RS-14-143, Responses to NRC Requests for Additional Information, Set 21, Dated April 17, 2014, Related to the Braidwood Station, Units 1 and 2, and Byron Station, Units 1 and 2, License Renewal Application

Responses to NRC Requests for Additional Information, Set 21, Dated April 17, 2014, Related to the Braidwood Station, Units 1 and 2, and Byron Station, Units 1 and 2, License Renewal Application

ML14135A179
Person / Time
Site:	Byron, Braidwood
Issue date:	05/15/2014
From:	Gallagher M Exelon Generation Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
RS-14-143
Download: ML14135A179 (37)

Text

Michael P. Gallagher Vice President, License Renewal Exelon Generation Exelon Nuclear 200 Exelon Way Kennett Square, PA 19348 610 765 5958 Office 610 765 5956 Fax www.exeloncorp.com michaelp.gallagher@exeloncorp.com 10 CFR 50 10 CFR 51 10 CFR 54 RS-14-143 May 15, 2014 U. S. Nuclear Regulatory Commission Attention : Document Control Desk Washington, DC 20555-0001 Braidwood Station, Units 1 and 2 Facility Operating License Nos. NPF-72 and NPF-77 NRC Docket Nos. STN 50-456 and STN 50-457 Byron Station, Units 1 and 2 Facility Operating License Nos. NPF-37 and NPF-66 NRC Docket Nos. STN 50-454 and STN 50-455

Subject:

Responses to NRC Requests for Additional Information, Set 21, dated April 17, 2014, related to the Braidwood Station, Units 1 and 2, and Byron Station, Units 1 and 2, License Renewal Application

References:

1. Letter from Michael P. Gallagher, Exelon Generation Company LLC (Exelon) to NRC Document Control Desk, dated May 29, 2013, "Application for Renewed Operating Licenses."

2. Letter from Lindsay R. Robinson, US NRC to Michael P. Gallagher, Exelon, dated April17, 2014, "Request for Additional Information for the Review of the Byron Station, Units 1 and 2, and Braidwood Station, Units 1 and 2, License Renewal Application, Set 21 (TAC NOS. MF1879, MF1880, MF1881, and MF1882)"

In the Reference 1 letter, Exelon Generation Company, LLC (Exelon) submitted the License Renewal Application (LRA) for the Byron Station, Units 1 and 2, and Braidwood Station, Units 1 and 2 (BBS). In the Reference 2 letter, the NRC requested additional information to support staff review of the LRA.

Enclosure A contains the responses to these requests for additional information.

Enclosure B contains updates to sections of the LRA (except for the License Renewal Commitment List) affected by the responses.

May 15, 2014 U.S. Nuclear Regulatory Commission Page2 Enclosure C provides an update to the License Renewal Commitment List (LRA Appendix A, Section A.5). There are no other new or revised regulatory commitments contained in this letter.

If you have any questions, please contact Mr. AI Fulvio, Manager, Exelon License Renewal, at 610-765-5936.

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

Executed on Respectfully, Vice President - License Renewal Projects Exelon Generation Company, LLC

Enclosures:

A. Responses to Requests for Additional Information B. Updates to affected LRA sections C: License Renewal Commitment List Changes cc: Regional Administrator- NRC Region Ill NRC Project Manager (Safety Review), NRR-DLR NRC Project Manager (Environmental Review), NRR-DLR NRC Senior Resident Inspector, Braidwood Station NRC Senior Resident Inspector, Byron Station NRC Project Manager, NRR-DORL-Braidwood and Byron Stations Illinois Emergency Management Agency- Division of Nuclear Safety

RS-14-143 Enclosure A Page 1 of 17 Enclosure A Byron and Braidwood Stations (BBS), Units 1 and 2 License Renewal Application Responses to Requests for Additional Information RAI B.2.1.28-3a RAI B.2.1.28-5a RAI B.2.1.8-1 RAI B.2.1.8-2 RAI B.2.1.11-1

RS-14-143 Enclosure A Page 2 of 17 RAI B.2.1.28-3a Applicability:

Bryon Station (Byron) and Braidwood Station (Braidwood), all units

Background:

By letter dated January 13, 2014, you responded to the staffs request for additional information (RAI) regarding the use of cathodic protection for buried piping systems. With regard to Enhancement No. 9, Exelon provided additional information regarding the use of soil corrosion probes. Based on its review of the response, the staff has additional questions.

1. The response to RAI B.2.1.28-3 states that if soil corrosion probes indicate a material loss of 1 mil per year (mpy) or less, the cathodic protection system would be considered effective for that given surveillance year and no further evaluation would be required.

2. The response to RAI B.2.1.28-3 states that [f]or each installation application, two (2) probes will be installed; one connected to the cathodic protection system and one left unprotected.

3. The response to RAI B.2.1.28-3 states that a remaining life calculation will be based on previous volumetric wall thickness measurements, annual corrosion rates and cumulative total loss of material since the volumetric measurements, and the current years' measured corrosion rate extrapolated through the end of the life of the plant.

4. The response to RAI B.2.1.28-3 states that NACE International Publication 05107 "Report on Corrosion Probes in Soil or Concrete," along with input from vendor, manufacturer, and NACE qualified cathodic protection experts will be used to specific details on the installation and use of the soil corrosion probes.

Issue:

1. Although the 1 mpy acceptance criterion is a standard industry value used to demonstrate an effective cathodic protection system, the staff lacks sufficient information to conclude that there is reasonable assurance that all buried in-scope piping would be capable of meeting its current licensing basis intended function with 60 mils of corrosion that could occur through the end of the period of extended operation.

2. It is not clear to the staff whether the phrase, for each installation application, applies to each cathodic protection survey data point that did not meet the negative 850mV polarization potential acceptance criterion during cathodic protection surveys.

3. It is not clear to the staff how the existing wall thickness will be determined when the specific location has not been volumetrically examined to determine the wall thickness.

It is also not clear whether nominal wall thickness or maximum wall thickness (e.g.,

nominal wall thickness plus 12-1/2 percent) will be used to determine the as-found corrosion rate when volumetric examinations have been conducted to determine wall thickness.

RS-14-143 Enclosure A Page 3 of 17

4. Neither license renewal application (LRA) Section B.2.1.28 nor Enhancement No. 9 has been revised to include the information sources (described in the Background) on how the soil corrosion probes will be installed and used. The staff considers this information to be necessary to ensure that accurate corrosion rate data will be obtained by the soil corrosion probes.

Request:

1. State whether all buried in-scope components will be able to perform their current licensing basis intended function(s) if 60 mils loss of material were to occur by the end of the period of extended operation. If this is not the case, provide the basis for why the 1 mpy criterion is acceptable.

2. Clarify whether the two probes that will be installed (one connected to the cathodic protection system and one left unprotected) will be installed at each cathodic protection survey data point that did not meet the negative 850mV polarization potential acceptance criterion during the evaluation cathodic protection survey results. If this is not the case, state the basis for how the cathodic protection system will be demonstrated effective at these locations when local probes are not used.

3. Explain:

a. How the existing wall thickness of buried in-scope components will be determined when the component has not been volumetrically examined to determine the wall thickness.

b. The basis for how as-found corrosion rates will be determined for buried in-scope piping components.

4. Revise LRA Section B.2.1.28 or Enhancement No. 9 to include pertinent information on installation and use of the soil corrosion probes.

Exelon Response:

1. A review was performed of the buried Service Water System and Main Condensate and Feedwater System piping at Byron and Braidwood, as well as Demineralized Water System piping at Byron only, to determine whether the in-scope piping could withstand 60 mils of material loss while still maintaining their intended function. This review included approximately 50 pipe lines at Byron and 25 at Braidwood. Minimum wall calculations of in-scope piping previously prepared in support of other historical examination activities were identified and included as part of the review. Documented wall thickness requirements necessary to satisfy soil overburden limits and hoop and axial stress requirements, not accounting for locations of specific geometries (e.g.,

elbows) and configurations (e.g., branch and test connections), demonstrated that all analyzed buried piping was capable of withstanding at least 60 mils of material loss, from 87.5% of the nominal thicknesses, while still maintaining their intended function.

Additionally, piping specification and system design information, such as pipe materials, material grades, pipe diameters, safety-classifications, nominal thicknesses, manufacturing tolerances, and design pressures, for all other individual in-scope buried pipe lines without associated pre-existing minimum wall calculations were also evaluated to assess pipe wall thickness requirements and margin with respect to external material

RS-14-143 Enclosure A Page 4 of 17 loss. A review of these inputs, considering the equations used in previously prepared minimum wall calculations for soil overburden and hoop stress, indicates all other buried in-scope piping (i.e., pipes which have not had minimum wall thickness requirements previously calculated) are also capable of withstanding 60 mils of material loss, from 87.5% of the nominal thickness, while still maintaining their intended function.

Based upon the above described review of available existing minimum wall calculations, as well as in-scope piping and system design information, there is reasonable assurance that sufficient pipe wall thickness margin exists for the aforementioned buried piping systems above to withstand 60 mils of material loss, while still remaining capable of performing their current licensing basis intended function(s).

2. Soil corrosion probe assemblies, including one soil corrosion probe connected to the cathodic protection system, one soil corrosion probe left unprotected, and a new reference electrode, will not necessarily be installed at each existing cathodic protection survey test point. In fact, most often, the soil corrosion probe assemblies will be installed away from existing cathodic protection test points in order to better distribute the locations of cathodic protection readings. This provides for additional information and better assessment of the cathodic protection effectiveness across the overall piping system. It also allows for finer sectionalizing or division of the piping system lengths when assessing the areas of adequate and inadequate protection.

The installation location of soil corrosion probe assemblies will be strategically selected with the assistance of NACE qualified cathodic protection experts to maximize the usefulness of the soil corrosion probe assemblies with respect to assessing overall cathodic protection. Once the soil corrosion probe assemblies are installed, data obtained from soil corrosion probes during an annual cathodic protection survey may be used to assess cathodic protection effectiveness at a particular existing test point, located away from the soil corrosion probes, when the existing test point exhibits a polarization potential that does not meet the -850mV criteria. In a situation such as this, the location of the existing test point and buried pipe of interest would need to be located between the impressed current anode bed and the soil corrosion probes exhibiting satisfactory results (i.e., soil corrosion probes located further from the anode bed than the test point location on the pipe). Additionally, the difference in the respective locations between the soil corrosion probes and the existing test point would need to be evaluated by a NACE qualified cathodic protection expert to determine whether the difference in the relative data could be reasonably attributed to other significant site features, such as exposed large surface area tank bottoms, heavily congested areas of other buried piping, or very large diameter pipes (e.g., circulating water). If the difference in the observed data could be attributed to adjacent site features, cathodic protection effectiveness at the existing test point will not be evaluated by use of data from the soil corrosion probes.

The use and applicability of soil corrosion probe data to areas away from where the soil corrosion probes are directly installed is considered valid, in certain situations, as the soil corrosion probes provide for a more accurate understanding of the relative corrosivity of the soil and the effectiveness of the cathodic protection system. In addition to installing both a cathodically protected and non-cathodically protected (i.e., freely corroding) probe, these soil corrosion probe assemblies also include the installation of a permanent

RS-14-143 Enclosure A Page 5 of 17 reference electrode for obtaining polarization potentials. Generally, both the soil corrosion probes and the permanent reference electrode are installed below-grade and in close proximity to the buried piping of interest. Placement of the reference electrode below-grade and in close proximity to the buried piping being measured allows for a more accurate reading than during normal cathodic protection surveys, which utilize a portable reference electrode taking readings from the soil surface at grade-level.

Conventional above-grade test locations with portable reference electrodes placed on the soil surface are not always directly over the piping being measured (i.e., shortest distance from the surface to the pipe), but rather can be some moderate distance away, thus further affecting the accuracy of the readings. Therefore, the readings from the new permanently installed reference electrodes associated with the soil corrosion probe assemblies produce more accurate readings. Additionally, placement of the actual soil corrosion probes directly adjacent to the buried piping of interest prior to backfilling an excavated area allows for the probes to more accurately reflect the true corrosion potential experienced by the pipe itself.

The use of the soil corrosion probes and associated new permanent reference electrodes also allows for evaluating the relative effectiveness of the cathodic protection system in mitigating corrosion, even when the -850mV polarization potential criterion is not achieved. While the -850mV criterion is the standard acceptance criterion used when evaluating cathodic protection, often the true polarization potential needed to mitigate corrosion is less negative. For example, if a soil corrosion probe were to exhibit a corrosion rate of less than 1 mpy while the reported polarization potential readings from the new permanently installed reference electrode were less negative than -850mV (e.g., -700mV), the soil corrosion probe would demonstrate that adequate cathodic protection is still being provided despite not meeting the -850mV NACE criterion. In such situations, other adjacent convention test points exhibiting values less negative than -850mV could be evaluated, as applicable, in accordance with the criteria described above. Therefore, the soil corrosion probes can potentially demonstrate that certain in-scope buried piping is adequately protected even when the -850mV criterion is not achieved.

In summary, soil corrosion probe assemblies are not planned to be installed at each cathodic protection test point evaluated during annual surveys. Rather, the soil corrosion probes will be installed away from existing cathodic protection test points in areas with limited existing cathodic protection information. They will also be strategically placed, with guidance from industry experts, in order to provide bounding information to verify and further evaluate the results of existing test point data on buried piping that is located closer in proximity to the actual anode beds. Given that the soil corrosion probes and new permanently installed reference electrodes provide more detailed and accurate data than a conventional test point, surveyed with a portable surface electrode, data from the soil corrosion probe assemblies may be used to evaluate cathodic protection effectiveness at locations already assessed by existing conventional test points. Placement of the soil corrosion probe assemblies will consider factors such as the location of the nearest anode beds, proximity of the buried in-scope piping of interest and respective test points to the anode beds, and adjacent site features which could affect the measurements taken from both the test points and the soil corrosion probe assemblies.

RS-14-143 Enclosure A Page 6 of 17 3a. Remaining life calculations will be performed in order to assess the effectiveness of the cathodic protection system. The calculations will utilize actual volumetric inspection data of piping that is exposed by excavation when the soil corrosion probe assemblies are installed. Installation of soil corrosion probes will typically be coordinated with the excavation and inspection of buried piping of interest (e.g., locations exhibiting historically low levels of cathodic protection). This allows for the soil corrosion probe to be electrically connected to and installed in close proximity to the actual piping being assessed. As a result, both the soil corrosion probe and the pipe are exposed to the same soil and cathodic protection conditions. The volumetric data obtained from previous excavations may be used as an input into a remaining life calculation to assess cathodic protection effectiveness, for the portion of piping monitored by the soil corrosion probe, during future annual surveys. Since the remaining life calculations require as-found wall thickness measurements, this method of assessing cathodic protection effectiveness will only be utilized in locations where buried piping has been volumetrically examined during installation of the soil corrosion probes. For any locations in which soil corrosion probes are installed without excavation, and volumetric examination of piping is not possible, the remaining life calculations will not be used to demonstrate cathodic protection effectiveness.

3b. The as-found corrosion rate determined at the time of the volumetric examination, based on either the nominal wall thickness or maximum wall thickness (e.g., nominal wall thickness plus 12-1/2 percent), is not required to be determined for the purposes of performing remaining life calculations to assess cathodic protection effectiveness during future annual surveys. The use of remaining life calculations to assess cathodic protection effectiveness during future annual surveys will be based on the following criteria:

As-found pipe wall thickness values obtained from volumetric examinations conducted during previous excavations and inspections (i.e., during installation of the probes)

All corrosion and corrosion rate data taken from the probes over the time period between when the probes were originally installed up through the particular annual survey year being evaluated The observed corrosion rate over the last one (1) year prior to the annual survey year being evaluated. This corrosion rate will be assumed constant and projected through the end of the period of extended operation.

This methodology is considered appropriate because the calculation accounts for all previous cumulative loss of material that has occurred prior to the particular annual survey which is being evaluated, while also assessing whether the performance of the cathodic protection system over the last one year has been effective in mitigating corrosion to the extent that the component intended function would be maintained if those conditions continued for the remainder of the life of the plant. Cathodic protection will be considered effective, for the portion of piping monitored by the probe and for the given surveillance year being evaluated, if the above factors demonstrate that the piping will continue to perform its intended function through the period of extended operation.

These conditions would then be re-evaluated the following year during the next annual survey, if the other cathodic protection acceptance criteria were not satisfied. Therefore, for the purposes of assessing cathodic protection effectiveness using soil corrosion

RS-14-143 Enclosure A Page 7 of 17 probe data and remaining life calculations during annual cathodic protection surveys, the as-found corrosion rate, determined at the time of the volumetric examination (i.e.,

corrosion rate since initial construction and the time of the volumetric examination), is not required for applicable buried in-scope piping components.

4. LRA Appendix B, Section B.2.1.28, program description, is revised to include references to pertinent information sources on the installation and use of the soil corrosion probes.

These information sources are consistent with the information previously provided in Response 1 to RAI B.2.1.28-3, contained in Exelon Letter RS-14-003, dated January 13, 2014. LRA Appendix B, Section B.2.1.28, program description, is revised as shown in Enclosure B of this letter.

RS-14-143 Enclosure A Page 8 of 17 RAI B.2.1.28-5a Applicability:

Byron

Background:

RAI B.2.1.28-5 requested that, [g]iven the plant-specific operating experience in relation to the quality of coatings, state the overall condition of coatings as a preventive action in relation to crediting them for the preventive action categories of LR-ISG-2011-03, Table 4a, Inspections of Buried Pipe.

Issue:

Although the RAI response did not state the overall condition of coatings as a preventive action in relation to crediting them for the Preventive Action Inspection categories (i.e., category E or F) of LR-ISG-2011-03 Table 4a for any of the seven systems with in-scope buried piping, the staff found that the information provided was sufficient to resolve the staffs concern in RAI B.2.1.28-5 for all three systems at Braidwood that have buried in-scope piping and for the condensate and fire protection systems at Byron. However, given the results of service water and demineralized water systems inspections conducted at Byron, the staff cannot complete its evaluation of buried in-scope service water and demineralized water piping until it understands whether the existing coating conditions satisfy the criterion for Preventive Action inspection category E or F. Although the staff considers the information provided for the condensate and fire protection systems at Byron acceptable, any inspections that revealed significant coating damage or metal loss should be included in the percentage computation in the request.

Request:

State whether more than 10 percent of the excavated direct visual inspections of in-scope buried piping at Byron have revealed significant coating damage regardless of whether the coating degradation is age-related (except for coating damage occurring during a current excavation), or metal loss.

Exelon Response:

Since 2009, 14 buried pipe inspections of Service Water and Demineralized Water system piping have been performed. No direct visual inspections of buried condensate system piping have been performed at Byron. Additionally, a search of operating experience over the last ten-years at Byron identified no instances of degraded or damaged coatings on buried condensate or fire protection system piping. Based upon a review of the 14 inspections on Service Water and Demineralized Water system piping, seven (7) inspections have exhibited evidence of coating damage associated with causes other than the current excavation process.

Although greater than 10% of the number of inspections have exhibited evidence of coating damage (except when due to the current excavation process), this assessment does not account for the actual lengths of pipe inspected during each excavation and the overall area of damage identified in each instance. In accordance with Enhancement 4 to the Buried and

RS-14-143 Enclosure A Page 9 of 17 Underground Piping (B.2.1.28) aging management program, future inspections of buried in-scope piping will be performed by qualified or specially trained individuals in the assessment of buried coating conditions. As a result, future inspections will include more detailed characterizations on the extent of potential coating damages observed during each inspection.

Operating experience has shown that the identified coating damage found so far has mostly been the result of improper restoration work after the piping was previously excavated for installing freeze seals or line stops. Therefore, more detailed characterizations on the coating conditions observed during future inspections, including inspections of previously undisturbed areas as well as the few remaining areas still potentially affected by previous excavation activities or improper restoration work, is expected to result in less than 10% of the total inspected areas exhibiting evidence of coating damage or degradation. Nevertheless, consistent with Enhancement 5 to the Buried and Underground Piping (B.2.1.28) aging management program, the number of inspections performed during each 10-year period will be in accordance with LR-ISG-2011-03, Table 4a. The extent of coating damages observed during future inspections will be considered when cathodic protection performance requires that piping populations be evaluated as meeting Preventive Action inspection category E or F criteria.

RS-14-143 Enclosure A Page 10 of 17 RAI B.2.1.8-1 Applicability:

Byron and Braidwood

Background:

The Generic Aging Lessons Learned (GALL) Report age management program (AMP) XI.M17, Flow-Accelerated Corrosion, states that the program relies on implementation of the Electric Power Research Institute (EPRI) guidelines in Nuclear Safety Analysis Center (NSAC)-202L, Recommendations for an Effective Flow Accelerated Corrosion Program. The NSAC guidelines state that the program addresses wall thinning due to flow-accelerated corrosion and does not address other thinning mechanisms. LRA Section B.2.1.8 states that the program is consistent with the GALL Report AMP XI.M17 and does not cite any enhancements or exceptions.

Several of the Byron operating experience documents indicate that the current Flow-Accelerated Corrosion (FAC) program addresses aging mechanisms other than FAC and also manages components made from stainless steel, which are exempted from the FAC program.

This is shown in AR 01415234, which addresses a FAC program examination of a susceptible-not-modeled component, 1DV006-1, and notes that the wall thinning was due to droplet impingement (a non-FAC mechanism). In addition, AR 01416484 addresses a FAC program examination of a stainless steel component, 1SD319. Both aspects are inconsistent with the industry guidance for a FAC program.

Additionally, the staff noted that Exelon manages loss of material due to erosion mechanisms through its procedure ER-AA-430-1004, Erosion in Piping and Components Guide. Although this procedure is in the same numbering sequence as Exelons ER-AA-430, Conduct of Flow-Accelerated Corrosion Activities, the staff could not determine which AMP uses implementing procedure ER-AA-430-1004 for managing loss of material due to erosion mechanisms.

Issue:

As currently implemented, the FAC program is inconsistent with the GALL Report because it manages wall thinning mechanisms other than FAC and manages stainless steel components that are not susceptible to FAC. It is unclear to the staff whether Exelon will change its current approach to manage these non-FAC mechanisms and components made from non-FAC susceptible materials through an alternate AMP, or whether Exelon will change the LRA to reflect how it currently implements its FAC program.

Request:

Either modify the LRA and the associated program basis documents for the Flow-Accelerated Corrosion program to reflect the current implementation (i.e., that it manages mechanisms other than FAC and components made from stainless steel, which are not susceptible to FAC), or provide details regarding which AMP (either an enhancement to an existing program or a plant specific program) will manage loss of material due to erosion. Include information regarding

RS-14-143 Enclosure A Page 11 of 17 which AMP(s) will credit Exelon procedure ER-AA-430-1004, Erosion in Piping and Components Guide.

Exelon Response:

Exelon procedure ER-AA-430-1004, Erosion in Piping and Components Guide was implemented at the Byron and Braidwood sites in October 2013, after the Byron and Braidwood License Renewal Application was submitted in May 2013. The purpose of the procedure is to provide a standardized approach for inspection, monitoring, and mitigation of systems susceptible to cavitation, flashing, liquid droplet impingement, and solid particle erosion. This procedure is applicable to, but is not limited to, carbon steel, chrome-molybdenum, and stainless steel components and is consistent with the guidance in LR-ISG-2012-01, Wall Thinning Due to Erosion Mechanisms, issued in April 2013.

Since the procedure has been implemented at Byron and Braidwood, the Flow-Accelerated Corrosion (B.2.1.8) aging management program is updated through this submittal to take credit for this procedure, thereby implementing the recommendations in LR-ISG-2012-01. As a result, LRA Table 3.1.2-4, Section 3.3.2.1.2, Table 3.3.2-2, Table 3.4.2-5, Section A.2.1.8, and Section B.2.1.8 are updated, as shown in Enclosure B. In addition, the Flow-Accelerated Corrosion (B.2.1.8) aging management program basis document will be updated as appropriate.

RS-14-143 Enclosure A Page 12 of 17 RAI B.2.1.8-2 Applicability:

Byron and Braidwood

Background:

The GALL Report AMP XI.M17, Flow-Accelerated Corrosion, states that the program relies on implementation of the EPRI guidelines in NSAC-202L, Recommendations for an Effective Flow Accelerated Corrosion Program. The GALL Report AMP XI.M17 also states that the program includes the use of a predictive code, such as CHECWORKS, to provide assurance that aging effects caused by FAC are properly managed. The NSAC guidelines state that corporate commitment is essential to an effective FAC program, which includes ensuring that appropriate quality assurance is applied. In addition, the NSAC guidelines recommend that the governing procedures include quality assurance requirements and that several portions of the program be independently checked, to include the susceptibility analysis, the predictive plant model, the selection of inspection locations, and component structural evaluations.

LRA Section B.2.1.8 states that the program is consistent with the GALL Report AMP XI.M17 and does not cite any enhancements or exceptions. The LRA also states that the program is based on NSAC-202L and that the analyses to determine critical locations are performed using the predictive code (software), CHECWORKS. The LRA further states that the FAC program is implemented as required by NRC Generic Letter (GL) 89-08, Erosion/Corrosion Induced Pipe Wall Thinning. In its response to GL 89-08, dated July 21, 1989, Exelon states that all stations have implemented erosion/corrosion inspection programs, and that corporate guidance, which was provided to ensure a consistent approach at each site, meets or exceeds the recommendations of industry organizations such as EPRI. In addition, LRA Section A.2.1.8 states that the program activities include analyses to determine critical locations. The staff also noted that Exelon Procedure ER-AA-430, Conduct of Flow Accelerated Corrosion Activities, Section 4.6, Evaluation of Inspection Data, states, Ultrasonic inspection data should be evaluated using an approved (i.e., validated and verified) software program.

Based on discussions during the NRCs AMP Audit, Exelon categorized the CHECWORKS software as Class DD, Screened, in accordance with IT-AA-101, Digital Technology Software Quality Assurance (DTSQA) Procedure. According to statements in IT-AA-101, the Class DD designation applies to software whose failure to perform would have little or no risk of operational impact. The staff noted that Exelon does not categorize CHECWORKS as Class BB, Nuclear Regulatory Related, which includes software required by either nuclear licensing or regulations or whose failure to operate as expected would have an indirect effect on nuclear plant safety. The staff noted that the DTSQA procedure includes a number of documentation requirements for Class BB software, including a validation and verification plan, whereas Class DD software requires minimal documentation and does not require or suggest validation and verification. The staff noted that, although EPRI (the developer and provider of CHECWORKS) currently validates and verifies the software, these activities are not required by Exelons DTSQA procedure based on its current categorization.

Issue:

RS-14-143 Enclosure A Page 13 of 17 Although not required by GL 89-08, the industrys initial recommendations for effective FAC programs included the use of predictive software to identify locations for inspections. Exelons response to GL 89-08 states that corporate guidance for long-term erosion-corrosion inspection programs met or exceeded the industrys recommendations. Exelon uses CHECWORKS as the predictive software to perform analyses to determine critical locations. Although the use of CHECWORKS is not required by nuclear licensing or regulations, Exelon uses it to satisfy its current commitments to GL 89-08, and its future commitments in license renewal. Although the LRA states that a validated and verified computer program such as FAC Manager is also used in conjunction with CHECWORKS, it is not clear that validation and verification activities are programmatic requirements for any of the software used by the FAC program.

In addition, although Exelon Procedure ER-AA-430-1001, Guidelines for Flow Accelerated Corrosion Activities, requires independent verification or independent review of several FAC activities, it is not clear that the appropriate quality assurance has been applied to all of the program aspects recommended by NSAC-202L. In particular, it is not clear whether predictive plant models have been independently checked to ensure that the susceptibility analyses provide valid results.

Request:

For software used by the FAC program (e.g., CHECWORKS and FAC Manager), provide information to demonstrate that appropriate quality assurance measures are being applied with regard to validation and verification. Specifically discuss how software discussed in Section 4.6 of Procedure ER-AA-430 (noted above) is being addressed.

For the portions of the FAC program that NSAC-202L recommends be independently checked, provide information demonstrating that implementing procedures apply appropriate quality assurance measures to these activities. Specifically discuss whether predictive plant models have been independently checked.

Exelon Response:

Exelon procedure ER-AA-430, Conduct of Flow Accelerated Corrosion Activities, section 4.6, provides a summary of Flow-Accelerated Corrosion (B.2.1.8) aging management program activities related to the evaluation of inspection data. Detailed guidelines and requirements for these activities are documented in a second Exelon procedure, ER-AA-430-1001, Guidelines for Flow Accelerated Corrosion Activities. This procedure includes guidance and requirements for the determination of component wear, wear rates, remaining component life, and next scheduled inspection (NSI) for each inspected component. The guidance and requirements in procedure ER-AA-430-1001 are consistent with the guidance in NSAC-202L, Revision 3, Recommendations for an Effective Flow Accelerated Corrosion Program. Exelon currently utilizes vendor supplied software (IDDEAL) to store the inspection data for all inspected components and inputs data into the applicable CHECWORKSTM plant model. The IDDEAL software has replaced the FAC Manager software at Braidwood and Byron. The IDDEAL software also calculates component wear, wear rate, remaining component life, and NSI consistently with the guidelines in NSAC-202L, Revision 3. Consistency with NSAC-202L was verified and validated by Exelon personnel during owner acceptance testing prior to implementation of the IDDEAL software at Byron and Braidwood. When the IDDEAL software is revised, Exelon verifies and validates the revised software to ensure component wear, wear

RS-14-143 Enclosure A Page 14 of 17 rate, remaining component life, and NSI are calculated consistently with NSAC-202L, Revision 3. To ensure that any future software revision is also verified and validated prior to use during the period of extended operation, the Flow-Accelerated Corrosion (B.2.1.8) aging management program is enhanced to revise the program procedures to require documentation of these activities.

Procedure ER-AA-430-1001 also requires independent review of calculated component wear, wear rate, remaining component life, and NSI by a second qualified FAC Engineer for each inspected component, regardless of whether the calculations are made by IDDEAL, CHECWORKSTM, or any other commercially available software, such as Excel.

The Flow-Accelerated Corrosion (B.2.1.8) aging management program uses the CHECWORKSTM software, developed by EPRI, to calculate predicted wear rates and component service life as an aid in selecting the inspection scope for the next inspection campaign (i.e., the next operating cycle including the next refueling outage). Specific CHECWORKSTM plant models of each BBS unit were developed and validated in the 1990s in accordance with the NSAC-202L recommendations. Each time EPRI updates the CHECWORKSTM software, Exelon performs functional testing of the new version using test cases and test databases in accordance with EPRI guidance, before it is placed in production mode. To ensure that updated versions of the CHECWORKSTM software are verified and validated (i.e., functionally tested) prior to use during the period of extended operation, the Flow-Accelerated Corrosion (B.2.1.8) aging management program is enhanced to revise the program procedures to require documentation.

As shown in Enclosure B of this letter, Byron and Braidwood LRA, Appendix A, Section A.1.1 and Section A.2.1.8, and Appendix B, Section B.1.5 and B.2.1.8, are revised to add a new enhancement to require documentation of verification and validation of updated program software. The Byron and Braidwood LRA Table A.5 Commitment List, Item 8, is also updated as shown in Enclosure C of this letter.

The CHECWORKSTM software includes the Pass 2 feature in which individual unit models are updated after each inspection campaign. Model updates include: accumulated operating hours, accumulated chemistry data, new configuration changes, UT data for newly inspected components, and wear rates for newly inspected components. This Pass 2 feature allows verification of the wear rates that were predicted prior to the inspection campaign and calibration of plant model wear rate predictions for the next inspection campaign. The output is then used as one of several inputs in selecting the inspection scope for the next inspection campaign. Exelon procedure ER-AA-430-1001 provides specific requirements for update of CHECWORKSTM plant models consistently with guidelines of NSAC-202L, Revision 3, after each inspection campaign and provides specific requirements that each change to a CHECWORKSTM plant model will be independently reviewed and validated by a second qualified FAC Engineer. Documentation of the update of the CHECWORKSTM plant models and independent reviews are included in the outage/cycle report. This report also includes component structural evaluations, NDE inspection packages, completed work orders, and descriptions of resulting repairs and replacements.

NSAC-202L section 3.3 recommends that the following FAC program attributes are independently checked: Susceptibility Analysis, Predictive Plant Model, Selection of Inspection

RS-14-143 Enclosure A Page 15 of 17 Locations, Component Structural Evaluations, and Outage Reports. Described below are Exelon procedural requirements for the independent checks of these activities.

1) Susceptibility Analyses of each BBS unit were developed in the 1990s, consistent with EPRI guidance and documented in site calculations. These calculations were independently reviewed. Revisions of these calculations require independent review per Exelons Configuration Control Procedures.

2) Updates to each BBS CHECWORKSTM predictive plant model after each inspection campaign is controlled and independently reviewed by a second qualified FAC Engineer in accordance with Exelon procedures. A detailed summary and rationale of CHECWORKSTM predictive plant model updates is included in the outage/cycle report.

3) Exelon procedures require that the selection of inspection locations for the next inspection campaign is independently reviewed by a second qualified FAC Engineer.

4) Exelon procedures require independent review by a second qualified FAC Engineer of component structural evaluations which include calculated component wear, wear rate, remaining component life, and NSI, regardless of whether the calculations are made by IDDEAL, CHECWORKSTM, or any other commercially available software, such as Excel. These evaluations are included in the outage/cycle report for the inspection campaign.

5) Exelon procedures require the completion of outage/cycle reports after each inspection campaign. The outage/cycle reports are prepared, approved, and submitted into the sites document control system and include summaries of the rationale of predictive plant model updates and wear evaluations (which are independently reviewed), as described in items 2 and 4 above. The report also includes: NDE inspection packages, including the inspection datasheets for each inspected component; NDE inspector qualifications and procedures; completed work orders; and descriptions of resulting repair and replacement activities. All these documents require review and approval by site supervision.

RS-14-143 Enclosure A Page 16 of 17 RAI B.2.1.11-1 Applicability:

Byron and Braidwood

Background:

The GALL Report AMP XI.M20, Open-Cycle Cooling Water System, states that the program relies on implementation of the recommendations of NRCs Generic Letter (GL) 89-13, Service Water System Problems Affecting Safety-Related Equipment. LRA Section B.2.1.11 states that the activities for this program are consistent with the site commitments to the requirements of GL 89-13. By letter dated January 29, 1990, Exelon responded to GL 89-13 and addressed Item III (with respect to establishing maintenance program activities to ensure that corrosion of piping and components cannot degrade the performance of safety-related systems supplied by service water), by stating, Corrosion rates are continuously monitored with a corrator and with corrosion coupons of the appropriate metallurgy.

During its review of the program basis document, BB-PBD-AMP-XI.M20, Open-Cycle Cooling Water System, the staff noted that it did not discuss monitoring corrosion rates with a corrator or with corrosion coupons, as noted in the sites response to GL 89-13. During the AMP audit at Braidwood, Exelon personnel stated that site activities are performed through the chemistry department and are consistent with its commitments to GL 89-13.

Issue:

The program basis document states that the activities for this program are consistent with the site commitments to GL 89-13. However the program basis document did not describe the maintenance activities associated with evaluating corrosion rates using corrosion coupons, even though the sites are apparently performing these maintenance activities consistent with the sites commitments to GL 89-13.

Request:

Reconcile the apparent discrepancy between the program activities being performed by the sites relating to the monitoring of corrosion rates, and the program activities described in the Open-Cycle Cooling Water System program basis document.

Exelon Response:

The activities and commitments associated with the stations GL 89-13 responses are included in the letter to the NRC dated January 29, 1990 (Accession Number 9002060369). Byron and Braidwood Stations monitor the corrosion of the open-cycle cooling water components by inspecting the condition of corrosion coupons and corrators installed in the systems and perform internal inspections of select components within these systems, as delineated in Item III of the stations response. These activities verify that the wetted material exposed to the internal environment of the raw water systems is not experiencing unexpected corrosion. The corrosion coupons are strips of metal (i.e., copper alloys, carbon steel, stainless steel), which are installed in the raw water system such that they are exposed to a continuous flow of raw water.

RS-14-143 Enclosure A Page 17 of 17 Periodically, these coupons are removed and analyzed to determine the corrosion rates for the monitored systems. The materials of these coupons are representative of the metallic materials that are used in the raw water systems. This data is reviewed by station personnel on a quarterly basis in accordance with station procedures.

The Open-Cycle Cooling Water (B.2.1.11) aging management program basis document will be revised to describe the monitoring of corrosion coupons and corrators in Element 5, Monitoring and Trending. This action is being tracked under our license renewal change request (LRCR) process. The procedure that directs the activities involving the corrosion coupons and corrators is presently credited as an implementing procedure for the Open-Cycle Cooling Water (B.2.1.11) aging management program and is listed as such in the program basis document.

RS-14-143 Enclosure B Page 1 of 16 Enclosure B Byron and Braidwood Stations, Units 1 and 2 License Renewal Application (LRA) updates resulting from the response to the following RAIs:

RAI B.2.1.28-3a RAI B.2.1.8-1 RAI B.2.1.8-2 Note: To facilitate understanding, the original LRA pages have been repeated in this Enclosure, with revisions indicated. Existing LRA text is shown in normal font. Changes are highlighted with bolded italics for inserted text and strikethroughs for deleted text.

RS-14-143 Enclosure B Page 2 of 16 As a result of the response to RAI B.2.1.28-3a provided in Enclosure A of this letter, LRA Appendix B, Section B.2.1.28, page B-174, is revised as shown below. Additions are indicated with bolded italics.

B.2.1.28 Buried and Underground Piping Program Description The Buried and Underground Piping aging management program is an existing preventive, mitigative, and condition monitoring program that manages the external surface aging effects for buried and underground piping. The program manages aging through preventive, mitigative, and inspection activities for piping and components within the scope of license renewal. It manages the aging effects of loss of material at Byron and Braidwood Stations, as well as cracking and change in material properties (e.g., cracking, blistering, and change in color) at Braidwood Station only.

The Buried and Underground Piping aging management program includes preventive and mitigative techniques, such as external coatings for external corrosion control, the application of cathodic protection, and the quality of backfill utilized. The program also relies on periodic inspection activities, including visual examination of buried and underground piping, manual examination of polymeric materials, and electrochemical verification of the effectiveness of the cathodic protection system. Directed inspections of buried and underground piping are planned based on categorization criteria contained in LR-ISG-2011-03, Changes to the Generic Aging Lessons Learned (GALL) Report Revision 2 Aging Management Program XI.M41, Buried and Underground Piping and Tanks. Buried and underground piping are opportunistically inspected by visual means whenever they become accessible.

In assessing and verifying the effectiveness of the cathodic protection system, soil corrosion probe assemblies may also be used to verify the effectiveness during annual surveys. Data from the soil corrosion probe assemblies may be used to evaluate cathodic protection effectiveness at locations already assessed by existing conventional test points. Placement of the soil corrosion probe assemblies will consider factors such as the location of the nearest anode beds, proximity of the buried in-scope piping of interest and respective test points to the anode beds, and adjacent site features which could affect the measurements taken from both the test points and the soil corrosion probe assemblies.

Information provided in National Association of Corrosion Engineers (NACE)

Internal Publication 05107, Report on Corrosion Probes in Soil or Concrete will be considered during the application, installation, and use of soil corrosion probes. Additional specific details on the installation and use of the probes will be in accordance with vendor, manufacturer, and NACE qualified cathodic protection expert recommendations.

The Fire Protection System was installed in accordance with National Fire Protection Association (NFPA) Standard 24. Aging management of the buried Fire Protection System piping will be accomplished through performance of annual system leakage surveillances. Any abnormal system leakage beyond baseline acceptance criteria will be investigated, and the location, source, and cause of the abnormal leakage identified in the system. Therefore, directed inspections of fire protection piping are not required.

RS-14-143 Enclosure B Page 3 of 16 Byron and Braidwood Stations do not have any buried or underground tanks within the scope of license renewal.

The program will be enhanced as described below to provide reasonable assurance that buried and underground piping and components, constructed of steel, stainless steel, and polymeric materials at Byron and Braidwood Stations will perform their intended function during the period of extended operation.

RS-14-143 Enclosure B Page 4 of 16 As a result of the response to RAI B.2.1.8-1 provided in Enclosure A of this letter, LRA Table 3.1.4-2, page 3.1-100, is revised as shown below. Changes are highlighted with bolded italics for inserted text and strikethroughs for deleted text.

Table 3.1.2-4 Steam Generators (Continued)

Component Intended Material Environment Aging Effect Aging Management NUREG-1801 Table 1 Item Notes Type Function Requiring Programs Item Management Piping, piping Leakage Boundary Stainless Steel Treated Water > 140 F Cracking One-Time Inspection VIII.F.SP-88 3.4.1-11 A components, and (Internal) (B.2.1.20) piping elements Water Chemistry (B.2.1.2) VIII.F.SP-88 3.4.1-11 A Cumulative Fatigue TLAA IV.C2.R-18 3.1.1-5 A, 1 Damage Loss of Material Inspection of Internal H, 2 Surfaces in Miscellaneous Piping and Ducting Components (B.2.1.25)

Loss of Material One-Time Inspection VIII.F.SP-87 3.4.1-16 A (B.2.1.20)

Water Chemistry (B.2.1.2) VIII.F.SP-87 3.4.1-16 A Wall Thinning Flow-Accelerated H, 2 Corrosion (B.2.1.8)

RS-14-143 Enclosure B Page 5 of 16 As a result of the response to RAI B.2.1.8-1 provided in Enclosure A of this letter, Note 2 to LRA Table 3.1.2-4, page 3.1-121, is revised as shown below. Changes are highlighted with bolded italics for inserted text and strikethroughs for deleted text.

2. The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B.2.1.25) program will be used to manage the loss of material due to erosion in stainless steel pipe in a treated water >140 F environment.

2. The Flow-Accelerated Corrosion (B.2.1.8) aging management program will be used to manage wall thinning due to mechanisms other than FAC in stainless steel pipe in treated water > 140 °F environments.

RS-14-143 Enclosure B Page 6 of 16 As a result of the response to RAI B.2.1.8-1 provided in Enclosure A of this letter, LRA Section 3.3.2.1.2, Chemical & Volume Control System, page 3.3-5, is revised as shown below. Additions are highlighted with bolded italics.

Environments The Chemical & Volume Control System components are exposed to the following environments:

Air with Borated Water Leakage Air/Gas - Dry Condensation Lubricating Oil Treated Borated Water Treated Borated Water > 140°F Treated Water Waste Water Aging Effect Requiring Management The following aging effects associated with the Chemical & Volume Control System components require management:

Cracking Cumulative Fatigue Damage Loss of Material Loss of Preload Reduction of Heat Transfer Wall Thinning Aging Management Programs The following aging management programs manage the aging effects for the Chemical & Volume Control System components:

ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD (B.2.1.1)

Bolting Integrity (B.2.1.9)

Boric Acid Corrosion (B.2.1.4)

Closed Treated Water Systems (B.2.1.12)

External Surfaces Monitoring of Mechanical Components (B.2.1.23)

Flow-Accelerated Corrosion (FAC) (B.2.1.8)

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B.2.1.25)

RS-14-143 Enclosure B Page 7 of 16 As a result of the response to RAI B.2.1.8-1 provided in Enclosure A of this letter, LRA Table 3.3.2-2, page 3.3-120, is revised as shown below. Changes are highlighted with bolded italics for inserted text.

Table 3.3.2-2 Chemical & Volume Control System (Continued)

Component Intended Material Environment Aging Effect Aging Management NUREG-1801 Table 1 Item Notes Type Function Requiring Programs Item Management Piping, piping Pressure Boundary Stainless Steel Air with Borated Water None None VII.J.AP-18 3.3.1-120 A components, and Leakage (External) piping elements Lubricating Oil (Internal) Loss of Material Lubricating Oil Analysis VII.E1.AP-138 3.3.1-100 A (B.2.1.26)

One-Time Inspection VII.E1.AP-138 3.3.1-100 A (B.2.1.20)

Treated Borated Water Loss of Material Water Chemistry (B.2.1.2) VII.E1.A-88 3.3.1-29 A (Internal)

Treated Borated Water > Cracking Water Chemistry (B.2.1.2) VII.E1.AP-82 3.3.1-28 A 140 F (Internal) Cumulative Fatigue TLAA VII.E1.A-57 3.3.1-2 A, 1 Damage Loss of Material Water Chemistry (B.2.1.2) VII.E1.A-88 3.3.1-29 A Wall Thinning Flow-Accelerated H, 7 Corrosion (B.2.1.8)

RS-14-143 Enclosure B Page 8 of 16 As a result of the response to RAI B.2.1.8-1 provided in Enclosure A of this letter, LRA Table 3.6.2-1, page 3.3-133, is revised to add plant specific Note 7 as shown below. The addition is highlighted with bolded italics.

7. The Flow-Accelerated Corrosion (B.2.1.8) aging management program will be used to manage wall thinning due to mechanisms other than FAC in stainless steel pipe in treated borated water > 140 °F environments.

RS-14-143 Enclosure B Page 9 of 16 As a result of the response to RAI B.2.1.8-1 provided in Enclosure A of this letter, LRA Table 3.4.2-5, page 3.4-72, is revised as shown below. Changes are highlighted with bolded italics for inserted text and strikethroughs for deleted text.

Table 3.4.2-5 Main Turbine and Auxiliaries System Component Intended Material Environment Aging Effect Aging Management NUREG-1801 Table 1 Item Notes Type Function Requiring Programs Item Management Flow Device Leakage Boundary Carbon Steel Air - Indoor Loss of Material External Surfaces VIII.H.S-29 3.4.1-34 A Uncontrolled (External) Monitoring of Mechanical Components (B.2.1.23)

Treated Water (Internal) Loss of Material Inspection of Internal H, 1 Wall Thinning Surfaces in Miscellaneous Piping and Ducting Components (B.2.1.25)

Flow-Accelerated Corrosion (B.2.1.8)

Loss of Material One-Time Inspection VIII.C.SP-73 3.4.1-14 A (B.2.1.20)

Water Chemistry (B.2.1.2) VIII.C.SP-73 3.4.1-14 A

RS-14-143 Enclosure B Page 10 of 16 As a result of the response to RAI B.2.1.8-1 provided in Enclosure A of this letter, note 1 to LRA Table 3.4.2-5, page 3.4-78, is revised as shown below. Changes are highlighted with bolded italics for inserted text and strikethroughs for deleted text.

1. The aging effects for carbon steel in a treated water environment include loss of material due to erosion. The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B.2.1.25) program is used to manage the identified aging effect applicable to carbon steel components in a treated water environment.

1. The Flow-Accelerated Corrosion (B.2.1.8) aging management program will be used to manage wall thinning due to mechanisms other than FAC in carbon steel pipe components in treated water environments.

RS-14-143 Enclosure B Page 11 of 16 As a result of the response to B.2.1.8-2 provided in Enclosure A of this letter, LRA Appendix A, Section A.1.1, NUREG-1801 Chapter XI Aging Management Programs, on page A-5 is revised as shown below. Additions are indicated with bolded italics.

A.1.1 NUREG-1801 Chapter XI Aging Management Programs The Byron and Braidwood NUREG-1801 Chapter XI Aging Management Programs (AMPs) are described in this section. The AMPs are either existing, existing with enhancements (enhanced) or new.

The following list reflects the status of these programs at the time of the License Renewal Application (LRA) submittal. Commitments for program additions and enhancements are identified in the Appendix A.5 License Renewal Commitment List.

1. ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD (Section A.2.1.1) [Existing - Requires Enhancement]

2. Water Chemistry (Section A.2.1.2) [Existing]

3. Reactor Head Closure Stud Bolting (Section A.2.1.3) [Existing - Requires Enhancement]

4. Boric Acid Corrosion (Section A.2.1.4) [Existing]

5. Cracking of Nickel-Alloy Components and Loss of Material Due to Boric Acid-Induced Corrosion in Reactor Coolant Pressure Boundary Components (Section A.2.1.5) [Existing]

6. Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS)

(Section A.2.1.6) [New]

7. PWR Vessel Internals (Section A.2.1.7) [New]

8. Flow-Accelerated Corrosion (Section A.2.1.8) [Existing - Requires Enhancement]

9. Bolting Integrity (Section A.2.1.9) [Existing - Requires Enhancement]

10. Steam Generators (Section A.2.1.10) [Existing - Requires Enhancement]

11. Open-Cycle Cooling Water System (Section A.2.1.11) [Existing - Requires Enhancement]

12. Closed Treated Water Systems (Section A.2.1.12) [Existing - Requires Enhancement]

13. Inspection of Overhead Heavy Load and Light Load (Related to Refueling)

Handling Systems (Section A.2.1.13) [Existing - Requires Enhancement]

14. Compressed Air Monitoring (Section A.2.1.14) [Existing - Requires Enhancement]

15. Fire Protection (Section A.2.1.15) [Existing - Requires Enhancement]

RS-14-143 Enclosure B Page 12 of 16 As a result of the responses to RAI B.2.1.8-1 and B.2.1.8-2 provided in Enclosure A of this letter, LRA appendix A.2.1.8, Flow-Accelerated Corrosion, Program Description, on page A-13 is revised as shown below. Additions are indicated with bolded italics.

A.2.1.8 Flow-Accelerated Corrosion The Flow-Accelerated Corrosion (FAC) aging management program is an existing condition monitoring program based on implementation of EPRI guidelines in NSAC-202L-R3, Recommendations for an Effective Flow Accelerated Corrosion Program. Program activities include analyses to determine critical locations, baseline inspections to determine the extent of wall thinning at these critical locations, and follow-up inspections to confirm or quantify the predictions, and take long term corrective actions. Repairs and replacements are performed as necessary. Inspections are performed using ultrasonic, visual, or other approved testing techniques capable of detecting wall thinning. The program provides guidance for prediction, detection, and monitoring wall thinning in piping, piping components, and piping elements, and heat exchangers due to FAC.

The Flow-Accelerated Corrosion aging management program also manages wall thinning caused by mechanisms other than FAC, such as cavitation, flashing, droplet impingement, and solid particle impingement, in situations where periodic monitoring is used in lieu of eliminating the cause of various erosion mechanism(s).

The Flow-Accelerated Corrosion (FAC) aging management program will be enhanced to:

1. Revise program procedures to require the documentation of the validation and verification of updated vendor supplied FAC program software which calculates component wear, wear rates, remaining life, and next scheduled inspection. The validation and verification will verify that the updated software performs these calculations consistently with NSAC-202L-R3 guidelines.

This enhancement will be implemented prior to the period of extended operation.

RS-14-143 Enclosure B Page 13 of 16 As a result of the response to B.2.1.8-2 provided in Enclosure A of this letter, LRA Appendix B, Section B.1.5, NUREG-1801 Chapter XI Aging Management Programs, on page B-9 is revised as shown below. Additions are indicated with bolded italics.

3. Reactor Head Closure Stud Bolting (Section B.2.1.3) [Existing - Requires Enhancement]

4. Boric Acid Corrosion (Section B.2.1.4) [Existing]

5. Cracking of Nickel-Alloy Components and Loss of Material Due to Boric Acid-Induced Corrosion in Reactor Coolant Pressure Boundary Components (Section B.2.1.5) [Existing]

6. Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) (Section B.2.1.6) [New]

7. PWR Vessel Internals (Section B.2.1.7) [New]

8. Flow-Accelerated Corrosion (Section B.2.1.8) [Existing - Requires Enhancement]

9. Bolting Integrity (Section B.2.1.9) [Existing - Requires Enhancement]

10. Steam Generators (Section B.2.1.10) [Existing - Requires Enhancement]

11. Open-Cycle Cooling Water System (Section B.2.1.11) [Existing - Requires Enhancement]

12. Closed Treated Water Systems (Section B.2.1.12) [Existing - Requires Enhancement]

13. Inspection of Overhead Heavy Load and Light Load (Related to Refueling)

Handling Systems (Section B.2.1.13) [Existing - Requires Enhancement]

14. Compressed Air Monitoring (Section B.2.1.14) [Existing - Requires Enhancement]

15. Fire Protection (Section B.2.1.15) [Existing - Requires Enhancement]

16. Fire Water System (Section B.2.1.16) [Existing - Requires Enhancement]

17. Aboveground Metallic Tanks (Section B.2.1.17) [New]

18. Fuel Oil Chemistry (Section B.2.1.18) [Existing - Requires Enhancement]

19. Reactor Vessel Surveillance (Section B.2.1.19) [Existing - Requires Enhancement]

20. One-Time Inspection (Section B.2.1.20) [New]

21. Selective Leaching (Section B.2.1.21) [New]

22. One-Time Inspection of ASME Code Class 1 Small Bore-Piping (Section B.2.1.22)

[New]

23. External Surfaces Monitoring of Mechanical Components (Section B.2.1.23) [New]

RS-14-143 Enclosure B Page 14 of 16 As a result of the response to RAIs B.2.1.8-1 and B.2.1.8-2 provided in Enclosure A of this letter, LRA Appendix B, Section B.2.1.8, Flow-Accelerated Corrosion, on pages B-61 and B-62 are revised as shown below. Changes are highlighted with bolded italics for inserted text and strikethroughs for deleted text.

B.2.1.8 Flow-Accelerated Corrosion Program Description The Flow-Accelerated Corrosion (FAC) aging management program is an existing condition monitoring program based on implementation of EPRI guidelines in NSAC-202L-R3, Recommendations for an Effective Flow Accelerated Corrosion Program.

Program activities include analyses to determine critical locations, baseline inspections to determine the extent of wall thinning at these critical locations, and follow-up inspections to confirm or quantify the predictions, and take long term corrective actions. Repairs and replacements are performed as necessary. Inspections are performed using ultrasonic, visual, or other approved testing techniques capable of detecting wall thinning. The program provides guidance for prediction, detection, and monitoring wall thinning in piping, piping components, and piping elements, and heat exchangers due to FAC in closed cycle cooling water, treated water, and steam environments. The monitoring methods are effective in detecting the applicable aging effects and the frequency of monitoring is adequate to prevent significant age-related degradation.

Where applicable, analyses to determine critical locations in piping and other components susceptible to FAC are performed utilizing CHECWORKS, a predictive code that uses the implementation guidance of NSAC-202L-R3 to satisfy the criteria specified in 10 CFR Part 50, Appendix B for development of procedures and control of special processes. For each examined component, a verified and validated web-based computer program, such as FAC Manager, is utilized in conjunction with CHECWORKS to calculate component wear, wear rate, projected thickness, and remaining life. If a components remaining life cannot be demonstrated to be more than one operating cycle, then corrective action is required, such as repair, replacement, or re-evaluation.

FAC is only applicable to carbon steel piping and components. Field measurement results are used to confirm the predicted wear rate. The CHECWORKS model is evaluated and updated as required to reflect any significant changes in plant operating parameters such as power uprates. The CHECWORKS model is also refined by importing actual UT inspection data thickness measurements and re-running the wear rate analysis, thereby, improving the predictive capability of the model. The FAC program relies on industry and in-house operating experience including CHECWORKS Users Group (CHUG) Notices, Plant Event databases, Significant Operating Event Reports, Nuclear Operation Notices, Information Notices, and plant experience.

No preventive attributes are directly associated with the Flow-Accelerated Corrosion program. However, water chemistry monitoring is used to control pH and dissolved oxygen content and is effective in reducing FAC. The program considers water treatment changes that may affect the FAC rates (e.g., water treatment amines, hydrogen water chemistry, hydrazine addition, or any other change that affects the pH

RS-14-143 Enclosure B Page 15 of 16 or dissolved oxygen concentration).

The Flow-Accelerated Corrosion program, which was originally outlined in NUREG-1344, is implemented as required by NRC Generic Letter 89-08, Erosion/Corrosion-Induced Pipe Wall Thinning. As noted above, the Flow-Accelerated Corrosion program is based on the EPRI guidelines in NSAC-202L-R3.

The Flow-Accelerated Corrosion aging management program also manages wall thinning caused by mechanisms other than FAC, such as cavitation, flashing, droplet impingement, and solid particle impingement, in situations where periodic monitoring is used in lieu of eliminating the cause of various erosion mechanism(s).

NUREG-1801 Consistency The Flow-Accelerated Corrosion aging management program will be is consistent with the ten elements of aging management program XI.M17, Flow-Accelerated Corrosion, specified in NUREG-1801.

Exceptions to NUREG-1801 None.

Enhancements None.

The Flow-Accelerated Corrosion (FAC) aging management program will be enhanced to:

1. Revise program procedures to require the documentation of the validation and verification of updated vendor supplied FAC program software which calculates component wear, wear rates, remaining life, and next scheduled inspection. The validation and verification will verify that the updated software performs these calculations consistently with NSAC-202L-R3 guidelines.

This enhancement will be implemented prior to the period of extended operation.

RS-14-143 Enclosure B Page 16 of 16 As a result of the response to RAIs B.2.1.8-1 provided in Enclosure A of this letter, the Conclusion section of LRA appendix B.2.1.8, Flow-Accelerated Corrosion, on pages B-66 is revised as shown below. Changes are highlighted with bolded italics for inserted text and strikethroughs for deleted text.

Conclusion The enhanced existing Flow-Accelerated Corrosion program will provides reasonable assurance that wall thinning aging effects will be are adequately managed so that the intended functions of components within the scope of license renewal are maintained consistent with the current licensing basis during the period of extended operation.

RS-14-143 Enclosure C Page 1 of 2 Enclosure C Byron and Braidwood Stations (BBS) Units 1 and 2 License Renewal Commitment List Changes This Enclosure identifies commitments made or revised in this document and is an update to the Byron and Braidwood Station (BBS) LRA Appendix A, Table A.5 License Renewal Commitment List. Any other actions discussed in the submittal represent intended or planned actions and are described to the NRC for the NRCs information and are not regulatory commitments.

Changes to the BBS LRA Appendix A, Table A.5 License Renewal Commitment List are as a result of the Exelon response to the following RAI:

RAI B.2.1.8-2 Notes:

To facilitate understanding, portions of the original License Renewal Commitment List have been repeated in this Enclosure, with revisions indicated.

Existing LRA text is shown in normal font. Changes are highlighted with bolded italics for added text and strikethroughs for deleted text.

RS-14-143 Enclosure C Page 2 of 2 As a result of the response to RAI B.2.1.8-2 provided in Enclosure A of this letter, LRA Table A.5, License Renewal Commitment List, page A-71, is revised as shown below. Changes are highlighted with bolded italics for inserted text and strikethroughs for deleted text.

NO. PROGRAM OR IMPLEMENTATION COMMITMENT SOURCE TOPIC SCHEDULE 8 Flow-Accelerated Corrosion Existing program is credited. Ongoing Section A.2.1.8 The Flow-Accelerated Corrosion aging management program is Program to be enhanced an existing program that will be enhanced to: prior to the period of Exelon letter extended operation. RS-14-143

1. Revise program procedures to require the documentation May 15, 2014 of the validation and verification of updated vendor RAI B.2.1.8-2 supplied FAC program software which calculates component wear, wear rates, remaining life, and next scheduled inspection. The validation and verification will verify that the updated software performs these calculations consistently with NSAC-202L-R3 guidelines.