASME Section XI, Division 1 shall be referenced for the latest approved revision of ASME Code Case N-513 and any conditions placed upon the code case.

4.9.3 Wall Thinning Rate Calculation

a. Wall thinning rates can be calculated as described in 4.9.3.b below, however these calculated linear rates must be used with caution. The plant has been in operation for >40 years and the wall thinning rates of raw water piping have been found to vary widely throughout the system. Wall thinning rates depend on the piping configuration, operating conditions and chemical treatment regimen. For example, a section of the 24 inch.

South SW header was inspected after >40 years of service and wall thickness measurements were all found within a 10% band of nominal wall showing that little to no wall thinning has occurred. In contrast other sections of piping exposed to MIC pitting attack or cavitation erosion for example developed through wall leaks and required replacement after < 20 years of service. The highest wall thinning rates have occurred in the piping areas described as problem areas in Section 4.6.1.f.

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL SERVICE WATER AND FIRE PROTECTION INSPECTION PROGRAM NP 7.7.22 Revision 9 Page 16 of 21 INFORMATION USE NOTE:

Linear wear rates should be used with caution as described in Section 4.9.3.a.

b. Wear rates can be calculated assuming a linear rate as described below.

Formulation for Wear Rate:

Wear Rate = (Tinitial-Twall) / (Service Life)

Where:

- Tinitial is the nominal pipe wall thickness or the pipe wall thickness at initial examination, as applicable.

- Twall is the current measured minimum wall thickness.

-Service Life is the years of operation since original installation or since initial examination, as applicable.

4.9.4 Life-Cycle Management NOTE:

Linear wear rates should be used with caution as described in Section 4.9.3.a.

a. The remaining service life estimates the years until the wall thinning violates the minimum allowed wall or other operational criteria established by the program. It also provides predictive tools to aid in managing the SWS/FPS until the end of licensing life. This calculation assumes the linear wear rate defined in Section 4.9.3.

Formulation for remaining Service Life:

Remaining Service Life = (Twall - Design) / Wear Rate Where:

Twall is the current measured minimum wall thickness.

Design is the minimum allowed wall defined under Section 4.9.2.

Wear Rate is calculated as stated in Section 4.9.3.

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL SERVICE WATER AND FIRE PROTECTION INSPECTION PROGRAM NP 7.7.22 Revision 9 Page 17 of 21 INFORMATION USE 4.10 Degraded Component Characterization and System Failure Analysis NOTE:

When characterizing pipe wall thinning for use in operability determinations, refer to EN-AA-203-1001, Operability Determinations &

Functionality Assessments. The use of Code Case N-513 applies to accepting flaws, including through-wall flaws, in moderate energy Class 2 or 3 piping. Refer to NRC RG 1.147 for the latest revision acceptable to the NRC and any conditions placed upon the code case.

4.10.1 The extent of pipe wall degradation shall be characterized by volumetric NDE for subsequent flaw evaluation. Flaw geometry shall be adequately bounded by utilization of UT and/or RT techniques to account for examination uncertainties and limitations. Examination techniques should be able to determine remaining wall thickness, wall loss, flaw dimensions and orientation, and have adequate sensitivity to establish whether the flaw is approaching a through-wall condition.

4.10.2 An analysis of the degradation shall be performed to determine the most probable failure mechanism, i.e. MIC, erosion, etc. The results of the evaluation shall be reviewed to determine whether other pipe sections or systems are at potential risk. Thinning can result in loss of structural integrity and failure of the piping, while blockage reduces water flow, thereby affecting heat removal capacity from essential systems and components. Both failure mechanisms have a significant effect on plant operation. Knowing the failure mechanisms can aid in determining which actions should be taken to preclude failure and its consequences on system operability and reliability. Note that the identification of the failure mechanisms and determination of follow-up actions would typically be determined by a CAP action such as an ACE or CE.

4.11 Augmented Inspection 4.11.1 Where pipe wall thinning reaches 50% (or greater) or cross sectional blockage reaches 50% (or greater) due to corrosion nodules (i.e. non-flushable blockage) that are not in a dead leg piping section, augmented volumetric inspection or further testing should be performed to confirm the extent of the overall degradation of the affected system.

4.11.2 If pipe wall thinning of 50% or greater or non-flushable blockage of 50% or greater is found in the augmented inspection sample, additional inspection of the same sample size should be performed. This process should be repeated until no additional flaw is detected to ascertain the extent of the degradation mechanism.

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL SERVICE WATER AND FIRE PROTECTION INSPECTION PROGRAM NP 7.7.22 Revision 9 Page 18 of 21 INFORMATION USE 4.11.3 If a failure occurs (e.g. through wall leak or blockage impacting operability) the failure mechanisms shall be identified and used to determine the most susceptible system locations for additional inspections, including consideration to the other unit systems. Note that the identification of the failure mechanisms would typically be driven by a CAP action such as a CE, ACE or RCE.

4.11.4 When piping is replaced prior to failure due to concerns with wall thinning or blockage, inspections should be considered on similar areas of the system to determine the presence and extent of degradation.

4.11.5 Flaws detected in the augmented inspections shall be characterized and evaluated as outlined in this procedure.

4.11.6 If a Temporary Non-Code repair is made on ASME Section XI Class 3 SW piping as allowed by NRC Generic Letter 90-05, the requirements of NP 7.2.5, Repair/Replacement Program, Attachment G, Temporary Non-Code Repairs shall be followed. NP 7.2.5 Attachment G provides specific requirements on the quantity and frequency of augmented NDE inspections related to the defect.

4.12 Inspection Report Documentation 4.12.1 The official record of each inspection is the applicable NDE form which is signed by NDE personnel and an engineering reviewer.

4.12.2 Each NDE inspection is to be documented on the applicable NDE form and signed by the NDE examiner and NDE interpreter as applicable.

4.12.3 Each NDE inspection form is to receive an engineering review by the SW System Engineer or designee. This review shall compare inspection results to the acceptance criteria of this procedure. An Action Request (AR) shall be initiated by the engineering reviewer if acceptance criteria are exceeded or if an AR is considered appropriate for any reason. The engineering reviewer shall sign the NDE form and record any applicable AR numbers and comments on the form.

4.12.4 The completed NDE inspection forms are to be attached to the implementing Work Order (WO) and filed with the WO in plant records.

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL SERVICE WATER AND FIRE PROTECTION INSPECTION PROGRAM NP 7.7.22 Revision 9 Page 19 of 21 INFORMATION USE 4.13 Annual Report 4.13.1 The SW System Engineer shall document inspections, results and Corrective Action planned, initiated or performed each year in an annual report. This report provides a complete historical record of the inspection work performed and related Corrective Actions.

• The report is to be documented in an internal correspondence memo with a Subject title of 20XX Service Water ISI Program (SWP) Annual Report"

• The report should be issued by the end of the 1st Quarter each year.

4.13.2 The annual report shall include:

• The past years examination WO numbers

• A listing of the specific examination locations with examination results for each location

• Action Requests (ARs) and Work Requests (W/Rs) initiated

• Corrective actions completed over the last year

• Other important comments related to the SW ISI program.

• Planned focus areas for next years inspections 4.13.3 At a minimum, copies of the Annual Report shall be sent to the following:

• Program and System Engineering Managers

• Service Water and Fire Protection System Engineers

• GL 89-13 Program Administrator

• Plant File 4.14 Database 4.14.1 Database Discussion For Information Only (i.e. un-controlled) databases have been used to document shot locations taken, wall thinning observed, blockage observed, and to record comments on corrective actions taken. These databases are used as an informational tool when determining future inspection scope. Note that the annual reports issued by the SW System Engineer and the completed work orders used for the inspections (which include copies of the NDE reports) serve as the official records of examinations performed under the SW ISI program.

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL SERVICE WATER AND FIRE PROTECTION INSPECTION PROGRAM NP 7.7.22 Revision 9 Page 20 of 21 INFORMATION USE 4.14.2 Historical Paradox Databases In the past, two related electronic databases utilizing Paradox software were used to record examinations and monitor corrective actions. These databases were transferred to a Microsoft Access database for ease of use. These databases are maintained as a table (Historical Data 1992-1999) in the current Access database. Database fields in the historical Paradox Database are defined in APPENDIX A of the SWP, Service Water In-Service Inspection Program.

4.14.3 Microsoft Access Database (current database)

A Microsoft Access database has replaced the original Paradox database.

Each field is detailed in the SW ISI Radiography Database User Manual in APPENDIX B of the SWP, Service Water In-Service Inspection Program.

Annual SW ISI results may be entered into the database if considered appropriate by the SW System Engineer. For repetitive exam location, an entry would typically be made in the database. For one time only exams that show insignificant levels of degradation, an entry into the database is typically not made.

5.0 REFERENCES

5.1 Generic Letter 89-13, SW System Problems Affecting Safety-Related Equipment.

5.2 EPRI TR-103403, Service Water System Corrosion and Deposition Source Book.

5.3 EPRI NP-5580, Sourcebook for Microbiologically Influenced Corrosion in Nuclear Power Plants.

5.4 EPRI NP-5911M, Acceptance Criteria for Structural Evaluation of Erosion-Corrosion Thinning in Carbon Steel Piping.

5.5 USAS/ASME B31.1.

5.6 ASME Code Case N-597-2, Requirements for Analytical Evaluation of Pipe Wall Thinning.

5.7 Generic Letter 90-05, Guideline for Performing Temporary Non-Code Repair of ASME Class 1, 2, and 3 Piping.

5.8 NUMARC memorandum on Follow-Up on Generic Letter 90-05 Regarding Guidance for Performing Temporary Non-Code Repair of ASME Code Class 1, 2 and 3 Piping.

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL SERVICE WATER AND FIRE PROTECTION INSPECTION PROGRAM NP 7.7.22 Revision 9 Page 21 of 21 INFORMATION USE 5.9 ASME Code Case N-513, Evaluation Criteria for Temporary Acceptance of Flaws in Moderate Energy Class 2 or 3 Piping Section XI, Division 1.

5.10 Regulatory Guide 1.147, Inservice Inspection Code Case Acceptability, ASME Section XI, Division 1.

5.11 NEI White Paper, Treatment of Operational Leakage from ASME Class 2 and 3 components Rev 1, October 2006.

5.12 NP 7.2.5, Repair/Replacement Program 5.13 NP 7.7.25, PBNP Renewed License Program 5.14 EN-AA-203-1001, Operability Determinations / Functionality Assessments 5.15 EN-AA-205-1102, Temporary Configuration Changes 5.16 DG-M09, Design Requirements for Piping Stress Analysis 5.17 EN-AA-101, Conduct of Engineering 6.0 BASES B-1 LR-TR-505-QAPELE, Evaluation of Quality Assurance Program Elements for License Renewal.

B-2 LR-AMP-021-OCCW, Open Cycle Cooling (Service) Water System Surveillance Program Basis Document for License Renewal.

B-3 LR-AMP-010-FP, Fire Protection Program Basis Document for License Renewal.

B-4 NUREG-1839, US NRC Safety Evaluation Report related to the License Renewal of the Point Beach Nuclear Plant, Unit 1 and 2.

B-5 GL 89-13 Program Document B-6 SWP, Service Water In-Service Inspection Program

Point Beach Nuclear Plant, Units 1 and 2 L-2023-075 Docket Nos. 50-266 and 50-301 Enclosure Point Beach Nuclear Plant Procedure, OI-55, Revision 35 Primary Leak Rate Calculation (22 pages follow)

OI 55 PRIMARY LEAK RATE CALCULATION DOCUMENT TYPE: Technical CLASSIFICATION: Safety Related REVISION: 35 REVIEWER: Qualified Reviewer APPROVAL AUTHORITY: Department Manager PROCEDURE OWNER (title): Group Head OWNER GROUP: Operations Verified Current Copy:

Signature Date Time List pages used for Partial Performance Controlling Work Document Numbers

POINT BEACH NUCLEAR PLANT OPERATING INSTRUCTION PRIMARY LEAK RATE CALCULATION OI 55 SAFETY RELATED Revision 35 Page 2 of 22 REFERENCE USE NOTE:

Only the completed Cover Page and Attachment A OR Attachment B are required to be sent to Records Group for retention.

1.0 PURPOSE 1.1 To provide instructions for calculating primary system leak rate by water inventory balances as required by Technical Specification LCO 3.4.13 and SR 3.4.13.1. Document the completion of this leak rate on Attachment A, Primary Leak Rate Worksheet, of this procedure.

1.2 To provide instructions for calculating primary system leak rate by water inventory balances for off normal events and for operations troubleshooting.

2.0 PREREQUISITES 2.1 Calculate baseline for each of the following conditions:

2.1.1 At the end of each three months for use in the next three months.

2.1.2 After maintenance and operations activities where gross RCS leak rate is reduced (or increased) due to specific maintenance or operations activities.

These activities may include repairing leaking valve(s) or similar activities which have an influence on RCS leak rate. A change in gross leakage immediately following a change in operating charging pumps should be investigated and Non-Reactor Coolant Pressure Boundary (RCPB) Leakage term in unidentified leak rate calculation adjusted accordingly.

2.1.3 A new baseline is required when starting up from a refueling outage.

Typically, after plant heat-up to MODE 3, a containment walk down is performed to ensure there is no pressure boundary leakage. After plant conditions have stabilized, periodic RCS leak rate calculations are initiated as required by technical specifications. RCS leak rate for the first ten days may not be accurate. Therefore, for the first seven (7) days after refueling outage baseline mean and standard deviation from the three months prior to the outage should be used. Thereafter, calculate a 7 day baseline value, a 14 day baseline value, a 21 day baseline value, and then a 30 day baseline value each month until the first quarter is completed.

POINT BEACH NUCLEAR PLANT OPERATING INSTRUCTION PRIMARY LEAK RATE CALCULATION OI 55 SAFETY RELATED Revision 35 Page 3 of 22 REFERENCE USE 2.1.4 Daily RCS unidentified leak rate monitoring per this procedure is only performed with the plant at a stable power level.

NOTE:

Performing this monitoring during non-stable plant conditions will adversely impact the statistical nature of this monitoring and therefore is not performed.

a. Expectations for the performance of the daily RCS unidentified leak rate monitoring is as follows:

As long as the stability criteria specified in this procedure are satisfied, an evaluation of the RCS unidentified leak rate for each calendar day shall be completed.

Known contributors to RCS identified leakage shall be measured and quantified in conjunction with daily RCS leak rate calculation. (Ref 6.9)

The Operations Supervisor shall be notified of the results.

The basic tasks involved in the statistical monitoring of the RCS unidentified leak rate are as follows:

b. For each calendar day, daily monitoring is completed per Section 5.0.

c. At start of each New Year, (January 1) setup of an EXCEL spreadsheet or eSOMS for the upcoming year.

d. Every three months resetting of the RCS unidentified leak rate baseline mean (µ) and standard deviation () values is completed.

e. If maintenance or an operational evolution has changed RCS unidentified leak rate mean (µ), resetting of the RCS unidentified leak rate baseline mean (µ) and standard deviation () values is completed.

2.2 Operations Support Personnel In order to satisfy the statistical based portion, Operations Support will establish and maintain baseline mean (µ) and standard deviation () values for the RCS unidentified leak rate. These mean (µ) and standard deviation () values are used to compare the daily value of RCS unidentified leak rate (from Section 5.0) against the statistically based Action Level limits.

POINT BEACH NUCLEAR PLANT OPERATING INSTRUCTION PRIMARY LEAK RATE CALCULATION OI 55 SAFETY RELATED Revision 35 Page 4 of 22 REFERENCE USE 3.0 PRECAUTIONS AND LIMITATIONS 3.1 The parameters shall normally be measured at a selected time interval of at least two hours at a steady-state power level. Shorter intervals may be selected during implementation of Abnormal Operating Procedures or as directed by Shift Management.

A leak rate time interval ( Time) of at least two hours will provide a more representative leak rate result.

3.2 Normally no system dilution, boration, or divert to holdup tank should take place, but this can be accounted for by use of blender totalizers and operator timed manual full divert (letdown flow times minutes diverted).

3.2.1 RCS makeup (boration or dilution) to VCT may be performed as long as an accurate measurement of water volume added is known.

3.2.2 Makeup additions should be targeted to middle portion of leak rate time interval to allow time for VCT to reach equilibrium conditions before end point data set is taken.

3.2.3 Makeup should not be in progress at start or end of leak rate check.

3.2.4 If charging pump seals are known to leak, whether the pump is running or not, make the appropriate adjustment to Non-RCPB Leakage.

3.3 Do not allow automatic divert to holdup tanks during the "check" as this could not be accounted for. Operator must use timed manual full divert.

3.4 The Reactor Coolant system shall be in a steady-state conditions with the following conditions maintained over duration of the check. (Validity Check) 3.4.1 Maintain PZR level constant. Target: +/- 0.5% of level span.

3.4.2 The plant has been in steady state conditions for at least 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

3.4.3 Maintain TAVG constant. Target: +/-0.5°F.

3.4.4 Maintain reactor power constant. Target +/- 0.1% rated thermal output.

POINT BEACH NUCLEAR PLANT OPERATING INSTRUCTION PRIMARY LEAK RATE CALCULATION OI 55 SAFETY RELATED Revision 35 Page 5 of 22 REFERENCE USE 3.5 The following rules apply to scheduled and unscheduled Technical Specification Surveillance Tests for calculating RCS leak rate:

3.5.1 Rule 1: Valid Result--if a leak rate is performed within the bounds of the validity checks (including negative values), then the leak rate should be considered valid.

a. If leak rate Valid, then include result in the long-term statistical data set of calculating the running mean.

b. If leak rate is a negative value, then it should not be included in the statistical data set.

3.5.2 Rule 2: Invalid Result--if validity checks are not met, re-perform leak rate when plant conditions have stabilized.

3.6 Do not pump identified leakage collection tanks (PRT, RCDT) during the leak rate check.

3.7 Change in containment pressure or temperature may affect leak rate or upset identified collection tank equilibrium.

3.8 RCS leak rates reported on daily status report will be both Unidentified and Identified leak rate calculation results.

3.9 Both RCS Unidentified and Identified leak rates will be tracked daily in Plan of the Day.

3.10 Action Level Limits will be calculated and maintained per Attachment C, Action Levels.

3.11 RCS Leak Rate can still be performed with RCDT and/or PRT level indicators out of service. Identified Leakage from out of service level indicator (RCDT/PRT) would be zero.

4.0 INITIAL CONDITIONS 4.1 Chemistry is not sampling RCS control volume (RCS, PZR, VCT, PRT, RCDT, etc.)

POINT BEACH NUCLEAR PLANT OPERATING INSTRUCTION PRIMARY LEAK RATE CALCULATION OI 55 SAFETY RELATED Revision 35 Page 6 of 22 REFERENCE USE 5.0 PROCEDURE NOTE:

Acceptance criteria stated in this procedure are more conservative than regulatory requirements for Point Beach. Refer to LCO 3.4.13, RCS Operational Leakage for limiting conditions of operation.

NOTE:

All externally reported leak rates (Total, Identified, and Unidentified) should be rounded to the nearest hundredth (0.01) gpm per WCAP-16423-NP.

NOTE:

All calculated leak rates (Total, Identified, and Unidentified) should be rounded to the nearest thousandth (0.001) gpm.

5.1 IF the Unit is in MODE 1, 2, 3, or 4, THEN determine RCS Leak Rate as follows:

5.1.1 IF desired to isolate letdown divert to HUT, THEN PERFORM the following:

a. PLACE 1(2)CV-112A, 1(2)T-4 VCT Divert LCV, to the VCT position.

b. SHUT 1(2)CV-256B, 1(2)CV-112A Divert Outlet to T-8A-C CVCS HUT.

5.1.2 RECORD initial set of parameter readings on Attachment A.

5.1.3 At time near end of selected time interval, ADJUST TAVG and T(error) meter to the same reading as recorded as in time one by moving rods, diluting, or borating if necessary.

5.1.4 Using the same instrumentation channels as for the first set of readings, RECORD second set of parameter readings when T(error) meter is the same as in initial data set.

5.1.5 IF dilution or boration took place, THEN CORRECT the leak rate by using the different totalizer readings.

5.1.6 IF operator timed manual full divert was used, THEN CALCULATE the number of gallons diverted by multiplying the letdown flow in gpm times minutes diverted.

5.1.7 QUANTIFY known contributors to RCS Identified leakage during performance of RCS leak rate calculation. (Ref 6.9) 5.1.8 QUANTIFY known Non-RCPB leakage during performance of RCS leak rate calculation. (Ref 6.9)

POINT BEACH NUCLEAR PLANT OPERATING INSTRUCTION PRIMARY LEAK RATE CALCULATION OI 55 SAFETY RELATED Revision 35 Page 7 of 22 REFERENCE USE 5.1.9 CALCULATE and RECORD leak rate.

5.1.10 IF letdown divert to HUT was isolated in Step 5.1.1, THEN PERFORM the following:

a. OPEN 1(2)CV-256B, 1(2)CV-112A Divert Outlet to T-8A-C CVCS HUT.

b. PLACE 1(2)CV-112A, 1(2)T-4 VCT Divert LCV, to the desired position.

5.2 IF the Unit is in MODE 5, THEN PERFORM Attachment B, Cold Shutdown Primary Leak Rate Worksheet as follows:

5.2.1 RECORD initial set of parameter readings on Attachment B.

5.2.2 At time near end of selected time interval, ADJUST temperature to the same reading as recorded as in time one by adjusting RHR cooling.

5.2.3 Using the same instrumentation channels as for the first set of readings, RECORD second set of parameter readings when RCS temperature is the same as in initial data set.

5.2.4 IF dilution or boration took place, THEN CORRECT the leak rate by using the different totalizer readings.

5.2.5 IF operator timed manual full divert was used, THEN CALCULATE the number of gallons diverted by multiplying the letdown flow in gpm times minutes diverted.

5.2.6 QUANTIFY known contributors to RCS Identified leakage during performance of RCS leak rate calculation. (Ref 6.9) 5.2.7 CALCULATE and RECORD leak rate.

5.3 IF the plant is in MODE 1 through 4, AND Pressure Boundary leakage is detected, THEN ENTER Technical Specification LCO 3.4.13 Action Condition B.

POINT BEACH NUCLEAR PLANT OPERATING INSTRUCTION PRIMARY LEAK RATE CALCULATION OI 55 SAFETY RELATED Revision 35 Page 8 of 22 REFERENCE USE 5.4 IF RCS Unidentified Leakage shows a significantly increasing trend, OR reaches 0.15 gpm, THEN PERFORM the following actions:

5.4.1 INFORM the Shift Manager and Duty Station Manager.

5.4.2 CHECK the following at least once per hour:

a. Containment particulate monitor (RE 211) high and low values.

b. Containment radiogas monitor (RE 212) high and low values.

c. Containment humidity.

5.4.3 PERFORM the RCS leak rate calculation of Section 5.1 or 5.2 as applicable at least once per shift.

5.4.4 OBTAIN a sump A sample and have Chemistry analyze to aid in determining the source of leakage.

5.4.5 DIRECT Chemistry to sample and analyze Containment atmosphere for hydrogen content and REPORT the results to the SM. (Ref 6.8) 5.4.6 NOTIFY Engineering to review Containment Air Cooler performance and cleaning frequencies to determine if an adverse long term trend exists.

5.4.7 IF a containment inspection is warranted to localize the source of leakage, THEN the inspection should consist of the following: (B-2)

a. Evidence of steam in containment.

b. Wetness on the floor.

c. Boric Acid deposits.

d. Abnormal packing or gasket leakage.

NOTE:

A thorough examination should be performed of the reactor vessel head using binoculars or other methods allowed by RP.

e. Reactor vessel head locations as permitted by Health Physics.

POINT BEACH NUCLEAR PLANT OPERATING INSTRUCTION PRIMARY LEAK RATE CALCULATION OI 55 SAFETY RELATED Revision 35 Page 9 of 22 REFERENCE USE 5.5 IF the RCS leak rate approaches 0.20 gpm and the cause is known, THEN the priority of the work order associated with the contributor SHALL be increased.

5.6 IF the plant is in MODE 1 through 4, AND Unidentified Leakage exceeds one gpm, THEN ENTER Technical Specification LCO 3.4.13 Action Condition.

5.7 IF Unidentified Leakage is greater than 1.0 gpm OR Identified Leakage is greater than 10 gpm, THEN INITIATE AOP 1A, Reactor Coolant Leak.

5.8 IF the plant is in MODE 1 through 4, AND Identified Leakage exceeds 10 gpm, THEN ENTER Technical Specification LCO 3.4.13 Action Condition.

POINT BEACH NUCLEAR PLANT OPERATING INSTRUCTION PRIMARY LEAK RATE CALCULATION OI 55 SAFETY RELATED Revision 35 Page 10 of 22 REFERENCE USE

6.0 REFERENCES

6.1 Technical Specification LCO 3.4.13, RCS Operational Leakage 6.2 AOP-1A, Reactor Coolant Leak 6.3 Tank Level Book 6.3.1 TLB 3.14, Reactor Vessel 6.3.2 TLB 2, Pressurizer 6.3.3 TLB 4, Volume Control Tank 6.3.4 TLB 14, Reactor Coolant Drain Tank 6.4 WCAP-16423-NP, Pressurized Water Reactor Owner's Group Standard Process and Methods for Calculating RCS Leak Rate for Pressurized Water Reactors, Revision 0, dated September 2006 6.5 WCAP-16465-NP, Pressurized Water Reactor Owners Group Standard RCS Leakage Action Levels and Response Guidelines for Pressurized Water Reactors, Revision 0, dated September 2006 6.6 PWROG Letter OG-07-387, Recommendations for Implementation of Guidelines for PWROG RCS Leak Rate Programs with Respect to NEI-03-08 (PA-OSC-0189 and PA-OSC-0218), dated August 27, 2007 6.7 AR 01128521, RCS Leak Rate Program 6.8 OE 9060, Increase in containment bulk hydrogen concentration occurred due to a pressurizer steam space leak (Surry Unit 2) 6.9 CE 02049543, Consistency Of RCS Leak Rate Determination With WCAP 16423 6.10 Calculation 2010-0034 Rev 0, Volume Control Tank 1(2)T4 Volume to Percent Calculation.

7.0 BASES B-2 VPNPD-88-899 (NRC-88-049) Response to Generic Letter 88-05, Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary Components, 5/24/1988.

POINT BEACH NUCLEAR PLANT OPERATING INSTRUCTION PRIMARY LEAK RATE CALCULATION OI 55 SAFETY RELATED Revision 35 Page 11 of 22 REFERENCE USE REMARKS:

POINT BEACH NUCLEAR PLANT OPERATING INSTRUCTION PRIMARY LEAK RATE CALCULATION OI 55 SAFETY RELATED Revision 35 INITIALS Page 12 of 22 REFERENCE USE ATTACHMENT A PRIMARY LEAK RATE WORKSHEET Page 1 of 4 NOTE:

Only the completed Cover Page and Attachment A are required to be sent to the Records Group for retention.

UNIT ______________

DATE ______________

NOTE:

Normally, no system dilution, boration, or divert to holdup tank should take place. However, if required, blender totalizers and operator timed manual full divert can account for these operations. Positive leak rates indicate leakage from the RCS.

NOTE:

VCT Level is taken at the same point in the level cycle when the LDGS is on-line to provide as accurate of a leak rate as possible.

1.0 MONITOR AND MAINTAIN the following during the performance of this test:

1.1 Reactor Power is stable.

1.2 The Letdown Gas Stripper (LDGS) meets ONE of the following:

1.2.1 The LDGS is operating normally with control in AUTO AND with no level adjustments being made.

1.2.2 The LDGS is bypassed per OI 17, Letdown Gas Stripper Operation.

1.3 IF desired to isolate letdown divert to HUT, THEN PERFORM the following:

1.3.1 PLACE 1(2)CV-112A, 1(2)T-4 VCT Divert LCV, to the VCT position.

1.3.2 SHUT 1(2)CV-256B, 1(2)CV-112A Divert Outlet to T-8A-C CVCS HUT.

POINT BEACH NUCLEAR PLANT OPERATING INSTRUCTION PRIMARY LEAK RATE CALCULATION OI 55 SAFETY RELATED Revision 35 ATTACHMENT A PRIMARY LEAK RATE WORKSHEET Page 13 of 22 REFERENCE USE Page 2 of 4 NOTE:

Final and Initial values of TAVG must be equal.

2.0 RECORD the following data:

RCS LEAK RATE DATA Parameter Initial Final Formula Result Time (T) min TF TI = T min RC TAVG(TAVG)

°F

°F TAVGI TAVGF = TAVG

°F Pzr Level (PZR)

% (PZRI PZRF ) 64.9 = PZRgal gal VCT Level (VCT)

% (VCTI VCTF ) 12.64 = VCTgal gal RMW AND BA ADDITIONS Time of Addition Gallons Added gal gal gal Total Gallons Added (MUgal):

gal DIVERT Time of Divert Flow Rate (DF)

Divert Duration (DT)

Formula Gallons Diverted (DV) gpm min DF x DT =

DV gal gpm min DF x DT =

DV gal gpm min DF x DT =

DV gal Total Gallons Diverted (Dgal):

gal 3.0 CALCULATE RCS leak rate:

CALCULATED RCS LEAK RATE Parameter Formula Leak Rate RCS Leak Rate (LRRCS)

LRRCS = (PZRgal + VCTgal + MUgal - Dgal ) T gpm

POINT BEACH NUCLEAR PLANT OPERATING INSTRUCTION PRIMARY LEAK RATE CALCULATION OI 55 SAFETY RELATED Revision 35 ATTACHMENT A PRIMARY LEAK RATE WORKSHEET Page 14 of 22 REFERENCE USE Page 3 of 4 4.0 CALCULATE RCS Unidentified Leak Rate as follows:

NOTE:

PRT and RCDT Calculated Leak Rate being a negative value is not valid.

Therefore enter 0 gpm or perform a new leak rate calculation.

4.1 CALCULATE Identified RCS Leak Rate:

IDENTIFIED RCS LEAK RATE DATA Parameter Initial Final Formula Result Time (T) min TF TI = T min PRT Level (PRT)

% LRPRT = (PRTF - PRTI)

• 62.5 T gpm RCDT Level (RCDT)

% LRRCDT =(RCDTF RCDTI ) 3.5 T gpm SG Tube Leakage (SGTL)

LRSGTL = Obtained from Control Room summary report within past 72-hours gpm Reactor Component Leak Rate LRRC = Other known and documented RCS leakage not accounted for in RCDT, PRT, or Steam Generator leakage gpm RCS Identified Leak Rate (LRID)

LRID = LRPRT + LRRCDT + LRRC + LRSGTL gpm 4.2 CALCULATE Non Reactor Coolant Pressure Boundary Leakage:

NON REACTOR COOLANT PRESSURE BOUNDARY Parameter Formula Leak Rate Charging Pump Seals LRP2 = (P-2A + P-2B + P-2C) cc/min

• 2.64e-4 gpm Non RCPB Leakage (Not Charging)

LRP3 = Non Reactor Pressure Boundary Leakage Other Than Charging gpm

POINT BEACH NUCLEAR PLANT OPERATING INSTRUCTION PRIMARY LEAK RATE CALCULATION OI 55 SAFETY RELATED Revision 35 INITIALS ATTACHMENT A PRIMARY LEAK RATE WORKSHEET Page 15 of 22 REFERENCE USE Page 4 of 4 NOTE:

Due to indication accuracies, the Unidentified RCS Leak Rate may be a negative number. In this case, the Unidentified RCS Leak Rate is Zero.

4.3 CALCULATE RCS Unidentified leakage:

UNIDENTIFIED RCS LEAK RATE Parameter Formula Leak Rate Unidentified Leak Rate (LRUID)

LRUID = LRRCS - LRID - LRP2 - LRP3 gpm 5.0 IF letdown divert to HUT was isolated in Step 1.3, THEN PERFORM the following:

5.1 OPEN 1(2)CV-256B, 1(2)CV-112A Divert Outlet to T-8A-C CVCS HUT.

5.2 PLACE 1(2)CV-112A, 1(2)T-4 VCT Divert LCV, to the desired position.

6.0 Primary Leak Rate calculation COMPLETE.

7.0 Review Attachment C to determine if any Action Level thresholds have been met.

8.0 Primary Leak Rate calculation review COMPLETE.

SRO

POINT BEACH NUCLEAR PLANT OPERATING INSTRUCTION PRIMARY LEAK RATE CALCULATION OI 55 SAFETY RELATED Revision 35 Page 16 of 22 REFERENCE USE ATTACHMENT B COLD SHUTDOWN PRIMARY LEAK RATE WORKSHEET Page 1 of 3 NOTE:

Only the completed Cover Page and Attachment B are required to be sent to the Records Group for retention.

UNIT ______________

DATE ______________

NOTE:

Normal duration of test is two to six hours. Final and initial values of RC Temp must be equal. Positive leak rates indicate leakage from the RCS.

1.0 RECORD the following data:

RCS LEAK RATE DATA Parameter Initial Final Formula Result Time (T) min TF TI = T min RC Temp (Trcs)

°F

°F TrcsI TrcsF = Trcs

°F Pzr Temp

°F Pzr Conversion Factor (PCF)

Table 1, "Pressurizer Cold Cal CSD Compensation."

gal/%

Pzr Level (PZR)

% (PZRI PZRF ) PCF = PZRgal gal VCT Level (VCT)

% (VCTI VCTF ) 12.64 = VCTgal gal Reactor Vessel Level (RV)

% (RVI RVF) 52 = RVgal gal RCDT Level (RCDT)

% (RCDTF RCDTI ) 3.5 = RCDTgal gal 2.0 IF RMW or BA additions are made during test period, THEN RECORD the following data:

RMW AND BA ADDITIONS Time of Addition Gallons Added gal gal gal Total Gallons Added (MUgal):

gal 3.0 IF divert to holdup tank is performed during test period, THEN RECORD the following data:

DIVERT Time of Divert Flow Rate (DF)

Divert Duration (DT)

Formula Gallons Diverted (DV) gpm min DF x DT = DV gal gpm min DF x DT = DV gal gpm min DF x DT = DV gal Total Gallons Diverted (Dgal):

gal

POINT BEACH NUCLEAR PLANT OPERATING INSTRUCTION PRIMARY LEAK RATE CALCULATION OI 55 SAFETY RELATED Revision 35 ATTACHMENT B COLD SHUTDOWN PRIMARY LEAK RATE WORKSHEET Page 17 of 22 REFERENCE USE Page 2 of 3 4.0 CALCULATE RCS leak rate:

CALCULATED RCS LEAK RATE Parameter Formula Leak Rate RCS Leak Rate (LRRCS)

(PZRgal + VCTgal + RVgal + MUgal Dgal ) T = LRRCS gpm 5.0 IF RCS Leak Rate is greater than 0.15 gpm, THEN PERFORM the following:

5.1 CALCULATE RCDT leak rate:

CALCULATED RCDT LEAK RATE Parameter Formula RCDT Leak Rate RCDT Leak Rate (LRRCDT)

RCDTgal T = LRRCDT gpm 5.2 MEASURE and RECORD below any identified component leakage that is NOT Pressure Boundary Leakage:

COMPONENT LEAK RATE Component Leak Rate gpm gpm gpm gpm Total Component Leakage (LRC):

gpm

POINT BEACH NUCLEAR PLANT OPERATING INSTRUCTION PRIMARY LEAK RATE CALCULATION OI 55 SAFETY RELATED Revision 35 INITIALS ATTACHMENT B COLD SHUTDOWN PRIMARY LEAK RATE WORKSHEET Page 18 of 22 REFERENCE USE Page 3 of 3 5.3 CALCULATE Identified Leakage:

RCS IDENTIFIED LEAKAGE Parameter Formula Identified Leakage RCS Identified Leakage (LRID)

LRRCDT + LRC = LRID gpm NOTE:

Due to indication accuracies, the Unidentified RCS Leak Rate may be a negative number. In this case, the Unidentified RCS Leak Rate is Zero.

5.4 CALCULATE Unidentified Leakage:

RCS UNIDENTIFIED LEAKAGE Parameter Formula Unidentified Leakage RCS Unidentified Leakage (LRUID)

LRRCS - LRID = LRUID gpm 6.0 Primary Leak Rate calculation COMPLETE.

7.0 Review Attachment C to determine if any Action Level thresholds have been met.

8.0 Primary Leak Rate calculation review COMPLETED.

SRO

POINT BEACH NUCLEAR PLANT OPERATING INSTRUCTION PRIMARY LEAK RATE CALCULATION OI 55 SAFETY RELATED Revision 35 Page 19 of 22 REFERENCE USE ATTACHMENT C ACTION LEVELS Page 1 of 3 NOTE:

Calculation of absolute RCS Inventory Balance values must include rules for treatment of negative daily values and missing daily observations.

NOTE:

"daily means "daily average value" which is: the average of all valid measurements performed on a given calendar day.

1.0 Action Levels on the absolute value of Unidentified RCS Inventory Balance (from surveillance data) and the deviation from the baseline mean.

1.1 Action Level 1 1.1.1 Seven day rolling average of daily RCS Unidentified Leakage greater than 0.10 gpm.

1.1.2 Nine consecutive RCS Unidentified Leakage greater than the baseline mean value ().

1.2 Action Level 2 1.2.1 Two consecutive daily RCS Unidentified Leakage greater than 0.15 gpm.

1.2.2 Two of three consecutive daily RCS Unidentified Leakage greater than the baseline mean value plus two times the standard deviation [ + 2].

1.3 Action Level 3 1.3.1 One RCS Unidentified Leakage greater than 0.30 gpm.

1.3.2 One daily RCS Unidentified Leakage greater than the baseline mean value plus three times the standard deviation [ + 3].

POINT BEACH NUCLEAR PLANT OPERATING INSTRUCTION PRIMARY LEAK RATE CALCULATION OI 55 SAFETY RELATED Revision 35 ATTACHMENT C ACTION LEVELS Page 20 of 22 REFERENCE USE Page 2 of 3 2.0 Action Levels Response:

2.1 Action Level 1 2.1.1 Confirm the indication.

2.1.2 Operations Manager has reviewed results and concurs with entry into Action Level 1.

2.1.3 Check for abnormal trends in other leak rate related indicators (containment sump levels, containment radiation monitors, etc.).

2.1.4 Perform an immediate review of the previous 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> of plant activities that could have caused the increasing trend. 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> review should include but not be limited to components having been manipulate during removal or restoration to service, testing, sampling or maintenance.

2.1.5 Initiate a CAP for evaluation of pertinent input parameters.

2.2 Action Level 2 2.2.1 Confirm the indication.

2.2.2 Operations Manager has reviewed results and concurs with entry into Action Level 2.

2.2.3 Check for abnormal trends in other leak rate related indicators (containment sump levels, containment radiation monitors, etc.).

2.2.4 Perform an immediate review of the previous 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> of plant activities that could have caused the increasing trend. 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> review should include but not be limited to components having been manipulate during removal or restoration to service, testing, sampling or maintenance.

2.2.5 Initiate a CAP.

2.2.6 Review recent plant operational and maintenance evolutions to identify any potential sources for the increased leakage.

2.2.7 Initiate outside containment walk downs on pertinent systems.

POINT BEACH NUCLEAR PLANT OPERATING INSTRUCTION PRIMARY LEAK RATE CALCULATION OI 55 SAFETY RELATED Revision 35 ATTACHMENT C ACTION LEVELS Page 21 of 22 REFERENCE USE Page 3 of 3 2.3 Action Level 3 2.3.1 Confirm the indication.

2.3.2 Operations Manager has reviewed results and concurs with entry into Action Level 3.

2.3.3 Check for abnormal trends in other leak rate related indicators (containment sump levels, containment radiation monitors, etc.).

2.3.4 Perform an immediate review of the previous 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> of plant activities that could have caused the increasing trend. 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> review should include but not be limited to components having been manipulate during removal or restoration to service, testing, sampling or maintenance.

2.3.5 Initiate a CAP.

2.3.6 Review recent plant operational and maintenance evolutions to identify any potential sources for the increased leakage.

2.3.7 Initiate outside containment walk downs on pertinent systems.

2.3.8 If leakage is inside containment, perform a containment entry to walk down accessible areas of containment.

POINT BEACH NUCLEAR PLANT OPERATING INSTRUCTION PRIMARY LEAK RATE CALCULATION OI 55 SAFETY RELATED Revision 35 Page 22 of 22 REFERENCE USE TABLE 1 Page 1 of 1 PRESSURIZER COLD CAL CSD COMPENSATION TEMP GAL/%

TEMP GAL/%

200 62.59 134 64.03 198 62.64 132 64.06 196 62.69 130 64.1 194 62.74 128 64.13 192 62.79 126 64.17 190 62.84 124 64.2 188 62.89 122 64.23 186 62.93 120 64.27 184 62.98 118 64.3 182 63.03 116 64.33 180 63.08 114 64.36 178 63.12 112 64.39 176 63.17 110 64.42 174 63.21 108 64.45 172 63.26 106 64.48 170 63.3 104 64.51 168 63.34 102 64.53 166 63.39 100 64.56 164 63.43 98 64.59 162 63.48 96 64.61 160 63.52 94 64.64 158 63.56 92 64.66 156 63.6 90 64.69 154 63.64 88 64.71 152 63.68 86 64.73 150 63.72 84 64.75 148 63.76 82 64.77 146 63.8 80 64.8 144 63.84 78 64.82 142 63.88 76 64.83 140 63.92 74 64.85 138 63.95 72 64.87 136 64 70 64.88 Use current pressurizer temperature to correct the gallons per percent.

Point Beach Nuclear Plant, Units 1 and 2 L-2023-075 Docket Nos. 50-266 and 50-301 Enclosure Point Beach Nuclear Plant Procedure, NP 7.7.31, Revision 6 Alloy 600 Management Program (30 pages follow)

NP 7.7.31 ALLOY 600 MANAGEMENT PROGRAM DOCUMENT TYPE: Administrative REVISION: 6 APPROVAL AUTHORITY: Department Manager PROCEDURE OWNER (title): Group Head OWNER GROUP: Program Engineering

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL ALLOY 600 MANAGEMENT PROGRAM NP 7.7.31 Revision 6 Page 2 of 30 INFORMATION USE TABLE OF CONTENTS SECTION TITLE PAGE 1.0 PURPOSE............................................................................................................................3 2.0 DISCUSSION......................................................................................................................3 2.1 Applicability........................................................................................................................3 2.2 Definitions............................................................................................................................3 3.0 RESPONSIBILITIES..........................................................................................................4 4.0 PROCEDURE......................................................................................................................5 4.1 Industry Experience.............................................................................................................5 4.2 Alloy 600/82/182 Locations................................................................................................7 4.3 Inspection Requirements......................................................................................................8 4.4 Repair Methods..................................................................................................................12 4.5 Mitigation Methods............................................................................................................13 4.6 PWSCC Susceptibility Ranking........................................................................................14

5.0 REFERENCES

..................................................................................................................15 5.1 Source Documents.............................................................................................................15 5.2 Reference Documents........................................................................................................15 5.3 Records..............................................................................................................................16 6.0 BASES...............................................................................................................................16 Attachment A Alloy 600 Repairs/Replacements...............................................................................17 Attachment B NRC Generic Communications..................................................................................18 Attachment C Alloy 600/82/182 Locations.......................................................................................25

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL ALLOY 600 MANAGEMENT PROGRAM NP 7.7.31 Revision 6 Page 3 of 30 INFORMATION USE 1.0 PURPOSE 1.1 Scope This document describes the overall programmatic requirements that Point Beach Nuclear Plant (PBNP) will follow for the development, control, and implementation of an Alloy 600 Management Program for PBNP Units 1 and 2.

This document also implements a commitment to the NRC to manage the effects of aging for systems, structures, and components (SSC) within the scope of License Renewal (LR) as described in NP 7.7.25, PBNP Renewed License Program. Applicable LR commitments require the implementation of an Alloy 600 Program. (B-1, B-2)

The program is focused on both pressure and non-pressure boundary Reactor Coolant System (RCS) components constructed of Alloy 600 and welds constructed of the associated Alloy 82/182 filler metals. Industry experience has shown these materials to be susceptible to failure by primary water stress corrosion cracking (PWSCC). Steam generator tubing is excluded from this program because it is covered under the Steam Generator Integrity Program.

This program was developed utilizing the EPRI MRP-126 Generic Guidance for Alloy 600 Management industry guidance document, and NEI 03-08 Guideline for the Management of Materials Issues. The Alloy 600 Management Program is a living document and will be revised periodically to reflect the latest plant configurations.

1.2 Objective The overall objectives of the Alloy 600 Management Program are as follows:

1.2.1 Maintain the integrity and operability of Alloy 600/82/182 materials.

1.2.2 Ensure regulatory compliance.

1.2.3 Maintain plant safety.

1.2.4 Minimize the impact of PWSCC on plant availability.

2.0 DISCUSSION 2.1 Applicability The Alloy 600 Management Program includes the management of short and long term examination, evaluation, mitigation, and repair/replacement activities. Implementation of these activities is controlled by other programs and procedures.

2.2 Definitions None.

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL ALLOY 600 MANAGEMENT PROGRAM NP 7.7.31 Revision 6 Page 4 of 30 INFORMATION USE 3.0 RESPONSIBILITIES The overall responsibility for the development, revision and implementation of the Alloy 600 Management Program resides with Fleet Program Engineering. Responsibilities of the various groups contained therein are described below.

3.1 Fleet Programs Engineering 3.1.1 Preparation, maintenance and ownership of the Alloy 600 Management Program.

3.1.2 Development of refueling outage examination plans.

3.1.3 Development of a recommended strategy for the management of Alloy 600/82/182 materials.

3.1.4 Ensuring compliance with regulatory requirements.

3.1.5 Serving as the contact for outside technical communications (NEI, INPO, NRC, EPRI, ASME, PWR Owners Group, etc.).

3.1.6 Participating in industry owners groups.

3.1.7 Providing analysis and response to significant industry events.

3.1.8 Conducting periodic self-assessments of the Alloy 600 Management Program.

3.2 Design Engineering 3.2.1 Preparation of Design Change Packages (DCPM) packages for repairs or modifications that would result in a configuration change to existing Alloy 600/82/182 components/welds.

3.2.2 Disposition of Condition Reports associated with examination results.

3.3 Site Maintenance and Projects Departments 3.3.1 Performance of work orders for the implementation of examination, evaluation, mitigation and repair/replacement activities.

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL ALLOY 600 MANAGEMENT PROGRAM NP 7.7.31 Revision 6 Page 5 of 30 INFORMATION USE 4.0 PROCEDURE 4.1 Industry Experience 4.1.1 Construction Alloy 600/82/182 materials were incorporated into the RCS of Westinghouse (PBNP 1 & 2) PWR designs for three primary reasons:

resistance to chloride stress corrosion cracking.

corrosion resistance in high temperature water.

compatible coefficient of thermal expansion to nuclear pressure vessel steels.

The Westinghouse design utilized Alloy 600/82/182 for the RPV penetrations, the Bottom-Mounted Instrumentation (BMI) penetrations, and to a lesser extent some RCS piping connections. A complete listing of the Alloy 600/82/182 locations at PBNP 1 & 2 is located in Attachment C.

4.1.2 Mechanism PWSCC is a form of stress corrosion cracking that affects Alloy 600/82/182 materials exposed to a primary water environment within chemistry specification limits. The primary susceptibility factors for PWSCC include:

thermo-mechanical processing.

stress level.

chemical environment.

temperature.

a. Thermo-mechanical processing variables utilized during the fabrication of Alloy 600 components directly affect the materials microstructure and degree of cold work. A high temperature mill anneal produces a microstructure that has been found to be more resistant to PWSCC than one resulting from lower mill anneal temperatures. High degrees of cold work and lower forging temperatures have also been found detrimental to PWSCC resistance.

b. PWSCC susceptibility is directly proportional to higher total stress levels, including both applied and residual. Furthermore, higher yield strength often correlates with a shorter PWSCC initiation time because it allows the material to retain higher residual stress levels from welding and machining processes.

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL ALLOY 600 MANAGEMENT PROGRAM NP 7.7.31 Revision 6 Page 6 of 30 INFORMATION USE

c. The normal primary water environment is fully capable of supporting PWSCC. Additionally, contaminants or chemical additives such as sulfate, lead, and hydrogen in primary water may accelerate PWSCC. The Primary Chemistry Control Program alone is ineffective for prevention of PWSCC in Alloy 600/82/182 materials.

d. PWSCC susceptibility is directly proportional to temperature as the mechanism is a thermally activated process. While there is no proven minimum temperature for PWSCC, 561oF is the lowest temperature at which it has been observed in service.

4.1.3 History Stress corrosion cracking of nickel base materials in high purity water at elevated temperatures was first demonstrated in the laboratory in the late 1950s. In operating PWRs, PWSCC was initially observed on the primary side of Alloy 600 steam generator tubing. The first case of PWSCC involving a leaking Alloy 600 pressurizer instrument nozzle was discovered at San Onofre Unit 3 in 1986. The first instance in a RPV upper head Alloy 600 penetration was identified in France at Bugey Unit 3 in 1991. Finally, the first confirmed case of PWSCC in an Alloy 82/182 weld metal was discovered in 2000 at V.C. Summer, in a butt weld joining a reactor vessel hot leg nozzle to the RCS piping.

Since the above mentioned events, there have been numerous failures at foreign and domestic PWRs, involving Alloy 600 pressurizer heater sleeves, instrument nozzles, thermocouple nozzles, CRDM nozzles and safe ends, and buttering welds of piping exposed to the RCS. A compilation of domestic and foreign PWR components that were repaired/replaced due to PWSCC or concerns thereof is included in Table 3-1 of EPRI MRP 76. A listing of Alloy 600 components that have been replaced at PBNP due to PWSCC, or concerns thereof, is included as Attachment A.

4.1.4 NRC Communications Since the early 90s, the NRC has issued a significant number of generic communications to PWR licensees concerning PWSCC of Alloy 600/82/182 materials. Given the generic nature of this issue, joint industry issue programs organized through NSSS owners groups, EPRI and NEI have been, and continue to be, instrumental in investigating the issue and addressing the NRCs safety concerns. Summaries of the generic communications and PBNPs response when they were required, are included in Attachment B.

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL ALLOY 600 MANAGEMENT PROGRAM NP 7.7.31 Revision 6 Page 7 of 30 INFORMATION USE 4.2 Alloy 600/82/182 Locations A comprehensive list of the Alloy 600/82/182 locations for PBNP Units 1 and 2 is provided in Attachment C. These locations include the following:

4.2.1 Reactor Pressure Vessel Shells The Unit 1 lower shell course is internally clad with Alloy 82/182 on the bottom 11-7/8 inches. Four (4) core support guides made from Alloy 600 are welded to the bottom of the shell course. (Ref. 5.1.4)

The Reactor Pressure Vessel Shells have no Alloy 600 penetrations.

4.2.2 Reactor Vessel Internals The Reactor Vessel Clevis Insert Lock Keys and Clevis Inserts are manufactured from Alloy 600 material for both units.

4.2.3 Reactor Vessel Heads The Reactor Vessel Upper Heads were replaced in 2005. The thirty-eight (38) upper vessel head penetrations are Alloy 690 material attached to the upper head with J-groove welds using Alloy 52/152 filler material. Only Alloy 52 weld filler metal is exposed to primary water. (Ref. 5.1.5, 5.1.6)

Thirty-six (36) lower head Bottom-Mounted Instrumentation (BMI) penetrations are Alloy 600 penetrations. (Ref. 5.1.3, 5.1.4) 4.2.4 Steam Generators Each Unit 1 Steam Generator has Alloy 600/82/182 in the Unit 1 Steam Generator channel head divider plate weld and nozzle dam rings.

Each Unit 2 Steam Generator has two (2) Alloy 82/182 welds. The Alloy 82/182 welds are for the primary nozzles to safe-end on each hot and cold leg.

These welds were inlaid during manufacture with Alloy 52/152.

Each Unit 2 Steam Generator has two (2) Alloy 690 penetrations. The Alloy 690 penetrations are the primary vent nozzles on each cold and hot leg side of the Steam Generator Channel Head.

4.2.5 Pressurizers, Reactor Coolant Pumps, and Reactor Coolant Piping The pressurizers, reactor coolant pumps and reactor coolant piping have no Alloy 600 penetrations or Alloy 82/182 weld metal.

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL ALLOY 600 MANAGEMENT PROGRAM NP 7.7.31 Revision 6 Page 8 of 30 INFORMATION USE 4.3 Inspection Requirements Current examination requirements for the various Alloy 600/82/182 locations are included in Attachment C. Given the emergent nature of the Alloy 600 issue throughout the industry, these listings will likely require ongoing revision upon issuance of new examination requirements. Sources of these examination requirements include:

a. ASME Section XI In-Service Inspection (ISI) Program

b. NRC Orders

c. License Renewal Programs

d. Plant Procedures and Programs

e. Joint Industry Issues Programs (i.e. MRP-139)

f. NSSS Vendors

g. NRC Regulations (10 CFR 50.55a) 4.3.1 ASME Section XI ISI Program 10 CFR 50.55a requires that all power reactors maintain an ISI program in accordance with the ASME Boiler and Pressure Vessel Code,Section XI.

Applicable requirements for Alloy 600/82/182 components addressed by this program (Class 1) are included in IWB-2500 of Section XI.

Code Case N-722-X requires the performance of visual examinations (VT) of highly susceptible Alloy 600/82/182 components during each refueling outage (hot leg temperature and above). Other Alloy 600/82/182 components that are considered less susceptible to PWSCC cracking (e.g., cold leg instrument connections) are required to be examined by VT once per interval, with the exception of BMIs which are every other outage. Code Case N-722 was incorporated into 10 CFR 50.55a on September 10, 2008.

Code Case N-729-X requires the performance of visual, surface, or volumetric examination of the Reactor Vessel Upper Head Nozzles having Pressure-Retaining Partial Penetration Welds. The examination technique used is based on the desired frequency of examination, material, and effective degradation years (EDY). Code Case N-729-X was incorporated into 10 CFR 50.55a on September 10, 2008.

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL ALLOY 600 MANAGEMENT PROGRAM NP 7.7.31 Revision 6 Page 9 of 30 INFORMATION USE Code Case N-770-X (applicable version in 10CFR50.55a) provides inspection and management guidance for Alloy 82/182 dissimilar metal (DM) butt welds.

Code Case N-770-X was incorporated into 10 CFR 50.55a on June 21, 2011.

NRC regulations require Alloy 82/182 welds with Alloy 52 inlays or onlays to be examined in accordance with Code Case N-770-X, regardless of when the Alloy 52 inlay or onlay was applied. The NRC will not exempt these welds from the requirements of Code Case N-770-X.

By letter NRC 2015-0040 dated August 23, 2015, NextEra Energy Point Beach, LLC (NextEra) submitted Relief Request 2-RR-11 to the Nuclear Regulatory Commission (NRC) to allow for extension of the inspection interval from 5 to 7.5 years for the four steam generator nozzle dissimilar metal welds installed in Point Beach Nuclear Plant (PBNP) Unit 2. The NRC authorized the proposed alternative at PBNP Unit 2 until the end of the spring 2020 scheduled refueling outage. (B-3) 4.3.2 NRC Orders Orders issued concerning examination of Alloy 600/82/182 materials included EA-03-009 (February 11, 2003) and EA-03-009, Rev. 1 (February 20, 2004).

Both addressed reactor pressure vessel head penetrations. Code Case N-729-1 has been incorporated into the PBNP ISI program and replaces NRC Order EA-03-009.

4.3.3 License Renewal Programs The license renewal processes conducted at PBNP 1 & 2 created a number of programs to ensure that the integrity of structures and components is maintained throughout the periods of extended operation at both sites.

Specific programs concerning Alloy 600/82/182 materials include:

LR-AMP-017-IWBCD, ASME Section XI, Subsections IWB, IWC, and IWD Inservice Inspection Program Basis Document for License Renewal.

LR-AMP-005-BAC, Boric Acid Corrosion Program Basis Document for License Renewal.

LR-AMP-013-RCA600, RCS Alloy 600 Inspection Program Basis Document for License Renewal.

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL ALLOY 600 MANAGEMENT PROGRAM NP 7.7.31 Revision 6 Page 10 of 30 INFORMATION USE 4.3.4 Procedures and Programs Procedures and programs developed to verify the integrity of the RCS and minimize the chances of equipment degradation due to boric acid corrosion include: individual site program documents for Boric Acid Corrosion Control (BACC), Reactor Coolant System Leak Test, BMI Examination, and RPV Closure Head examinations.

4.3.5 Joint Industry Issues Programs Joint industry issues programs are often utilized to address the degradation of Alloy 600/82/182 in the most cost effective and efficient manner. Applicable issues programs and their current examination requirements include:

a. EPRI Materials Reliability Program (MRP)

MRP 2010-046, MRP-139, Revision 1 Interim Guidance on Rescission of MRP-139, R1 Mandatory Requirements with Implementation of Code Case N-770, (January 4, 2011) - Provides interim guidance accepting Code Case N-770. EPRI MRP considers Code Case N-770 to be an acceptable alternative inspection and degradation management framework for A82/182 DM butt welds to that promulgated by MRP-139, Revision 1. Upon completion of NRC Rulemaking regarding the incorporation of ASME Code Case N-770 into 10 CFR 50.55a as a regulatory mandate and unit-specific implementation of the resulting final Rule requirements, all Mandatory requirements contained in MRP-139, Revision 1 shall be rescinded for that specific unit.

b. ASME Code Cases Code Case N-722-X (applicable version in 10CFR50.55a)

Code Case N-729-X (applicable version in 10CFR50.55a)

Code Case N-770-X (applicable version in 10CFR50.55a) (This Code Case was incorporated into 10CFR50.55a, effectively replacing MRP-139)

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL ALLOY 600 MANAGEMENT PROGRAM NP 7.7.31 Revision 6 Page 11 of 30 INFORMATION USE 4.3.6 NSSS Vendors Industry OE and information from NSSS vendors is evaluated for effect on inspection requirements. Industry OE has included:

Westinghouse Technical Bulletin (TB) - TB-04-19, Steam Generator Channel Head Bowl Drain Line Leakage, (October 18, 2004) - Boric acid crystals were observed around the channel head bowl drain line coupling. The TB recommends that a visual examination of each steam generator drain coupling and surrounding weld build-up, adjacent to the coupling with insulation removed at each refueling outage.

NOTE:

EC 288078 removed the Alloy 600 (Alloy 82/182) weld filler metal and heat-affected zone for the Point Beach Unit 1 Steam Generator Channel Head Bowl drains. The weld was replaced with Alloy 690 (Alloy 52) filler metal.

Westinghouse InfoGram (IG) - IG-10-1, "Reactor Internals Lower Support Clevis Insert Cap Screw Degradation," (March 31, 2010) - Visual evidence that cap screws had cracked was found at D.C.

Cook during the 10-year in-service inspection (ISI). Visual (VT-3) examinations of the PBNP Unit 1 and Unit 2 clevis inserts were performed during the 10-year ISI in the U1R32 (Spring 2010) and U2R30 (Fall 2009) outages. No indications of wear, fracture, or other anomalies with the clevis insert cap screws or dowel pins were noted at any location.

Westinghouse Technical Bulletin (TB) - TB-14-5, Reactor Internals Lower Support Clevis Insert Cap Screw Degradation, (August 25, 2014) - This TB supersedes IG-10-1 which was issued to communicate an operating experience (OE) related to clevis insert cap screw (bolt) degradation. This TB provides a summary of the OE as well as root cause findings and the applicability of these findings on Westinghouse and Combustion Engineering (CE) pressurized water reactor designs.

This TB also reviews the safety implications of the OE and root cause analysis results as well as inspection recommendations for licensees to consider including as part of their aging management program to address this OE.

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL ALLOY 600 MANAGEMENT PROGRAM NP 7.7.31 Revision 6 Page 12 of 30 INFORMATION USE 4.4 Repair Methods Since the first pressurizer instrumentation nozzle failure in 1986, PWR licensees have implemented a variety of repair methods. Selection of the optimum repair method is normally based upon available technology, ASME Code requirements, radiological conditions, and economic factors. Most repairs implemented since the mid 1990s have utilized only PWSCC resistant Alloy 690/52/152 materials. Summaries of the most common methods for the various Alloy 600 material locations are provided below.

Repairs implemented to date at PBNP are included in Attachment A.

4.4.1 RPV Upper Head CRDM Nozzles PBNP completed a program of RPV head replacements. The replacement RPV heads are constructed using Alloy 690 (vice Alloy 600) nozzles attached using A52/152 weld material vice (A82/182). Only A52 weld material comes in direct contact with the primary water. The PBNP Unit 1 and 2 RPV Heads were replaced in 2005.

4.4.2 RPV Lower Head BMI Nozzles The PBNP 1 and 2 Alloy 600 BMI nozzles are attached to the lower RPV vessel using J-groove welds.

a. Full Nozzle Repair The failed nozzle is replaced in its original configuration. Radiological conditions would likely make this method impractical.

b. Half Nozzle Repair The outer portion of the nozzle is machined out from below, leaving the defect in the inner portion of the nozzle and/or j-groove weld in place. A half nozzle is inserted below and welded to the RPV lower head base material.

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL ALLOY 600 MANAGEMENT PROGRAM NP 7.7.31 Revision 6 Page 13 of 30 INFORMATION USE

c. Mini-Inside Diameter Temper Bead Repair The mid-wall or ID temper bead repair involves removing the nozzle and machining the nozzle remnant away to a depth of approximately half the component wall thickness. The bore is liquid penetrant inspected. The replacement nozzle is then installed into the bore and welded into place to the inside diameter of the bore using an Alloy 690 (Filler Metal 52). A machine GTAW process employing the ambient temperature temper bead welding technique is used. The inside diameter of the weld deposit is machined and/or ground to establish the nozzle bore. The weld deposit is examined by liquid penetrant and ultrasonic examination. This method can be used in nozzle bores as small as one inch in diameter, making it an effective approach for bottom mounted nuclear instrumentation nozzle BMI repairs. However, for Point Beach, this method would be impractical since the BMI nozzle IDs are 0.390 and 0.375 for Units 1 and 2, respectively.

4.5 Mitigation Methods There are a number of mitigation methods for PWSCC that may provide cost effective alternatives to the replacement of Alloy 600 components. Most of these methods have previously been utilized to address IGSCC of austenitic SS in BWRs. Their functions vary from providing preventative benefits to total structural replacement. Mitigation methods include:

4.5.1 Mechanical Stress Improvement (MSIP) 4.5.2 Induction Heating Stress Improvement (IHSI) 4.5.3 Weld Overlay 4.5.4 Mechanical Nozzle Seal Assembly (MSNA) 4.5.5 Zinc Injection 4.5.6 Abrasive Water Jet (AWJ) 4.5.7 Nickel Plating 4.5.8 Cavitation Peening

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL ALLOY 600 MANAGEMENT PROGRAM NP 7.7.31 Revision 6 Page 14 of 30 INFORMATION USE 4.6 PWSCC Susceptibility Ranking 4.6.1 Historical Ranking Models The NSSS owners groups and EPRI developed a number of PWSCC ranking models following the discovery of PWSCC in RPV upper head nozzles at Bugey and several other foreign PWRs in the early 1990s. The models attempted to incorporate differences in operating time and temperature, water chemistry environment, surface stress, component geometry, material yield strength and microstructure, and fabrication practices (amount of cold work during machining). Unfortunately, uncertainties about surface stress state, microstructure and fabrication practices introduced significant error into all these models.

Subsequent to the discovery of circumferential cracking in CRDM nozzles at Oconee-3, the EPRI Materials Reliability Program (MRP) submitted the MRP-44, Part 2 report to provide an interim safety assessment for PWSCC of alloy RPV upper head nozzles and associated Alloy 182 J-groove welds in PWR plants. This report included a simplified ranking model based only upon the operating time and temperature of the RPV head penetrations, effective full power years (EFPY). This model was later challenged by the discovery of PWSCC in three RPV upper head penetrations at Millstone Unit 2 in 2002 which had been ranked as one of the least susceptible plants.

In Bulletin 2002-02, the NRC described of a comprehensive RPV upper head examination program that addressed a combination of visual and non-visual examinations on a graded approach based upon plant susceptibilities to PWSCC. This Bulletin introduced a time at temperature model, effective degradation years (EDY), to characterize plant susceptibility. This same model was included in the subsequent Orders (EA-03-009 Revisions 0 and 1) to determine the frequency and type of examinations for RPV head penetrations at individual plants.

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL ALLOY 600 MANAGEMENT PROGRAM NP 7.7.31 Revision 6 Page 15 of 30 INFORMATION USE

5.0 REFERENCES

5.1 Source Documents 5.1.1 CIM-00109, WEST, Unit 2 Steam Generators 5.1.2 CIM-00112, CE, Unit 2 Reactor Vessel 5.1.3 CIM-00210, B/W, Unit 1 Reactor Vessel 5.1.4 WCAP-16345-P, Nuclear Management Company - Point Beach Unit 1 Nuclear Power Plant Replacement Reactor Vessel Closure Head - Design Report 5.1.5 WCAP-16266-P, Nuclear Management Company - Point Beach Unit 2 Nuclear Power Plant Replacement Reactor Vessel Closure Head - Design Report 5.1.6 Westinghouse Letter WEP-02-8, Point Beach Units 1 and 2 Reactor Internals CMTR Summary, dated September 12, 2002 5.2 Reference Documents 5.2.1 EPRI MRP-126, Generic Guidance for Alloy 600 Management.

5.2.2 NEI 03-08, Guideline for the Management of Materials Issues.

5.2.3 EPRI MRP-227, PWR Internals Inspection and Evaluation Guidelines.

5.2.4 EPRI MRP-44, PWR Materials Reliability Project Interim Alloy 600 Safety Assessments for US PWR Plants.

5.2.5 EPRI MRP-139, Materials Reliability Program: Primary System Piping Butt Weld Inspection and Evaluation Guidelines.

5.2.6 ASME Boiler and Pressure Vessel Code Case N-722-X (applicable version in 10CFR50.55a), Additional Examinations for PWR Pressure Retaining Welds in Class 1 Components Fabricated With Alloy 600/82/182 Materials. (Note:

This Code Case was mandated by 10CFR50.55a dated September 10, 2008.)

5.2.7 ASME Boiler and Pressure Vessel Code Case N-729-X (applicable version in 10CFR50.55a). (Note: This Code Case was mandated by 10CFR50.55a dated September 10, 2008.)

5.2.8 ER-AA-105, Reactor Coolant System Materials Degradation Management Program (RCS MDMP).

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL ALLOY 600 MANAGEMENT PROGRAM NP 7.7.31 Revision 6 Page 16 of 30 INFORMATION USE 5.2.9 NRC Letter TAC No. ML092710593, Safety Evaluation of the Alloy 600 Program License Renewal Commitment Submittal, FPL Energy Point Beach, LLC, Dated October 6, 2009.

5.2.10 EPRI MRP-76, "Report on Repair and Mitigation Historical Applications".

5.2.11 ASME Boiler and Pressure Vessel Code Case N-770-X (applicable version in 10CFR50.55a). (Note: This Code Case was mandated by 10CFR50.55a dated June 21, 2011.)

5.2.12 ER-SR-107, Alloy 600 Management Program.

5.2.13 WCAP-16983-P, Point Beach Units 1 and 2 Extended Power Uprate (EPU)

Engineering Report, Revision 0, dated September 2009.

5.3 Records None 6.0 BASES B-1 LR-AMP-0113-RCA600, RCS Alloy 600 Inspection Program Basis Document for License Renewal B-2 NUREG-1839, US NRC Safety Evaluation Report Related to the License Renewal of the Point Beach Nuclear Plant, Unit 1 and 2 B-3 NRC SER Dated March 22, 2016, Point Beach Nuclear Plant, Unit 2 - Approval of Relief Request 2-RR-11; Steam Generator Nozzle to Safe-End Dissimilar Metal (OM)

Weld Inspection

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL ALLOY 600 MANAGEMENT PROGRAM NP 7.7.31 Revision 6 Page 17 of 30 INFORMATION USE ATTACHMENT A ALLOY 600 REPAIRS/REPLACEMENTS Page 1 of 1 Unit Location Tag ID Repair/Replacement Date Repair/Replacement Method Inconel Buildup Pad Design Document Reason for Replacement PB-1 Reactor Pressure Vessel Head 11/05 New Head Modification MR 03-047 PB-1 Steam Generator Bowl Drains 10/17 Half Nozzle Repair was completed during U1R37 EC 288078 PB-2 Reactor Pressure Vessel Head 7/05 New Head Modification MR 03-056

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL ALLOY 600 MANAGEMENT PROGRAM NP 7.7.31 Revision 6 Page 18 of 30 INFORMATION USE ATTACHMENT B NRC GENERIC COMMUNICATIONS Page 1 of 7 NRC Information Notice (IN) 90-10 (February 23, 1990), Primary Water Stress Corrosion Cracking (PWSCC) of Inconel 600, was issued to alert PWR licensees of the potential problems associated with PWSCC of Alloy 600 that had occurred at several domestic and foreign PWR plants. During the 1989 RFO at Calvert Cliffs Unit 2, visual examination detected leakage in 20 pressurizer heater sleeves and 1 upper-level pressurizer instrument nozzle. Subsequent NDE confirmed the presence of axially oriented, crack-like indications in these components and 4 additional heater sleeves. The causative failure mechanism was postulated to be PWSCC.

On February 27, 1986 leakage was detected in an upper-level pressurizer instrument nozzle at San Onofre Nuclear Generating Station Unit 3. Subsequent NDE and metallurgical examination revealed the leak path to be axially oriented PWSCC.

In spring 1989, leakage from pressurizer instrument nozzles was observed in two foreign PWRs.

NDE revealed crack like indications that were both axially and circumferentially oriented. NDE of five additional PWRs revealed 12 more nozzles with crack-like indications.

NRC Generic Letter (GL) 97-01 (April 1, 1997), Degradation of Control Rod Drive Mechanism Nozzle and Other Vessel Closure Head Penetrations, requested PWR licensees to describe their program for ensuring the timely inspection of the control rod drive mechanisms (CRDMs) and other reactor vessel head penetrations (RVHPs). In addition, licensees were asked to assess and provide a description of any resin bead intrusion, as described in NRC Information Notice (IN) 96-11, which would have resulted in sulfate levels exceeding the EPRI primary water chemistry guidelines.

PBNP Response:

Letter No. NPL 97-0420, dated July 30, 1997 NRC IN 2000-17 (October 18, 2002), Crack in Weld Area of Reactor Coolant System Hot Leg Piping at V.C. Summer, described the licensees discovery of leakage from the air boot around the A loop RCS hot leg pipe on 10/7/2000. Subsequent NDE revealed that the leak path was an ID initiated axial indication the Alloy 182/82 weld metals. A metallurgical failure analysis determined that the causative failure mechanism was PWSCC. High residual tensile stresses resulting from extensive weld repairs during original construction were determined to have been a significant contributor. The "A" loop hot leg weld was removed and replaced in its entirety.

The licensee also identified other ECT indications in four of the other five reactor coolant system nozzle to pipe welds. Westinghouse performed an evaluation to justify continued operation of the B and C hot legs without repair of these ECT indications.

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL ALLOY 600 MANAGEMENT PROGRAM NP 7.7.31 Revision 6 ATTACHMENT B NRC GENERIC COMMUNICATIONS Page 19 of 30 INFORMATION USE Page 2 of 7 As a result of their evaluation of this event, the NRC identified several generic issues:

1) potential weaknesses in the ability of the ASME Code-required non-destructive examination techniques to detect and size small inner-diameter stress corrosion cracks; 2) potential weaknesses in the ASME Code that allows multiple weld repairs which affect residual weld stress and PWSCC; and 3) potential weaknesses in RCS leak detection systems; and

4) questions regarding the continued applicability of leak before break analyses.

NRC IN 2001-05 (April 30, 2001), Through-Wall Circumferential Cracking of Reactor Pressure Vessel Head Control Rod Drive Mechanism Penetration Nozzles at Oconee Nuclear Station, Unit 3, was issued to alert addressees to the recent detection of through-wall circumferential cracks in two of the control rod drive mechanism (CRDM) penetration nozzles and weldments at the Oconee nuclear Station, Unit 3 (ONS3). On February 18, 2001, nine leaking CRDM nozzles at ONS3 were detected by visual examinations during a planned maintenance outage. All of the flaws were initially characterized as either axial or below-the-weld circumferential indications by NDE. However, subsequent NDE and metallurgical examinations revealed the presence of OD initiated PWSCC, located above the welds and with circumferential orientation in two of the nozzles. The discovery of such flaws challenged previous safety assessments conducted by the PWR owners groups and the NRC that had assumed PWSCC of RPVH penetrations would be predominantly axial in orientation.

NRC Bulletin 2001-01 (August 3, 2001), Circumferential Cracking of Reactor Pressure Vessel Head Penetration Nozzles, was issued following the discovery of circumferential cracks in two CRDM nozzles at Oconee Nuclear Station Unit 3 (ONS3). The bulletin requested PWR licensees to provide information related to the structural integrity of the RPVH penetration nozzles. The requested data included the results of previous inspections, the inspections and repairs undertaken to satisfy applicable regulatory requirements, and the basis for concluding that future inspections would ensure compliance with applicable regulatory requirements. This information was provided to the NRC in the letters listed below. The NRC responded in a letter dated August 16, 2002 that PBNP provided the requested information.

In response to NRC Bulletin 2001-01, a bare metal visual examination of the RPV upper head was performed during the Unit 2 Spring 2002 outage and the Unit 1 Fall 2002 refueling outage with acceptable results. Reactor Vessel Head Inspection Findings were provided to the NRC in letters NRC 2002-0050 and NRC 2002-0102.

PBNP Responses: to Letter No. NRC 2001-060, dated September 4, 2001 to Letter No. NRC 2002-0002, dated January 3, 2002 Letter No. NRC 2002-0011, dated January 28, 2002 Letter No. NRC 2002-0038, dated May 09, 2002 Letter No. NRC 2002-0050, dated June 12, 2002 - Unit 2 Reactor Vessel Head Inspection Findings Letter No. NRC 2002-0102, dated November 15, 2002 - Unit 1 Reactor Vessel Head Inspection Findings

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL ALLOY 600 MANAGEMENT PROGRAM NP 7.7.31 Revision 6 ATTACHMENT B NRC GENERIC COMMUNICATIONS Page 20 of 30 INFORMATION USE Page 3 of 7 NRC IN 2002-11 (March 12, 2002), Recent Experience with Degradation of Reactor pressure Vessel Head, was issued following the discovery of severe degradation of the RPVH at Davis-Besse Nuclear Power Station. On February 27, 2002 while conducting RPVH inspections in response to Bulletin 2001-01, the licensee discovered axially oriented PWSCC in three CRDM nozzles in the RPVH. Part way through the repair process on one of the nozzles, a cavity in RPVH was discovered. Leaking boric acid had consumed the ferritic steel in a localized region on the downstream side of the nozzle, leaving only the 3/8 SS cladding still intact.

NRC Bulletin 2002-01 (March 18, 2002), Pressure Vessel head Degradation and Reactor Coolant Pressure Boundary Integrity, was issued following the discovery by Davis-Besse of cracking in several CRDM nozzles and significant reactor head degradation associated with one of these leaking nozzles. The bulletin requested PWR licensees to provide: 1) information related to the integrity of the reactor coolant pressure boundary including the reactor pressure vessel head and the extent to which inspection and maintenance programs have been undertaken to satisfy applicable regulatory requirements, and 2) the basis for concluding that plants satisfy applicable regulatory requirements related to the structural integrity of the reactor coolant pressure boundary and future inspections will ensure continued compliance with applicable regulatory requirements. A Request for Additional Information (RAI) was later issued by the NRC in a letter dated November 18, 2002 to obtain more detailed information regarding licensees boric acid corrosion control (BACC) programs.

PBNP Responses:

Letter No. NRC 2002-0027, dated April 2, 2002 Letter No. NRC 2002-0029, dated April 18, 2002 Letter No. NRC 2002-0037, dated May 9, 2002 to Letter No. NRC 2002-043, dated May 16, 2002 Letter No. NRC 2002-0050, dated June 12, 2002 Letter No. NRC 2002-0102, dated November 15, 2002 Letter No. NRC 2003-0006, dated January 20, 2003

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL ALLOY 600 MANAGEMENT PROGRAM NP 7.7.31 Revision 6 ATTACHMENT B NRC GENERIC COMMUNICATIONS Page 21 of 30 INFORMATION USE Page 4 of 7 NRC IN 2002-13 (April 4, 2002), Possible Indicators of Ongoing Reactor Pressure Vessel Head Degradation, was issued to report the findings of an augmented inspection team (AIT) sent by the NRC to investigate the circumstances of the degradation of the Davis-Besse RPVH material.

This AIT identified several possible indicators of the observed reactor pressure boundary degradation. These included: 1) unidentified RCS leakage; 2) containment air cooler fouling; and 3) radiation element filter fouling. Licensees were advised to be aware of such indicators even though they do not provide clear evidence of ongoing degradation.

NRC Bulletin 2002-02 (August 9, 2002), Reactor Pressure Vessel Head and Vessel Head Penetration Nozzle Inspection Programs, was issued in response to the discoveries of circumferential cracking of VHP nozzles at Oconee Nuclear Station 3 and other PWR facilities, the RPV head material degradation at Davis-Besse, and the NRCs review of licensees responses to Bulletins 2001-01 and 2002-01. These issues raised concerns about the adequacy of current inspection programs that rely solely on visual examinations as the primary inspection method to ensure RPVH and VHP nozzle structural integrity and compliance with applicable regulations. PWR licensees were strongly encouraged to supplement their inspection programs with non-visual methods and to provide technical justification for the efficacy of these programs.

In response to NRC Bulletin 2002-02, an ultrasonic examination of the vessel head penetration (VHP) nozzle base material and a supplemental ultrasonic leak path examination of the interference region of the VHP penetrations were performed. These examinations were started for Unit 1, during the U1R27 Fall 2002 refueling outage and were performed on a refueling outage interval until the reactor pressure vessel head was replaced during U1R29 (Fall 2005).

During the Unit 1 refueling outage (U1R28) Spring 2004, the UT examinations showed a flaw in penetration 26 that exceeded the acceptance criteria of the original design and repairs were made under modification MR 03-041. These examinations were also started for Unit 2, during the U2R26 Fall 2003 refueling outage and were performed on a refueling outage interval until the reactor pressure vessel head was replaced during U2R27 (Spring 2005).

PBNP Responses:

Letter No. NRC 2002-0082, dated September 12, 2002 Letter No. NRC 2002-0102, dated November 15, 2002

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL ALLOY 600 MANAGEMENT PROGRAM NP 7.7.31 Revision 6 ATTACHMENT B NRC GENERIC COMMUNICATIONS Page 22 of 30 INFORMATION USE Page 5 of 7 NRC Order EA-03-009 (February 11, 2003) modified PWR licenses by establishing required inspections of RPV heads and associated penetration nozzles. The NRC felt that these requirements were necessary to provide reasonable assurance that plant operations did not pose an undue risk to the public health and safety. The inspection requirements included: 1) bare metal visual (BMV) inspections of the RPVH surface, including 360o around each penetration nozzle, and 2) volumetric (UT) or surface (ECT or PT) inspections of the wetted surface of each J-Groove weld and RPVH penetration nozzle base material. The frequency of these examinations was determined by a reactors susceptibility category, calculated as effective degradation years (EDY) based upon operating time and RVH temperature. The requirements of the Order were expected to remain in effect pending long-term changes to the NRC regulations, specifically 10 CFR 50.55a.

NRC Regulatory Issue Summary (RIS) 2003-13 (July 29, 2003), NRC Review of Responses to Bulletin 2002-01, Reactor pressure vessel Head Degradation and Reactor Coolant Pressure Boundary Integrity, provided the conclusions of the NRC staffs review of PWR licensees responses to Bulletin 2002-01. In it, they concluded that: 1) most licensees do not perform inspections of Inconel Alloy 600/82/182 materials beyond those required by Section XI of the ASME Code, 2) such inspections are generally performed without removing insulation and are not capable, in many cases, of detecting through-wall leakage, and 3) existing monitoring programs may need to be enhanced to ensure early detection and prevention of leakage from the RCPB. No responses to the RIS from PWR licensees were required.

NRC Bulletin 2003-02 (August 21, 2003), Leakage from Reactor Pressure Vessel Lower Head Penetrations and Reactor Coolant Pressure Boundary Integrity, was issued subsequent to the discovery of two leaking bottom mounted instrumentation (BMI) penetration in the RPV lower head at South Texas Project Unit 1 on April 12, 2003. The NRC advised PWR licensees that current methods of inspecting the RPV lower head penetrations may need to be supplemented with additional measures (e.g., bare-metal visual inspections (BMV) to detect RCPB leakage.

Licensees were requested to provide a description and findings of the RPV lower head inspection program that has been performed in the past, and a description of the program that will be implemented during future refueling outages. Inspection results were provided in letters NRC 2004-0006 and NRC 2004-0077. The NRC replied in a letter dated November 22, 2004 that PBNP met the reporting requirements of this Bulletin.

In response to NRC Bulletin 2003-02, a bare metal visual examination of the RPV lower head and BMI nozzles were performed during the Unit 2 October 2003 outage and the Unit 1 April 2004 refueling outage with acceptable results. Each of the 36 BMI nozzles per head were examined with VT-1 quality resolution 360 degrees around their circumference, as well as all bare metal for at least six (6) to twelve (12) inches above the highest BMI.

PBNP Responses:

Letter No. NRC 2003-0089, dated September 22, 2003 Letter No. NRC 2004-0006, dated January 15, 2004 - Unit 2 Reactor Vessel Inspections Letter No. NRC 2004-0077, dated August 6, 2004 - Unit 1 Reactor Vessel Inspections

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL ALLOY 600 MANAGEMENT PROGRAM NP 7.7.31 Revision 6 ATTACHMENT B NRC GENERIC COMMUNICATIONS Page 23 of 30 INFORMATION USE Page 6 of 7 NRC IN 2003-11 (August 13, 2003), Leakage Found on Bottom Mounted Instrumentation Nozzles, described indications of leakage in the form of boron deposits discovered on two bottom-mounted instrumentation (BMI) nozzles at South Texas Project Unit 1 (STP Unit 1).

These deposits were discovered while performing BACC walkdowns during the units 1RE11 RFO. Similar inspections performed during the prior RFO had not detected any evidence of leakage.

NRC Information Notice 2003-11 Supplement 1 (January 8, 2004), Leakage Found on Bottom Mounted Instrumentation Nozzles, provided the destructive examination results of the boat sample extracted from the STP Unit 1 BMI nozzle: 1) the nozzle exhibited OD initiated, axially oriented PWSCC in the vicinity of the J-groove weld; 2) there was evidence of LOF at the tube-to-weld interface; 3) the leak path in the weld metal was a crack-like defect that was thought to be an initial fabrication flaw. The 561oF operating temperature of the BMIs was the lowest recorded temperature for PWSCC of an Alloy 600 component in an operating PWR to date.

NRC First Revised Order EA-03-009 (February 20, 2004) was issued to address revisions to bare metal visual inspections, penetration nozzle inspection coverage, flexibility in combination of non-destructive examination methods, flaw evaluation and requirements for plants which had replaced their RPV heads. These were common issues that had emerged in numerous relaxation requests from licensees since original issuance of the Order.

PBNP Response:

Letter No. NRC 2004-0023, dated March 10, 2004 NRC Bulletin 2004-01 (May 28, 2004), Inspection of Alloy 82/182/600 Materials Used in the Fabrication of Pressurizer Penetrations and Steam Space Piping Connections at Pressurized Water Reactors, was issued to advise PWR licensees that existing inspection methods may need to be supplemented to detect and characterize PWSCC flaws. Licensees were requested to provide descriptions of the pressurizer penetrations and steam space piping, as well as past and future inspections that will be performed to ensure that degradation of Alloy 600/82/182 materials used in the fabrication of the pressurizer penetrations and steam space piping connection will be identified, adequately characterized and repaired.

PBNP responded to Bulletin 2004-01 indicating that no Alloy 82/182/600 materials exist in the PBNP Unit 1 and Unit 2 pressurizers. The NRC replied in a letter dated March 7, 2006 that, based on the responses to items 1a, 1b, 1c, and 1d of the Bulletin, the NRC staff no longer requires a specific response for PBNP for item 2 of the Bulletin.

PBNP Response:

Letter No. NRC 2004-0075, dated July 23, 2004

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL ALLOY 600 MANAGEMENT PROGRAM NP 7.7.31 Revision 6 ATTACHMENT B NRC GENERIC COMMUNICATIONS Page 24 of 30 INFORMATION USE Page 7 of 7 NRC IN 2004-11, (May 6, 2004) Cracking in Pressurizer Safety and Relief Nozzles and in Surge Line Nozzle, described the discovery of PWSCC in several bimetallic nozzle-to-safe end welds. In September 2003, axially oriented cracks were discovered in the Alloy 132 weld metal joining the 316 SS safe ends to the low alloy steel pressurizer safety and relief nozzles at Tsuruga Unit 2. In October 2003, a similar indication was discovered by UT in Alloy 82/182 weld metal joining the carbon steel surge line nozzle to cast 316 SS safe end at Three Mile Island, Unit 1 (TMI-1). Investigations conducted by both utilities revealed evidence of previous weld repairs during construction on the safety nozzle at Tsuruga and the surge line nozzle at TMI-1. TMI-1 performed a full structural weld overlay repair to maintain weld integrity.

NRC IN 2005-02 (February 4, 2005) Catawba SG Bowl Drain Cracking, described the discovery of boric acid deposits in the vicinity of a SG bowl drain line while conducting bare metal visual examinations of the plants Alloy 600/82/182 components during the Fall 2004 Unit 2 RFO. The hot and cold leg temperatures were reported to be 617oF and 588 oF, respectively. It was noted that the leakage would have gone undetected if the surrounding insulation had not been removed to facilitate the inspections. No response from PWR Licensees was requested.

NRC Regulatory Issue Summary 2008-25 (October 2, 2008) Regulatory Approach For Primary Water Stress Corrosion Cracking Of Dissimilar Metal Butt Welds In Pressurized Water Reactor Primary Coolant System Piping described the regulatory approach for ensuring the integrity of primary coolant system dissimilar metal (DM) butt welds containing Alloy 82/182 in pressurized-water reactor (PWR) power plants. No response from PWR Licensees was requested.

NRC Regulatory Issue Summary 2015-10 (July 16, 2015), Applicability of ASME Code Case N-770-1 as Conditioned in 10 CFR 50.55a, Codes and Standards, to Branch Connection Butt Welds. This RIS informs addressees about reactor coolant system (RCS)

Alloy 82/182 branch connection dissimilar metal nozzle welds that may be of a butt weld configuration and therefore require inspection under 10 CFR 50.55a(g)(6)(ii)(F),

Augmented ISI [inservice inspection] requirements: Examination requirements for Class 1 piping and nozzle dissimilar-metal butt welds. This RIS required no action or written response. Operating Experience Evaluation 02072895-01 was completed in response to this RIS and concluded that PBNP met NRC regulations regarding inspection requirements.

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL ALLOY 600 MANAGEMENT PROGRAM NP 7.7.31 Revision 6 Page 25 of 30 INFORMATION USE ATTACHMENT C ALLOY 600/82/182 LOCATIONS Page 1 of 6 Information Description PWSCC Susceptibility Weld number Location Material Pipe Dia.

Thickness Operating Temperature Failure Consequence Ranking (Low, Moderate, High, Very High)

Unit 1 Vessel Head Penetrations (38)

Reactor Vessel Head A690 A52/152 4

.625 611.1oF (Note 1)

B,E,G Low - Resistant Material BMI Nozzles (36)

Bottom Mounted Instrumentation SB-166 A600 1.5" 0.390 ID 540ºF B,E,G Moderate -(Low Temperature, Low Probability of failure, good industry exam record)

Internal clad Bottom 11-7/8 inches of lower shell course A82/182 N/A N/A 540ºF None Low - (No Industry OE of Failure, Low Consequence, Not Pressure Boundary)

SG Channel Head Drains 1 per SG A52

.375" 0.091" (Note 2)

B,E,G Low - (Resistant Material)

SG Channel Head Divider Plate 1 per SG SB-166 A600 N/A 2.0 (Note 2)

None (under evaluation)

Low - (Foreign OE exists, No domestic OE of failure, Not Pressure Boundary]

RV Clevis Insert Lock Keys Reactor Vessel A600 N/A N/A 540ºF G

Low - (Low Consequence, Not Pressure Boundary)

RV Clevis Inserts Reactor Vessel Internals A600 N/A N/A 540ºF G

Low - (Low Consequence, Not Pressure Boundary)

SG Nozzle Dam Rings SG Nozzles A600 N/A NA 540ºF / 611.1ºF G

Low - (No Industry OE of Failure, Low Consequence, Not Pressure Boundary)

B - Causes a design-basis accident.

E - Breaches reactor coolant pressure boundary integrity.

G - Causes a significant economic impact. Significant events are those for which we do not have a proven fix and would result in significant regulatory and/or public scrutiny, such as first-of-a-kind consideration would be a suitable test. It can be considered that non-significant events are those for which it is expected that a proven fix exists that will require minimal regulatory and/or public scrutiny.

Note 1 - Per Section 3.2.4 of WCAP-16893-P, the upper head region fluid temperature is slightly below THOT. THOT temperature conservatively assumed.

Note 2 - Temperature between THOT. (611.1ºF) and TCOLD (540ºF)

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL ALLOY 600 MANAGEMENT PROGRAM NP 7.7.31 Revision 6 ATTACHMENT C ALLOY 600/82/182 LOCATIONS Page 26 of 30 INFORMATION USE Page 2 of 6 Information Description PWSCC Susceptibility Weld number Location Material Pipe Dia.

Thickness Operating Temperature Failure Consequence Ranking (Low, Moderate, High, Very High)

Unit 2 Vessel Head Penetrations (38)

Reactor Vessel Head A690 A52/152 4

.625 611.1oF (Note 1)

B,E,G Low - Resistant Material BMI Nozzles (36)

Bottom Mounted Instrumentation SB-166 A600 1.5" 0.375 ID 540ºF B,E,G Moderate - (Low Temperature, Low Probability of failure, good industry exam record)

RC-34-MRCL-AI-05 SG 'A' Hot Leg S/G Primary Nozzle Safe-End Weld A82/182 34" 3" nominal 611.1ºF B,E,G Low - (Clad with Alloy 52 during initial fabrication)

RC-36-MRCL-AII-01A SG 'A' Cold Leg S/G Primary Nozzle Safe-End Weld A82/182 36 3" nominal 540ºF B,E,G Low - (Clad with Alloy 52 during initial fabrication)

RC-34-MRCL-BI-05 SG 'B' Hot Leg S/G Primary Nozzle Safe-End Weld A82/182 34" 3" nominal 611.1ºF B,E,G Low - (Clad with Alloy 52 during initial fabrication)

RC-36-MRCL-BII-01A SG 'B' Cold Leg S/G Primary Nozzle Safe-End Weld A82/182 36 3" nominal 540ºF B,E,G Low - (Clad with Alloy 52 during initial fabrication)

Primary Vent Nozzles (4) 2 per SG Steam Generator A690 A152 0.75" 0.154" 540 ºF &

611.1ºF B,E,G Low - Resistant Material RV Clevis Insert Lock Keys Reactor Vessel A600 N/A N/A 540ºF G

Low - (No Industry OE of Failure, Low Consequence, Not Pressure Boundary)

RV Clevis Inserts Reactor Vessel Internals A600 N/A N/A 540ºF G

Low -(No Industry OE of Failure, Low Consequence, Not Pressure Boundary)

B - Causes a design-basis accident.

E - Breaches reactor coolant pressure boundary integrity.

G - Causes a significant economic impact. Significant events are those for which we do not have a proven fix and would result in significant regulatory and/or public scrutiny, such as first-of-a-kind consideration would be a suitable test. It can be considered that non-significant events are those for which it is expected that a proven fix exists that will require minimal regulatory and/or public scrutiny.

Note 1 - Per Section 3.2.4 of WCAP-16893-P, the upper head region fluid temperature is slightly below THOT. THOT temperature conservatively assumed.

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL ALLOY 600 MANAGEMENT PROGRAM NP 7.7.31 Revision 6 ATTACHMENT C ALLOY 600/82/182 LOCATIONS Page 27 of 30 INFORMATION USE Page 3 of 6 Inspections 1, 2 Weld number Most Recent BMV Exam BMV Results Current BMV Frequency Next Scheduled BMV As-Built Geometry Acquired PWSCC Category Volumetric Inspection Comments Unit 1 Vessel Head Penetrations (38)

Per ISI Program NRI 3 Each RFO Per ISI Program Yes A 4, 5 Fall 2023 Per ASME Code Case N-729-X. BMV per PBNP Letter NRC 2002-0082.

BMI Nozzles (36)

Per ISI Program NRI 3 Each RFO Per ISI Program N/A N/A N/A Code Case N-722-X No commitment at this time for UT. BMV per PBNP Letter NRC 2003-0089.

SG Channel Head Drains Per ISI Program NRI 3 None Required N/A N/A N/A N/A Code Case N-722-X SG Channel Head Divider Plate Spring 2013 NRI 3 None Required N/A N/A N/A N/A RV Clevis Insert Lock Keys To Follow EPRI Materials Reliability Program (MRP) Reactor Vessel Internals ITG Program Requirements RV Clevis Inserts To Follow EPRI Materials Reliability Program (MRP) Reactor Vessel Internals ITG Program Requirements SG Nozzle Dam Rings None N/A None Required N/A N/A N/A N/A NOTES:

1. 10CFR50.55a mandates that PDI techniques are used. For those welds with single-sided access, we can take credit for only that side (50%), even though we may be able to penetrate the weld and see some of the other side.

2. The PBNP Risk-Informed ISI Program does not require every DM weld to be examined. However, due to NEI 03-08 guidance and MRP-139, and subsequently replaced by Code Case N770-1 as identified in 10CFR50.55a, these DM Welds have been included in the ISI schedule. The thickness for DM safe-end welds must be determined by actual measurement. These measurements have all been performed.

3. NRI - No recordable indications.

4. PWSCC Category A - Resistant Materials.

5. Alloy 690/52/152.

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL ALLOY 600 MANAGEMENT PROGRAM NP 7.7.31 Revision 6 ATTACHMENT C ALLOY 600/82/182 LOCATIONS Page 28 of 30 INFORMATION USE Page 4 of 6 Inspections 1, 2 Weld number Most Recent BMV Exam BMV Results Current BMV Frequency Next Scheduled BMV As-Built Geometry Acquired PWSCC Category Volumetric Inspection Comments Unit 2 Vessel Head Penetrations (38)

Per ISI Program NRI 3 Each RFO Per ISI Program Yes A 4, 5 Spring 2023 Per ASME Code Case N-729-X.

BMV per PBNP Letter NRC 2002-0082.

BMI Nozzles (36)

Per ISI Program NRI 3 Each RFO Per ISI Program N/A N/A N/A Code Case N-722-X No commitment at this time for UT.

BMV per PBNP Letter NRC 2003-0089.

RC-34-MRCL-AI-05 Per ISI Program NRI 3 Each RFO Per ISI Program Yes A 4 Spring 2020 Code Cases N-722-X and N-770-X Relief Request 2-RR-11 RC-36-MRCL-AII-01A Fall 2009 NRI 3 Once per interval Per ISI Program Yes A 4 Spring 2020 Code Cases N-722-X and N-770-X Relief Request 2-RR-11 RC-34-MRCL-BI-05 Per ISI Program NRI 3 Each RFO Per ISI Program Yes A 4 Spring 2020 Code Cases N-722-X and N-770-X Relief Request 2-RR-11 RC-36-MRCL-BII-01A Fall 2009 NRI 3 Once per interval Per ISI Program Yes A 4 Spring 2020 Code Cases N-722-X and N-770-X Relief Request 2-RR-11 Primary Vent Nozzles (4) 2 per SG Fall 2009 NRI 3 N/A N/A N/A N/A N/A RV Clevis Insert Lock Keys To Follow EPRI Materials Reliability Program (MRP) Reactor Vessel Internals ITG Program Requirements RV Clevis Inserts To Follow EPRI Materials Reliability Program (MRP) Reactor Vessel Internals ITG Program Requirements NOTES:

1. 10CFR50.55a mandates that PDI techniques are used. For those welds with single-sided access, we can take credit for only that side (50%), even though we may be able to penetrate the weld and see some of the other side.

2. The PBNP Risk-Informed ISI Program does not require every DM weld to be examined. However, due to NEI 03-08 guidance and MRP-139, and subsequently replaced by Code Case N770-X as identified in 10CFR50.55a, these DM Welds have been included in the ISI schedule. The thickness for DM safe-end welds must be determined by actual measurement. These measurements have all been performed.

3. NRI - No recordable indications.

4. PWSCC Category A - Resistant Materials.

5. Alloy 690/52/152.

6. For vent nozzles at hot leg temperature. Otherwise, once per ISI interval.

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL ALLOY 600 MANAGEMENT PROGRAM NP 7.7.31 Revision 6 ATTACHMENT C ALLOY 600/82/182 LOCATIONS Page 29 of 30 INFORMATION USE Page 5 of 6 Weld Number Mitigation Options Repair Options Plan Summary Unit 1 Vessel Head Penetrations (38)

Head replaced in Fall 2005 with resistant material BMI Nozzles (36)

Preventative or Repair via a Half Nozzle Repair ASME Code Case N-722-X SG Channel Head Drains Half Nozzle Repair was completed during U1R37 SG Channel Head Divider Plate Grind indications smooth. Re-inspect with PT Visual examination concurrent with planned ECT inspections.

Follow future guidance from EPRI regarding inspection techniques, acceptance criteria and repair methods.

RV Clevis Insert Lock Keys Follow PWR Owners Group recommendations on repair strategies.

Follow EPRI RVI-ITG and Westinghouse TB-14-5 recommendations on inspections.

RV Clevis Inserts Follow PWR Owners Group recommendations on repair strategies.

Follow EPRI RVI-ITG and Westinghouse TB-14-5 recommendations on inspections.

SG Nozzle Dam Rings PWR OG Developing Repair Options Follow PWR Owners Group recommendations on possible replacement.

POINT BEACH NUCLEAR PLANT PROCEDURES MANUAL ALLOY 600 MANAGEMENT PROGRAM NP 7.7.31 Revision 6 ATTACHMENT C ALLOY 600/82/182 LOCATIONS Page 30 of 30 INFORMATION USE Page 6 of 6 Weld Number Mitigation Options Repair Options Plan Summary Unit 2 Vessel Head Penetrations (38)

Head replaced in Spring 2005 with resistant material BMI Nozzles (36)

Preventative or Repair via a Half Nozzle Repair ASME Code Case N-722-X RC-34-MRCL-AI-05 Mitigated during fabrication with inlay of A52/152 prior to installation.

None Code Cases N-722-X and N-770-X Relief Request 2-RR-11 RC-36-MRCL-AII-01A Mitigated during fabrication with inlay of A52/152 prior to installation.

None Code Cases N-722-X and N-770-X Relief Request 2-RR-11 RC-34-MRCL-BI-05 Mitigated during fabrication with inlay of A52/152 prior to installation.

None Code Cases N-722-X and N-770-X Relief Request 2-RR-11 RC-36-MRCL-BII-01A Mitigated during fabrication with inlay of A52/152 prior to installation.

None Code Cases N-722-X and N-770-X Relief Request 2-RR-11 Primary Vent Nozzles (4) 2 per SG Resistant material RV Clevis Insert Lock Keys Follow PWR Owners Group recommendations on repair strategies.

Follow EPRI RVI-ITG and Westinghouse TB-14-5 recommendations on inspections.

RV Clevis Inserts Follow PWR Owners Group recommendations on repair strategies.

Follow EPRI RVI-ITG and Westinghouse TB-14-5 recommendations on inspections.