Text

License Amendment Request to Revise Units 1 and 2 Technical Specification 5.5.12 for Permanent Extension of Type a and Type C Leak Rate Test Frequencies
	ML19058A768
Person / Time
Site:	Brunswick
Issue date:	02/27/2019
From:	William Gideon; Duke Energy Progress
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	RA-18-0148
	Download: ML19058A768 (185)
	v • d • e

(_~ DUKE ENERGY February 27, 2019 Serial: RA-18-0148 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001

Subject:

Brunswick Steam Electric Plant, Unit Nos. 1 and 2 Renewed Facility Operating License Nos. DPR-71 and DPR-62 Docket Nos. 50-325 and 50-324 License Amendment Request to Revise Units 1 and 2 Technical William R. Gideon Vice President Brunswick Nuclear Plant P.O. Box 10429 Southport, NC 28461 o: 910.832.3698 10 CFR 50.90 Specification 5.5.12 for Permanent Extension of Type A and Type C Leak Rate Test Frequencies Ladies and Gentlemen:

Pursuant to 10 CFR 50.90, Duke Energy Progress, LLC (Duke Energy), is requesting an amendment for the Brunswick Steam Electric Plant (BSEP), Unit Nos. 1 and 2. The proposed change revises Technical Specification 5.5.12, Primary Containment Leakage Rate Testing Program.

The enclosure provides a description and assessment of the proposed change. Attachments 1 and 2 to the enclosure provide the existing TS pages, for Units 1 and 2, respectively, marked to show the proposed change. Attachments 3 and 4 provide revised (i.e., typed) TS pages for Units 1 and 2, respectively. Attachment 5 provides existing Unit 1 TS Bases pages marked to show associated TS Bases changes and is provided for information only. Attachment 6 provide an evaluation of the risk significance of the proposed change.

Approval of the proposed amendment is requested within one year of completion of the NRC's acceptance review. Once approved, the amendment shall be implemented within 120 days.

In accordance with 1 O CFR 50.91, Duke Energy is providing a copy of the proposed license amendment to the designated representative for the State of North Carolina.

This document contains no new regulatory commitments. Please refer any questions regarding this submittal to Mr. Art Zaremba, Director - Nuclear Fleet Licensing, at (980) 373-2062.

I declare, under penalty of perjury, that the foregoing is true and correct. Executed on February 27, 2019.

s~

William R. Gideon

U.S. Nuclear Regulatory Commission Page 2 of 2 MAT/mat

Enclosure:

Description and Assessment of the Proposed Change : Proposed Technical Specification Changes (Mark-Up) - Unit 1 : Proposed Technical Specification Changes (Mark-Up) - Unit 2 : Revised (Typed) Technical Specification Pages - Unit 1 : Revised (Typed) Technical Specification Pages - Unit 2 : Proposed Technical Specification Bases Pages (Mark-Up) Unit 1 (For Information Only) : BSEP Evaluation of Risk Significance of Permanent ILRT Evaluation cc:

U. S. Nuclear Regulatory Commission, Region II ATTN: Ms. Catherine Haney, Regional Administrator 245 Peachtree Center Ave, NE, Suite 1200 Atlanta, GA 30303-1257 U.S. Nuclear Regulatory Commission ATTN: Mr. Dennis J. Galvin 11555 Rockville Pike Rockville, MD 20852-2738 U. S. Nuclear Regulatory Commission ATTN: Mr. Gale Smith, NRC Senior Resident Inspector 8470 River Road Southport, NC 28461-8869 Chair - North Carolina Utilities Commission (Electronic Copy Only) 4325 Mail Service Center Raleigh, NC 27699-4300 swatson@ncuc.net Mr. W. Lee Cox, III, Section Chief (Electronic Copy Only)

Radiation Protection Section North Carolina Department of Health and Human Services 1645 Mail Service Center Raleigh, NC 27699-1645 lee.cox@dhhs.nc.gov

RA-18-0149 Enclosure Page 1 of 90 EVALUATION OF THE PROPOSED CHANGE

SUBJECT:

License Amendment Request to Revise Units 1 and 2 Technical Specification 5.5.12 for Permanent Extension of Type A and Type C Leak Rate Test Frequencies 1.0

SUMMARY

DESCRIPTION 2.0 DETAILED DESCRIPTION

3.0 TECHNICAL EVALUATION

3.1 Description of Containment System 3.2 Plant Operational Performance 3.3 Emergency Core Cooling System Net Positive Suction Head Analysis 3.4 Justification for the TS Change 3.5 Plant Specific Confirmatory Analysis 3.6 Non-Risk Based Assessment 3.7 Operating Experience 3.8 License Renewal Aging Management 3.9 NRC SER Limitations and Conditions 3.10 Conclusion

4.0 REGULATORY EVALUATION

4.1 Applicable Regulatory Requirements/Criteria 4.2 Precedent 4.3 No Significant Hazards Consideration 4.4 Conclusion

5.0 ENVIRONMENTAL CONSIDERATION

6.0 REFERENCES

ATTACHMENTS:

1. Proposed Technical Specification Changes Pages (Mark-up) Unit 1

2. Proposed Technical Specification Changes Pages (Mark-up) Unit 2

3. Revised (Typed) Technical Specification Pages Unit 1

4. Revised (Typed) Technical Specification Pages Unit 2

5. Proposed Technical Specification Bases Pages (Mark-Up) Unit 1 (For Information Only)

6. BSEP Evaluation of Risk Significance of Permanent ILRT Evaluation

RA-18-0149 Enclosure Page 2 of 90 1.0

SUMMARY

DESCRIPTION In accordance with 10 CFR 50.90, "Duke Energy Progress, LLC (Duke Energy) requests an amendment to Renewed Facility Operating License DPR-71 and DPR-62 for Brunswick Steam Electric Plant (BSEP), Unit No. 1 and Unit No. 2, respectively, to allow for permanent extension of the Type A and Type C leakage rate testing frequencies. The proposed change revises Units 1 and 2 Technical Specification (TS) 5.5.12, "Primary Containment Leakage Rate Testing Program," to reflect the following:

Increases the existing Type A integrated leakage rate test (ILRT) program test interval from 10 years to 15 years in accordance with Nuclear Energy Institute (NEI) Topical Report (TR) NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J," Revision 3-A (i.e., Reference 2) and the conditions and limitations specified in NEI 94-01, Revision 2-A (i.e., Reference 3).

Adopts an extension of the containment isolation valve (CIV) leakage rate testing (i.e.,

Type C) frequency from the 60 months currently permitted by 10 CFR 50, Appendix J, "Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors,"

Option B, to a 75-month frequency for Type C leakage rate testing of selected components, in accordance with NEI 94-01, Revision 3-A.

Adopts the use of American National Standards Institute/American Nuclear Society (ANSI/ANS 56.8-2002, "Containment System Leakage Testing Requirements" (i.e.,

Reference 4).

Adopts a more conservative allowable test interval extension of nine months, for Type A, Type B and Type C leakage rate tests in accordance with NEI 94-01, Revision 3-A.

Specifically, the proposed change revises each of the BSEP Units 1 and 2 TS 5.5.12, by replacing the references to Regulatory Guide (RG) 1.163, "Performance-Based Containment Leak-Test Program," (i.e., Reference 1) and 10 CFR 50, Appendix J, Option B with a reference to NEI 94-01, Revision 3-A, and the conditions and limitations specified in NEI 94-01, Revision 2-A, as the documents used by BSEP to implement the performance-based leakage testing program in accordance with Option B of 10 CFR 50, Appendix J.

This License Amendment Request (LAR) also proposes administrative changes to the exceptions in Units 1 and 2 TS 5.5.12. Two exceptions listed in the Units 1 and 2 TS 5.5.12 contain references to revisions and years of the ANSI/ANS 56.8 and NEI 94-01. Unit 1 and 2 TS exceptions 5.5.12.c reference NEI 94-01 Revision 0 (i.e., Reference 5) and Units 1 and 2 exceptions TS 5.5.12.f reference ANSI/ANS 56.8-1994 (i.e., Reference 6). With the approval of the proposed amendment, the referenced revision and year will no longer be the licensing basis for the program. The evaluation and continued use of these amendments is further described in Section 3.4.3.

2.0 DETAILED DESCRIPTION BSEP Units 1 and 2 TS 5.5.12, "Primary Containment Leakage Rate Testing Program," each currently state, in part:

A primary containment leakage rate testing program shall establish requirements to implement the leakage rate testing of the primary containment as required by 10 CFR

RA-18-0149 Enclosure Page 3 of 90 50.54(o) and 10 CFR 50, Appendix J, Option B as modified by approved exemptions. This program shall be in accordance with the guidelines contained in Regulatory Guide 1.163, September 1995, as modified by the following exceptions:

a. The visual examination of concrete surfaces intended to fulfill the requirements of 10 CFR 50, Appendix J, Option B testing, will be performed in accordance with the requirements of and frequency specified by the ASME Section XI Code, Subsection IWL, except where relief has been authorized by the NRC.

b. The visual examination of the metallic shell, penetrations, and appurtenances intended to fulfill the requirements of 10 CFR 50, Appendix J, Option B, will be performed in accordance with the requirements of and frequency specified by the ASME Section XI Code, Subsection IWE, except where relief has been authorized by the NRC.

c. Following air lock door seal replacement, performance of door seal leakage rate testing with the gap between the door seals pressurized to 10 psig instead of air lock testing at Pa as specified in Nuclear Energy Institute Guideline 94-01, Revision 0.

d. Reduced duration Type A tests may be performed using the criteria and Total Time method specified in Bechtel Topical Report BN-TOP-1, Revision 1.

e. Performance of Type C leak rate testing of the hydrogen and oxygen monitor isolation valves is not required; and

f.

Performance of Type C leak rate testing of the main steam isolation valves at a pressure less than Pa instead of leak rate testing at Pa as specified in ANSI/ANS 56.8-1994.

The proposed changes to BSEP Units 1 and 2 TS 5.5.12 will replace the reference to RG 1.163 with reference to NEI Topical Report NEI 94-01 Revisions 2-A and 3-A.

This LAR also proposes administrative changes to two of the exceptions in Units 1 and 2 TS 5.5.12. These two exceptions provided in TS 5.5.12.c and TS 5.5.12.f contain references to revisions and years of NEI 94-01 and ANSI/ANS 56.8. Specifically, 5.5.12.c references NEI 94-01 Revision 0 and TS 5.5.12.f references ANSI/ANS 56.8-1994. These two exceptions will be updated to reflect the appropriate document revisions, accordingly. With the approval of the proposed amendment, the referenced revision and year will no longer be the licensing basis for the program.

The proposed change revises the BSEP Units 1 and 2 TS 5.5.12 to read as follows (i.e., with recommended changes in bold-type for clarification purposes):

A primary containment leakage rate testing program shall establish requirements to implement the leakage rate testing of the primary containment as required by 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance with the guidelines contained in NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J,"

Revision 3-A, dated July 2012, and the conditions and limitations specified in NEI 94-01, Revision 2-A, dated October 2008 as modified by the following exceptions:

a. The visual examination of concrete surfaces intended to fulfill the requirements of 10 CFR 50, Appendix J, Option B testing, will be performed in accordance with the

RA-18-0149 Enclosure Page 4 of 90 requirements of and frequency specified by the ASME Section XI Code, Subsection IWL, except where relief has been authorized by the NRC.

b. The visual examination of the metallic shell, penetrations, and appurtenances intended to fulfill the requirements of 10 CFR 50, Appendix J, Option B will be performed in accordance with the requirements of and frequency specified by the ASME Section XI Code, Subsection IWE, except where relief has been authorized by the NRC.

c. Following air lock door seal replacement, performance of door seal leakage rate testing with the gap between the door seals pressurized to 10 psig instead of air lock testing at Pa as specified in Nuclear Energy Institute Guideline 94-01, Revision 3-A.

d. Reduced duration Type A tests may be performed using the criteria and Total Time method specified in Bechtel Topical Report BN-TOP-1, Revision 1.

e. Performance of Type C leak rate testing of the hydrogen and oxygen monitor isolation valves is not required; and

f.

Performance of Type C leak rate testing of the main steam isolation valves at a pressure less than Pa instead of leak rate testing at Pa as specified in in ANSI/ANS 56.8-2002.

The marked-up TS pages for BSEP Units 1 and 2 TS 5.5.12 are provided in Attachments 1 and 2, respectively. The retyped pages of the BSEP TS pages for the BSEP Units 1 and 2 TS 5.5.12 are provided in Attachments 3 and 4, respectively.

The proposed changes to the TS Bases are provided in Attachment 5 for information only.

Changes to the attached TS Bases pages will be incorporated in accordance with BSEP TS 5.5.10, "Technical Specifications (TS) Bases Control Program." contains the plant specific risk assessment conducted to support this proposed change. This risk assessment followed the guidelines of NRC RG 1.174, Revision 2 (i.e.,

Reference 7) and NRC RG 1.200, Revision 2 (i.e., Reference 29). The risk assessment concluded that increasing the ILRT on a permanent basis to one-in-fifteen-year frequency is considered to represent a very small change in the BSEP risk profile.

3.0 TECHNICAL EVALUATION

3.1 Description of Containment System The reactor building encloses the drywell and the suppression chamber. Both the drywell and the suppression chamber consist of reinforced concrete pressure vessels with leak-tight steel liners on all inside surfaces. Welded seams on the steel liner are covered by channels intended for leak testing these welds. Where the test channel ports are covered with a pipe plug, the test channels provide a redundant primary containment barrier and are considered part of the primary containment boundary. All three structures are founded on a common reinforced concrete mat supported on a layer of dense sand which overlays limestone strata.

The drywell is composed of vertical right cylinders and truncated cones with inside diameters varying between 36 feet and 65 feet forming a configuration similar to the conventional steel containment "light bulb" shape. The overall height from the top of the foundation mat to the drywell head flange connection is approximately 111 feet. The 35 feet, 10-inch diameter steel

RA-18-0149 Enclosure Page 5 of 90 dome covering the top of the drywell is furnished with double gasketed flanges and is securely fastened to the reinforced drywell liner extension, which is in turn anchored to the top of the reinforced concrete portion of the drywell with 84 uniformly spaced pretensioned bolts. The flange detail includes provision for pressurizing the space between the two gaskets.

The lower cylindrical section of the drywell contains two large circular openings, each 10 feet in diameter. The openings are directly opposite each other. One opening, the personnel air lock, serves as a combination personnel air lock and equipment access hatch. The second opening, the equipment hatch, is used solely to install or remove equipment and is closed during operation with an internal bolted steel cover. Each opening has a steel liner sleeve welded to an insert plate in the drywell liner and anchored to the concrete at the junction of the drywell liner and the opening.

During operation, the personnel air lock is bolted to the 10 feet diameter penetration sleeve in the drywell. Entrance is gained through a series of two interlocking doors. The air lock is mounted on rails and when required for equipment access it can be unbolted and rolled away from the drywell providing a 10 feet diameter opening.

The Units 1 and 2 personnel air lock penetration sleeves have been modified by adding a concentric sleeve inside the existing liner sleeves. Each units concentric sleeves are circumferentially welded into place at both ends. An air gap of approximately one inch remains between the new and old penetration sleeve to provide for thermal expansion, as in the original design.

The equipment hatch opening is closed during operation by a steel cover which is bolted to an insert plate in the drywell liner. The insert plate is in turn anchored to the reinforced concrete.

Since the equipment hatch opening is covered, it does not experience the thermal transients that the other large openings are subject to and therefore the felt layers were not required. The pressure loads on the hatch cover were lumped around the perimeter of the opening to maximize the reinforcing stresses.

The suppression chamber is a hollow reinforced concrete shell of rectangular cross-section encircling the lower portion of the drywell containment structure. The concrete encloses 16 continuous, inter-connected cylindrical sections 3/8-inch thick, that form a torus steel liner. The cross-sectional diameter of the suppression chamber is 29 feet and the major centerline of the torus is 109 feet. The suppression chamber is structurally independent of the drywell.

Eight 6 feet 4-inch diameter vent openings are uniformly spaced at 45-degree intervals in the lower conical section of the drywell. The vent openings are coincident with and connected to the eight respective vent openings in the suppression chamber. Each vent is enclosed by a steel liner sleeve that is welded to an insert plate in the drywell liner, and anchored to the reinforced concrete and the junction of the drywell liner and the vent line opening. The steel liner sleeves of the vents are also wrapped with felt, similar to the personnel airlock penetration sleeve, to allow for free thermal expansion.

3.1.1 Drywell and Suppression Chamber The drywell consists of two vertical right cylinders jointed by two truncated conical sections with a solid cylindrical base pedestal. The top of the drywell is closed by a continuous steel dome, which is bolted to the top of the drywell.

RA-18-0149 Enclosure Page 6 of 90 The drywell pedestal is a 17-foot thick solid cylindrical concrete disk and contains top and bottom reinforcing over the total plan area. The top reinforcing grid consists of radially and circumferentially spaced bars. The circumferential bars are continuous closed circular hoops.

The radial bars are terminated on the outside face of the pedestal by a 90-degree hook extending into the depth of the pedestal. Near the pedestal centerline, where concrete tensile stresses are minimum or in compression, the radial bars are terminated and lap-sliced with an orthogonal grid of reinforcing bars. The bottom pedestal reinforcing contains two orthogonal layers of reinforcing bars uniformly spaced over the full area of the pedestal. The bottom reinforcing grid is terminated in the concrete compression zone near the outside perimeter of the mat. In addition to the top and bottom reinforcing, a band of closed hoop bars, evenly spaced through the full depth of the pedestal, runs along the outside face. Pedestal shear reinforcing is provided through the depth in the form of bent Z bars inclined at an angle of 45 degrees.

The drywell wall reinforcing consists of circumferential closed hoops on each face along its full height, continuous meridional reinforcing on each face, diagonal seismic reinforcing on the outside face, and shear reinforcing.

The drywell openings described above have special reinforcing as discussed below. The closed hoop reinforcing bars are evenly grouped or banded above and below the openings. The continuous main meridional reinforcing, which would be interrupted by the openings, is grouped and bent or splayed around the openings to maintain the continuity of the reinforcing.

Supplemental reinforcing is placed around the openings in the areas left void of the meridional and hoop bars. Closed hoop rings are provided around the openings to accommodate stress concentration effects. Radial shear reinforcing consisting of hooked bars is placed around the large openings to accommodate transverse and popout shears.

Shear reinforcing is provided in the drywell wall in the form of inclined and horizontal hooked bars through the depth of the wall. A diagonal grind of reinforcing is provided at the outside face of the drywell wall to resist tangential (in plane) seismic shear.

The suppression chamber is structurally independent of the drywell containment and supported on the same foundation mat. A paper joint is provided between the bottom of the suppression chamber and the foundation mat to allow radial expansion of the suppression chamber. Vertical keys are provided along the outside perimeter of the drywell pedestal to allow independent, unrestrained expansion of the suppression chamber when subjected to symmetrical loading conditions. Under asymmetric loads the keys force the drywell and suppression chamber to respond as a single unit. The suppression chamber is reinforced with a single layer of continuous closed hoop reinforcing equally spaced around the perimeter of the liner. Meridional reinforcing in the form of closed rings is provided, and is placed radially to the centerline of the containment. Diagonal seismic reinforcing is located along the vertical faces of the suppression chamber. Additional reinforcing is provided in the top section of the suppression chamber for crack control.

The suppression chamber contains eight symmetrically located vent openings corresponding to the vent openings in the drywell. The main hoop reinforcing which would normally occur in the openings is banded above and below the openings. The meridional bars which would normally occur at these locations are grouped on either side. Reinforcing for areas left void by banding the main hoop and meridional reinforcing is provided by fill steel. Radial stirrups are provided around each vent opening to accommodate the transverse shears due to the openings.

RA-18-0149 Enclosure Page 7 of 90 3.2 Plant Operational Performance During power operation, the primary containment atmosphere is inerted with nitrogen to ensure that no external sources of oxygen are introduced into containment. The containment inerting system is used during initial purging of the primary containment prior to power operation and provides a supply of makeup nitrogen to maintain primary containment oxygen concentration within TS limits. As a result, the primary containment is maintained at a slightly positive pressure during power operation. During power operation, instrument air system (i.e., nitrogen) leaks occur from pneumatically-operated valves inside primary containment which gradually pressurize the primary containment. Primary containment pressure is monitored in the control room. The primary containment atmosphere is periodically vented in order to maintain containment pressure within an acceptable operating range. This cycling of the primary containment pressure during operation amounts to a periodic integrated pressure test of the containment at a low differential pressure. Although this cycling does not challenge the structural and leak tight integrity of the primary containment system at post-accident pressure, it provides assurance that a gross containment leakage that may develop during power operation will be detected. This feature is a compliment to visual inspection of the interior and exterior of the containment structure for those areas that may be inaccessible for visual examination. In the event pressurization does not occur, a leakage path must be present. During power operation, drywell pressure is monitored from the control room and vented if pressure reaches 0.7 pounds per square inch (psi). Additionally, Engineering performs system monitoring and trending of overall drywell pressure during power operations to determine the health of the Containment Atmospheric Control (CAC) System.

3.3 Emergency Core Cooling System Net Positive Suction Head Analysis Original plant Net Positive Suction Head (NPSH) calculations took no credit for containment (i.e., suppression chamber) pressure. As part of the 120 percent power uprate, the commitment was revised. Specifically, a 5-pound per square inch gauge (psig) credit for containment overpressure was established as acceptable for evaluating low pressure Emergency Core Cooling System (ECCS) pump NPSH. The 120 percent power uprate was approved by the NRC on May 31, 2002 (i.e., Reference 53).

3.3.1 Short Term NPSH Requirements For short term (i.e. 0 to 600 seconds) post-loss of coolant accident (LOCA) operation, no operator action is credited and, as a result, the residual heat removal (RHR) and core spray (CS) pumps are assumed to be at maximum flow conditions. For RHR, expected flow is 10,500 gallons per minute (gpm) per pump and 21,000 gpm per loop. For CS, expected flow is 6,700 gpm. The peak suppression pool temperature prior to assumed operator action (i.e. short term) was found to be 169.1 degrees Fahrenheit (°F). This is adequate such that no credit for containment overpressure is needed for the short-term conditions.

3.3.2 Long Term NPSH Requirements For long-term (i.e., greater than 600 seconds) post-LOCA operation, operator action to throttle the RHR and CS pumps is assumed. As such, the assumed pump flows are 5,750 gpm per RHR pump (i.e., 11,500 gpm loop flow) and 5,000 gpm for the CS pumps. The 120 percent power uprate analysis was also performed both with and without crediting containment spray.

The case that did not credit containment spray produced the peak temperature response of 207.7°F with a corresponding pressure of 25.5 psig. However, the case that credited

RA-18-0149 Enclosure Page 8 of 90 containment spray produced a slightly lower temperature profile (i.e., a 206.8°F peak) and a much lower pressure profile with an 11.3 psig peak. For conservatism, the NPSH calculations were performed based on the containment spray case, with the containment spray temperature profile increased by 0.9°F such that the peak temperature equaled that of the no spray case.

The maximum expected RHR flow was found to be 21,000 gpm or 10,500 gpm per pump.

This analysis demonstrated that runout for two-pump operation does not occur even in the worst case of discharge through a broken loop. Single pump runout was not evaluated because single pump operation implies loss of one pump which is an additional failure over-and-above the failure of the discharge valve to close.

Using the conservative profile discussed above, the NPSH parameters were determined for bounding evaluations. For the period of interest, the maximum required overpressure needed to ensure NPSH is 2.65 psig, with 11.3 psig containment overpressure available. In all cases, the available containment overpressure is in excess of three times the amount required to ensure adequate NPSH. To ensure sufficient margin exists to address potential future issues, the submittal for 120 percent power uprate requested that containment overpressure of up to 5.0 psig be credited for calculating ECCS pump NPSH margins. The NRC approved the request.

The High-Pressure Coolant Injection (HPCI) pumps are designed to operate continuously with suppression pool temperatures up to 140°F, normal suction is taken from the outside condensate storage tank. In the event of a failure of this storage tank, alternate suction exists to the suppression pool. Since the suppression pool temperature (SPT) will exceed 140°F during a design basis accident (DBA), the HPCI system has been designed to operate for short periods of time up to a temperature of 170°F. Because the reactor system depressurizes very rapidly after a DBA, the HPCI system will not operate for any significant length of time, nor is it required to mitigate the effects of the accident. Sufficient NPSH is available to the HPCI pump for these temperatures.

3.3.3 Containment Accident Pressure Evaluation In general, core damage frequency (CDF) is not significantly impacted by an extension of the ILRT interval; however, plants that rely on containment accident pressure (CAP), also referred to as containment overpressure (COP), for NPSH for ECCS injection for certain accident sequences may experience an increase in CDF. BSEP credits CAP in support of ECCS performance to mitigate design basis accidents; a loss of CAP may lead to degraded or a total loss of ECCS pump flow. Therefore, a detailed analysis was performed in BSEP Calculation 54011-CALC-01 (i.e., Attachment 6 to this submittal) to quantify the potential effect on CDF.

The following provides an overview and summary of the analysis and the results.

Per the EPRI 1009325 guidance (i.e., Reference 8):

In the case where containment overpressure may be a consideration, plants should examine their ECCS NPSH requirements to determine if containment overpressure is required (and assumed to be available) in various accident scenarios. Examples include the following:

LOCA scenarios where the initial containment pressurization helps to satisfy the NPSH requirements for early injection in BWRs or PWR sump recirculation

RA-18-0149 Enclosure Page 9 of 90 Total loss of containment heat removal scenarios where gradual containment pressurization helps to satisfy the NPSH requirements for long-term use of an injection system from a source inside of containment (for example, BWR suppression pool).

In a design basis LOCA event, for long-term (i.e., greater than 600 seconds) post-LOCA operation, up to 5.0 psig of CAP is credited at BSEP to ensure adequate NPSH margin (i.e.,

NPSH available minus NPSH required); for short-term, less than 600 seconds, operation; the NPSH margin is sufficient and no credit for CAP is needed. Therefore, LOCA sequences must be analyzed for an impact from a loss of CAP. In the Probabilistic Risk Assessment (PRA), all LOCA sequences are considered, which includes all modeled Reactor Coolant System (RCS) pipe breaks and transient-induced LOCAs (e.g., inadvertent safety relief valve (SRV) opening without closure).

Further, the EPRI guidance states If either of these cases is susceptible to whether or not containment overpressure is available (or other cases are identified), then the PRA model should be adjusted to account for this requirement.

The BSEP PRA also credits CAP for the intermittent use of long-term injection systems with suction from the suppression pool for transient sequences where suppression pool cooling is failed; this function requires an elevated pressure in containment to support NPSH to the ECCS.

Therefore, transient sequences must be analyzed for an impact from a loss of CAP.

The effect of a loss of CAP on CDF was analyzed for both internal and external events.

3.3.4 Loss of CAP Analysis A loss of CAP may lead to failure of the low pressure ECCS, RHR and CS, due to inadequate NPSH available to support required pump flow. Suppression pool cooling (SPC) can be initiated to lower the SPT and increase the available NPSH. In other words, CAP is not required if SPC is successfully established in time to preclude SPT from exceeding the value where available NPSH would decrease below that required to support pump flow. If SPC is not initiated in time or fails, the intermittent use of the low pressure ECCS for post-vent, long-term injection for transient scenarios credits elevated containment pressure to function. Given the possible existence of a pre-existing leak in containment evaluated in this risk analysis, these long-term injection sources may be failed if SPC is not successful.

The approach to modeling the risk impact due to the potential loss for CAP given a pre-existing leak involved two model changes:

First, the PRA timing for the operator actions to establish SPC was confirmed adequate to preclude the need for CAP. Timing was verified for all accident sequences where low pressure ECCS are credited, and, if the existing operator action timing was not adequate to preclude the need for CAP, then the model was adjusted to include the required (i.e., shorter) operator action timing. The details are discussed below.

Second, the PRA model was adjusted to ensure low pressure ECCS were failed if SPC fails, which models the impacts of inadequate NPSH given the pre-existing leak, no SPC, but sequences where containment venting succeeds and long-term low-pressure injection is required.

RA-18-0149 Enclosure Page 10 of 90 MAAP Analyses Inputs In order to establish the operator action timing for initiating SPC in time to preclude the need for CAP for low pressure ECCS NPSH, existing and new MAAP analyses cases were utilized.

MAAP analyses supporting the Fire PRA were performed in order to analyze the effect of a loss of CAP due to multiple spurious operations (MSOs) that result in an un-isolated containment on the low pressure ECCS. Review of these cases determined they are applicable/bounding for transient sequences in the BSEP PRA because the un-isolated containment ensures no CAP can build to support low pressure ECCS NPSH, and the Fire PRA is composed of mostly transient risk. According to the Fire PRA MAAP analysis, an SPT of 192°F will degrade RHR pump flow and an SPT of 202°F will degrade the CS flow. It was determined that if SPC is initiated when the SPT reaches 185°F, the SPT will remain below these criteria. Per the Fire PRA MAAP results, the most limiting timing for initiating SPC with an un-isolated containment is 3.69 hours7.986111e-4 days 0.0192 hours 1.140873e-4 weeks 2.62545e-5 months . The operator action to initiate SPC following a non-LOCA in the PRA modes is OPER-SPCE, which has a timing of 3.8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months . This small difference in time leads to no change in the Human Error Probability (HEP) value, and thus no change in risk. Therefore, the modeled operator action to initiate SPC for a transient sequence is considered appropriate for the loss of CAP analysis.

Existing MAAP analyses were applicable to transient risk in the BSEP PRA, but do not apply to RCS pipe break LOCA conditions and the heatup timing of the suppression pool in LOCA sequences. To establish the timing required to initiate SPC given an RCS pipe break LOCA to preclude the need for CAP, MAAP runs were performed for small, medium, and large LOCA scenarios for the CAP analysis using similar methodology to the Fire PRA MAAP analyses discussed above. Per the BSEP Level 2 analysis, a 2-inch diameter opening in containment equates to 30 - 35 wt.%/day, and an opening size of 3.5-inches equates to 100 wt.%/day. Per Section 5.2.2 of Attachment 6 of this submittal, allowable containment leakage, La, is 0.5 wt.%/day; therefore, 100 La is 50 wt.%/day, which approximately equates to an opening size of 2.5-inches in diameter. Therefore, the loss of CAP LOCA analyses assume a containment opening size of 2.5 inches; minor changes in the size of the opening have little impact on the results.

The results of the CAP analysis MAAP runs indicate that initiating SPC at 2.4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for small and medium LOCAs and 1.75 hours8.680556e-4 days 0.0208 hours 1.240079e-4 weeks 2.85375e-5 months for large LOCAs prevents reaching the SPT criterion.

Using these timings, two detailed Human Failure Event (HFEs) were created for initiating SPC with loss of CAP, one for small and medium LOCAs and one for large LOCAs. The HFEs were based off operator action OPER-SPC, which is the operator action to initiate SPC following a LOCA. The BSEP PRA model was adjusted to utilize these HFEs for LOCA scenarios to model the time in which SPC must be initiated to preclude the need for CAP to support low pressure ECCS NPSH.

Model Adjustment With the timing to initiate SPC to preclude the need for CAP to support low pressure ECCS NPSH established via the MAAP analyses, the Unit 1 and Unit 2 models (i.e., Internal and External Events) were revised. The revised CAP analysis models include failure of the low pressure ECCS (i.e., RHR and CS) given a pre-existing leak in containment and failure to initiate SPC in time to preclude the need for CAP to support low pressure ECCS NPSH (i.e.,

new HFEs) in all applicable sequences in each model. For the purposes of this risk assessment, internal events models are the full-power internal events and internal flooding PRA

RA-18-0149 Enclosure Page 11 of 90 models; external event models are Fire PRA and High Winds PRA models. The CAP analysis Unit 1 and Unit 2 models were quantified to estimate the change in CDF from the increased likelihood of pre-existing leaks given the ILRT surveillance frequency change.

The pre-existing leak basic event probability was varied from 2.30E-03 (i.e., probability of a 3b leak based on an ILRT interval of 3-in-10 years) to 1.15E-02 (i.e., probability of a 3b leak based on the ILRT interval of 1-in-15 years) and the CDF for each surveillance frequency was estimated. The CDF was estimated as the difference between the two surveillance frequency cases. The CDF was also estimated for the 1-in-10 years ILRT interval by changing the pre-existing leak basic event probability to 7.67E-03.

Quantification Results The results of the analysis are provided below and summarized in Table 5-20 for Unit 1 and Table 5-21 for Unit 2 of Attachment 6 of this submittal.

The CDF increase due to a loss of CAP due to the ILRT extension to 1-in-15 years from 3-in-10 years is estimated to be 1.61E-08/year for Unit 1 and 1.54E-08/year for Unit 2. This CDF was assumed equal to the change in large early release frequency (LERF) from CAP and added to the EPRI Class 3b frequency and included in the results provided in Section 6.0 and in the sensitivities performed in Section 5.3 of Attachment 6 of this submittal. The CDF increase due to a loss of CAP due to the ILRT extension to 1-in-10 years from 3-in-10 years is estimated to be 9.37E-09/year for Unit 1 and 9.01E-09/year for Unit 2.

Similarly, for High Wind events, the pre-existing leak basic event probability was varied from 2.30E-03 to 1.15E-02, which causes a delta of 6.41E-08 for Unit 1 and 6.31E-08 for Unit 2. This CDF was assumed equal to LERF from CAP and added to the EPRI Class 3b frequency for High Winds events in the external events analysis. The CDF increase due to a loss of CAP due to the ILRT extension to 1-in-10 years from 3-in-10 years is estimated to be 3.75E-08/year for Unit 1 and 3.69E-08/year for Unit 2.

For Fire events, the quantification showed no increase in CDF due to the pre-existing leak in containment; therefore, there is a negligible change in CDF due to the ILRT extension.

For seismic events, a qualitative and bounding CAP analysis was performed. Since BSEP credits the use of RHR and CS for long-term intermittent injection for transient sequences, there may be some impact to seismic CDF due to a loss of CAP. Generally, seismic risk is dominated by failure of key plant structures and key plant systems due to seismic motion which exceeds the capacity of key structures and systems. Failure of key structures (e.g., containment building, reactor building, etc.) are typically assumed to lead straight to core damage; and therefore, a loss of CAP will have no impact. It is common to treat equipment of the same type at the same elevation as being failed due to the seismic event, so seismic events that only fail some low pressure ECCS pumps are much more likely than seismic events that only fail some low pressure ECCS pumps while others survive; a loss of CAP will have no impact on scenarios where all ECCS pumps are failed. Furthermore, a loss of CAP will have no impact on station blackout (SBO) scenarios; since the ECCS pumps will be failed due to a loss of power. A loss of CAP may impact seismic scenarios where a key structure is not failed and the low pressure ECCS pumps are available. As a bounding estimate, the CDF for seismic scenarios is assumed proportional to the CDF for Internal Events. This is bounding because the predominant contributor to the increase due to a loss of CAP for Internal Events is LOCA sequences and seismic events are far more likely to lead to key structure and system failures or

RA-18-0149 Enclosure Page 12 of 90 SBO sequences than LOCA sequences. This leads to a seismic CDF of 3.02E-08 for Unit 1 and 3.10E-08 for Unit 2. These CDF sequences were assumed equal to LERF from CAP and added to the EPRI Class 3b frequency for seismic events in the external events analysis.

The CDF increase due to a loss of CAP due to the ILRT extension to 1-in-10 years from 3-in-10 years is estimated to be 1.76E-08/year for Unit 1 and 1.81E-08/year for Unit 2.

RG 1.174 defines very small changes in CDF as resulting in increases of CDF less than 1.0E-06/year. Per the analysis, the change CDF due to a loss of CAP and the ILRT extension is considered "very small".

3.3.5 Key Assumptions and Sources of Uncertainty Key assumptions or sources of uncertainty for the loss of CAP analysis are the following:

No credit is given for alignment of CS to the Condensate Storage Tank (CST), a source outside containment. Procedures are in place to align CS to the CST. Aligning the CS pumps to the CST would significantly reduce CDF for single unit events. Not crediting CS alignment to the CST is conservative.

Another source of uncertainty is whether or not a "large" "early" release would occur in a loss of NPSH scenario. This uncertainty is addressed with the CAP related assumption that loss of low pressure injection (i.e., CS and RHR) due to a pre-existing leak and loss of SPC leads to a large early release. This may be a conservative assumption. Loss of inventory make-up may result in a delayed "non-Large" release, for which there would be adequate time for evacuation.

Diverse and Flexible Coping Strategies (FLEX) is not modeled in the External Events models; and therefore, was not credited in the External Events loss of CAP analysis.

Crediting FLEX would reduce the increase due to a loss of CAP for High Winds events, since FLEX is a separate form of late injection that would likely be available even if the intermittent long-term use of the low pressure ECCS systems was failed due to a loss of CAP. Similarly, FLEX would reduce the risk from seismic events given a loss of CAP; however, seismic events were not quantitatively analyzed in the CAP analysis.

It is assumed the low pressure ECCS pumps will fail when the SPT criteria is met. The reduction in NPSH may not lead to immediate failure of the pumps, and instead, may only degrade the flow. Furthermore, it is noted that industry testing and analysis indicate that ECCS pumps used in BWR 3/4 plants are capable of adequate short term (i.e.,

approximately 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months ) operation well below the manufacturers recommended design NPSH (e.g., 65% of the specified NPSH limit for Browns Ferry as documented in NUREG/CR-2973 (i.e., Reference 9)). Therefore, additional margin exists beyond that reflected in the MAAP calculations.

MAAP is known to have some modeling deficiencies (e.g., potential for reverse flow not modeled) for Large LOCA scenarios. These deficiencies only impact results in the early portion of the run (i.e., approximately first three minutes) prior to core recovery. These deficiencies do not impact the ILRT MAAP calculation results because the peak torus temperature is reached hours into each run.

RA-18-0149 Enclosure Page 13 of 90 3.4 Justification for the TS Change 3.4.1 Chronology of Testing Requirements of 10 CFR 50, Appendix J The testing requirements of 10 CFR 50, Appendix J, provide assurance that leakage from the containment, including systems and components that penetrate the containment, does not exceed the allowable leakage values specified in the TS. 10 CFR 50, Appendix J also ensures that periodic surveillance of reactor containment penetrations and isolation valves are performed so that proper maintenance and repairs are made during the service life of the containment and those systems and components penetrating primary containment. The limitation on containment leakage provides assurance that the containment would perform its design function following an accident up to and including the plant DBA. Appendix J identifies three types of required tests: 1) Type A tests, intended to measure the primary containment overall integrated leakage rate; 2) Type B tests, intended to detect local leaks and to measure leakage across pressure-containing or leakage limiting boundaries (other than valves) for primary containment penetrations, and; 3) Type C tests, intended to measure CIV leakage rates. Type B and C tests identify the vast majority of potential containment leakage paths.

Type A tests identify the overall (i.e., integrated) containment leakage rate and serve to ensure continued leakage integrity of the containment structure by evaluating those structural parts of the containment not covered by Types B and C testing.

In 1995, 10 CFR 50, Appendix J, was amended to provide a performance-based Option B for the containment leakage testing requirements. Option B requires that test intervals for Type A, Type B, and Type C testing be determined by using a performance-based approach.

Performance-based test intervals are based on consideration of the operating history of the component and resulting risk from its failure. The use of the term "performance-based" in 10 CFR 50, Appendix J refers to both the performance history necessary to extend test intervals as well as to the criteria necessary to meet the requirements of Option B.

Also, in 1995, RG 1.163 (i.e., Reference 1) was issued. The RG endorsed NEI 94-01, Revision 0, (i.e., Reference 5) with certain modifications and additions. Option B, in concert with RG 1.163 and NEI 94-01, Revision 0, allows licensees with a satisfactory ILRT performance history (i.e., two consecutive, successful Type A tests) to reduce the test frequency for the containment Type A ILRT test from three tests in 10 years to one test in 10 years. This relaxation was based on an NRC risk assessment contained in NUREG-1493, (i.e., Reference 10) and Electric Power Research Institute (EPRI) TR-104285 (i.e., Reference

11) both of which showed that the risk increase associated with extending the ILRT surveillance interval was very small. In addition to the 10-year ILRT interval, provisions for extending the test interval an additional 15 months were considered in the establishment of the intervals allowed by RG 1.163 and NEI 94-01, but that this extension of interval "should be used only in cases where refueling schedules have been changed to accommodate other factors."

In 2008, NEI 94-01, Revision 2-A (i.e., Reference 3), was issued. This document describes an acceptable approach for implementing the optional performance-based requirements of Option B to 10 CFR 50, Appendix J, subject to the limitations and conditions noted in Section 4.0 of the NRC Safety Evaluation Report (SER) on NEI 94-01. NEI 94-01, Revision 2-A, includes provisions for extending Type A ILRT intervals to up to 15 years and incorporates the regulatory positions stated in RG 1.163 (i.e., Reference 1). It delineates a performance-based approach for determining Type A, Type B, and Type C containment leakage rate

RA-18-0149 Enclosure Page 14 of 90 surveillance testing frequencies. Justification for extending test intervals is based on the performance history and risk insights.

In 2012, NEI 94-01, Revision 3-A (i.e., Reference 2), was issued. This document describes an acceptable approach for implementing the optional performance-based requirements of Option B to 10 CFR 50, Appendix J and includes provisions for extending Type A ILRT intervals to up to 15 years. NEI 94-01 has been endorsed as an acceptable methodology for complying with the provisions of 10 CFR Part 50, Appendix J, Option B, by RG 1.163 and NRC SERs dated June 25, 2008, and June 8, 2012 (i.e., References 1, 12, and 13, respectively). The regulatory positions stated in RG 1.163 as modified by References 10 and 11 are incorporated in this document. It delineates a performance-based approach for determining Type A, Type B, and Type C containment leakage rate surveillance testing frequencies. Justification for extending test intervals is based on the performance history and risk insights. Extensions of Type B and Type C test intervals are allowed based upon completion of two consecutive periodic as-found tests where the results of each test are within a licensees allowable administrative limits.

Intervals may be increased from 30 months up to a maximum of 120 months for Type B tests (i.e., except for containment airlocks) and up to a maximum of 75 months for Type C tests. If a licensee considers extended test intervals of greater than 60 months for Type B or Type C tested components, the review should include the additional considerations of as-found tests, schedule and review as described in NEI 94-01, Revision 3-A, Section 11.3.2.

The NRC has provided guidance concerning the use of test interval extensions in the deferral of ILRTs beyond the 15-year interval in NEI 94-01, Revision 2-A, NRC SER Section 3.1.1.2 that states, in part:

Section 9.2.3, NEI TR 94-01, Revision 2, states, "Type A testing shall be performed during a period of reactor shutdown at a frequency of at least once per 15 years based on acceptable performance history." However, Section 9.1 states that the "required surveillance intervals for recommended Type A testing given in this section may be extended by up to 9 months to accommodate unforeseen emergent conditions but should not be used for routine scheduling and planning purposes." The NRC staff believes that extensions of the performance-based Type A test interval beyond the required 15 years should be infrequent and used only for compelling reasons. Therefore, if a licensee wants to use the provisions of Section 9.1 in TR NEI 94-01, Revision 2, the licensee will have to demonstrate to the NRC staff that an unforeseen emergent condition exists.

NEI 94-01, Revision 3-A, Section 10.1, Introduction, concerning the use of test interval extensions in the deferral of Type B and Type C LLRTs, based on performance, states in part, that:

Consistent with standard scheduling practices for TS Required Surveillances, intervals of up to 120 months for the recommended surveillance frequency for Type B testing and up to 75 months for Type C testing given in this section may be extended by up to 25% of the test interval, not to exceed nine months.

Notes: For routine scheduling of tests at intervals over 60 months, refer to the additional requirements of Section 11.3.2.

Extensions of up to nine months (total maximum interval of 84 months for Type C tests) are permissible only for non-routine emergent conditions. This provision (nine-month extension) does not apply to valves that are restricted and/or limited to 30-month intervals

RA-18-0149 Enclosure Page 15 of 90 in Section 10.2 (such as BWR MSIVs) or to valves held to the base interval (30 months) due to unsatisfactory LLRT performance.

The NRC has also provided the following concerning the extension of ILRT intervals to 15 years in NEI 94-01, Revision 3-A, NRC SER Section 4.0, Condition 2, which states, in part:

The basis for acceptability of extending the ILRT interval out to once per 15 years was the enhanced and robust primary containment inspection program and the local leakage rate testing of penetrations. Most of the primary containment leakage experienced has been attributed to penetration leakage and penetrations are thought to be the most likely location of most containment leakage at any time.

3.4.2 Current BSEP Primary Containment Leakage Rate Testing Program Requirements 10 CFR 50, Appendix J was revised, effective October 26, 1995, to allow licensees to choose containment leakage testing under either Option A, "Prescriptive Requirements," or Option B, "Performance-Based Requirements." On February 1, 1996, the NRC approved TS Amendment 181 for BSEP Unit 1 and Amendment 213 for BSEP Unit 2 (i.e., Reference 14) authorizing the implementation of 10 CFR 50, Appendix J, Option B for Types A, B and C tests.

Current Units 1 and 2 TS 5.5.12 requires that a program be established to comply with the containment leakage rate testing requirements of 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B. The program is required to be in accordance with the guidelines contained in RG 1.163. RG 1.163 endorses, with certain exceptions, NEI 94-01, Revision 0 (i.e., Reference 5), as an acceptable method for complying with the provisions of Appendix J, Option B.

RG 1.163, Section C.1 states that licensees intending to comply with 10 CFR 50, Appendix J, Option B, should establish test intervals based upon the criteria in Section 11.0 of NEI 94-01 rather than using test intervals specified in ANSI/ANS 56.8-1994 (i.e., Reference 6). NEI 94-01, Section 11.0 refers to Section 9, which states that Type A testing shall be performed during a period of reactor shutdown at a frequency of at least once per ten years based on acceptable performance history. Acceptable performance history is defined as completion of two consecutive periodic Type A tests where the calculated performance leakage was less than 1.0La, where La is the maximum allowable leakage rate at design pressure. Elapsed time between the first and last tests in a series of consecutive satisfactory tests used to determine performance shall be at least 24 months.

Adoption of the Option B performance-based containment leakage rate testing program altered the frequency of measuring primary containment leakage in Types A, B, and C tests but did not alter the basic method by which Appendix J leakage testing is performed. The test frequency is based on an evaluation of the "as found" leakage history to determine a frequency for leakage testing which provides assurance that leakage limits will not be exceeded. The allowed frequency for Type A testing as documented in NEI 94-01 is based, in part, upon a generic evaluation documented in NUREG-1493 (i.e., Reference 10). The evaluation documented in NUREG-1493 includes a study of the dependence or reactor accident risks on containment leak tightness for differing types of containment types, including a pressure suppression containment similar to the BSEP containment structure. NUREG-1493 concludes in Section 10.1.2 that reducing the frequency of Type A tests from the original three tests per 10 years to one test per 20 years was found to lead to an imperceptible increase in risk. The estimated increase in risk

RA-18-0149 Enclosure Page 16 of 90 is very small because ILRTs identify only a few potential containment leakage paths that cannot be identified by Types B and C testing, and the leaks that have been found by Type A tests have been only marginally above existing requirements. Given the insensitivity of risk to containment leakage rate and the small fraction of leakage paths detected solely by Type A testing, NUREG-1493 concludes that increasing the interval between ILRTs is possible with minimal impact on public risk.

3.4.3 BSEP 10 CFR 50, Appendix J, Option B Licensing History February 1, 1996 The NRC issued Amendment Nos. 181 and 213, which modified Units 1 and 2 TS 5.5.12, respectively, to allow the use of 10 CFR Part 50, Appendix J, Option B, Performance-Based Containment Leakage Rate Testing. (i.e., Reference 14)

March 6, 2002 The NRC issued Amendment No. 216, which modified Unit 1 TS 5.5.12 to allow for a one-time increase in the BSEP, Unit 1 Type A, ILRT for no more than 3 years, 2 months. (i.e., Reference

15)

November 21, 2002 The NRC issued Amendment No. 250, which modified Unit 2 TS 5.5.12 to allow for a one-time increase to the BSEP, Unit 2 Type A, ILRT for no more than 2 years, 2 months. (i.e., Reference

16)

March 9, 2005 The NRC issued an exemption from the requirements of 10 CFR Part 50, Appendix J to exclude the main steam isolation valve (MSIV) leakage from the overall integrated leakage rate test measurements required by Section III.A of Appendix J, Option B. (i.e., Reference 17)

February 8, 2006 The NRC issued Amendment No. 238 and Amendment No. 266, which revised Units 1 and 2 TS 5.5.12, respectively, to remove an exemption that allowed for compensation of flow meter instrument inaccuracies in accordance with the guidance document ANSI/ANS 56.8-1987, rather than meeting the instrument accuracy requirements in ANSI/ANS 56.8-1994. (i.e.,

Reference 18)

March 2, 2006 The NRC issued Amendment No. 239 and Amendment No. 267, for Units 1 and 2, respectively, which revised Surveillance Requirement 3.6.1.3.9 to increase the allowable MSIV leakage rate.

Specifically, the limit was revised from an allowable leakage rate of less than or equal to 11.5 standard cubic feet per hour scfh through each MSIV to less than or equal to 100 scfh through each main steam line (MSL) with the combined leakage of the four MSLs being less than or equal to 150 scfh. (i.e., Reference 19)

RA-18-0149 Enclosure Page 17 of 90 February 8, 2008 The NRC issued Amendment No. 245 and Amendment No. 273, which revised Units 1 and 2 TS 5.5.12, respectively to allow the required Appendix J visual inspections to be performed in accordance with the ASME Boiler and Pressure Vessel (B&PV) Code,Section XI, Subsections IWE and IWL. (i.e., Reference 20) 3.4.3.1 Continued Acceptability of Units 1 and 2 TS 5.5.12.a, b, d and e.

Units 1 and 2 Exceptions TS 5.5.12.a and TS 5.5.12.b By letter dated February 8, 2008, the NRC issued Amendment No. 245 and Amendment No. 273 which revised Units 1 and 2 TS 5.5.12, respectively to allow the required Appendix J visual inspections to be performed in accordance with the ASME BPV Code,Section XI, Subsections IWE and IWL. (i.e., Reference 20)

Units 1 and 2 TS Exception 5.5.12.d By letter dated December 9, 1983, the NRC provided correspondence to BSEP stating that the use of Bechtel Topical Report BN-TOP-1, Revision 1, "Testing Criteria for Integrated Leakage Rate Testing of Primary Containment Structures for Nuclear Power Plants," had been previously approved and therefore offered no objection for its use for ILRTs at BSEP. Subsequently, by letter dated August 4, 1989, the NRC approved Amendment Nos. 136 and 166 for BSEP Units 1 and 2 to delete the requirement to use only the mass point method for Type A containment ILRTs permitted by Appendix J. (i.e., References 21, 22)

Units 1 and 2 TS Exception 5.5.12.e By letter dated May 12, 1987, the NRC issued an exception from the requirements of 10 CFR 50, Appendix J which revised the BSEP Units 1 and 2 TS to exempt the hydrogen/oxygen monitor isolation valves from Type C testing. (i.e., Reference 23)

NEI 94-01, Revisions 2-A and 3-A, Section 1.1 state, in part, Generally, a FSAR (Final Safety Analysis Report) describes plant testing requirements, including containment testing. In some cases, FSAR testing requirements differ from those of Appendix J. In many cases, Technical Specifications were approved that incorporated exemptions to provisions of Appendix J. Additionally, some licensees have requested and received exemptions after their Technical Specifications were issued.

The alternate performance-based testing requirements contained in Option B of Appendix J will not invalidate such exemptions. However, any exemptions to the provisions of 10 CFR 50, Appendix J to be maintained in force as part of the Containment Leakage Testing Program should be clearly identified as part of the plants program documentation.

By letter dated June 25, 2008, the NRC issued the Final Safety Evaluation Report (SER) for NEI 94-01, Rev. 2, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J" and EPRI Report Number 1009325, Rev. 2, August 2007, "Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals." The SER states, If the exemptions were issued after the Technical Specifications were approved, when the licensee amends the TS requirements to the new test interval (for Type A, Type B or

RA-18-0149 Enclosure Page 18 of 90 Type C tests), it should explicitly describe which exemptions the licensee wants to continue with and which exemptions it will not use during the implementation of the new test intervals. This information should be part of the TS amendment request. The NRC staff requests that this section be clarified to state that this approach is acceptable provided the NRC has a chance to review the licensees choice, as part of the TS amendment.

==

Conclusion:==

This LAR does not change the Units 1 and 2 TS exceptions 5.5.12.a, b, d and e. Therefore, BSEP will continue to use the provisions of Unit 1 and 2 TS exceptions 5.5.12.a, b, d and e as written.

3.4.3.2 Continued Acceptability of Units 1 and 2 TS Exceptions 5.5.12.c and f with Minor Administrative Changes.

TS Exception 5.5.12.c By letter dated November 23, 1977, the NRC issued Amendments No. 12 and 39 for BSEP Units 1 and 2 to Operating Licenses revising Standard Technical Specifications (STS) for Unit 1 and incorporating similar STS for Unit 2 (i.e., Reference 24). The plants original TS required testing of the Personnel Airlock seals at 10 psig. This testing procedure was changed in 1977 to 49 psig to conform to Appendix J criteria. With the issuance of the STS, the test pressure was changed back to 10 psig in conformance with the General Electric STS.

TS exception 5.5.12.c allows for testing of the airlock door seals at 10 psig in lieu of Pa, as specified in NEI 94-01, following airlock door seal replacement. This exception specifically references Revision 0 to NEI 94-01. Section 10.2.2.1 (i.e., fourth paragraph) of NEI 94-01 Revision 0 states, Door seals are not required to be tested when containment integrity is not required, however, they must be tested prior to reestablishing containment integrity. Door seals shall be tested at Pa, or at a pressure stated in the plant Technical Specifications.

As part of the proposed change, BSEP will incorporate NEI 94-01, Revision 3-A by reference into TS 5.5.12. The wording in NEI 94-01 Revision 3-A Section 10.2.2.1 regarding airlock door seal testing remains the same as in Revision 0. Therefore, TS exception 5.5.12.c will be revised to read, Following air lock door seal replacement, performance of door seal leakage rate testing with the gap between the door seals pressurized to 10 psig instead of airlock testing at Pa, as specified in Nuclear Energy Institute Guideline 94-01, Revision 3-A.

TS Exception 5.5.12.f By letter dated November 8, 1977 (i.e., Reference 25), the NRC issued an exception from the requirements of Section III.C.2 of 10 CFR 50, Appendix J. This exception allowed BSEP to perform the Type C LLRT of the main steam isolation valves at a pressure of 25 psig instead of Pa (i.e., 49 psig).

RA-18-0149 Enclosure Page 19 of 90 TS exception 5.5.12.f allows for testing of the MSIVs at a pressure less than Pa, instead of leak rate testing at Pa. This exception specifically references ANSI/ANS 56.8-1994. ANSI/ANS 56.8-1994 Section 3.3.2 states, Types B and C tests shall be conducted at a differential pressure of not less than Pac

[containment accident pressure], except on airlock door seals, which may have a lower pressure specified in the plants licensing basis. When a higher differential pressure results in increased sealing, such as a check valve, the differential pressure shall not exceed 1.1 Pac.

As part of the proposed change, BSEP will incorporate NEI 94-01 Revision 3-A by reference into TS 5.5.12. NEI 94-01 Revision 3-A requires performance of integrated and local leakage rate testing in accordance with ANSI/ANS 56.8-2002. The wording in ANSI/ANS 56.8-2002 regarding the test pressure for Type B and C tests remains the same as in the 1994 edition of the ANSI standard. Therefore, TS exception 5.5.12.f will be revised to read, Performance of Type C leak rate testing of the main steam isolation valves at a pressure less than Pa instead of leak rate testing at Pa as specified in ANSI/ANS 56.8-2002.

==

Conclusion:==

The proposed changes to TS Exceptions 5.5.12.c and f are administrative in nature, and, therefore, do not change the requirements or performance of the Types B and C leakage testing.

3.4.4 Integrated Leakage Rate Testing History (ILRT)

As noted previously, BSEP TS 5.5.12 currently requires Types A, B, and C testing in accordance with RG 1.163, which endorses the methodology for complying with Option B.

Since the adoption of Option B, the performance leakage rates are calculated in accordance with NEI 94-01, Section 9.1.1 for Type A testing. Tables 3.4.4-1 and 3.4.4-2 lists the past Periodic Type A ILRT results for BSEP Units 1 and 2, respectively.

RA-18-0149 Enclosure Page 20 of 90 Table 3.4.4-1 BSEP Unit 1 Type A Testing History Test Date 95% Upper Confidence Limit (wt.%/day)

As-Found Leakage (wt.%/day)

Acceptance Criteria (wt.%/day)

As-Left Leakage (wt.%/day)

Acceptance Criteria (0.75La)

(wt.%/day)

Performance Leakage Rate (wt.%/day)

Acceptance Criteria (La)

(wt.%/day) 9/2/1976 0.191 0.191 0.375 0.191 0.375 N/A 0.5 6/12/1981 0.307 0.356 0.375 0.352 0.375 N/A 0.5 9/25/1985 0.276 0.365 0.375 0.284 0.375 N/A 0.5 5/19/1987 0.205 (Note 1) 0.375 0.215 0.375 N/A 0.5 2/4/1991 0.3251 0.4956 (Note 2) 0.375 0.3408 0.375 N/A 0.5 3/25/2004 0.1265 0.3351 0.5 0.2602 0.375 0.2602 0.5 4/11/2010 0.1775 0.21 0.5 0.1387 0.375 0.1387 0.5

RA-18-0149 Enclosure Page 21 of 90 Table 3.4.4-2 BSEP Unit 2 Type A Test History Test Date 95% Upper Confidence Limit (wt.%/day)

As-Found Leakage (wt.%/day)

Acceptance Criteria (La)

(wt.%/day)

As-Left Leakage (wt.%/day)

Acceptance Criteria (0.75La)

(wt.%/day)

Performance Leakage Rate (wt.%/day)

Acceptance Criteria (La)

(wt.%/day) 10/8/1974 0.153 0.153 0.375 0.153 0.375 N/A 0.5 7/14/1982 0.304 0.653 (Note 3) 0.375 0.318 0.375 N/A 0.5 9/24/1984 0.298 (Note 4) 0.375 0.293 0.375 N/A 0.5 5/5/1986 0.237 (Note 5) 0.375 0.24 0.375 N/A 0.5 2/19/1990 0.308 (Note 6) 0.375 0.334 0.375 N/A 0.5 12/2/1991 0.327 0.4956 (Note 7) 0.375 0.355 0.375 N/A 0.5 2/26/1993 0.318 0.442 (Note 8) 0.375 0.351 0.375 N/A 0.5 3/30/2005 0.3236 0.2922 0.5 0.2557 0.375 0.2602 0.5 4/1/2015 0.4237 0.4797 0.5 0.299 0.375 0.299 0.5

RA-18-0149 Enclosure Page 22 of 90 Tables 3.4.4.1 and 3.4.4.2 Notes:

Note 1: The BSEP Unit 1 1987 ILRT As-Found leakage rate exceeded its limit of 0.75 La (i.e.,

0.375 wt.%/day) with a leakage rate greater than La. This was primarily due to immeasurable leakage on Penetration X9A, Feedwater Loop A Injection and Penetration X54E, Containment Monitor, CAC-AT-1262, Discharge. Penetration X9A was repaired during the 1987 refueling outage by repairing valve B21-F010B and repairing the leak-off line and packing on valve B21-F032A. Penetration X54E was repaired by replacing the discs in valves CAC-SV-1211E and CAC-SV-3439. Without the leakage additions from Penetrations X9A and X54A, the as-found leakage savings would have been approximately 0.049 wt.%/day.

Note 2: The BSEP Unit 1 1991 As-Found Leakage rate exceeded its limit of 0.75La (i.e., 0.375 wt.%/day) with a leakage rate 0.4956 wt.%/day. This was primarily due to excessive leakage on Penetration X9B, Feedwater Loop B Injection, Penetration X14, Reactor Water Clean Up Suction Line and Penetration X10, Reactor Core Isolation Cooling Turbine Steam Supply Line. Penetration X9B was repaired by replacing the soft seat ring on valve B21-F010B. Penetration X14 was repaired by replacing valves G31-F001 and G31-F004. Penetration X10 was repaired by replacing valves E51-F007 and E51-F008.

Note 3: During the 1982 Unit 2 ILRT, excessive leakage was noted in several areas of the containment structure following initial pressurization. One of the areas found to be contributing to the leakage was a root valve on a pressure instrument which was incorrectly left open. The valve was subsequently closed. Another area found to be contributing to the high leakage readings was a leak on a tubing connector to pressure recorder CAC-PT-2685 which was repaired. A third area contributing to the leakage was the RHR A Loop heat exchanger relief valve, E11-F055A. The leakage was secured by installing a gagging bolt and subsequent snooping of the relief valve confirmed no other leaks in the area. Also, during the data gathering phase, personnel performing leak searches found a number of small leaks throughout the plant, contributing to the excessive leakage, though no single large leaks were found.

Leakages in the stem and packing of the temporary piping valves used for the pressurization were found and repaired. Caps were installed on lines which had no leakage but were discovered to be missing caps. Following the repairs of the items above, components were found to be mispositioned which were also leading to the excessive measured leakage. HPCI valves E41-F075 and E41-F079 along with RCIC valves E51-F066 and F51-F062 were positioned open rather than the required test position of closed. The other mispositioning event involved a sample line which was in service during the ILRT. These valves were subsequently correctly positioned.

Note 4: Local leakage rate testing of Unit 2 primary CIVs revealed a nonquantifiable leakage rate on several containment penetrations. These observed conditions made the calculation of the "As-Found" containment leakage indeterminate. The components contributing to the excessive leakage were B21-F010A and B21-F010B which were repaired by machining the disc and replacing the soft seat; B21-F032B, E51-F013 and G31-F039 which were repaired by removing G31-F039 from the flow path and installing a freeze seal to isolate the line; CAC-V47 which was repaired by resetting the actuator; CAC-X20A, CAC-V16 which were repaired by replacing V16; CAC-SV1263-4 and CAC-SV4409-3 which were removed from the system via design change;

RA-18-0149 Enclosure Page 23 of 90 CAC-PV1218C which was repaired by replacing the component and the valve internals; E11-F008, E11-F009 which was repaired by lapping the seats of E11-F009; E11-F001B which were repaired by performing maintenance on the test boundary valves; E11-F020A which was repaired by resetting torque switch, adjusting the Belville springs and resetting the torque switch; E11-F020B which was repaired by replacing the stem, resetting the torque switch, and lapping the seats; E21-F001A which was repaired by machining the disc and lapping the seat; E41-F021, E41-F049 which were repaired by lubricating the packing; E51-F001, E51-F040 which were repaired by lapping the seats and lubricating the valve stem; G31-F001, G31-F004 which were repaired by flushing the seats of the valve, lapping the seats, repacking the valve and retorquing the bonnet bolts; G31-F042 which was repaired by replacing the valve; RXS-PV1222B, PV1222C which were repaired by replacing the internals on both valves; and TD-V22, TD-V1 which were repaired by replacing all gaskets.

Note 5: During the 1986 Unit 2 ILRT, the total leakage savings due to performing Type B and C tests prior to the Type A test indicated that the acceptance criteria would have been exceeded due to two penetrations that could not be pressurized. The two penetrations which were unable to be pressurized were Penetration 13B (i.e., valves E11-F015B and E11-F017B) and Penetration 77C (i.e., valve RXS-SV-1222C). Both penetrations were repaired and retested with an As-Left leakage rate of 0 scfh.

Note 6: During the Unit 2 1990 ILRT, the total leakage savings due to performing Type B and C tests prior to the Type A test indicated that a leakage savings of 0.153 wt.%/day would have exceeded the acceptance criteria of La.

Note 7: The BSEP Unit 2 1991 As-Found Leakage rate exceeded its limit of 0.75 La (i.e.,

0.375 wt.%/day) with a leakage rate 0.4956 wt.%/day. This was primarily due to excessive leakage on Penetration X220, Torus Purge to Standby Gas and Penetration X8, Main Steam Line Drain. Penetration X220 was repaired by repairing valves CAC-V7 and CAC-V8. Penetration X8 was repaired by rebuilding valve B21-F016 to restore the low spots found on the inboard disc seat and by lapping the seats and rebuilding valve B21-F019.

Note 8: The BSEP Unit 2 1992 As-Found Leakage rate exceeded its limit of 0.75 La (i.e.,

0.375 wt.%/day) with a leakage rate 0.442 wt.%/day. This was primarily due to excessive leakage on Penetration X14, Reactor Water Clean Up Suction and Penetration X12, RHR Cooling Suction. Penetration X14 was repaired by rebuilding Valve G31-F001 to close the sealing gap and repair casting flaws found in the upper and lower wedges. Penetration X12 was repaired by rebuilding valve E11-F009 to restore low spots on the in-body seats.

As demonstrated in the Tables, BSEP Units 1 and 2 were required to accelerate the testing frequency of the ILRTs due to the As-Found failures which exceeded the 0.75 La leakage limit.

The primary reason for the As-Found was the leakage savings additions from Type B and C testing of valves and penetrations, where leakage rates of repaired or replaced components from Type B and C testing are added into the ILRT results.

At the time of the As-Found ILRT failures, plant TS required ILRTs to be performed at each plant shutdown for refueling or every 18 months, whichever occurred first, until two consecutive ILRTs meet the specified leakage limit if two consecutive ILRTs failed to meet the 0.75 La leakage limit. On October 19, 1993, BSEP filed for an amendment to the TS to allow a one-time

RA-18-0149 Enclosure Page 24 of 90 exemption from the accelerated testing requirement to return the units to a normal ILRT frequency (i.e., Reference 26). On January 11, 1994, the NRC approved the one-time exemption from the accelerated containment ILRT requirements to return the containment ILRT frequency for both units to a normal test interval (i.e., Reference 27). The basis for the approval was the adequate assurance that there would not be any significant degradation in the primary containment leakage during the next Type A test interval since the primary contributors to the excessive leakage would be measured during the required LLRT Type B and Type C tests.

Performance Leakage Rate Determination NEI 94-01 defines the performance leakage rate, or performance criteria, for the Type A ILRT as allowable leakage less than 1.0 La. Extensions of the Type A ILRT are allowed based upon two consecutive, periodic Type A ILRTs where the performance leakage rate is less than 1.0 La.

The past two ILRTs for BSEP Unit 1 (i.e., 2004 and 2010) and Unit 2 (i.e., 2005 and 2015) had measured performance leakage rates less than 1.0 La (i.e., 0.5 wt.%/day). Since all tests were satisfactory, the BSEP ILRTs remained on an extended frequency. The current ILRT frequency for BSEP is 10 years. Tables 3.4.4-3 and 3.4.4-4 provide a breakdown of the calculation of the performance leakage rate for the past two ILRTs at BSEP Units 1 and 2.

RA-18-0149 Enclosure Page 25 of 90 Table 3.4.4 Verification of Current Extended ILRT Interval for BSEP Unit 1 Test Date Measured Leakage Rate at 95%

UCL

(%wt./day)

Water Level Corrections

(%wt./day)

Corrections for valves not in Accident Positions during Test

(%wt./day)

Components Isolated During ILRT Due to Excessive Leakage

(%wt./day)

Performance Leakage Rate

(%wt./day)

(Acceptance Criteria 0.5 wt.%/day Test Method 3/25/2004 0.1265 0.0306 0.1031 0

0.2602 Total Time 4/11/2010 0.1775

-0.0862 0.0474 0

0.1387 Total Time Table 3.4.4 Verification of Current Extended ILRT Interval for BSEP Unit 2 Test Date Measured Leakage Rate at 95%

UCL

(%wt./day)

Water Level Corrections

(%wt./day)

Corrections for valves not in Accident Positions during Test

(%wt./day)

Components Isolated During ILRT Due to Excessive Leakage

(%wt./day)

Performance Leakage Rate

(%wt./day)

(Acceptance Criteria 0.5 wt.%/day Test Method 3/30/2005 0.1265 0.0306 0.1031 0

0.2602 Total Time 4/1/2015 0.2799

-0.0798 0.0989 0

0.299 Mass Point

RA-18-0149 Enclosure Page 26 of 90 3.5 Plant Specific Confirmatory Analysis 3.5.1 Methodology A plant specific confirmatory analysis was performed to provide a risk assessment of extending the currently allowed containment Type A ILRT to a permanent interval of fifteen years. The risk assessment follows the guidelines from:

1. NEI 94-01, Revision 3-A (i.e., Reference 2), the methodology used in EPRI TR-104285 (i.e., Reference 11).

2. The NEI document Interim Guidance for Performing Risk Impact Assessments in Support of One-Time Extensions for Containment Integrated Leakage Rate Test Surveillance Intervals (i.e., Reference 28).

3. The NRC regulatory guidance on the use of Probabilistic Risk Assessment (PRA) as stated in RG 1.200 (i.e., Reference 29) as applied to ILRT interval extensions.

4. Risk insights in support of a request for a change of the plants licensing basis as outlined in RG 1.174 (i.e., Reference 7)

5. The methodology used for Calvert Cliffs to estimate the likelihood and risk implications of corrosion-induced leakage of steel liners going undetected during extended test interval (i.e., Reference 30).

6. The methodology used in EPRI 1009325, Revision 2-A (i.e., Reference 8).

Revisions to 10 CFR 50, Appendix J, Option B allow individual plants to extend the ILRT Type A surveillance testing frequency requirement from three in ten years to at least once in ten years.

The revised Type A frequency is based on an acceptable performance history defined as two consecutive periodic Type A tests at least 24 months apart in which the calculated performance leakage rate was less than the limiting containment leakage rate of 1.0 La.

The basis for the current 10-year test interval is provided in Section 11.0 of NEI 94-01, Revision 0, and was established in 1995 during development of the performance-based Option B to Appendix J. Section 11.0 of NEI 94-01 (i.e., Reference 5) states that NUREG-1493, "Performance-Based Containment Leak Test Program," dated January 1995 (i.e., Reference 10), provides the technical basis to support rulemaking to revise leakage rate testing requirements contained in Option B to Appendix J. The basis consisted of qualitative and quantitative assessments of the risk impact, in terms of increased public dose, associated with a range of extended leakage rate test intervals. To supplement the NRCs rulemaking basis, NEI undertook a similar study. The results of that study are documented in Electric Power Research Institute (EPRI) Research Project Report TR-104285, "Risk Impact Assessment of Revised Containment Leak Rate Testing Intervals."

The NRC report on performance-based leak testing, NUREG-1493, analyzed the effects of containment leakage on the health and safety of the public and the benefits realized from the containment leak rate testing. In that analysis, it was determined for a representative BWR plant (i.e., Peach Bottom), that increasing the containment leak rate from a nominal 0.5% per day to 5% per day leads to a barely perceptible increase in total population exposure and increasing the leak rate to 50% per day increases the total population exposure by less than 1%. Because ILRTs represent substantial resource expenditures, it is desirable to show that

RA-18-0149 Enclosure Page 27 of 90 extending the ILRT interval will not lead to a substantial increase in risk from containment isolation failures to support a reduction in the test frequency for BSEP.

NEI 94-01, Revision 3-A (i.e., Reference 2) supports using EPRI Report No. 1009325, Revision 2-A, "Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals" (i.e., Reference 8) for performing risk impact assessments in support of ILRT extensions. The Guidance provided in Appendix H of EPRI Report No. 1009325, Revision 2-A builds on the EPRI Risk Assessment methodology, EPRI TR-104285. This methodology is followed to determine the appropriate risk information for use in evaluating the impact of the proposed ILRT changes.

It should be noted that containment leak-tight integrity is also verified through the periodic in-service inspections conducted in accordance with the requirements of the ASME B&PV Code Section XI. More specifically, Subsection IWE provides the rules and requirements for inservice inspection of Class MC pressure-retaining components and their integral attachments, and of metallic shell and penetration liners of Class CC pressure-retaining components and their integral attachments in light-water cooled plants. Furthermore, NRC regulations 10 CFR 50.55a(b)(2)(ix)(E) require licensees to conduct visual inspections of the accessible areas of the interior of the containment. The associated change to NEI 94-01 will require that visual examinations be conducted during at least three other refueling outages, and in the outage during which the ILRT is being conducted. These requirements will not be changed as a result of the extended ILRT interval. In addition, Appendix J, Type B local leak tests performed to verify the leak-tight integrity of containment penetration bellows, airlocks, seals and gaskets are also not affected by the change to the Type A test frequency.

In the SER issued by the NRC letter dated June 25, 2008 (i.e., Reference 12), the NRC concluded that the methodology in EPRI TR-1009325, Revision 2, was acceptable for referencing by licensees proposing to amend their TS to extend the ILRT surveillance interval to 15 years, subject to the limitations and conditions noted in Section 4.0 of the Safety Evaluation (SE). Table 3.5.1-1 addresses each of the four limitations and conditions for the use of EPRI 1009325, Revision 2.

Table 3.5.1-1, EPRI Report No. 1009325 Revision 2 Limitations and Conditions Limitation/Condition (From Section 4.2 of SE)

BSEP Response

1.

The licensee submits documentation indicating that the technical adequacy of their PRA is consistent with the requirements of RG 1.200 relevant to the ILRT extension.

BSEP PRA technical adequacy is addressed in Section 3.5.2 of this LAR and, "Brunswick Nuclear Plant:

Evaluation of Risk Significance of Permanent ILRT Extension," Appendix A, PRA Model Technical Adequacy.

RA-18-0149 Enclosure Page 28 of 90 Table 3.5.1-1, EPRI Report No. 1009325 Revision 2 Limitations and Conditions Limitation/Condition (From Section 4.2 of SE)

BSEP Response 2.a The licensee submits documentation indicating that the estimated risk increase associated with permanently extending the ILRT surveillance interval to 15 years is small, and consistent with the clarification provided in Section 3.2.4.5 of this SE.

RG 1.174 provides guidance for determining the risk impact of plant-specific changes to the licensing basis. RG 1.174 defines very small changes in risk as resulting in increases of CDF less than 1.0E-6/year. Since BSEP relies on containment accident pressure for ECCS NPSH during certain design basis accidents, extending the ILRT interval may impact CDF. The BSEP PRA model was used to estimate the potential change in CDF if containment accident pressure was unavailable due to a pre-existing containment leak. The containment accident pressure analysis performed in Section 5.2.7 of of this submittal estimates the potential increase in the overall CDF to be 1.61E-08 for Unit 1 and 1.54E-08 for Unit 2, which are "very small" using the acceptance guidelines of RG 1.174. (i.e., Reference )

2.b Specifically, a small increase in population dose should be defined as an increase in population dose of less than or equal to either 1.0 person-rem per year or 1% of the total population dose, whichever is less restrictive.

The effect resulting from changing the Type A test frequency to 1-per-15 years, measured as an increase to the total integrated plant risk for those accident sequences influenced by Type A testing, is 4.98E-03 person-rem/year for Unit 1 and 4.67E-03 person-rem/year for Unit 2. NEI 94-01 states that a small population dose is defined as an increase of 1.0 person-rem/year, or 1% of the total population dose, whichever is less restrictive for the risk impact assessment of the extended ILRT intervals. The results of this calculation meet these criteria.

Moreover, the risk impact for the ILRT extension when compared to other severe accident risks is negligible.

RA-18-0149 Enclosure Page 29 of 90 Table 3.5.1-1, EPRI Report No. 1009325 Revision 2 Limitations and Conditions Limitation/Condition (From Section 4.2 of SE)

BSEP Response 2.c In addition, a small increase in CCFP should be defined as a value marginally greater than that accepted in a previous one-time 15-year ILRT extension requests. This would require that the increase in CCFP be less than or equal to 1.5 percentage point.

The increase in the conditional containment failure probability from a 3-in-10 years interval to a 1 in 15 years interval is 1.20% for Unit 1 and 1.213% for Unit 2. NEI 94-01 states that increases in Conditional Containment Failure Probability (CCFP) of 1.5 is small.

Therefore, this increase is judged to be small.

3.

The methodology in EPRI Report No.

1009325, Revision 2, is acceptable except for the calculation of the increase in expected population dose (per year of reactor operation). In order to make the methodology acceptable, the average leak rate accident case (accident case 3b) used by the licensees shall be 100 La instead of 35 La.

The representative containment leakage for Class 3b sequences is 100 La based on the guidance provided in EPRI Report No.

1009325, Revision 2. It should be noted that this is more conservative than the earlier previous industry Type A test interval extension requests, which utilized 35 La for the Class 3B sequences.

4.

A license amendment request (LAR) is required in instances where containment over-pressure is relied upon for ECCS performance.

Section 3.3 of this enclosure summarizes the current licensing basis for application of CAP at BSEP.

3.5.2 PRA Acceptability 3.5.2.1 Internal Events PRA Quality Statement for Permanent 15-Year ILRT Extension The BSEP internal events PRA model (i.e., MOR16) is used to calculate CDF and large early release frequency (LERF) for the permanent 15-year ILRT extension. Any elements of the supporting requirements detailed in ASME/ANS RA-Sa-2009 (i.e., Reference 31) that could be significantly affected by the application are required to meet Capability Category (CC) II requirements.

The BSEP Units 1 and 2 Internal Events and Internal Flooding PRA Peer Review was performed in April 2010 using the NEI 05-04 process (i.e., Reference 32), the ASME PRA Standard (i.e., Reference 31) and RG 1.200, Revision 2 (i.e., Reference 29). The purpose of this review was to establish the acceptability of the PRA for the spectrum of potential risk-informed plant licensing applications for which the PRA may be used. The 2010 BSEP PRA Peer Review was a full-scope review of the Technical Elements of the Internal Events and Internal Flooding, at-power PRA. A focused scope peer review of the Internal Flood model was conducted in December 2016, which covered 28 SRs.

RA-18-0149 Enclosure Page 30 of 90 The ASME PRA Standard has 325 individual Supporting Requirements (SRs); 322 SR are applicable to the BSEP PRA. Three of the ASME/ANS PRA Standard Supporting Requirements are not applicable to BSEP (e.g., PWR-related, linked event tree methodology-related). Of the 322 ASME/ANS PRA Standard Supporting Requirements applicable to BSEP, approximately 88% are supportive of Capability Category II or greater. Of the 79 unique Facts and Observations (F&Os) generated by the Peer Review Team, 44 were considered peer review Findings and 35 were Suggestions.

An F&O closure technical review was conducted in August 2017 and most, but not all, open F&Os were reviewed for closure. Following the F&O closure, 15 Internal Event and Internal Flooding F&Os remain open; these F&Os are dispositioned in Section A.1.1 of Attachment 6 of this submittal for their impact on the ILRT extension. All of the Finding Level F&Os have been determined to not significantly affect the ILRT extension analysis.

3.5.2.2 Fire PRA Quality Statement for Permanent 15-Year ILRT Extension The BSEP Fire Probabilistic Risk Assessment (FPRA) Peer Review was performed December 2011 using the NEI 07-12 process (i.e., Reference 33), the ASME PRA Standard (i.e., Reference 31), and RG 1.200, Revision 2 (i.e., Reference 29). The purpose of this review was to establish the acceptability of the FPRA for the spectrum of potential risk-informed plant licensing applications for which the FPRA may be used. The 2011 BSEP FPRA Peer Review was a full-scope review of all of the technical elements of the BSEP at-power 2011 MOR Fire PRA against all technical elements in Section 4 of the ASME/ANS Combined PRA Standard, including the referenced internal events SRs in Section 2 of the ASME/ANS Combined PRA Standard (i.e., Reference 31).

The Peer Review team consisted of six team members, with extensive qualifications in all areas of FPRA as required by NEI 07-12 (i.e., Reference 33). The team members experience averaged over 20 years in PRA or Fire Protection, with extensive experience in FPRA, the FPRA Section of the Standard, and NUREG/CR-6850.

The Fire PRA Section of the ASME PRA Standard has 182 individual SRs, and references 237 individual SRs in the internal events PRA section of the Standard; the BSEP Peer Review included all of the SRs and all applicable reference SRs (i.e., see Table A.2-1 of Attachment 6 of this submittal). For the assessment of the reviewed ASME PRA Standard SRs, 105 unique F&Os were generated by the Peer Review team, 53 were peer review Findings, 50 were Suggestions, and one was an "Unreviewed Analytical Method."

An F&O Finding closure technical review was conducted in July 2017 to review all open Fire PRA F&Os. Following the F&O closure, six F&Os remain open; these F&Os are dispositioned in Section A.2.1of Attachment 6 of this submittal for their impact on the ILRT extension. All the Finding Level F&Os have been determined to not significantly affect the ILRT extension analysis.

3.5.2.3 High Winds PRA Quality Statement for Permanent 15-Year ILRT Extension The BSEP Units 1 and 2 High Winds PRA Peer Review was performed January 2012 using the ASME PRA Standard (i.e., Reference 31) and RG 1.200, Rev. 2 (i.e., Reference 29). The purpose of this review was to establish the acceptability of the High Winds PRA for the spectrum of potential risk-informed plant licensing applications for which the High Winds PRA may be used. The 2012 BSEP High Winds PRA Peer Review was a full-scope review of all of

RA-18-0149 Enclosure Page 31 of 90 the technical elements of the BSEP at-power 2011 MOR High Winds PRA against all technical elements of the PRA (i.e., Reference 34).

The ASME PRA Standard has 29 individual SRs pertaining to High Winds; the BSEP Peer Review included all of the SRs.

An F&O Finding closure technical review of the High Winds PRA and a focused-scope closure review of the High Winds HRA were conducted in July 2017, with the documentation finalized in August 2017, to review all open High Winds PRA F&Os. Following the F&O closure all High Winds PRA F&Os are closed.

3.5.3 Summary of Plant-Specific Risk Assessment Results Based on the results from Section 5.2 and the sensitivity calculations in Section 5.3 of of this submittal, the following conclusions regarding the assessment of the plant risk are associated with extending the Type A ILRT test frequency to fifteen years:

RG 1.174 (i.e., Reference 7) provides guidance for determining the risk impact of plant-specific changes to the licensing basis. RG 1.174 defines very small changes in risk as resulting in increases of CDF less than 1.0E-06/year. Since BSEP relies on containment accident pressure for ECCS NPSH during certain design basis accidents, extending the ILRT interval may impact CDF. The BSEP PRA model was used to estimate the potential change in CDF if containment accident pressure was unavailable due to a pre-existing containment leak. The containment accident pressure analysis performed in Section 5.2.7 of estimates the potential increase in the overall CDF to be 1.61E-08 for Unit 1 and 1.54E-08 for Unit 2, which are "very small" using the acceptance guidelines of RG 1.174.

When external event risk is included, the increase in CDF resulting from a change in the Type A ILRT test interval from 3 in 10 years to 1 in 15 years is estimated as 1.10E-07/year for Units 1 and 2 using the EPRI guidance. As such, the estimated change in CDF is determined to be "very small" using the acceptance guidelines of RG 1.174 (i.e.,

Reference 7). The risk change resulting from a change in the Type A ILRT test interval from 3-in-10 years to 1-in-15 years bounds the 1 in 10 years to 1 in 15 years risk change.

RG 1.174 (i.e., Reference 7) provides guidance for determining the risk impact of plant-specific changes to the licensing basis. RG 1.174 defines very small changes in risk as resulting increases in LERF less than 1.0E-07/year. The increase in LERF resulting from a change in the Type A ILRT test interval from 3-in-10 years to 1-in-15 years is estimated as 6.03E-08/year for Unit 1 and 5.67E-08/year for Unit 2 using the EPRI guidance; this value increases negligibly if the risk impact of corrosion-induced leakage of the steel liners occurring and going undetected during the extended test interval is included. As such, the estimated change in LERF is determined to be "very small" using the acceptance guidelines of RG 1.174.

When external event risk is included, the increase in LERF resulting from a change in the Type A ILRT test interval from 3-in-10 years to 1-in-15 years is estimated as 4.05E-07/year for Unit 1 and 4.33E-07/year for Unit 2 using the EPRI guidance, and total LERF is 5.55E-06/year for Unit 1 and 5.53E-06/year for Unit 2. As such, the estimated change in LERF is determined to be "small" using the acceptance guidelines of RG 1.174 (i.e., Reference 7).

RA-18-0149 Enclosure Page 32 of 90 The risk change resulting from a change in the Type A ILRT test interval from 3-in-10 years to 1-in-15 years bounds the 1-in-10 years to 1-in-15 years risk change.

The effect resulting from changing the Type A test frequency to 1-in-15 years, measured as an increase to the total integrated plant risk for those accident sequences influenced by Type A testing, is 4.98E-03 person-rem/year for Unit 1 and 4.67E-03 person-rem/year for Unit 2. NEI 94-01 (i.e., Reference 2) states that a small population dose is defined as an increase of 1.0 person-rem per year, or 1% of the total population dose, whichever is less restrictive for the risk impact assessment of the extended ILRT intervals. The results of this calculation meet these criteria. Moreover, the risk impact for the ILRT extension when compared to other severe accident risks is negligible.

The increase in the conditional containment failure probability from the 3-in-10 years interval to 1-in-15 years interval is 1.206% for Unit 1 and 1.213% for Unit 2. NEI 94-01 (i.e.,

Reference 2) states that increases in CCFP of 1.5% is small. Therefore, this increase is judged to be small.

Therefore, increasing the ILRT interval to 15 years is considered to be small since it represents a small change to the BSEP risk profile.

Previous Assessments In NUREG-1493 (Reference 10), the NRC has previously concluded that:

Reducing the frequency of Type A tests from 3-in-10 years to 1-in-20 years was found to lead to an imperceptible increase in risk. The estimated increase in risk is very small because ILRTs identify only a few potential containment leakage paths that cannot be identified by Type B or Type C testing, and the leaks that have been found by Type A tests have been only marginally above existing requirements.

Given the insensitivity of risk to containment leakage rate and the small fraction of leakage paths detected solely by Type A testing, increasing the interval between integrated leakage-rate tests is possible with minimal impact on public risk. The impact of relaxing the ILRT frequency beyond 1-in-20 years has not been evaluated. Beyond testing the performance of containment penetrations, ILRTs also test integrity of the containment structure.

The findings for BSEP confirm these general findings on a plant-specific basis considering the severe accidents evaluated for BSEP, the BSEP containment failure modes, and the local population surrounding BSEP.

3.5.4 RG 1.174 Revision 3 Defense in Depth Evaluation RG 1.174, Revision 3 (i.e., Reference 35) describes an approach that is acceptable for developing risk-informed applications for a licensing basis change that considers engineering and applies risk insights. One of the considerations included in RG 1.174 is Defense in Depth.

Defense in Depth is a safety philosophy that employs successive compensatory measures to provide accidents or mitigate damage if a malfunction, accident, or naturally caused event occurs at a nuclear facility. The following seven considerations as presented in RG 1.174 Revision 3, Section 2.1.1.2 will serve to evaluate the proposed licensing basis change for overall impact on Defense in Depth.

RA-18-0149 Enclosure Page 33 of 90

1. Preserve a reasonable balance among the layers of defense.

A reasonable balance of the layers of defense (i.e., minimizing challenges to the plant, preventing any events from progressing to core damage, containing the radioactive source term, and emergency preparedness) helps to ensure an apportionment of the plants capabilities between limiting disturbances to the plant and mitigating their consequences. The term "reasonable balance" is not meant to imply an equal apportionment of capabilities. The NRC recognizes that aspects of a plants design or operation might cause one or more of the layers of defense to be adversely affected. For these situations, the balance between the other layers of defense becomes especially important when evaluating the impact of the proposed licensing basis change and its effect on defense in depth.

Response

Several layers of defense are in place to ensure the BSEP containment structure(s);

penetrations, isolation valves and mechanical seal systems; continue(s) to perform their intended safety function. The purpose of the proposed change is to extend the testing frequencies of the Type A ILRT from 10 years to 15 years and Type C LLRTs for selected components from 60 months to 75 months.

As shown in NUREG-1493, Performance-Based Containment Leak-Test Program (i.e.,

Reference 10), increasing the test frequency of ILRTs up to a 20-year test interval was found to lead to an imperceptible increase in risk. The estimated increase in risk is very small because ILRTs identify only a few potential containment leakage paths that cannot be identified by Type B or Type C testing. The study also concluded that extending the frequency of Type B tests is possible with no adverse impact on risk as identified leakage through Type B mechanical penetrations are both infrequent and small. Finally, the study concluded that Type B and C tests could identify the vast majority (i.e., greater than 95 percent) of all potential leakage paths.

Several programmatic factors can also be cited as layers of defense ensuring the continued safety function of the BSEP containment pressure boundary. NEI 94-01 Revisions 2-A and 3-A require sites adopting the 15-year extended ILRT interval perform visual examinations of the accessible interior and exterior surfaces of the containment structure for structural degradation that may affect the containment leak-tight integrity at the frequency prescribed by the guidance or, if approved through a TS amendment, at the frequencies prescribed by ASME Section XI.

Additionally, several measures are put in place to ensure integrity of the Type B and C tested components. NEI 94-01 limits large containment penetrations such as airlocks, purge and vent valves, BWR main steam and feedwater isolation valves, to a maximum 30-month testing interval. For those valves that meet the performance standards defined in NEI 94-01 Revision 3-A and are selected for test intervals greater than 60 months, a leakage understatement "penalty" is added to the minimum pathway leakage rate (MNPLR) prior to the frequency being extended beyond 60-months. Finally, identification of adverse trends in the overall Type B and C leakage rate summations and available margin between the Type B and Type C leakage rate summation and its regulatory limit are required by NEI 94-01 Revision 3-A to be shown in the BSEP post-outage report(s). Therefore, the proposed change does not challenge or limit the layers of defense available to assess the ability of the BSEP containment structure to perform its safety function.

RA-18-0149 Enclosure Page 34 of 90 PRA Response:

The usage of the risk metrics of LERF, population dose, and CCFP collectively ensures the balance between prevention of core damage, prevention of containment failure, and consequence mitigation is preserved. The change in LERF is "small" per RG 1.174, and the change in population dose and CCFP are "small" as defined in this analysis and consistent with the NRC SER on NEI 94-01 Revision 2-A.

2. Preserve adequate capability of design features without an overreliance on programmatic activities as compensatory measures.

Nuclear power plant licensees implement a number of programmatic activities, including programs for quality assurance, testing and inspection, maintenance, control of transient combustible material, foreign material exclusion, containment cleanliness, and training. In some cases, activities that are part of these programs are used as compensatory measures; that is, they are measures taken to compensate for some reduced functionality, availability, reliability, redundancy, or other feature of the plants design to ensure safety functions (e.g., reactor vessel inspections that provide assurance that reactor vessel failure is unlikely). NUREG-2122, "Glossary of Risk-Related Terms in Support of Risk-Informed Decision making," defines "safety function" as those functions needed to shut down the reactor, remove the residual heat, and contain any radioactive material release.

A proposed licensing basis change might involve or require compensatory measures.

Examples include hardware (e.g., skid-mounted temporary power supplies); human actions (e.g., manual system actuation); or some combination of these measures. Such compensatory measures are often associated with temporary plant configurations. The preferred approach for accomplishing safety functions is through engineered systems. Therefore, when the proposed licensing basis change necessitates reliance on programmatic activities as compensatory measures, the licensee should justify that this reliance is not excessive (i.e., not overly reliant).

The intent of this consideration is not to preclude the use of such programs as compensatory measures but to ensure that the use of such measures does not significantly reduce the capability of the design features (e.g., hardware).

Response

The purpose of the proposed change is to extend the testing frequencies of the Type A ILRT from 10 years to 15 years and select Type C LLRTs from 60-months to 75-months. Several programmatic factors were defined in the response to Question 1 above, which are required when adopting NEI 94-01, Revisions 2-A and 3-A. These factors are conservative in nature and are designed to generate corrective actions if the required testing or inspections are deemed unsatisfactory well in advance to ensure the continued safety function of the containment is maintained. The programmatic factors are designed to provide differing ways to test and/or examine the containment pressure boundary in a manner that verifies the BSEP containment pressure boundary will perform its intended safety function. Since the proposed change does not alter the configuration of the BSEP containment pressure boundary, continued performance of the tests and inspections associated with NEI 94-01 will only serve to ensure the continued safety function of the containment without affecting any margin of safety.

RA-18-0149 Enclosure Page 35 of 90 PRA Response:

The adequacy of the design feature (i.e., the containment boundary subject to Type A testing) is preserved as evidenced by the overall "small" change in risk associated with the Type A test frequency change.

3. Preserve system redundancy, independence, and diversity commensurate with the expected frequency and consequences of challenges to the system, including consideration of uncertainty.

As stated in Section C.2.1.1.1 above, the defense-in-depth philosophy has traditionally been applied in plant design and operation to provide multiple means to accomplish safety functions.

System redundancy, independence, and diversity result in high availability and reliability of the function and also help ensure that system functions are not reliant on any single feature of the design. Redundancy provides for duplicate equipment that enables the failure or unavailability of at least one set of equipment to be tolerated without loss of function. Independence of equipment implies that the redundant equipment is separate such that it does not rely on the same supports to function. This independence can sometimes be achieved by the use of physical separation or physical protection. Diversity is accomplished by having equipment that performs the same function rely on different attributes such as different principles of operation, different physical variables, different conditions of operation, or production by different manufacturers which helps reduce common-cause failure (CCF). A proposed change might reduce the redundancy, independence, or diversity of systems. The intent of this consideration is to ensure that the ability to provide the system function is commensurate with the risk of scenarios that could be mitigated by that function. The consideration of uncertainty, including the uncertainty inherent in the PRA, implies that the use of redundancy, independence, or diversity provides high reliability and availability and also results in the ability to tolerate failures or unanticipated events.

Response

The proposed change to extend the testing frequencies of the Type A ILRT from 10 years to 15 years and select Type C LLRTs from 60-months to 75-months does not reduce the redundancy, independence or diversity of systems. As shown in NUREG-1493, increasing the test frequency of ILRTs up to a 20-year test interval was found to lead to an imperceptible increase in risk. The estimated increase in risk is very small because ILRTs identify only a few potential containment leakage paths that cannot be identified by Type B or Type C testing. The study also concluded that extending the frequency of Type B tests is possible with no adverse impact on risk as identified leakage through Type B mechanical penetrations are both infrequent and small. Additionally, the study concluded that Type B and C tests could identify the vast majority (i.e., greater than 95 percent) of all potential leakage paths.

Despite the change in test interval, containment isolation diversity remains unaffected and will continue to provide the inherent isolation, as designed. In addition, NEI 94-01 Revisions 2-A and 3-A, Section 11.3.2 requires a schedule of tests be developed, for components on a test interval greater than 60 months, such that unanticipated random failures and unexpected common-mode failures are avoided. This is typically accomplished by implementing test intervals at approximately evenly distributed intervals. Therefore, the proposed change preserves system redundancy, independence, and diversity and ensures a high reliability and

RA-18-0149 Enclosure Page 36 of 90 availability of the containment structure to perform its safety function in the event of unanticipated events.

PRA Response:

The redundancy, independence, and diversity of the containment subject to the Type A test is preserved, commensurate with the expected frequency and consequences of challenges to the system, as evidenced by the overall "small" change in risk associated with the Type A test frequency change.

4. Preserve adequate defense against potential common-cause failures (CCFs).

An important aspect of ensuring defense in depth is to guard against CCF. Multiple components may fail to function because of a single specific cause or event that could simultaneously affect several components important to risk. The cause or event may include an installation or construction deficiency, accidental human action, extreme external environment, or an unintended cascading effect from any other operation or failure within the plant. CCFs can also result from poor design, manufacturing, or maintenance practices. Defenses can prevent the occurrence of failures from the causes and events that could allow simultaneous multiple component failures. Another aspect of guarding against CCF is to ensure that an existing defense put in place to minimize the impact of CCF is not significantly reduced; however, a reduction in one defense can be compensated for by adding another.

Response

As part of the proposed change, BSEP will be required to adopt the performance-based testing standards outlined in NEI 94-01, Revisions 2-A and 3-A along with ANSI/ANS 56.8-2002.

NEI 94-01 Revisions 2-A and 3-A, Section 11.3.2 requires a schedule of tests be developed, for components on test intervals greater than 60 months, such that unanticipated random failures and unexpected common-mode failures are avoided. This is typically accomplished by implementing test intervals at approximately evenly distributed intervals. In addition, components considered to be risk-significant from a PRA standpoint are required to be limited to a testing interval less than the maximum allowable limit of 75-months. For those components that have demonstrated satisfactory performance and have had their testing limits extended, administrative testing limits are assigned on a component-by-component basis and are used to identify potential valve or penetration degradation. Administrative limits are established at a value low enough to identify and should allow early correction in advance of total valve failure.

Should a component exceed its administrative limit during testing, NEI 94-01 Revisions 2-A and 3-A state cause determinations should be performed designed to reinforce achieving acceptable performance. The cause determination is designed to identify and address common-mode failure mechanisms through appropriate corrective actions. The proposed change also imposes a requirement to address margin management i.e. margin between the current containment leakage rate and its pre-established limit. As a result, adoption of the performance-based testing standards proposed by this change ensures adequate barriers exist to preclude failure of the containment pressure boundary due to common-mode failures and therefore continues to guard against CCF.

PRA Response:

Adequate defense against CCFs is preserved. The Type A test detects problems in the containment, which may or may not be the result of a CCF; such a CCF may affect failure of

RA-18-0149 Enclosure Page 37 of 90 another portion of containment (i.e., local penetrations) due to the same phenomena. Adequate defense against CCFs is preserved via the continued performance of the Type B and C tests and the performance of inspections. The change to the Type A test, which bounds the risk associated with containment failure modes including those involving CCFs, does not degrade adequate defense as evidenced by the overall "small" change in risk associated with the Type A test frequency change.

5. Maintain multiple fission product barriers.

Fission product barriers include the physical barriers themselves (e.g., the fuel cladding, reactor coolant system pressure boundary, and containment) and any equipment relied on to protect the barriers (e.g., containment spray). In general, these barriers are designed to perform independently so that a complete failure of one barrier does not disable the next subsequent barrier. For example, one barrier, the containment, is designed to withstand a double-ended guillotine break of the largest pipe in the reactor coolant system, another barrier.

A plants licensing basis might contain events that, by their very nature, challenge multiple barriers simultaneously. Examples include interfacing-system loss-of-coolant accidents, steam generator tube rupture, or crediting containment accident pressure. Therefore, complete independence of barriers, while a goal, might not be achievable for all possible scenarios.

Response

The purpose of the proposed change is to extend the testing frequencies of the Type A ILRT from 10 years to 15 years and select Type C LLRTs from 60-months to 75-months. As part of the proposed change, BSEP will be required to adopt the performance-based testing standards outlined in NEI 94-01, Revisions 2-A and 3-A along with ANSI/ANS 56.8-2002. The overall containment leakage rate calculations associated with the testing standards contain inherent conservatisms through the use of margin. Plant TS require the overall primary containment leakage rate to be less than or equal to 1.0 La. NEI 94-01 requires the as-found Type A test leakage rate must be less than the acceptance criterion of 1.0 La given in the plant TS. Prior to entering a mode where containment integrity is required, the as-left Type A leakage rate shall not exceed 0.75 La. The as-found and as-left values are as determined by the appropriate testing methodology specifically described in ANSI/ANS-56.8-2002. Additionally, the combined leakage rate for all Type B and Type C tested penetrations shall be less than or equal to 0.6 La, determined on a maximum pathway basis from the as-left LLRT results prior to entering a mode where containment integrity is required. This regulatory approach results in a 25% and 40%

margin, respectively, to the 1.0 La requirements. For those local leak rate tested components that have demonstrated satisfactory performance and have had their testing limits extended, administrative testing limits are assigned on a component by component basis and are used to identify potential valve or penetration degradation. Administrative limits are established at a value low enough to identify and allow early correction in advance of total valve failure. Should a component exceed its administrative limit during testing, NEI 94-01 Revisions 2-A and 3-A state cause determinations should be performed designed to reinforce achieving acceptable performance. The cause determination is designed to identify and address common-mode failure mechanisms through appropriate corrective actions. Therefore, the proposed change adopts requirements with inherent conservatisms to ensure the margin to safety limit is maintained, thereby, preserving the containment fission product barrier.

RA-18-0149 Enclosure Page 38 of 90 PRA Response:

Multiple Fission Product barriers are maintained. The portion of the containment affected by the Type A test extension is still maintained as an independent fission product barrier, albeit with a "small" change in the reliability of the barrier.

6. Preserve sufficient defense against human errors.

Human errors include the failure of operators to correctly and promptly perform the actions necessary to operate the plant or respond to off-normal conditions and accidents, errors committed during test and maintenance, and incorrect actions by other plant staff. Human errors can result in the degradation or failure of a system to perform its function, thereby significantly reducing the effectiveness of one of the layers of defense or one of the fission product barriers. The plant design and operation include defenses to prevent the occurrence of such errors and events. These defenses generally involve the use of procedures, training, and human engineering; however, other considerations (e.g., communication protocols) might also be important.

Response

Sufficient defense against human errors is preserved. Errors committed during testing and maintenance may be reduced by the less frequent performance of the Type A, Type B and Type C tests (i.e., less opportunity for errors to occur).

PRA Response:

Sufficient defense against human errors is preserved. The probability of a human error to operate the plant, or to respond to off-normal conditions and accidents is not significantly affected by the change to the Type A testing frequency. Errors committed during testing and maintenance may be reduced by the less frequent performance of the Type A test (i.e., less opportunity for errors to occur).

7. Continue to meet the intent of the plants design criteria.

For plants licensed under 10 CFR Part 50 or 10 CFR Part 52, the plants design criteria are set forth in the current licensing basis of the plant. The plants design criteria define minimum requirements that achieve aspects of the defense-in-depth philosophy; as a consequence, even a compromise of the intent of those design criteria can directly result in a significant reduction in the effectiveness of one or more of the layers of defense. When evaluating the effect of the proposed licensing basis change, the licensee should demonstrate that it continues to meet the intent of the plants design criteria.

Response

The purpose of the proposed change is to extend the testing frequencies of the Type A ILRT from 10 years to 15 years and select Type C LLRTs from 60-months to 75-months. The proposed extensions do not involve either a physical change to the plant or a change in the manner in which the plant is operated or controlled. As part of the proposed change, BSEP will be required to adopt the performance-based testing standards outlined in NEI 94-01, Revisions 2-A and 3-A along with ANSI/ANS 56.8-2002. The leakage limits imposed by plant TS remain unchanged when adopting the performance-based testing standards outlined in NEI 94-01 Revision 3-A and ANSI/ANS 56.8-2002. Plant design limits imposed by the Updated Final

RA-18-0149 Enclosure Page 39 of 90 Safety Analysis Report (UFSAR) also remain unchanged as a result of the proposed change.

Therefore, the proposed change continues to meet the intent of the plants design criteria to ensure the integrity of the BSEP containment pressure boundary.

PRA Response:

The intent of the plants design criteria continues to be met. The extension of the Type A test does not change the configuration of the plant or the way the plant is operated.

==

Conclusion:==

The responses to the seven Defense in Depth questions above conclude that the existing Defense in Depth has not been diminished, rather, in some instances has been increased.

Therefore, the proposed change does not comprise a reduction in safety.

3.6 Non-Risk Based Assessment 3.6.1 Nuclear Coatings Program The Nuclear Coatings Program provides a standardized method of selecting, procuring, applying, maintaining, and periodically assessing coatings so they can be used to minimize the adverse impacts of degraded (i.e., detached) coatings on systems, structures, and components (SSCs), minimize material degradation of SSCs, facilitate decontamination of SSCs, and satisfy licensing and regulatory commitments.

Service Level I coatings are applied to exposed surfaces inside the reactor containment where coating failure (i.e., detachment) could adversely affect the operation of post-accident fluid systems and thereby, impair safe shutdown. Systems which could be impacted by detached coatings include the ECCS and the Containment Spray system. Therefore, coating systems used within the reactor containment are required to be Qualified Coating Systems.

Site Engineering personnel along with site QC staff are responsible for performing coatings assessments and inspections. Service Level I and Service Level III (i.e., Safety-Related) coating work at BSEP is considered to be Special Processes. Special Processes are controlled and accomplished by qualified personnel using qualified procedures in accordance with applicable codes, standards, specifications, criteria and other special requirements. The personnel are qualified in accordance with applicable employee training and qualification systems. The coating surveillance is performed on a 24-month basis. Additionally, coating degradations found during routine maintenance operations are tracked via the Nuclear Coatings Program for timely resolution.

3.6.1.1 Unqualified/Degraded Coatings in Containment Site Engineering is responsible for verifying that the amount of unqualified coatings allowed in the primary containment does not exceed limits defined in calculations and the UFSAR. A calculation is performed on the ECCS to ensure the amount of unqualified coatings in containment does not degrade the ECCS system. Areas where coatings are considered degraded are documented and tracked by a Coatings Exempt Log to ensure that the quality of unqualified coatings in the torus do not exceed analyzed limits.

The total amount of protective coating debris or Unqualified Coatings inside the primary containment is limited to 6,667 cubic feet (ft3) for each unit. The Maintenance Rule (a)(1) limit of

RA-18-0149 Enclosure Page 40 of 90 5.175 ft3 has been set as an alert limit for each unit. This quantity was considered acceptable based on ECCS suction strainer design analysis.

The estimated volumes of Unqualified Coatings inside the Unit 1 and Unit 2 BSEP primary containments are summarized in Tables 3.6.1-1 and 3.6.1-2 below. The total volume for each containment is still well below the design limit and is considered to be a conservative estimate.

Table 3.6.1-1 Unit 1 Primary Containment Unqualified Coatings following B1R22 Refueling Outage, March 2016 Design Limit 6.667 ft3 Maintenance Rule (a)(1) Limit 5.175 ft3 Total Volume following B121R1 3.120 ft3 Percent of Maintenance Rule (a)(1) limit at start up 60.5%

Table 3.6.1-2 Unit 2 Primary Containment Unqualified Coatings following B223R1 Refueling Outage, March 2017 Design Limit 6.667 ft3 Maintenance Rule (a)(1) Limit 5.175 ft3 Total Volume following B121R1 3.647 ft3 Percent of Maintenance Rule (a)(1) limit at start up 70.5%

3.6.2 Maintenance Rule Structural Monitoring Program The Structural Monitoring Program was established to ensure BSEP Maintenance Rule structural components are monitored and evaluated in accordance with the requirements of 10 CFR 50.65 using the guidance of NEI 96-03. The Maintenance Rule requires that licensees monitor the performance or condition of structures, systems, or components, against established criteria. Performance monitoring of structures is impracticable; thus, condition monitoring has been set forth as the method of determining compliance with these established requirements.

Baseline inspections were performed for the structural systems. The findings from these inspections provided input for determining the appropriate inspection frequency based on current condition and safety significance. The inspection frequencies were determined and justification documented in the Maintenance Rule database for an appropriate periodic inspection interval. Preventative Maintenance (PM) routes were created for both accessible and normally inaccessible areas.

RA-18-0149 Enclosure Page 41 of 90 The structural systems inspections will continue to be performed as established. The structural system engineer continues to inspect structures from normally available access locations utilizing lighting and binoculars for areas not readily accessible. The structural system inspection coincides with the non-structural system inspection allowing immediate interaction between the discipline system engineer and the structural system engineer when asked to provide assistance with evaluating structural deficiencies.

Boundaries are established between structural systems and structural components associated with non-structural systems to ensure that inspections are complete and thorough. The structural system engineer is responsible for inspecting structural systems. The discipline system engineer is responsible for inspecting structural components associated with their systems. System boundaries define where the structural system engineer and discipline engineer stop their inspection.

3.6.3 Containment Inservice Inspection Program The BSEP Containment Inspection Program is currently beginning its third inspection interval.

The governing code of record for the second inspection interval was the 2001 Edition with the 2003 Addenda of the ASME Code,Section XI; hereafter referred to as the ASME Code,Section XI. The third inspection interval for BSEP became effective on May 11, 2018 and will end on May 10, 2028, and will use the 2007 Edition with the 2008 Addenda of the ASME Code,Section XI. The Containment plan is being merged into the overall ISI plan which is in its 5th Interval beginning May of 2018 and ending May of 2028. Going forward for consistency, the Containment plan will be referenced as being in the Fifth Inspection interval.

Table 3.6.3-1 BSEP Unit 1 Third Containment MC/CC Inspection Interval4 First Period2,3 Second Period2,3 Third Period2 5/11/2018 -

5/10/2022 5/11/2022 -

5/10/2025 5/11/2025 -

5/10/20281 Outage 1 (B1R23)

Outage 3 (B1R25)

Outage 4 (B1R26)

Outage 2 (B1R24)

Outage 4 (B1R27)

Table 3.6.3-2 BSEP Unit 2 Third Containment MC/CC Inspection Interval4 First Period2,3 Second Period2,3 Third Period2,3 5/11/2018 -

5/10/2021 5/11/2021 -

5/10/2024 5/11/2024 -

5/10/20281 Outage 1 (B2R24)

Outage 3 (B2R26)

Outage 4 (B2R27)

Outage 2 (B2R25)

Outage 4 (B2R28)

RA-18-0149 Enclosure Page 42 of 90 Notes:

1. Unit 1 Fifth Interval end date for Class MC and CC components may be extended to no later than May 10, 2029 and may be reduced to no earlier than May 10, 2027. These provisions do not apply to inspection interval end dates for Class 1, 2, and 3 components.

2. Inspection periods for Subsection IWL (Class CC components) shall comply with the requirements of IWL-2410, based on a rolling 5-year frequency (+/- 1 year) from the completion date of the Structural Integrity Test (SIT). During the 5th Interval, IWL Examinations shall be performed only during the following periods:

a. Unit 1:

IWL Period 1: August 20, 2020 through August 20, 2022 (i.e., includes Refueling Outage B1R24)

IWL Period 2: August 20, 2025 through August 20, 2027 (i.e., includes Refueling Outage B1R26)

b. Unit 2:

IWL Period 1: October 8, 2018 through October 8, 2020 (i.e., includes Refueling Outage B2R24)

IWL Period 2: October 8, 2023 through October 8, 2025 (i.e., includes Refueling Outage B2R27)

3. The duration of the inspection periods has been adjusted, as permitted by IWA-2430(c)(3), to allow for Period 1 to have two (2) refueling outages, Period 2 to have a single (1) refueling outage, and Period 3 to have two (2) refueling outages.

4. The subsequent (i.e., 3rd) BSEP Inservice Inspection Interval Program for Class MC and CC components started on May 11, 2018, along with the start of the 5th Inservice Inspection Interval Program for Class 1, 2 and 3 components. To avoid confusion with regard to which inspection interval is being implemented, BSEP shall hereafter refer to the inspection interval starting on May 11, 2018 as the Fifth Inservice Inspection Interval for Class 1, 2, 3, MC and CC components.

Code of Federal Regulations 10 CFR 50.55a Conditions The following mandatory and optional Code of Federal Regulations Conditions are included in 10 CFR 50.55a (i.e., dated July 17, 2017). These conditions were reviewed for inclusion in the ISI Plan and include only those 10 CFR 50.55a conditions applicable to the Inservice Inspection Plan developed using the 2007 Edition with the 2008 Addenda of Section XI are listed below:

50.55a(b)(2)(vi)Section XI condition: Effective edition and addenda of Subsection IWE and Subsection IWL. Licensees that implemented the expedited examination of containment, in accordance with Subsection IWE and Subsection IWL, during the period from September 9, 1996, to September 9, 2001, may use either the 1992 Edition with the 1992 Addenda or the 1995 Edition with the 1996 Addenda of Subsection IWE and Subsection IWL, as conditioned by the requirements in paragraphs (b)(2)(viii) and (ix) of

RA-18-0149 Enclosure Page 43 of 90 this section, when implementing the initial 120-month inspection interval for the containment inservice inspection requirements of this section. Successive 120-month interval updates must be implemented in accordance with paragraph (g)(4)(ii) of this section.

During the 5th Inservice Inspection Interval, BSEP is updating the applicable Section XI Code of Record in accordance with paragraph (g)(4)(ii).

50.55a(b)(2)(viii)Section XI condition: Concrete containment examinations. Applicants or licensees applying Subsection IWL, 1992 Edition with the 1992 Addenda, must apply paragraphs (b)(2)(viii)(A) through (E) of this section. Applicants or licensees applying Subsection IWL, 1995 Edition with the 1996 Addenda, must apply paragraphs (b)(2)(viii)(A), (b)(2)(viii)(D)(3), and (b)(2)(viii)(E) of this section. Applicants or licensees applying Subsection IWL, 1998 Edition through the 2000 Addenda, must apply paragraphs (b)(2)(viii)(E) and (F) of this section. Applicants or licensees applying Subsection IWL, 2001 Edition through the 2004 Edition, up to and including the 2006 Addenda, must apply paragraphs (b)(2)(viii)(E) through (G) of this section. Applicants or licensees applying Subsection IWL, 2007 Edition up to and including the 2008 Addenda must apply paragraph (b)(2)(viii)(E) of this section. Applicants or licensees applying Subsection IWL, 2007 Edition with the 2009 Addenda through the latest edition and addenda incorporated by reference in paragraph (a)(1)(ii) of this section, must apply paragraphs (b)(2)(viii)(H) and (I) of this section.

During the 5th Inservice Inspection Interval, BSEP shall comply with the condition in§50.55a(b)(2)(viii)(E).

50.55a(b)(2)(viii)(E) Concrete containment examinations: Fifth provision. For Class CC applications, the applicant or licensee must evaluate the acceptability of inaccessible areas when conditions exist in accessible areas that could indicate the presence of or the result in degradation to such inaccessible areas. For each inaccessible area identified, the applicant or licensee must provide the following in the ISI Summary Report required by IWA-6000:

(1) A description of the type and estimated extent of degradation, and the conditions that led to the degradation; (2) An evaluation of each area, and the result of the evaluation; and (3) A description of necessary corrective actions.

50.55a(b)(2)(ix)Section XI condition: Metal containment examinations. Applicants or licensees applying Subsection IWE, 1992 Edition with the 1992 Addenda, or the 1995 Edition with the 1996 Addenda, must satisfy the requirements of paragraphs (b)(2)(ix)(A) through (E) of this section. Applicants or licensees applying Subsection IWE, 1998 Edition through the 2001 Edition with the 2003 Addenda, must satisfy the requirements of paragraphs (b)(2)(ix)(A) and (B) and (F) through (I) of this section. Applicants or licensees applying Subsection IWE, 2004 Edition, up to and including the 2005 Addenda, must satisfy the requirements of paragraphs (b)(2)(ix)(A) and (B) and (F) through (H) of this section. Applicants or licensees applying Subsection IWE, 2004 Edition with the 2006 Addenda, must satisfy the requirements of paragraphs (b)(2)(ix)(A)(2) and (b)(2)(ix)(B) of this section. Applicants or licensees applying

RA-18-0149 Enclosure Page 44 of 90 Subsection IWE, 2007 Edition through the latest edition and addenda incorporated by reference in paragraph (a)(1)(ii) of this section, must satisfy the requirements of paragraphs (b)(2)(ix)(A)(2) and (b)(2)(ix)(B) and (J) of this section.

During the 5th Inservice Inspection Interval, BSEP shall comply with the condition in §50.55a(b)(2)(ix)(A)(2), §50.55a(b)(2)(ix)(B), and §50.55a(b)(2)(ix)(J).

50.55a(b)(2)(ix)(A) Metal containment examinations: First provision. For Class MC applications, the following apply to inaccessible areas.

(1) The applicant or licensee must evaluate the acceptability of inaccessible areas when conditions exist in accessible areas that could indicate the presence of or could result in degradation to such inaccessible areas.

(2) For each inaccessible area identified for evaluation, the applicant or licensee must provide the following in the ISI Summary Report as required by IWA-6000:

(i) A description of the type and estimated extent of degradation, and the conditions that led to the degradation; (ii) An evaluation of each area, and the result of the evaluation; and (iii) A description of necessary corrective actions.

50.55a(b)(2)(ix)(B) Metal containment examinations: Second provision. When performing remotely the visual examinations required by Subsection IWE, the maximum direct examination distance specified in Table IWA-2210-1 (1992 Edition through 2004 Edition) or Table IWA-2211-1 (2005 Addenda through the latest edition and addenda incorporated by reference in paragraph (a)(1) of this section) may be extended and the minimum illumination requirements specified may be decreased provided that the conditions or indications for which the visual examination is performed can be detected at the chosen distance and illumination.

50.55a(b)(2)(ix)(J) Metal containment examinations: Tenth provision. In general, a repair/replacement activity such as replacing a large containment penetration, cutting a large construction opening in the containment pressure boundary to replace steam generators, reactor vessel heads, pressurizers, or other major equipment; or other similar modification is considered a major containment modification. When applying IWE-5000 to Class MC pressure-retaining components, any major containment modification or repair/replacement must be followed by a Type A test to provide assurance of both containment structural integrity and leak-tight integrity prior to returning to service, in accordance with 10 CFR part 50, Appendix J, Option A or Option B on which the applicant's or licensee's Containment Leak-Rate Testing Program is based. When applying IWE-5000, if a Type A, B, or C Test is performed, the test pressure and acceptance standard for the test must be in accordance with 10 CFR Part 50, Appendix J.

50.55a(g)(4)(v)(A) Metal and concrete containments: First provision. Metal containment pressure retaining components and their integral attachments must meet the inservice inspection, repair, and replacement requirements applicable to components that are classified as ASME Code Class MC;

RA-18-0149 Enclosure Page 45 of 90 This requirement imposes IWE on metal containments that were not designed in accordance with ASME Section III, Subsection NE.

50.55a(g)(4)(v)(B) Metal and concrete containments: Second provision. Metallic shell and penetration liners that are pressure retaining components and their integral attachments in concrete containments must meet the inservice inspection, repair, and replacement requirements applicable to components that are classified as ASME Code Class MC.

This requirement imposes IWE on metallic shell and penetration liners of concrete containments.

50.55a(g)(4)(v)(C) Metal and concrete containments: Third provision. Concrete containment pressure retaining components and their integral attachments, and the post-tensioning systems of concrete containments, must meet the inservice inspections, repair, and replacement requirements applicable to components that are classified as ASME Code Class CC.

This requirement imposes IWL on concrete containments that were not designed and constructed as Class CC components in accordance with ASME Section III, Division 2.

RA-18-0149 Enclosure Page 46 of 90 Table IWE-2500-1, Examination Category E-A, Containment Surfaces Table 3.6.2-3 BSEP Unit 1 E-A Examinations Item Numbers Parts Examined Number of Items Number of Examinations Scheduled by Period 1

2 3

E1.10 E1.11 Containment Vessel Pressure Retaining Boundary Accessible Surface Areas 203 203 203 203 E1.12 Wetted Surfaces of Submerged Areas 25 11 9

5 E1.20 BWR Vent System Accessible Surface Areas 19 0

0 19 E1.30 Moisture Barrier 1

1 1

1 Table 3.6.2-4 BSEP Unit 2 E-A Examinations Item Numbers Parts Examined Number of Items Number of Examinations Scheduled by Period 1

2 3

203 203 203 203

RA-18-0149 Enclosure Page 47 of 90 Table 3.6.2-4 BSEP Unit 2 E-A Examinations Item Numbers Parts Examined Number of Items Number of Examinations Scheduled by Period 1

2 3

E1.10 E1.11 Containment Vessel Pressure Retaining Boundary Accessible Surface Areas E1.12 Wetted Surfaces of Submerged Areas 25 11 9

5 E1.20 BWR Vent System Accessible Surface Areas 19 0

0 19 E1.30 Moisture Barrier 1

1 1

1 Notes:

1. Portions of the surfaces (including bolted connections) of electrical penetrations are considered inaccessible for general visual examination in accordance with Category E-A, E1.11 because welded electrical junction boxes are attached just off of the containment wall, not allowing sufficient space to perform this visual examination. Surfaces are considered to be accessible for visual examination if the examination can be performed, either directly or remotely, by line of sight from available viewing angles from floors, platforms, walkways, ladders, or other permanent vantage points, as specified in IWE-2310(c).

Table IWE-2500-01, Examination Category E-C, Containment Surfaces Requiring Augmented Examination

RA-18-0149 Enclosure Page 48 of 90 Table 3.6.2-5 BSEP Unit 1 E-C Examinations Item Numbers Parts Examined Number of Items Number of Examinations Scheduled by Period 1

2 3

E4.10 E4.11 Containment Surface Areas - Visible Surfaces 0

0 0

0 E4.12 Surface Area Grid - Minimum Wall Thickness Location 0

0 0

0 Table 3.6.2-6 BSEP Unit 2 E-C Examinations Item Numbers Parts Examined Number of Items Number of Examinations Scheduled by Period 1

2 3

E4.10 E4.11 Containment Surface Areas - Visible Surfaces 0

0 0

0 E4.12 Surface Area Grid - Minimum Wall Thickness Location 0

0 0

0 Notes:

RA-18-0149 Enclosure Page 49 of 90

1. At the start of the Fifth ISI Interval, there were no items identified requiring examination in accordance with Category E-C, Items E4.11 or E4.12. During the previous (Second) Containment ISI Interval, there were some Unit 2 items that required examination in accordance with Category E-C, but the requirements of IWE-2420(d) have been satisfied so these examinations are no longer required.

Table IWE-2500-1, Examination Category E-G, Pressure Retaining Bolting Table 3.6.2-7 BSEP Unit 1 E-C Examinations Item Numbers Parts Examined Number of Items Number of Examinations Scheduled by Period 1

2 3

E8.10 Bolted Connections 16 4

5 7

Table 3.6.2-8 BSEP Unit 2 E-C Examinations Item Numbers Parts Examined Number of Items Number of Examinations Scheduled by Period 1

2 3

E8.10 Bolted Connections 16 5

11 0

RA-18-0149 Enclosure Page 50 of 90 Note: 100 percent of the examinations are required to be performed by the end of Interval. Deferral to the end of the interval is permissible. Examinations may be performed at any time during the interval and may be performed with the connection assembled and bolting in place under tension, provided the connection is not disassembled during the interval. If the bolted connection is disassembled for any reason during the interval, the examination shall be performed with the connection disassembled.

Subsection IWL for Class CC Table 3.6.2-9 BSEP Unit 1 L-A Examinations Item Numbers Parts Examined Areas Required to be Examined During Each Period L1.10 L1.11 Concrete Surface All Accessible Surface Areas 100% (18 of 18 Areas)

L1.12 Suspect Areas 100% (If Any)

Table 3.6.2-10 BSEP Unit 2 L-A Examinations Item Numbers Parts Examined Areas Required to be Examined During Each Period L1.10 L1.11 Concrete Surface All Accessible Surface Areas 100% (18 of 18 Areas)

RA-18-0149 Enclosure Page 51 of 90 L1.12 Suspect Areas 100% (If Any)

Note: The IWL examination periods are as follows and do not align with those for Class 1, 2, 3 and MC Components:

a. Unit 1: IWL Period 1 - August 20, 2020 to August 20, 2022 IWL Period 2 - August 20, 2025 to August 20, 2027

b. Unit 2: IWL Period 1 - October 8, 2018 to October 8, 2020 IWL Period 2 - October 8, 2023 to October 8, 2025

RA-18-0149 Enclosure Page 52 of 90 3.6.4 Supplemental Inspection Requirements With the implementation of the proposed change, TS 5.5.12 will be revised by replacing the reference to RG 1.163 (i.e., Reference 1) with reference to NEI 94-01, Revision 3-A (i.e.,

Reference 2). This will require that a general visual examination of accessible interior and exterior surfaces of the containment for structural deterioration that may affect the containment leak-tight integrity be conducted. This inspection must be conducted prior to each Type A test and during at least three (3) other outages before the next Type A test if the interval for the Type A test has been extended to 15 years in accordance with the following sections of NEI 94-01, Revision 3-A:

Section 9.2.1, "Pretest Inspection and Test Methodology" Section 9.2.3.2, "Supplemental Inspection Requirements" BSEP License Amendments 245 and 273 were approved on February 8, 2008, to allow the performance of the visual examinations of the containment pursuant to ASME Code Section XI, Subsections IWE and IWL, in lieu of the visual examinations performed pursuant to RG 1.163.

The containment visual examination for the BSEP is implemented by the Primary Containment Inspection procedure. The purpose of this procedure is to perform examinations to assess the general condition of primary containment and to detect evidence of degradation that may affect structural integrity or leak tightness. This procedure fulfills the surveillance requirements of the Containment ISI Program Plan (i.e., IWE / IWL Plan), as all areas of the shell and liner which are accessible for direct or qualified remote examination are subject to these requirements.

Supplemental inspections will not be required.

3.6.5 Primary Containment Leakage Rate Testing Program - Type B and Type C Testing Program BSEP Types B and C testing program requires testing of electrical penetrations, airlocks, hatches, flanges, and CIVs in accordance with 10 CFR 50, Appendix J, Option B and RG 1.163 (i.e., Reference 1). The results of the test program are used to demonstrate that proper maintenance and repairs are made on these components throughout their service life. The Types B and C testing program provides a means to protect the health and safety of plant personnel and the public by maintaining leakage from these components below appropriate limits. In accordance with Unit 1 and Unit 2 TS 5.5.12, the allowable maximum pathway total Types B and C leakage is 0.6 La (159.78 standard cubic feet per hour (SCFH)) where La equals approximately 266.3 SCFH.

As discussed in NUREG-1493 (i.e., Reference 10), Type B and Type C tests can identify the vast majority of all potential containment leakage paths. Type B and Type C testing will continue to provide a high degree of assurance that containment integrity is maintained.

A review of the Type B and Type C test results from 2007 through 2018 for BSEP has shown substantial margin between the actual As-Found (AF) and As-Left (AL) outage summations and the regulatory requirements as described below:

The As-Found minimum pathway leak rate average for BSEP Unit 1 shows an average of 36.42% of 0.6 La with a high of 78.02% 0.6 La.

RA-18-0149 Enclosure Page 53 of 90 The As-Left maximum pathway leak rate average for BSEP Unit 1 shows an average of 59.60% of 0.6 La with a high of 78.04% 0.6 La.

The As-Found minimum pathway leak rate average for BSEP Unit 2 shows an average of 31.17% of 0.6 La with a high of 40.12% 0.6 La.

The As-Left maximum pathway leak rate average for BSEP Unit 2 shows an average of 61.80% of 0.6 La with a high of 87.14% 0.6 La.

Tables 3.6.5-1 and 3.6.5-2 provide LLRT data trend summaries for BSEP inclusive of the 2010 and 2015 ILRTs.

RA-18-0149 Enclosure Page 54 of 90 Table 3.6.5-1 BSEP Unit 1 Type B and C LLRT Combined As-Found / As-Left Trend Summary RFO /

Year 2008 2010 2012 2014 2016 2018 B117R1 B118R1 B119R1 B120R1 B121R1 B122R2 AF Min Path (SCFH) 54.397 64.885 124.662 40.734 35.013 29.474 Fraction of 0.6 La (percent) 34.04%

40.61%

78.02%

25.49%

21.91%

18.45%

AL Max Path (SCFH) 124.690 106.929 80.037 94.703 67.716 97.254 Fraction of 0.6 La (percent) 78.04%

66.92%

50.09%

59.27%

42.38%

60.87%

AL Min Path (SCFH) 53.337 35.485 26.760 35.921 25.007 27.525 Fraction of 0.6 La (percent) 33.38%

22.21%

16.75%

22.48%

15.65%

17.23%

RA-18-0149 Enclosure Page 55 of 90 Table 3.6.5-2 BSEP Unit 2 Type B and C LLRT Combined As-Found / As-Left Trend Summary RFO /

Year 2007 2009 2011 2013 2015 2017 B218R1 B219R1 B220R1 B221R1 B222R1 B223R1 AF Min Path (SCFH) 64.108 36.255 51.365 56.465 54.659 35.986 Fraction of 0.6 La (percent) 40.12%

22.69%

32.15%

35.34%

34.21%

22.52%

AL Max Path (SCFH) 139.232 88.887 112.810 73.833 91.724 90.251 Fraction of 0.6 La (percent) 87.14%

55.63%

70.60%

46.21%

57.41%

56.48%

AL Min Path (SCFH) 54.908 42.093 42.957 38.485 37.353 35.516 Fraction of 0.6 La (percent) 34.36%

26.34%

26.89%

24.09%

23.38%

22.23%

RA-18-0149 Enclosure Page 56 of 90 3.6.6 Type B and Type C Local Leak Rate Testing Program Implementation Review No LLRT components on an extended frequency exceeded their administrative limits over the last two refueling outages at BSEP Units 1 and 2.

BSEP Type B and C Component Performance:

The percentage of the total number of BSEP Unit 1 Type B tested components that are on 120-month extended performance-based test intervals is 100%.

The percentage of the total number of BSEP Unit 1 Type C tested components that are on 60-month extended performance-based test intervals is 56.8%.

The percentage of the total number of BSEP Unit 2 Type B tested components that are on 120 month extended performance-based test intervals is 100%.

The percentage of the total number of BSEP Unit 2 Type C tested components that are on 60 month extended performance-based test intervals is 60.2%.

3.7 Operating Experience During the performance of the various examinations and tests conducted in support of the Containment related programs previously mentioned, issues that do not meet established criteria or that provide indication of degradation, are identified, placed into the site's corrective action program, and corrective actions are planned and performed.

For the BSEP Primary Containment, the following site specific and industry events have been evaluated for impact on BSEP:

Information Notice (IN) 1992-20, "Inadequate Local Leak Rate Testing" IN 2004-09, "Corrosion of Steel Containment and Containment Liner" IN 2010-12, "Containment Liner Corrosion" IN 2014-07, "Degradation of Leak-Chase Channel Systems for Floor Welds of Metal Containment Shell and Concrete Containment Metallic Liner" Regulatory Issue Summary (RIS) 2016-07, "Containment Shell of Liner Moisture Barrier Inspection" Each of these areas is discussed in detail in Sections 3.7.1 through 3.7.5, respectively.

3.7.1 IN 1992-20, "Inadequate Local Leak Rate Testing" The NRC issued IN 92-20 to alert licensees of problems with local leak rate testing two-ply stainless steel bellows used on piping penetrations at four different plants: Quad Cities Nuclear Power Station, Dresden Nuclear Station, Perry Nuclear Power Plant and the Clinton Station.

Specifically, LLRTs could not be relied upon to accurately measure the leakage rate that would occur under accident conditions since, during testing, the two plies in the bellows were in contact with each other, restricting the flow of the test medium to the crack locations. Any two-ply bellows of similar construction may be susceptible to this problem. The common issue in the four events was the failure to adequately perform local leak rate testing on different

RA-18-0149 Enclosure Page 57 of 90 penetration configurations leading to problems that were discovered during ILRT tests in the first three cases.

In the event at Quad Cities the two-ply bellows design was not properly subjected to LLRT pressure and the conclusion of the utility was that the two-ply bellows design could not be Type B LLRT tested as configured.

In the events at both Dresden and Perry flanges were not considered a leakage path when the Type C LLRT test was designed. This omission led to a leakage path that was not discovered until the plant performed an ILRT test.

In the event at Clinton relief valve discharge lines that were assumed to terminate below the suppression pool minimum drawdown level were discovered to terminate at a level above that datum. These lines needed to be reconfigured and the valves should have been Type C LLRT tested.

Discussion IN 1992-20 is not applicable to BSEP Units 1 or 2. There are no steel bellows installed as containment isolation barriers. In addition, all local leak rate testing methods have been verified to account for all possible leakage paths, including those through gasketed flanges. In addition, all isolation valves that have been credited with maintaining a water seal and therefore exempt from Appendix J testing have been verified to have lines that terminate below the minimum suppression pool level.

3.7.2 IN 2004-09, "Corrosion of Steel Containment and Containment Liner" The NRC issued IN 2004-09 to alert addressees to recent occurrences of corrosion in freestanding metallic containments and in liner plates of reinforced and pre-stressed concrete containments. Any corrosion (i.e., metal thinning) of the liner plate or freestanding metallic containment could change the failure threshold of the containment under a challenging environmental or accident condition. Thinning changes the geometry of the containment shell or liner plate and may reduce the design margin of safety against postulated accident and environmental loads. Recent experience has shown that the integrity of the moisture barrier seal at the floor-to-liner or floor-to-containment junctions is important in avoiding conditions favorable to corrosion and thinning of the containment liner plate material. Inspections of containment at the floor level, as well as at higher elevations, have identified various degrees of corrosion and containment plate thinning.

Discussion In May of 1999, BSEP Unit 2 identified three areas in the drywell liner where corrosion had penetrated the liner. These areas were at the 18, 56, and 70-foot elevations.

18-Foot Elevation Defect Description The drywell liner plate at the 18-foot elevation is constructed of 5/16-inch thick ASTM A-516, Grade 60 carbon steel plate, backed by approximately 6 feet of concrete, and coated with approximately 9-13 mils of Keeler and Long epoxy paint. The defect on the 18-foot elevation was initially identified as a broken coating blister exceeding acceptance limits with corrosion products visible through the break in the coating. The blister and corrosion products were removed to determine if sound metal was present below the surface. After removal, a 5/16-inch

RA-18-0149 Enclosure Page 58 of 90 diameter hole cylindrical through-wall indication was identified, with an adjoining area of approximately 1-inch in diameter exhibiting surface corrosion which had been under the coating.

A small wire was inserted into the hole to a depth of 7/8-inch, indicating the presence of a 9/16-inch deep void in the concrete behind the defect in the liner plate.

Surface corrosion products and coatings were removed from the area, and a general visual examination was performed. Subsequent ultrasonic testing was performed in all directions immediately adjacent to the defect. Nominal metal thickness readings were obtained in all directions except for one subsurface indication. It connected to the through-wall defect and extended in the 8:00 direction (i.e., slightly below horizontal) for approximately 3/4-inch. The indication was approximately 1/4-inch wide and showed a reduced thickness of approximately 1/8-inch on the back of the plate.

During repairs, a metal burr was used to enlarge the opening as required to reach sound metal and to prepare a cavity suitable for welding. This resulted in an opening in the metal of approximately 3/4-inch by 2 inches. The subsurface defect appeared to be rust stained metal, with little or no powdered corrosion products as had been removed from the through-wall opening. The concrete was white, with only a light corrosion stain on the surface of the void. It was not filled with corrosion products. A small amount of concrete was removed to permit installation of a metal backing strip for the repair weld, and the subsurface concrete was sound, and white with no apparent cracking or other damage.

Root Cause of 18-Foot Elevation Defects Pitting on the liner propagating through the liner wall caused the defects observed on the 18-foot elevation of the containment liner. This was primarily caused by corrosion which went undetected in previous containment liner examinations. Prior inspections noted the presence of corrosion; however, the observed defects seemed to meet the acceptance criteria. The inspection procedures exhibited weaknesses in requiring probing of visual indications that meet visual acceptance limits. A secondary cause of the corrosion was localized coating breaks which exposed the bare steel containment liner to oxygen and moisture. The breaks in the coating could have been caused by local mechanical damage. The moisture which accumulated on the drywell liner was comprised of chlorides from salt air and made contact with the liner through a break in the coating or osmotic blistering. The area behind the corrosion product buildup stored moisture for continuous exposure. The corrosion was also provided an oxygen rich environment during refueling outages (i.e., 21 percent oxygen), with long exposure provided during a yearlong outage in 1992 to1993.

56-Foot Elevation Defects Description The cluster of defects located on the 56-foot elevation was the largest defect area identified but was unlike the defects on the 18 and 70-foot elevations. Therefore, it was evaluated separately.

The drywell liner plate at the 56-foot elevation is constructed of 5/16-inch thick ASTM A-516, Grade 60 carbon steel plate, backed by approximately 6 feet of concrete and coated with approximately 9 to 13 mils of Keeler and Long epoxy paint. This area was identified by the presence of fresh rust stains streaming down the drywell liner from a cluster of blisters. The blisters and corrosion products were removed to determine if sound metal was present below the surface. Eight small pits were discovered. Additionally, there was a pronounced bulge in the liner at the exact location of those defects. Visual examination of the pits revealed subsurface corrosion in the plate at a shallow depth. The coatings were removed and ultrasonic testing was performed in the area. The depth of sound metal adjacent to the pits averaged

RA-18-0149 Enclosure Page 59 of 90 approximately 0.100 inches, indicating a significant metal loss on the backside of the plate. A lamination in the steel plate was initially suspected. Further ultrasonic testing was performed to determine the extent of the subsurface damage and an area of sound metal was found in all directions from the defects.

Two small sections of liner plate were removed to permit visual examination, one containing a cluster of five of the defects and another in the estimated location of a retaining stud behind the liner. A large corrosion product deposit was visible through each of these openings, indicating further plate removal was required. The Nelson stud which had been welded to the back of the liner had been damaged by corrosion, which severed its connection with the liner.

A section of liner, approximately 7 inches tall by 10 inches wide, was then removed. A large corrosion deposit was found intact behind the plate. This deposit was bright red in the location of the largest cluster of pits, indicating fresh corrosion activity. The color faded toward the edges, indicating less recent activity. The back side of the plate exhibited a large cavity resulting from the corrosion, which thickness similar to the readings obtained before using the ultrasonic testing. The maximum corrosion deposit thickness was at the location of the pits, gradually tapering toward the edges.

The concrete just beyond the edges of the deposit were clean and showed no evidence of rust stain, moisture or other damage. The corrosion deposit appeared localized. The corrosion deposit was carefully removed from the surface of the concrete. In the center of the deposit, where the maximum corrosion had occurred, a void was found in the concrete which contained some irregularly shaped foreign material. The concrete material was carefully removed and portions of a glove were identified, which had apparently fallen into the concrete during construction was extracted. The glove material was in direct contact with the corrosion deposit which contacted the liner. The pit location was directly in front of the area containing the glove as well. Further excavation was performed until sound concrete was revealed. No cracks were found in the concrete and no voids or rust stains remained in the cavity after excavation.

The corrosion deposit debris was examined and no sound metal was identified. The original plate material had been completely converted to corrosion products; ruling out the initial theory of lamination in the plate. The low thickness readings of the plate material resulted solely from metal loss due to corrosion from the back side of the plate.

Approximately 2 inches of the 8-inch long by 1/2-inch diameter Nelson stud had been consumed by corrosion. The excavation of the adjacent concrete exposed about 2 inches of the remaining portion of the stud, permitting welding of an extension during repairs. The remainder of the stud encased in concrete exhibited no corrosion products or staining and there was no gap between the stud and the concrete. The corrosion damaged portion had been completely removed. The maximum cavity depth in the concrete was approximately 3.5 inches. Adjacent studs in each direction were checked by ultrasonic testing and determined to be in contact with the liner plate.

Ultrasonic testing of a four-square feet area surrounding the defect area was performed to assure that the defects were completely identified and repaired. No corrosion stains, debris or other indication of corrosion beyond the single location was found.

Root Cause of 56-Foot Elevation Defects Pitting on the liner propagating through the liner wall caused the defects observed on the 56-foot elevation of the containment liner. This was primarily caused by corrosion which was not detected in its earliest stages, since the corrosion was not visible during the previous

RA-18-0149 Enclosure Page 60 of 90 inspection. The corrosion initiated as general corrosion behind the liner plate and initially did not penetrate the coated surface. General corrosion propagated through the thin remaining liner plate since the previous inspection. The corrosion rate accelerated once perforation occurred due to availability of moisture from the coated side of liner. This resulted in corrosion product buildup which ultimately bulged the liner. Moisture inside the drywell condensed on the surface of the liner, absorbing chlorides from the salt air. Moisture passed through perforations initiated from the back side of the plate, accelerating the corrosion rate. On the concrete side of the liner plate, void and debris in the concrete wicked moisture from the concrete for long periods of time after initial construction, creating conditions for initiation of general corrosion.

70-Foot Elevation Defects Description The drywell liner plate at the 70-foot elevation is constructed of 5/16-inch thick ASTM A-516, Grade 60 carbon steel plate, backed by approximately 4 feet of concrete and coated with approximately 9 to 13 mils of Keeler and Long epoxy paint. The defect identified on the 70-foot elevation was also identified as a broken blister but was of a smaller size. The diameter of the corrosion deposit at the surface was approximately 1/4-inch, tapering down to 1/8-inch in the bottom of the pit. A grinder was used to prepare a cavity for welding. When the grinder contacted the indication, the corrosion products disintegrated, revealing a small through-wall defect 1/8-inch in diameter, 5/16-inch deep from the surface of the plate. No cavity was present in the concrete.

After coatings were removed adjacent to the defect, ultrasonic testing was performed indicating full metal thickness in all directions except for one area extending downward from the pit for approximately 1 inch. This area was approximately 1/8-inch wide and 1/16-inch deep on the back side of the plate.

The area was excavated to prepare a cavity for welding and to remove the area with reduced thickness. The exposed concrete exhibited rust staining but was dry and sound. No indication of moisture was present.

Root Cause of 70-Foot Elevation Defects Pitting on the liner propagating through the liner wall caused the defects observed on the 70-foot elevation of the containment liner. This was primarily caused by corrosion which went undetected in previous containment liner examinations. Prior inspections noted the presence of corrosion; however, the observed defects seemed to meet the acceptance criteria. The inspection procedures exhibited weaknesses in requiring probing of visual indications that meet visual acceptance limits. A secondary cause of the corrosion was localized coating breaks which exposed the bare steel containment liner to oxygen and moisture. The breaks in the coating could have been cause by local mechanical damage. The moisture which accumulated on the drywell liner was comprised of chlorides from salt air and contacted the liner through a break in the coating or osmotic blistering. The area behind the corrosion product buildup stored moisture for continuous exposure. The corrosion was also provided an oxygen rich environment during refueling outages (i.e., 21 percent oxygen), with long exposure provided during a yearlong outage in 1992 to 1993.

Repair Activities All liner repairs were completed during the 1999 Unit 2 refueling outage. This includes restoring the liner plate, anchor stud, and protective coating. Each area was given a local leak rate

RA-18-0149 Enclosure Page 61 of 90 pressure test with all areas testing satisfactorily. Ultrasonic testing of the defect areas on the 18-foot and 56-foot elevation was performed and no wall thinning or new indications were observed. Ultrasonic thickness of observed bulged areas previously identified on the containment liner were performed with no wall thinning observed.

3.7.3 IN 2010-12, "Containment Liner Corrosion" IN 2010-12 was issued to alert plant operators to three events that occurred where the steel liner of the containment building was corroded and degraded. At the Beaver Valley and Brunswick plants, material had been found in the concrete, which trapped moisture against the liner plate and corroded the steel. In one case, it was material intentionally placed in the building and in the other case, it was foreign material, which had inadvertently been left in the form when the wall was poured. The result in both cases was that the material trapped moisture against the steel liner plate leading to corrosion. In the third case, Salem, an insulating material placed between the concrete floor and the steel liner plate absorbed moisture and led to corrosion of the liner plate.

Discussion During the performance of containment inspections during the 2008 Unit 1 refueling outage, a VT-1 visual examination revealed two bulged areas in the 1-X-2 penetration sleeve. This is the drywell penetration sleeve associated with the personnel airlock. Based on a review of the examination data from previous outages, these two bulged areas were not previously recorded.

Based on the thickness readings on one of the bulged areas, localized areas (i.e., within the examination area) were determined to be below the minimum design wall thickness. As a result, a more comprehensive ultrasonic thickness examination of the entire 1-X-2 penetration sleeve was conducted. This additional UT examination identified several discrete locations, which existed over less than 3 percent of the sleeve surface area, that were below the established minimum design wall thickness.

During the performance of primary containment inspections during the 2007 Unit 2 refueling outage, bulging was identified in the drywell airlock penetration sleeve 2-X-2. An ultrasonic thickness examination of the bulged area was performed and thicknesses below the acceptance criteria were found. The emphasis during 2007 Unit 2 refueling outage was evaluating minimum wall thickness based on newly detected bulges and pitting observed on the inside diameter of the sleeve.

A lack of rigor with respect to fully understanding and characterizing the degradation mechanism caused areas at or below minimum wall thickness to go undetected for two cycles.

Because of previous lessons learned, a VT-1 visual examination of the 1-X-2 sleeve was performed during the 2008 Unit 1 refueling outage. The VT-1 visual examination is an enhanced visual examination method specified in the ASME Code,Section XI. Due to this enhanced visual examination method, areas of concern not identified during 2004 Unit 1 refueling outage were identified. Once identified, thickness readings using the static and dynamic ultrasonic scan methods were performed on the areas of concerned. For clarification, static readings are taken at the intersect points of the grid. The dynamic scan is performed by sweeping the transducer over the surface within the grid lines. Like the enhanced visual examination, the use of the dynamic scan method (to supplement the static readings) was based on lessons learned. The use of these enhanced examination methods assisted in identifying areas of wastage not observed during the 2004 Unit 1 refueling outage. It is apparent that if these enhanced examination methods were utilized during the 2004 Unit 1

RA-18-0149 Enclosure Page 62 of 90 refueling outage, the adverse condition would have been fully bounded and corrective actions implemented in a timelier manner.

Penetration sleeve 1-X-2 was considered to be operable, but degraded, with an interim use-as-is qualification until the next refueling outage. This operability evaluation was acceptable to all operating modes. The following actions were completed prior to startup:

Repair the area of the boat sample. This area was defined by engineering and the repair performed in accordance with the applicable requirements of Article IWA-4000 (1992 Edition with 1992 Addenda).

Repair the low reading area (<0.11") identified during the manual scan ultrasonic thickness examinations. This area was defined by engineering and the repair performed in accordance with the applicable requirements of Article IWA-4000 (1992 Edition with 1992 Addenda).

The repaired areas were tested at 50 psig in accordance with the applicable requirements of Article IWE-5000 (1992 Edition with 1992 Addenda) and 10 CFR 50, Appendix J, Option B. Measured leakage rate was 0.00 standard cubic feet per hour (SCFH).

The Unit 1 penetration sleeve (1-X-2) was replaced during the 2010 Unit 1 refueling outage and the Unit 2 penetration sleeve (2-X-2) was replaced during the 2015 Unit 2 refueling outage.

3.7.4 IN 2014-07, "Degradation of Leak-Chase Channel Systems for Floor Welds of Metal Containment Shell and Concrete Containment Metallic Liner" The NRC issued IN 2014-07 to inform the industry of issues concerning degradation of floor weld leak-chase channel systems of steel containment shell and concrete containment metallic liner that could affect leak-tightness and aging management of containment structures.

Specifically, this IN provides examples of operating experience at some plants of water accumulation and corrosion degradation in the leak-chase channel system that has the potential to affect the leak-tight integrity of the containment shell or liner plate. In each of the examples, the plant had no provisions in its ISI plan to inspect any portion of the leak-chase channel system for evidence of moisture intrusion and degradation of the containment metallic shell or liner within it. Therefore, these cases involved the failure to perform required visual examinations of the containment shell or liner plate leak-chase systems in accordance with the ASME Code Section XI, Subsection IWE, as required by 10 CFR 50.55a(g)(4).

The containment basemat metallic shell and liner plate seam welds of pressurized water reactors are embedded in 3 feet by 4 feet concrete floor during construction and are typically covered by a leak-chase channel system that incorporates pressurizing test connections. This system allows for pressure testing of the seam welds for leak-tightness during construction and also while in service, as required. A typical basemat shell or liner weld leak-chase channel system consists of steel channel sections that are fillet welded continuously over the entire bottom shell or liner seam welds and subdivided into zones, each zone with a test connection.

Each test connection consists of a small carbon or stainless-steel tube (less than 1-inch diameter) that penetrates through the back of the channel and is seal-welded to the channel steel. The tube extends up through the concrete floor slab to a small access (junction) box embedded in the floor slab. The steel tube, encased in a pipe, projects up through the bottom

RA-18-0149 Enclosure Page 63 of 90 of the access box with a threaded coupling connection welded to the top of the tube, allowing for pressurization of the leak-chase channel. After the initial tests, steel threaded plugs or caps are installed in the test tap to seal the leak-chase volume. Gasketed cover plates or countersunk plugs are attached to the top of the access box flush with the containment floor. In some cases, the leak-chase channels with plugged test connections may extend vertically along the cylindrical shell or liner to a certain height above the floor.

Discussion The BSEP Containment Structures are not constructed with Leak-Chase Channel Systems for the portion of liner that is made inaccessible by concrete.

The floor of containment is constructed with a slope away from the steel liner and concrete floor interface towards the containment floor drain sumps. Additionally, the original construction at the interface of the liner and concrete was designed with an asphaltic moisture barrier/seal to prevent moisture intrusion below grade.

In 1993 this interface was evaluated for each unit. Areas of liner degradation at the interface of the liner and concrete floor were noted. Concrete was excavated and the degradation was found limited to the interface and did not extend beyond the installed asphaltic seal. The degraded liner was repaired by welding. The moisture barrier/seal was also re-designed to further re-direct moisture away from the liner and concrete floor interface.

Inspection of the moisture barrier of each operating unit is included within the scope of the ASME Section XI Subsection IWE ISI Containment Inspection Program.

3.7.5 NRC RIS 2016-07, "Containment Shell or Liner Moisture Barrier Inspection" The NRC staff identified several instances in which containment shell or liner moisture barrier materials were not properly inspected in accordance with ASME Code Section XI, Table IWE-2500-1, Item E1.30. Note 4 (i.e., Note 3 in editions before 2013) for Item E1.30 under the "Parts Examined" column states, "Examination shall include moisture barrier materials intended to prevent intrusion of moisture against inaccessible areas of the pressure retaining metal containment shell or liner at concrete-to-metal interfaces and a metal-to-metal interfaces which are not seal welded. Containment moisture barrier materials include caulking, flashing and other sealants used for this application."

Examples of inadequate inspections have included licensees not identifying sealant materials at metal-to-metal interfaces as moisture barriers because they do not specifically match Figure IWE-2500-1, and licensees not inspecting installed moisture barriers, as required by Item E1.30, because the material was not included in the original design or was not identified as a "moisture barrier" in design documents.

Discussion:

The condition identified in RIS 2016-07 was evaluated for applicability at BSEP. As a result, the BSEP Containment ISI Program was updated to perform the following:

Identify all specific locations within each containment where moisture barriers exist.

For all locations identified where there is no moisture barrier present or where the condition of the moisture barrier had degraded such that moisture intrusion behind the

RA-18-0149 Enclosure Page 64 of 90 joint could occur if the joint were exposed to water, specific actions were taken to mitigate the situation and to perform the inspections required by ASME Section XI at a frequency concurrent with IWE-2500-1 Examination Category E-A, Item E1.30.

Verify that procedures for performing examinations of the containment moisture barrier in accordance with ASME Section XI IWE-2500-1 Examination Category E-A, Item E1.30 contain sufficient information pertaining to the scope and acceptance standards for visual examination of all types of moisture barriers at each site.

When this condition was identified, BSEP was in Interval 4 for the Containment ISI Program.

The 2018 Unit 1 refueling outage and the 2017 Unit 2 refueling outage were the last outages remaining in the interval where full compliance with the moisture barrier periodic examination requirements was possible. The results of these inspections are detailed in Section 3.7.6 of this submittal.

3.7.6 Results of Recent Containment Inspections Primary Containment Coatings Condition Assessment Unit 1 2016 Refueling Outage The general condition of the primary containment was satisfactory. The coatings observed in the Drywell and Torus appeared well adhered with minimal areas of degradation.

Understanding that mechanical damage, staining, and uncoated surfaces exists; the coatings on the vessel walls and structures, systems and components exhibited overall good adherence.

Four recordable conditions were identified in the Drywell with greater than 1 square foot of minor flaking; however, the majority of the area still exhibited well coated and protected surfaces. The ring header coatings were in excellent condition, as was the Dome; both see minimal personnel activity.

The degradation of the coatings was caused by contact and/or mechanical damage. Exposed and unpainted metal can corrode during outage time while the nitrogen purge is discontinued.

During the operating cycle, the nitrogen purge provides protection from continued oxidation of the metal. Coatings not mechanically damaged or disturbed exhibited good adhesion, especially surfaces out of reach, where physical contact does not occur.

The recordable conditions included a previous area under the vessel on the carousel, as well as spot locations on 17-foot and 52-foot elevations showing signs of initial peeling (i.e., all less than 1 square foot of affected area). On the -5 foot elevation, a single chipped paint location was identified on the liner by inspectors. All of the areas of degradation were entered into the Unqualified Coatings Exempt Log to be monitored in future outage walkdowns for worsening conditions, and potentially to be removed if needed. The Unqualified Coatings margin was well below the limit for the Maintenance Rule against the ECCS strainer. Following The 2012 Unit 1 refueling outage, the Unqualified Coatings as a percentage of MR a(1) limit was 60.3 percent.

Primary Containment Coatings Condition Assessment Unit 1 2018 Refueling Outage, Spring 2018 The overall general condition of the Service Level (SL-1) coatings was satisfactory. There were no observations of wide scale delamination caused by heat and/or humidity. Considering the environment of the drywell and the Torus/ring header, the well-adhered condition of the coatings is above average. There were areas with mechanical damage due to foot traffic, equipment paths, age and wear, however coatings around these locations of mechanical damage were

RA-18-0149 Enclosure Page 65 of 90 tightly adhered. Service Level I coatings in the drywell elevations foot, 17-foot, 38-foot, 67-foot and 80-foot were in a satisfactory condition. The SL-1 coatings in the Torus and ring header were in a satisfactory condition. The SL-1 coatings on the Drywell Dome were in a satisfactory condition.

Any specific location which exhibited actual loss of adhesion, as evidenced by peeling or flaking was due to heat, humidity, and possibly surface conditions. However, very limited locations of loss of adhesion have been observed. The mechanical damage observed was due to the refuel outage traffic which is necessary to conduct walkdowns, inspections and repairs. The degraded coatings trend for the Service Level 1 coatings in the BSEP Unit 1 containment is maintaining.

The exempt coatings log for Unit 1 tracks the volume of degraded coatings over the outages.

The unqualified coatings volume following the Unit 1 2018 refueling outage is 60.5 percent of the allowed volume.

Primary Containment Coatings Condition Assessment Unit 2 2015 Refueling Outage The overall general condition of the SL-1 coatings in the drywell elevations including foot, 17-foot, 38-foot, 52-foot, 67-foot, 80-foot, and the interior of the drywell dome were good with little change from the 2013 Unit 2 refueling outage. The SL-1 coatings exhibited good adhesion to the vessel walls and to the outer liner. There was no observation of new flaking, blistering, or cracking. Several legacy items were reviewed and photographed to show unchanged conditions to those of previous outages. These comparisons illustrate that degraded coating conditions are not worsening due to time and the temperature of a normal operating cycle in the primary containment environment. Mechanical damage is evident, especially on the 17 elevation, but not more severe. There were no new non-Service Level 1 coatings identified other than minor inclusions which were appropriately documented in exemption requests.

Overall the SL-1 coatings remain intact, are functioning well, and are protecting the substrate surfaces.

The observed conditions of the SL-1 coatings include various degradations mechanisms including mechanical damage, flaking of paint due to loss of adhesion, staining due to external sources, and discoloration due to temperature and time. There were no new discoveries of extreme coatings degradation. The inclusion of the zinc based, cold galvanizing products applied to galvanized steel ductwork at the time of plant construction had a negative impact to the reduction of unqualified coating volume. Although this "coating" is not failing, nor degrading, zinc based, cold galvanizing products have never been tested to withstand a DBA. As such its inclusion as an unqualified coating is necessary. The overall amount of degraded coatings as monitored via the Coatings Exempt Log has increased during the Unit 2 2015 refueling outage from 2.324 cubic feet to 2.440 cubic feet.

The overall general condition of the SL-1 coatings in the Torus is good. This assessment includes the ring header and the Torus above the water line, as observed from the catwalk. The SL-1 coatings exhibited good adhesion to the structural walls with no apparent changes from past outage walkdowns. There was no observation of new flaking, blistering, or cracking.

Several legacy items were reviewed and photographed to show unchanged conditions to those of previous outages. These comparisons illustrate that degraded coating conditions are not worsening due to time and temperature of the normal operating cycle in the primary containment environment. Mechanical damage is evident, especially on the catwalk framing and other support beams in the Torus, but not more severe. A new recordable condition was entered identifying tracked footprints and paint drips of Carboline 890N. Additionally, the Torus

RA-18-0149 Enclosure Page 66 of 90 coatings below the water line, specifically the liner coating, was 100% inspected during the Unit 2 2015 refueling outage. A total of 6421 pit defects in the coating were identified, characterized, and repaired. These defects were recoated with Bio-Dur 561 and are qualified as Service Level I coating. Overall, the Service Level 1 coatings remain intact and are functioning well.

There is minimal degradation in the ring header of the Torus; the coatings are in excellent shape. The main Torus liner coatings above the water line are also in good condition, but discolored and stained at some locations. The Torus coatings on structures above the water line have mechanical damage and some surfaces have had their coatings removed entirely (i.e.,

catwalk members). The Torus coatings below the water line exhibited very good adhesion.

However, there is pitting in the coating exposing the steel liner surface. The observed pitting is evidence of the interaction of the coating with elements in the water with agitation initiating small defects, leading to some galvanic action. These initiation sites could be due to defects/contamination left on the surface prior to recoating, however incomplete surface preparation would have more widespread adhesion issues. Pitting in the Torus below the water line coatings is common throughout the industry.

Primary Containment Coatings Condition Assessment Unit 2 2017 Refueling Outage The general condition in all locations of primary containment was satisfactory during the Unit 2 2017 refueling outage Coatings Condition Assessment. Coatings on all elevations and areas were assessed during the 100% walkdown and many photos were taken as to illustrate the overall generally good condition and good adhesion of the coatings. Specific areas of degradation were identified. The K&L 7145 / 7105 coating system applied over most vessel and containment structural surfaces during original construction is demonstrating good performance.

The Carboline 890 coating system, applied to various SCCs and locations within primary containment, also exhibits good adhesion. Photos from the previous three outages were compared with existing conditions. The change to the state of the coatings is negligible. Areas previously identified as degraded showed no significant or noticeable change or worsening.

Two of the recordable conditions were observed as peeling and flaking. This degradation mechanism is due to the heat, humidity and time of the exposure to the environment of the Drywell. The overall successful adhesion of both coating systems is quite good.

Unit 1 2014 Refueling Outage Primary Containment Inspection The purpose of the Primary Containment Inspection is to perform examinations to assess the general condition of the containment liner and concrete surfaces of the primary containment and to detect evidence of degradation that may affect structural integrity or leak tightness. During the 2014 Unit 1 Primary Containment Inspection, the following nonconformances were identified:

Item Group: DW-X1 Recordable Condition: Localized General Corrosion that Reduces the Bolt / Stud Cross-Sectional Area Disposition: No loss of structural integrity

RA-18-0149 Enclosure Page 67 of 90 Item Group: DW-X-6-BC Recordable Condition: Deformed or Sheared Threads Disposition: 1 bolt and nut had damaged (Galled) threads. Replaced under Work Order (WO) 12076389 Item Group: SC-C3 Recordable Condition: Efflorescence (leaching)

Disposition: Not a structural concern Item Group SC-C4 Recordable Condition: Efflorescence (leaching) and cracking Disposition: Not a structural concern Item Group: SC-ML-BWL Recordable Condition: Excessive Corrosion or Pitting, Material Loss Identified Disposition: All indications were found to be bounded by plant calculation 0RIP-1009, were cleaned, prepped, and re-coated per the direction of the coatings engineer.

Item Group: 1-SP-Vent-Header-Manway Recordable Condition: Other Coating Distress (coated surfaces only)

Disposition: Coatings engineer determined nozzle internal and outside surfaces were satisfactory.

Item Group: SC-X-200A Recordable Condition: Rust (coated surfaces only), Excessive Corrosion or Pitting, Surface Discontinuity or Irregularity Disposition: Conditions evaluated as acceptable by Engineering based on details of findings and EER 94-0263.

Item Group: SC-X-200A-BC Recordable Condition: Nut displayed evidence of arc strikes and galling of the flat on the inside face of nut.

Disposition: Equivalent nut evaluated as acceptable under Engineering Change (EC) 96051 and installed under WO 2076220.

RA-18-0149 Enclosure Page 68 of 90 Item Group: SC-X-200B Recordable Condition: Rust (coated surfaces only), Excessive Corrosion or Pitting, Surface Discontinuity or Irregularity.

Disposition: Conditions evaluated as acceptable by Engineering based on details of findings and Engineering Evaluation Report (EER) 94-0263.

Item Group: SC-X-206D (Exterior)

Recordable Condition: Blistering (coated surfaces only), Other Material Distress.

Disposition: Blistered paint is not within the pressure boundary and end plate has drain hole per plant drawing F-02807. Component is acceptable per Engineering.

Item Group: SC-X-210A (Exterior)

Recordable Condition: Rust (coated surfaces only).

Disposition: There was no base metal degradation noted. Work Request 11619442 was generated to remove the rust and re-coat the penetration. Component is evaluated as acceptable by Engineering.

Unit 1 2016 Refueling Outage Primary Containment Inspection The purpose of the Primary Containment Inspection is to perform examinations to assess the general condition of the containment liner and concrete surfaces of the primary containment and to detect evidence of degradation that may affect structural integrity or leak tightness. During the 2016 Unit 1 Primary Containment Inspection, the following nonconformances were identified.

Item Group: DW-IMB Recordable Condition: Damage, Tear, Separation. Several areas of the moisture barrier were found to have gouges and separation from the interface of the metallic liner and concrete floor of containment.

Disposition: The recordable conditions were documented under Condition Report (CR) 2007293. The portion of the moisture barrier, the curbing, found with recordable conditions are not credited to prevent moisture intrusions and are not sealing surfaces. Therefore, the conditions are acceptable and repairs are planned for a future outage under WO 20065692 Item Group: SC-ML-BWL (Bays 1-16)

Recordable Condition: Excessive Corrosion or Pitting Disposition: All identified pit indications were found to be bounded by plant calculation 0RIP-1009 and accepted by Engineering

RA-18-0149 Enclosure Page 69 of 90 Unit 2 2015 Refueling Outage Primary Containment Inspection The purpose of the Primary Containment Inspection is to perform examinations to assess the general condition of the containment liner and concrete surfaces of the primary containment and to detect evidence of degradation that may affect structural integrity or leak tightness. During the 2015 refueling outage Primary Containment Inspection, the following nonconformances were identified.

Item Group: SC-C3, -17' S RHR room Recordable Condition: Cracking, Distortion, Evidence of Corrosion Staining or Corrosion Disposition: The subject pipe is not a containment penetration or part of the containment pressure boundary. The condition is notable and entered into Corrective Action Program (CAP) under CR 736103. Of the remaining indications there is no evidence of structural damage or degradation to warrant further evaluation.

Item Group: SC-C4, -17' N RHR room Recordable Condition: Distortion, Evidence of Corrosion Staining or Corrosion Disposition: The subject pipe is not a containment penetration or part of the containment pressure boundary. The condition is notable and entered into CAP under CR 736103. Of the remaining indications there is no evidence of structural damage or degradation to warrant further evaluation.

Item Group: SC-C2, -17' N CS room Recordable Condition: Cracking, Distortion, Evidence of Corrosion Staining or Corrosion Disposition: There is no evidence of structural damage or degradation sufficient to warrant further evaluation at this time.

Item Group: DW-ML-4 Recordable Condition: Other Coating Distress (coated surfaces only), Bulging of the Liner Disposition: Based on the evaluated conditions and the actual findings during the VT-1 and UT exams the bulging conditions are acceptable by engineering evaluation. Reference CR 735266 and WO 13494663 Item Group: DW-ML-5 Recordable Condition: Other Coating Distress (coated surfaces only), Bulging of the Liner Disposition: Based on the evaluated conditions and the actual findings during the VT-1 and UT exams the bulge conditions are acceptable by engineering evaluation. Reference CR 735266 and WO 13494663

RA-18-0149 Enclosure Page 70 of 90 Item Group: DW-IMB Recordable Condition: Separation Disposition: Moisture barrier separation condition documented under CR 735566 and repaired under WO 13495235 Item Group: SC-ML-BWL (Bays 1-16)

Recordable Condition: Excessive Corrosion or Pitting, Bulging of the Liner Disposition: All identified pit indications were re-coated prior to Torus close out.

Unit 2 2015 Refueling Outage - Torus Project - Desludging, Inspection and Coating Repair Underwater desludging, inspection and coating repair were performed in the BSEP Unit 2 Torus during the Unit 2 2015 Refueling Outage. The project goals were to (1) remove any accumulation of sludge or foreign material that might affect ECCS strainer operation; (2) improve water clarity for inspection, repair, and water quality purposes; (3) perform VT-1/VT-3 examinations of the Torus immersion area, including liner plates, downcomers, test channels and other designated components; and (4) perform coating repair on areas of the Torus.

The desludging effort concentrated primarily on the shell plates and test channels of the Torus.

Components were desludged as necessary to perform examinations. Sludge accumulation on the floor and components was light and generally consistent with expectations for the plants operating cycle (i.e., less than or equal to 1/4-inch). Only minor foreign material was noted in the Torus proper and none of the ECCS strainers.

Mechanical damage, spot corrosion and staining of the coating were evident. Of the 6,421 exposed substrate locations that exceeded Engineerings repairable criteria, 1,428 locations meeting or exceeding Engineerings reportable criteria (i.e., less than or equal to 37 mils) were noted.

Coating repairs were performed on locations identified during the inspections that met or exceeded the repairable criteria. A visual inspection was performed by a VT-1 / VT-2 Level II inspector on 100% of the coating repairs on the shell plates in the Torus. All final repairs appeared fully cured and tightly bonded to the substrate with no evidence of bleed-through, cracking, peeling or other deleterious effects.

Overall, the condition of the principal coating system in the inspected immersion area was good.

Although numerous random localized failures have occurred, the majority of the coating is providing adequate protection of the base metal. With routine monitoring and periodic maintenance, it should continue to provide an adequate barrier protection.

RA-18-0149 Enclosure Page 71 of 90 Summary of Inspection Findings Torus Shell Plates and Channels In general, the principal coating system within the interior immersion area was noted to be in good condition. Surfaces of the Torus shell plates exhibited spot corrosion and mechanical damage. With the exception of four indications identified in Bay 16, metal loss from exposed substrate indications generally ranged from less than 37 mils to less than 70 mils. Intact coating adjacent to exposed substrate appeared tightly bonded.

Indication Exceeding Repair/Reportable Criteria A cumulative total of 6,421 exposed substrate indications were identified on the Torus shell plating throughout the immersion area meeting the requirements for coating repair. This accounted for an approximate total affected area of 1,240 square inches.

While metal loss at the greater percent (i.e., greater than 77 percent) of the exposed substrate locations fell below the reportable guidelines established by Plant Engineering (i.e., greater than 37 mils) a total of 1,428 indications did exceed the guidelines. Indications with metal loss exceeding the acceptance criteria were reported to Engineering on a day by day basis.

Additionally, it should be noted that during diving activities four bulge indications were identified in close proximity to Torus penetrations. After site review, the following scope of work was completed:

1. Dry Film Thickness (DFT) readings were taken in the affected areas

2. UT grids at 1-inch square locations were penciled on the four affected areas

3. Diver support was provided for the UT examinations Downcomers (Exterior Only)

Downcomer examinations were deferred in order to address inspection/repair of the large quantity of coating deficiencies/exposed substrate indications identified during examination of the Torus shell plates.

Quencher Support Flange Hardware The inspections on the quencher support flange hardware were conducted to verify the presence of the connecting flange hardware. High resolution video was used to document these inspections. In general, all quencher support flange hardware was present and appeared in good condition. No further data or documentation will be provided nor was any such documentation or data collecting established as part of this work scope.

ECCS Inspections As-left vide inspections were conducted on the ECCS Suction Strainers. These inspections were conducted to identify any foreign and/or fibrous material on the strainers themselves. High

RA-18-0149 Enclosure Page 72 of 90 resolution video was used to document these inspections. In general, no notable foreign material was identified on the inspected strainers.

Bay 7/8 Supports Video inspections were performed on the Bay 7 and Bay 8 component supports. High resolution video was used to document these inspections.

Coating Repair Coating repair was performed on all exposed substrate locations identified during the qualitative inspections. Surface preparation for each repair was performed in accordance with site procedures using pneumatic grinders equipped with a 3M wheel, Bio-Dur 561, an underwater applied two-part epoxy, was then applied immediately following the surface preparation.

A total of 6,421 indications were repaired on the Unit 2 Torus shell plates. The total surface area of these repair locations was 24,469 square inches (i.e.,170 square feet).

A certified Level II coating inspector performed a visual inspection on all repairs for final acceptance. All final repairs appeared fully cured and tightly bonded to the substrate and the surrounding coating with no evidence of bleed-through, cracking, peeling or other unfavorable effects. Dry film thickness readings were taken on a representative sample (i.e., less than 25 percent) of the repairs, and all final repairs were found to be within acceptable range (i.e., 10 to 40 mils). The average dry film thickness for these repairs was 26.3 mils.

Sludge and Debris Sludge accumulation in the Torus was considered light. Within a given Bay, the heaviest deposits were typically recorded near the invert weld seams of the Torus shell. Sludge depths averaged a nominal 1/8-inch to 1/4-inch with isolated areas up to 1-inch deep. This light accumulation along with the loose adhesion of the sludge material to the coating system resulted in the small percentage of the Unit 2 2017refueling outage dive time (i.e., less than 22 percent) spent in support of the desludge effort. As a direct result of the limited time required to support the desludge effort, nearly all of the ISI examinations were completed. While all of the bulk sludge was removed from the wetted surfaces of the Torus shell plates no sludge was removed from the downcomers and ECCS suction strainers.

Coating and Corrosion Conditions The condition of the inspection immersion area principal coating system on the shell plates were in good condition, with greater percentage of the inspected coated surface exhibiting little to no coating damage or degradation. Although numerous random small localized failures have occurred, the majority of the coating was providing excellent protection of the base metal. In concurrence, the results of the Unit 2 2017 refueling outage inspection strongly supported the conclusion that the corrosion rates remained low.

ECCS Strainer Conditions Foreign material only inspections were performed on all ECCS Suction strainers. No foreign material was noted. The strainers appeared to be in good condition with a moderate sludge film on the strainer mesh.

RA-18-0149 Enclosure Page 73 of 90 Unit 2 2017 Refueling Outage Primary Containment Inspection The purpose of the Primary Containment Inspection is to perform examinations to assess the general condition of the containment liner and concrete surfaces of the primary containment and to detect evidence of degradation that may affect structural integrity or leak tightness. During the 2017 Refueling Outage Primary Containment Inspection, the following nonconformances were identified.

Item Group: 2-DW-ML-4 Recordable Condition: While performing the general visual examination on the containment liner an area of material distress (i.e., depression/displacement) was noted at approximately 265 degrees azimuth at the 42'-foot elevation.

Disposition: Since the distressed area is localized and the remaining wall thickness exceeds the calculated minimum localized liner wall thickness this condition was determined to be acceptable by evaluation and no repairs were required.

3.7.7 BSEP Containment Modifications - Hardened Containment Venting System (HCVS)

Modification On March 19, 2013, the NRC Commissioners directed the staff per Staff Requirements Memorandum (SRM) for SECY-12-0157 (i.e., Reference 36) to require licensees with Mark I and Mark II containments to "upgrade or replace the reliable hardened vents required by Order EA-12-050 (i.e., Reference 37) with a containment venting system designed and installed to remain functional during severe accident conditions." In response, the NRC issued Order EA-13-109, Issuance of Order to Modifying Licenses with Regard to Reliable Hardened Containment Vents Capable of Operation Under Severe Accident Conditions (i.e., Reference

38) on June 6, 2013. The Order required that licensees of BWR facilities with Mark I and Mark II containment designs ensure that these facilities have a reliable hardened vent to remove decay heat from the containment and maintain control of containment pressure within acceptable limits following events that result in the loss of active containment heat removal capability while maintaining the capability to operate under severe accident (SA) conditions resulting from an Extended Loss of AC Power (ELAP).

The Order requirements are applied in a phased approach where:

Phase 1 involved upgrading the venting capabilities from the containment wetwell to provide reliable, severe accident capable hardened vents to assist in preventing core damage and if necessary to provide venting capability during severe accident conditions. (Completed no later than startup from the second refueling outage that begins after June 30, 2014 or June 30, 2018, whichever comes first.)

Phase 2 involves providing additional protections for severe accident conditions through installation of a reliable, severe accident capable drywell vent system or the development of a reliable containment venting strategy that makes it unlikely that a licensee would need to vent from the containment drywell during severe accident

RA-18-0149 Enclosure Page 74 of 90 conditions. (Completed no later than startup from the first refueling outage that begins after June 30, 2017, or June 30, 2019, whichever comes first.)

No containment or containment isolation system modifications were required at BSEP to comply with the NRC Orders. The HCVS utilizes CAC system valves CAC-V7 and CAC-V216 for containment isolation. CAC-V7 and CAC-V216 are air operated valves (AOVs) that are air-to-open and spring-to-close. A solenoid operated valve (SOV) must be energized to allow the motive air to open the valve from the main control room location. CAC-V7 and CAC-V216 have a safety-related function to maintain the containment pressure boundary during a DBA and are tested as required by 10 CFR 50, Appendix J. Although these valves are shared between the CAC and HCVS, separate control circuits are provided to each valve. Specifically, the CAC control circuit will be used during all design basis operating modes including all design basis transients and accidents.

Cross flow potential exists between the HVCS and the Standby Gas Treatment System (SBGT).

CAC valves CAC-V8 and CAC-V172 function as boundary valves within the SBGT system.

Valves CAC-V8 and CAC-V172 are CIVs with a safety-related function to maintain the containment pressure boundary during a DBA. These valves are tested and will continue to be tested for leakage under 10 CFR 50, Appendix J as part of the containment boundary. These valves therefore prevent cross-flow from the Severe Accident Wetwell Vent (SAWV) pipe to the SBGT system.

3.8 License Renewal Aging Management By letter dated October 18, 2004, Carolina Power & Light Company (CP&L) requested renewal of the operating licenses issued in Section 104b (i.e., Operating License Nos. DPR-71 and DPR-62) of the Atomic Energy Act of 1954, as amended, for BSEP Units 1 and 2 for a period of 20 years (i.e., Reference 39). The NRC issued the Renewed Operating Licenses on June 26, 2006 (i.e., Reference 52). The Renewed Operating License expiration dates are midnight on September 8, 2036, for Unit 1 and midnight on December 27, 2034, for Unit 2. The following Aging Management Programs are applicable to this LAR.

3.8.1 Aging Management Programs Appendix J Program The 10 CFR Part 50, Appendix J Program consists of monitoring of leakage rates through containment liner/welds, penetrations, fittings and access openings to detect degradation of the pressure boundary. Corrective actions are taken if leakage rates exceed acceptance criteria.

This Program is implemented in accordance with Option B (i.e., performance-based leak testing) of 10 CFR Part 50, Appendix J; RG 1.163; and NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J." This Program is consistent with the corresponding program described in NUREG-1801 (i.e., Reference 51).

ASME Section XI, Subsection IWE Program The ASME Section XI, Subsection IWE Program consists of periodic inspection of steel containment components for signs of degradation, assessment of damage, and corrective actions. This Program is in accordance with ASME Section XI, Subsection IWE, and in accordance with 10 CFR 50.55a. The ASME Section XI, Subsection IWE Program is consistent with the corresponding program described in NUREG-1801.

RA-18-0149 Enclosure Page 75 of 90 ASME Section XI, Subsection IWL Program The ASME Section XI, Subsection IWL Program is credited for the aging management of accessible and inaccessible pressure retaining Primary Containment concrete for both BSEP units. The BSEP containment structures do not use prestressing tendons. Therefore, ASME Section XI, Subsection IWL rules regarding post-tensioning systems are not applicable. This Program is in accordance with the ASME Section XI, Subsection IWL and in accordance with 10 CFR 50.55a. The ASME Section XI, Subsection IWL Program is consistent with the corresponding program described in NUREG-1801 with the exception that requirements associated with a post-tensioning system are not applicable.

Protective Coating Monitoring and Maintenance Program The Protective Coating Monitoring and Maintenance Program prevents clogging of the ECCS suction strainers and containment spray nozzles by monitoring the condition of coatings and assuring that the quantity of damaged, degraded, or unqualified coatings inside the Primary Containment of each unit which could detach during a LOCA remains below established design limits.

The Program administrative controls have been enhanced to: (1) add a requirement for a walk-through, general inspection of containment areas during each refueling outage, including all accessible pressure-boundary coatings not inspected under the ASME Section XI, Subsection IWE Program, (2) add a requirement for a detailed, focused inspection of areas noted as deficient during the general inspection, (3) assure that the qualification requirements for persons evaluating coatings are consistent among the Service Level I coating specifications, inspection procedures, and application procedures, and meet the requirements of ANSI N 101.4, "Quality Assurance for Protective Coatings Applied to Nuclear Facilities," and (4) document the results of inspections and compare the results to previous inspection results and to acceptance criteria. The Program is consistent with the corresponding program described in NUREG-1801 with the exception that the Program is not credited for preventing corrosion of primary containment components.

3.9 NRC SER Limitations and Conditions 3.9.1 Limitations and Conditions Applicable to NEI 94-01, Revision 2-A The NRC staff found that the use of NEI TR 94-01, Revision 2, was acceptable for referencing by licensees proposing to amend their TS to permanently extend the ILRT surveillance interval to 15 years, provided the following conditions as listed in Table 3.9.1-1 were satisfied:

RA-18-0149 Enclosure Page 76 of 90 Table 3.9.1-1: NEI 94-01, Revision 2-A, Limitations and Conditions Limitation/Condition (From Section 4.0 of SE)

BSEP Response For calculating the Type A leakage rate, the licensee should use the definition in the NEI TR 94-01, Revision 2, in lieu of that in ANSI/ANS-56.8-2002. (Refer to SE Section 3.1.1.1.)

BSEP will utilize the definition in NEI 94-01 Revision 3-A, Section 5.0. This definition has remained unchanged from Revision 2-A to Revision 3-A of NEI 94-01.

The licensee submits a schedule of containment inspections to be performed prior to and between Type A tests. (Refer to SE Section 3.1.1.3.)

Reference Sections 3.6.3 and 3.6.4 of this submittal.

The licensee addresses the areas of the containment structure potentially subjected to degradation. (Refer to SE Section 3.1.3.)

Reference Section 3.6.3 of this submittal.

The licensee addresses any tests and inspections performed following major modifications to the containment structure, as applicable. (Refer to SE Section 3.1.4.)

There are no major modifications planned.

No containment or containment isolation system modifications were required at BSEP to comply with the NRC Orders for FLEX.

The normal Type A test interval should be less than 15 years. If a licensee has to utilize the provision of Section 9.1 of NEI TR 94-01, Revision 2, related to extending the ILRT interval beyond 15 years, the licensee must demonstrate to the NRC staff that it is an unforeseen emergent condition. (Refer to SE Section 3.1.1.2.)

BSEP will follow the requirements of NEI 94-01 Revision 3-A, Section 9.1. This requirement has remained unchanged from Revision 2-A to Revision 3-A of NEI 94-01.

In accordance with the requirements of NEI 94-01 Revision 2-A, SER Section 3.1.1.2, BSEP will also demonstrate to the NRC staff that an unforeseen emergent condition exists in the event an extension beyond the 15-year interval is required.

RA-18-0149 Enclosure Page 77 of 90 Table 3.9.1-1: NEI 94-01, Revision 2-A, Limitations and Conditions Limitation/Condition (From Section 4.0 of SE)

BSEP Response For plants licensed under 10 CFR 52, applications requesting a permanent extension of the ILRT surveillance interval to 15 years should be deferred until after the construction and testing of containments for that design have been completed and applicants have confirmed the applicability of NEI 94-01, Revision 2, and EPRI Report No.

1009325, Revision 2, including the use of past containment ILRT data.

Not applicable. BSEP was not licensed under 10 CFR 52.

3.9.2 Limitations and Conditions Applicable to NEI 94-01, Revision 3-A The NRC staff found that the guidance in NEI TR 94-01, Revision 3, was acceptable for referencing by licensees in the implementation for the optional performance-based requirements of Option B to 10 CFR 50, Appendix J. However, the NRC staff identified two conditions on the use of NEI TR 94-01, Revision 3 (i.e., Reference NEI 94-01 Revision 3-A, NRC SER 4.0, Limitations and Conditions):

Topical Report Condition 1 NEI TR 94-01, Revision 3, is requesting that the allowable extended interval for Type C LLRTs be increased to 75 months, with a permissible extension (i.e., for non-routine emergent conditions) of nine months (i.e., 84 months total). The staff is allowing the extended interval for Type C LLRTs be increased to 75 months with the requirement that a licensee's post-outage report include the margin between the Type B and Type C leakage rate summation and its regulatory limit. In addition, a corrective action plan shall be developed to restore the margin to an acceptable level. The staff is also allowing the non-routine emergent extension out to 84 months as applied to Type C valves at a site, with some exceptions that must be detailed in NEI 94-01, Revision 3. At no time shall an extension be allowed for Type C valves that are restricted categorically (e.g., BWR MSIVs), and those valves with a history of leakage, or any valves held to either a less than maximum interval or to the base refueling cycle interval. Only non-routine emergent conditions allow an extension to 84 months.

Response to Condition 1 Condition 1 presents three separate issues that are required to be addressed. They are as follows:

ISSUE 1 - The allowance of an extended interval for Type C LLRTs of 75 months carries the requirement that a licensee's post-outage report include the margin between the Type B and Type C leakage rate summation and its regulatory limit.

RA-18-0149 Enclosure Page 78 of 90

ISSUE 2 - In addition, a corrective action plan shall be developed to restore the margin to an acceptable level.

ISSUE 3 - Use of the allowed 9-month extension for eligible Type C valves is only authorized for non-routine emergent conditions with exceptions as detailed in NEI 94-01, Revision 3-A, Section 10.1.

Response to Condition 1, ISSUE 1 The post-outage report shall include the margin between the Type B and Type C Minimum Pathway Leak Rate (MNPLR) summation value, as adjusted to include the estimate of applicable Type C leakage understatement, and its regulatory limit of 0.60 La.

Response to Condition 1, ISSUE 2 When the potential leakage understatement adjusted Type B and C MNPLR total is greater than the BSEP administrative leakage summation limit of 0.50 La, but less than the regulatory limit of 0.6 La, then an analysis and determination of a corrective action plan shall be prepared to restore the leakage summation margin to less than the BSEP leakage limit. The corrective action plan shall focus on those components which have contributed the most to the increase in the leakage summation value and the manner of timely corrective action, as deemed appropriate, that best focuses on the prevention of future component leakage performance issues so as to maintain an acceptable level of margin.

Response to Condition 1, ISSUE 3 BSEP will apply the 9-month allowable interval extension period only to eligible Type C components for non-routine emergent conditions. Such occurrences will be documented in the record of tests.

Topical Report Condition 2 The basis for acceptability of extending the ILRT interval out to once per 15 years was the enhanced and robust primary containment inspection program and the local leakage rate testing of penetrations. Most of the primary containment leakage experienced has been attributed to penetration leakage and penetrations are thought to be the most likely location of most containment leakage at any time. The containment leakage condition monitoring regime involves a portion of the penetrations being tested each refueling outage, nearly all LLRTs being performed during plant outages. For the purposes of assessing and monitoring or trending overall containment leakage potential, the as-found minimum pathway leakage rates for the just tested penetrations are summed with the as-left minimum pathway leakage rates for penetrations tested during the previous 1 or 2 or even 3 refueling outages. Type C tests involve valves, which in the aggregate, will show increasing leakage potential due to normal wear and tear, some predictable and some not so predictable. Routine and appropriate maintenance may extend this increasing leakage potential. Allowing for longer intervals between LLRTs means that more leakage rate test results from farther back in time are summed with fewer just tested penetrations and that total used to assess the current containment leakage potential. This leads to the possibility that the LLRT totals calculated understate the actual leakage potential of the penetrations. Given the required margin included with the performance criterion and the considerable extra margin most plants consistently show with their testing, any understatement of the LLRT total using a 5-year test frequency is thought to be conservatively accounted for.

RA-18-0149 Enclosure Page 79 of 90 Extending the LLRT intervals beyond 5 years to a 75-month interval should be similarly conservative provided an estimate is made of the potential understatement and its acceptability determined as part of the trending specified in NEI TR 94-01, Revision 3, Section 12.1.

When routinely scheduling any LLRT valve interval beyond 60 months and up to 75 months, the primary containment leakage rate testing program trending or monitoring must include an estimate of the amount of understatement in the Type B and C total leakage, and must be included in a licensee's post-outage report. The report must include the reasoning and determination of the acceptability of the extension, demonstrating that the LLRT totals calculated represent the actual leakage potential of the penetrations.

Response to Condition 2 Condition 2 presents two (2) separate issues that are required to be addressed as follows:

ISSUE 1 - Extending the LLRT intervals beyond 5 years to a 75-month interval should be similarly conservative provided an estimate is made of the potential understatement and its acceptability determined as part of the trending specified in NEI TR 94-01, Revision 3, Section 12.1.

ISSUE 2 - When routinely scheduling any LLRT valve interval beyond 60 months and up to 75 months, the primary containment leakage rate testing program trending or monitoring must include an estimate of the amount of understatement in the Type B and C total, and must be included in a licensee's post-outage report. The report must include the reasoning and determination of the acceptability of the extension, demonstrating that the LLRT totals calculated represent the actual leakage potential of the penetrations.

Response to Condition 2, ISSUE 1 The change in going from a 60-month extended test interval for Type C tested components to a 75-month interval, as authorized under NEI 94-01, Revision 3-A, represents an increase of 25%

in the LLRT periodicity. As such, BSEP will conservatively apply a potential leakage understatement adjustment factor of 1.25 to the actual As-Left leak rate, which will increase the As-Left leakage total for each Type C component currently on greater than a 60-month test interval up to the 75-month extended test interval. This will result in a combined conservative Type C total for all 75-month LLRTs being carried forward and will be included whenever the total leakage summation is required to be updated (i.e., either while on line or following an outage).

When the potential leakage understatement adjusted leak rate total for those Type C components being tested on greater than a 60-month test interval up to the 75-month extended test interval is summed with the non-adjusted total of those Type C components being tested at less than or equal to a 60-month test interval, and the total of the Type B tested components, if the MNPLR is greater than the BSEP administrative leakage summation limit of 0.50 La, but less than the regulatory limit of 0.6 La, then an analysis and corrective action plan shall be prepared to restore the leakage summation value to less than the BSEP leakage limit. The corrective action plan shall focus on those components which have contributed the most to the increase in the leakage summation value and the manner of timely corrective action, as deemed appropriate, that best focuses on the prevention of future component leakage performance issues.

RA-18-0149 Enclosure Page 80 of 90 Response to Condition 2, ISSUE 2 If the potential leakage understatement adjusted leak rate MNPLR is less than the BSEP administrative leakage summation limit of 0.50 La, then the acceptability of the greater than a 60-month test interval up to the 75-month LLRT extension for all affected Type C components has been adequately demonstrated and the calculated local leak rate total represents the actual leakage potential of the penetrations.

In addition to Condition 1, ISSUES 1 and 2, which deal with the MNPLR Type B and C summation margin, NEI 94-01, Revision 3-A, also has a margin related requirement as contained in Section 12.1, "Report Requirements."

A post-outage report shall be prepared presenting results of the previous cycles Type B and Type C tests, and Type A, Type B and Type C tests, if performed during that outage. The technical contents of the report are generally described in ANSI/ANS-56.8-2002 and shall be available on-site for NRC review. The report shall show that the applicable performance criteria are met, and serve as a record that continuing performance is acceptable. The report shall also include the combined Type B and Type C leakage summation, and the margin between the Type B and Type C leakage rate summation and its regulatory limit. Adverse trends in the Type B and Type C leakage rate summation shall be identified in the report and a corrective action plan developed to restore the margin to an acceptable level.

At BSEP, in the event an adverse trend in the aforementioned potential leakage understatement adjusted Type B and C summation is identified, then an analysis and determination of a corrective action plan shall be prepared to restore the trend and associated margin to an acceptable level. The corrective action plan shall focus on those components which have contributed the most to the adverse trend in the leakage summation value and the manner of timely corrective action, as deemed appropriate, that best focuses on the prevention of future component leakage performance issues.

At BSEP an adverse trend is defined as three (3) consecutive increases in the final pre-mode change Type B and C MNPLR leakage summation values, as adjusted to include the estimate of applicable Type C leakage understatement, as expressed in terms of La.

3.10 Conclusion 3.10.1 Adoption of NEI 94-01 Revision 3-A NEI 94-01, Revision 3-A, dated July 2012, and the conditions and limitations specified in NEI 94-01, Revision 2-A, dated October 2008, describe an NRC-accepted approach for implementing the performance-based requirements of 10 CFR 50, Appendix J, Option B. It incorporated the regulatory positions stated in RG 1.163 and includes provisions for extending Type A intervals to 15 years and Type C test intervals to 75 months. NEI 94-01, Revision 3-A delineates a performance-based approach for determining Type A, Type B, and Type C containment leakage rate surveillance test frequencies. BSEP is adopting the guidance of NEI 94-01, Revision 3-A, and the conditions and limitations specified in NEI 94-01, Revision 2-A, for the BSEP 10 CFR 50, Appendix J testing program plan.

Based on the previous ILRTs conducted at BSEP, it may be concluded that the permanent extension of the containment ILRT interval from 10 to 15 years represents minimal risk to increased leakage. The risk is minimized by continued Type B and Type C testing performed in

RA-18-0149 Enclosure Page 81 of 90 accordance with Option B of 10 CFR 50, Appendix J and the overlapping inspection activities performed as part of the following BSEP inspection programs:

ASME Section XI, IWE Examinations ASME Section XI, IWL Examinations Containment Maintenance Rule Inspections Primary Containment Coatings Program This experience is supplemented by risk analysis studies, including the BSEP risk analysis provided in Attachment 6 of this submittal. The risk assessment concludes that increasing the ILRT interval on a permanent basis to a one-in-fifteen-year frequency is not considered to be significant since it represents only a very small change in the BSEP risk profile.

4.0 REGULATORY EVALUATION

4.1 Applicable Regulatory Requirements/Criteria The proposed change has been evaluated to determine whether applicable regulations and requirements continue to be met. 10 CFR 50.54(o) requires primary reactor containments for water-cooled power reactors to be subject to the requirements of Appendix J to 10 CFR 50, "Leakage Rate Testing of Containment of Water Cooled Nuclear Power Plants." Appendix J specifies containment leakage testing requirements, including the types required to ensure the leak-tight integrity of the primary reactor containment and systems and components which penetrate the containment. In addition, Appendix J discusses leakage rate acceptance criteria, test methodology, frequency of testing and reporting requirements for each type of test.

The adoption of the Option B performance-based containment leakage rate testing for Type A, Type B and Type C testing did not alter the basic method by which Appendix J leakage rate testing is performed; however, it did alter the frequency at which Type A, Type B, and Type C containment leakage tests must be performed. Under the performance-based option of 10 CFR 50, Appendix J, the test frequency is based upon an evaluation that reviewed as-found leakage history to determine the frequency for leakage testing which provides assurance that leakage limits will be maintained. The change to the Type A test frequency did not directly result in an increase in containment leakage. Similarly, the proposed change to the Type C test frequencies will not directly result in an increase in containment leakage.

EPRI TR-1009325, Revision 2A (i.e., Reference 8), provided a risk impact assessment for optimized ILRT intervals up to 15 years, utilizing current industry performance data and risk informed guidance. NEI 94-01, Revision 3-A, Section 9.2.3.1 states that Type A ILRT intervals of up to 15 years are allowed by this guideline. The Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals, EPRI Report 1018243 (i.e., formerly TR-1009325, Revision 2A) indicates that, in general, the risk impact associated with ILRT interval extensions for intervals up to 15 years is small. However, plant-specific confirmatory analyses are required.

The NRC staff reviewed NEI TR 94-01, Revision 2, and EPRI Report No. 1009325, Revision 2A.

For NEI TR 94-01, Revision 2, the NRC staff determined that it described an acceptable approach for implementing the optional performance-based requirements of Option B to 10 CFR 50, Appendix J. This guidance includes provisions for extending Type A ILRT intervals

RA-18-0149 Enclosure Page 82 of 90 up to 15 years and incorporates the regulatory positions stated in RG 1.163 (i.e., Reference 1).

The NRC staff finds that the Type A testing methodology as described in ANSI/ANS-56.8-2002 (i.e., Reference 14), and the modified testing frequencies recommended by NEI TR 94-01, Revision 2, serve to ensure continued leakage integrity of the containment structure. Type B and Type C testing ensures that individual penetrations are essentially leak tight. In addition, aggregate Type B and Type C leakage rates support the leakage tightness of primary containment by minimizing potential leakage paths.

For EPRI Report No. 1009325, Revision 2A (i.e., Reference 8), a risk-informed methodology using plant-specific risk insights and industry ILRT performance data to revise ILRT surveillance frequencies, the NRC staff finds that the proposed methodology satisfies the key principles of risk-informed decision-making applied to changes to TS as delineated in RG 1.177, An Approach to Plant-Specific, Risk-Informed Decisionmaking: Technical Specifications (i.e., Reference 40) and RG 1.174 (i.e., Reference 7). The NRC staff, therefore, found that this guidance was acceptable for referencing by licensees proposing to amend their TS in regards to containment leakage rate testing, subject to the limitations and conditions noted in Section 4.2 of the SER.

The NRC staff reviewed NEI TR 94-01, Revision 3, and determined that it described an acceptable approach for implementing the optional performance-based requirements of Option B to 10 CFR 50, Appendix J, as modified by the conditions and limitations summarized in Section 4.0 of the associated SE. This guidance included provisions for extending Type C LLRT intervals up to 75 months. Type C testing ensures that individual CIVs are essentially leak tight. In addition, aggregate Type C leakage rates support the leakage tightness of primary containment by minimizing potential leakage paths. The NRC staff, therefore, found that this guidance, as modified to include two limitations and conditions, was acceptable for referencing by licensees proposing to amend their TS in regards to containment leakage rate testing. Any applicant may reference NEI TR 94-01, Revision 3, as modified by the associated SER and approved by the NRC, and the conditions and limitations specified in NEI 94-01, Revision 2-A, dated October 2008, in a licensing action to satisfy the requirements of Option B to 10 CFR 50, Appendix J.

4.2 Precedent This LAR is similar in nature to the following license amendments for extending the Type A test frequency to 15 years and the Type C test frequency to 75 months as previously authorized by the NRC:

Surry Power Station, Unit 1 (i.e., Reference 41)

Donald C. Cook Nuclear Plant, Unit 1 (i.e., Reference 42)

Beaver Valley Power Station, Unit Nos. 1 and 2 (i.e., Reference 43)

Calvert Cliffs Nuclear Power Plant, Unit Nos. 1 and 2 (i.e., Reference 44)

Peach Bottom Atomic Power Station, Units 2 and 3 (i.e., Reference 45)

Comanche Peak Nuclear Power Plant, Units 1 and 2 (i.e., Reference 46)

Catawba Nuclear Station, Units 1 and 2 (i.e., Reference 47)

RA-18-0149 Enclosure Page 83 of 90 H. B. Robinson Steam Electric Plant, Unit No. 2 (i.e., Reference 48)

Quad Cities Nuclear Power Station, Units 1 and 2 (i.e., Reference 49)

Dresden Nuclear Power Station, Units 2 and 3 (i.e., Reference 50) 4.3 No Significant Hazards Consideration Duke Energy Progress, LLC (Duke Energy) proposes to amend the Technical Specifications (TS) for Brunswick Steam Electric Plant (BSEP), Units 1 and 2 to allow extension of the Type A and Type C test intervals. The extension is based on the adoption of the Nuclear Energy Institute (NEI) 94-01, Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J, Revision 3-A and conditions set forth in Revision 2-A. Duke Energy has evaluated whether or not a significant hazards consideration is involved with the proposed amendment by focusing on the three standards set forth in 10 CFR 50.92, "Issuance of amendment," as discussed below:

1.

Does the proposed amendment involve a significant increase in the probability or consequences of an accident previously evaluated?

Response: No.

The proposed activity involves the revision of the Brunswick Steam Electric Plant (BSEP)

Units 1 and 2 Technical Specification (TS) 5.5.12, Primary Containment Leakage Rate Testing Program, to allow the extension of the Type A integrated leakage rate test (ILRT) containment test interval to 15 years, and the extension of the Type C test interval to 75 months. Per the guidance provided in Nuclear Energy Institute (NEI) 94-01, Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J, Revision 3-A, the current Type A test interval of 120 months (i.e., 10 years) would be extended on a permanent basis to no longer than 15 years from the last Type A test. The current Type C test interval of 60 months for selected components would be extended on a performance basis to no longer than 75 months. Extensions of up to nine months for Types A, B and C tests are permissible only for non-routine emergent conditions.

The proposed interval extensions do not involve either a physical change to the plant or a change in the manner in which the plant is operated or controlled. The containment is designed to provide an essentially leak tight barrier against the uncontrolled release of radioactivity to the environment for postulated accidents. As such, the containment and the testing requirements invoked to periodically demonstrate the integrity of the containment exist to ensure the plant's ability to mitigate the consequences of an accident, and do not involve the prevention or identification of any precursors of an accident.

The change in Type A test frequency to once-per-fifteen-years, measured as an increase to the total integrated plant risk for those accident sequences influenced by Type A testing, based on the probabilistic risk assessment (PRA) is 4.98E-03 person-rem/year. for Unit 1 and 4.67E-03 person-rem/year. for Unit 2. Electric Power Research Institute (EPRI) Report No. 1009325, Revision 2-A states that a very small population dose is defined as an increase of less than 1.0 person-rem per year or less than 1 percent of the total population dose, whichever is less restrictive for the risk impact assessment of the extended ILRT intervals. This is consistent with the Nuclear Regulatory Commission (NRC) Final Safety Evaluation for NEI 94-01 and EPRI Report No. 1009325, Revision 2A. Moreover, the risk

RA-18-0149 Enclosure Page 84 of 90 impact when compared to other severe accident risks is negligible. Therefore, the proposed extension does not involve a significant increase in the probability of an accident previously evaluated.

In addition, as documented in NUREG-1493, "Performance-Based Containment Leak-Test Program," dated September 1995, Types B and C tests have identified a very large percentage of containment leakage paths, and the percentage of containment leakage paths that are detected only by Type A testing is very small. The BSEP Unit 1 and Unit 2 Type A test history supports this conclusion.

The integrity of the containment is subject to two types of failure mechanisms that can be categorized as: (1) activity based, and (2) time based. Activity based failure mechanisms are defined as degradation due to system and/or component modifications or maintenance.

Local leak rate test requirements and administrative controls such as configuration management and procedural requirements for system restoration ensure that containment integrity is not degraded by plant modifications or maintenance activities. The design and construction requirements of the containment combined with the containment inspections performed in accordance with American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel (B&PV) Code,Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, Containment Maintenance Rule Inspections, Containment Coatings Program and TS requirements serve to provide a high degree of assurance that the containment would not degrade in a manner that is detectable only by a Type A test (ILRT). Based on the above, the proposed test interval extensions do not significantly increase the consequences of an accident previously evaluated.

The proposed amendment also proposes administrative changes to the exceptions in Units 1 and 2 TS 5.5.12.c and f. TS exceptions 5.5.12.c reference NEI 94-01 Revision 0 and TS exceptions 5.5.12.f reference ANSI/ANS 56.8-1994. This change proposes to update the referenced documents in these two TS exceptions to reflect the adoption of NEI 94-01, Revision 3-A and ANSI/ANS 56.8-2002, accordingly. This administrative change does not impact any accidents previously evaluated.

Therefore, the proposed changes do not result in a significant increase in the probability or consequences of an accident previously evaluated.

2.

Does the proposed change create the possibility of a new or different kind of accident from any accident previously evaluated?

Response: No.

The proposed amendment to the BSEP Units 1 and 2 TS 5.5.12, "Primary Containment Leakage Rate Testing Program," involves the extension of the BSEP, Units 1 and 2 Type A containment test interval to 15 years and the extension of the Type C test interval to 75 months. The containment and the testing requirements to periodically demonstrate the integrity of the containment exist to ensure the plants ability to mitigate the consequences of an accident.

The proposed change does not involve a physical modification to the plant (i.e., no new or different type of equipment will be installed) nor does it alter the design, configuration, or change the manner in which the plant is operated or controlled beyond the standard functional capabilities of the equipment.

RA-18-0149 Enclosure Page 85 of 90 The proposed amendment also proposes administrative changes to the exceptions in Units 1 and 2 TS 5.5.12.c and f. TS exceptions 5.5.12.c reference NEI 94-01 Revision 0 and TS exceptions 5.5.12.f reference ANSI/ANS 56.8-1994. This change proposes to update the referenced documents in these two TS exceptions to reflect the adoption of NEI 94-01, Revision 3-A and ANSI/ANS 56.8-2002, accordingly. This administrative change to the references listed in TS 5.5.12.c and f, does not create the possibility of a new or different kind of accident from any accident previously evaluated.

Therefore, the proposed change does not create the possibility of a new or different kind of accident from any previously evaluated.

3.

Does the proposed change involve a significant reduction in a margin of safety?

Response: No.

The proposed amendment to Unit 1 and Unit 2 TS 5.5.12 involves the extension of the BSEP Type A containment test interval to 15 years and the extension of the Type C to 75 months. This amendment does not alter the manner in which safety limits, limiting safety system set points, or limiting conditions for operation are determined. The specific requirements and conditions of the TS Containment Leak Rate Testing Program exist to ensure that the degree of containment structural integrity and leak-tightness that is considered in the plant safety analysis is maintained. The overall containment leak rate limit specified by TS is maintained.

The proposed change involves the extension of the interval between Type A containment leak rate tests and Type C tests for BSEP, Units 1 and 2. The proposed surveillance interval extension is bounded by the 15-year ILRT interval and the 75-month Type C test interval currently authorized within NEI 94-01, Revision 3-A. Industry experience supports the conclusion that Type B and C testing detects a large percentage of containment leakage paths and that the percentage of containment leakage paths that are detected only by Type A testing is small. The containment inspections performed in accordance with Option B to 10 CFR 50, Appendix J and the overlapping inspection activities performed as part of ASME Section Xl, and the TS serve to provide a high degree of assurance that the containment would not degrade in a manner that is detectable only by Type A testing. The combination of these factors ensures that the margin of safety in the plant safety analysis is maintained. The design, operation, testing methods and acceptance criteria for Types A, B, and C containment leakage tests specified in applicable codes and standards would continue to be met, with the acceptance of this proposed change, since these are not affected by changes to the Type A and Type C test intervals.

The proposed amendment also proposes administrative changes to the exceptions in Units 1 and 2 TS 5.5.12. Two exceptions listed in the Units 1 and 2 TS 5.5.12 contain references to revisions and years of the ANSI/ANS 56.8 and NEI 94-01. Units 1 and 2 TS 5.5.12 exception c references NEI 94-01, Revision 0 and Units 1 and 2 TS 5.5.12 exception f references ANSI/ANS 56.8-1994. This change proposes to update the referenced documents in these two TS exceptions to reflect the adoption of NEI 94-01, Revision 3-A and ANSI/ANS 56.8-2002, accordingly. This administrative change does not change how the unit is operated or maintained, thus there is no reduction in any margins of safety.

RA-18-0149 Enclosure Page 86 of 90 Therefore, the proposed changes do not involve a significant reduction in a margin of safety.

Based on the above, Duke Energy concludes that the proposed amendment does not involve a significant hazards consideration under the standards set forth in 10 CFR 50.92(c), and, accordingly, a finding of no significant hazards consideration is justified.

4.4 Conclusion In conclusion, based on the considerations discussed above, (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) such activities will be conducted in compliance with the Commissions regulations, and (3) the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public.

5.0 ENVIRONMENTAL CONSIDERATION

A review has determined that the proposed amendment would change a requirement with respect to installation or use of a facility component located within the restricted area, as defined in 10 CFR 20, or would change an inspection or surveillance requirement. However, the proposed amendment does not involve (i) a significant hazards consideration, (ii) a significant change in the types or significant increase in the amounts of any effluent that may be released offsite, or (iii) a significant increase in individual or cumulative occupational radiation exposure.

Accordingly, the proposed amendment meets the eligibility criterion for categorical exclusion set forth in 10 CFR 51.22(c)(9). Therefore, pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the proposed amendment.

6.0 REFERENCES

1.

Regulatory Guide 1.163, "Performance-Based Containment Leak-Test Program,"

September 1995

2.

NEI 94-01, Revision 3-A, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J," July 2012

3.

NEI 94-01, Revision 2-A, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J," October 2008

4.

ANSI/ANS 56.8-2002, "Containment System Leakage Testing Requirements," LaGrange Park, Illinois, November 2002

5.

NEI 94-01, Revision 0, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J," July 1995

6.

ANSI/ANS 56.8-1994, "Containment System Leakage Testing Requirements," dated August 4, 1994

7.

Regulatory Guide 1.174, Revision 2, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis," May 2011

RA-18-0149 Enclosure Page 87 of 90

8.

Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals: Revision 2-A of 1009325. EPRI, Palo Alto, CA: October 2008, 1018243

9.

NUREG/CR-2973, "Loss of DHR Sequences at Browns Ferry Unit One - Accident Sequence Analysis," Oak Ridge National Laboratory, May 1983

10.

NUREG-1493, "Performance-Based Containment Leak-Test Program," January 1995

11.

EPRI TR-104285, "Risk Impact Assessment of Revised Containment Leak Rate Testing Intervals," August 1994

12.

Letter from M. J. Maxin (NRC) to J. C. Butler (NEI), "Final Safety Evaluation for Nuclear Energy Institute (NEI) Topical Report (TR) 94-01, Revision 2, 'Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J' and Electric Power Research Institute (EPRI) Report No. 1009325, Revision 2, August 2007, 'Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals' (TAC No. MC9663),"

dated June 25, 2008

13.

Letter from S. Bahadur (NRC) to B. Bradley (NEI), "Final Safety Evaluation of Nuclear Energy Institute (NEI) Report 94-01, Revision 3, Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J (TAC No. ME2164)," dated June 8, 2012

14.

Letter from D.C. Trimble (NRC) to Mr. W.R. Campbell (CP&L), "Issuance of Amendment No. 181 to Facility Operating License No. DPR-71 and Amendment No. 213 to Facility Operating License No. DPR-62 Regarding 10 CFR Part 50, Appendix J, Option B -

Brunswick Steam Electric Plant, Units 1 and 2 (BSEP 95-0316) (TAC Nos. M93679 and M93680)." dated February 1, 1996

15.

Letter from A.G. Hansen (NRC) to J.S. Keenan (CP&L), "Brunswick Steam Electric Plant, Unit 1 - Issuance of Amendment Regarding Containment Leakage Rate Testing Program (TAC No. MB3470)," dated March 6, 2002

16.

Letter from B.L. Mozafari (NRC) to J.S. Keenan (CP&L), "Brunswick Steam Electric Plant, Unit 2 - Issuance of Amendment Regarding Containment Leakage Rate Testing Program (TAC No. MB3471)," dated November 21, 2002

17.

Letter from B.L. Mozafari (NRC) to C.J. Gannon (CP&L), "Brunswick Steam Electric Plant, Unit Nos. 1 and 2 - Issuance of Exemption from 10 CFR Part 50, Appendix J (TAC Nos. MC4879 and MC4880)," dated March 9, 2005

18.

Letter from B.L. Mozafari (NRC) to J. Scarola (CP&L), "Brunswick Steam Electric Plant, Units 1 and 2 - Issuance of Amendment on Primary Containment Leakage Rate (TAC Nos. MC8110 and MC8111)," dated February 8, 2006

19.

Letter from B.L. Mozafari (NRC) to J. Scarola (CP&L), "Brunswick Steam Electric Plant, Unit Nos. 1 and 2 - Issuance of Amendment Regarding Main Steam Isolation Valve Leakage Limit (TAC Nos. MC8106 and MC8107), Dated March 2, 2006.)"

20.

Letter S.N. Bailey (NRC) to B. Waldrep (CP&L), "Brunswick Steam Electric Plant, Units 1 and 2 - Issuance of Amendment Regarding Primary Containment Leakage Rate Testing Program (TAC Nos. MD6340 and MD6341)"

RA-18-0149 Enclosure Page 88 of 90

21.

Letter from D.B. Vassallo (NRC) to E.E. Utley (CP&L), dated December 9, 1983

22.

Letter from E.G. Tourigny (NRC) to L.W. Eury (CP&L), "Issuance of Amendment No. 136 to Facility Operating License No. DPR-71 and Amendment No. 166 to Facility Operating License No. DPR Brunswick Steam Electric Plant, Units 1 and 2, Regarding Containment Integrated Leak Rate Testing (TAC Nos. 73030 and 73031)"

23.

Letter from E.D. Sylvester (NRC) to E.E. Utley (CP&L), Brunswick Steam Electric Plant, Units 1 and 2 "Technical Exemption from the Requirements of Appendix J," dated May 12, 1987

24.

Letter from A. Schwencer (NRC) to J.A. Jones (CP&L), dated November 23, 1977

25.

Letter from V. Stello, Jr. (NRC) to J.A. Jones (CP&L), dated November 8, 1977

26.

Letter from R.A. Anderson (CP&L) to United States Nuclear Regulatory Commission Document Control Desk, "Brunswick Steam Electric Plant, Units 1 and 2 Dockets Nos.

50-325 & 50-324 / License Nos DPR-71 & DPR-62 Request for License Amendment Type A Integrated Leakage Rate Testing Schedule," dated October 19,1993

27.

Letter from P.D. Milano (NRC) to R.A. Anderson (CP&L), "Issuance of Amendment No.

167 to Facility Operating License No. DPR-71 and Amendment No. 198 to Facility Operating License No. DPR-62 Regarding Containment Integrated Leak Rate Test -

Brunswick Steam Electric Plant, Units 1 and 2 (TAC Nos. M88044 and M88045)," dated January 11, 1994

28.

Interim Guidance for Performing Risk Impact Assessments in Support of One-Time Extensions for Containment Integrated Leakage Rate Test Surveillance Intervals, Revision 4, developed for NEI by EPRI and Data Systems and Solutions, October 2001

29.

Regulatory Guide 1.200, Revision 2, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities," March 2009

30.

Response to Request for Additional Information Concerning the License Amendment Request for a One-Time Integrated Leakage Rate Test Extension, Letter from Mr. C.H.

Cruse (Calvert Cliffs Nuclear Power Plant) to NRC Document Control Desk, Docket No.

50-317, dated March 27, 2002

31.

ASME/ANS RA-Sa-2009, Addenda to ASME/ANS RA-S-2008, "Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications"

32.

NEI 05-04, "Process for Performing Internal Events PRA Peer Review Process Guidelines," Revision 1

33.

NEI 07-12, "Fire Probabilistic Risk Assessment (FPRA) Peer Review Process Guidelines," Revision 1

34.

Calculation BNP-PSA-068, "BNP - PSA Model Peer Review F&O," Revision 7

RA-18-0149 Enclosure Page 89 of 90

35.

Regulatory Guide 1.174, Revision 3, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis," May 2018

36.

SECY-12-0157, Consideration of Additional Requirements for Containment Venting Systems for Boiling Water Reactors with Mark I and Mark II Containments, dated November 26, 2012 (ML12325A704).

37. NRC Order EA-12-050, Order Modifying Licenses with Regard to Reliable Hardened Containment Vents, dated March 12, 2012 (ML12054A694).

38. NRC Order EA-13-109, Order to Modify Licenses with Regard to Reliable Hardened Containment Vents Capable of Operation Under Severe Accident Conditions, dated June 6, 2013 (ML13143A321)

39. Letter from C. J. Gannon (Progress Energy) to United States Nuclear Regulatory Commission Document Control Desk, "Application for Renewal of Operating License,"

dated October 18, 2004

40. Regulatory Guide 1.177, Revision 1, An Approach for Plant-Specific, Risk-Informed Decision Making: Technical Specifications, May 2011

41. Letter to D. Heacock from S. Williams (NRC), Surry Power Station, Unit 1 - Issuance of Amendment Regarding the Containment Type A and Type C Leak Rate Tests, dated July 3, 2014 (ML14148A235)

42. Letter to L. Weber from A. Dietrich (NRC), Donald C. Cook Nuclear Plant, Unit 1 -

Issuance of Amendments Re: Containment Leakage Rate Testing Program, dated March 30, 2015 (ML15072A264)

43.

Letter to E. Larson from T. Lamb (NRC), Beaver Valley Power Station, Unit Nos. 1 and 2

- Issuance of Amendment Re: License Amendment Request to Extend Containment Leakage Rate Test Frequency, dated April 8, 2015 (ML15078A058)

44.

Letter to G. Gellrich from A. Chereskin (NRC), Calvert Cliffs Nuclear Power Plant, Unit Nos. 1 and 2 - Issuance of Amendments Re: Extension of Containment Leakage Rate Testing Frequency, dated July 16, 2015 (ML15154A661)

45.

Letter to B. Hanson from R. Ennis (NRC), Peach Bottom Atomic Power Station, Units 2 and 3 - Issuance of Amendments Re: Extension of Type A and Type C Leak Rate Test Frequencies (TAC Nos. MF5172 AND MF5173), dated September 8, 2015 (ML15196A559)

46.

Letter from B. Singal (NRC) to R. Flores (Luminant), Comanche Peak Nuclear Power Plant, Units 1 and 2 - Issuance of Amendments Re: Technical Specification Change for Extension of the Integrated Leak Rate Test Frequency From 10 to 15 Years (CAC Nos.

MF5621 and MF5622), dated December 30, 2015

47.

Letter from M.D. Orenak (NRC) to K. Henderson, "Catawba Nuclear Station, Units 1 and 2 - Issuance of Amendments Regarding Extension of the Containment Integrated Leak Rate Test Intervals (CAC Nos. MF7265 and MF7266)," dated September 12, 2016 (ML16299A113)

RA-18-0149 Enclosure Page 90 of 90

48.

Letter from D.J. Galvin (NRC) to R.M. Glover (Duke Energy), "H.B. Robinson Steam Electric Plant, Unit No. 2 - Issuance of Amendment to Extend Containment Leakage Rate Test Frequencies (CAC No. MF7102)," dated October 11, 2016

49.

Letter K.J. Green (NRC) to B.C. Hanson (Exelon Generation Company), "Quad Cities Nuclear Power Station, Units 1 and 2 - Issuance of Amendments Regarding Permanent Extension of Type A and Type C Leak Rate Test Frequencies (CAC Nos. MF9675 and MF9676; EPID L-2017-LLA-0220) (RS-17-051)," dated December 1, 2017 (ML17311A162)

50.

Letter from R.S. Haskell (NRC) to B.C. Hanson (Exelon Generation Company), "Dresden Nuclear Power Station, Units 2 and 3 - Issuance of Amendments Regarding Permanent Extension of Type A and Type C Leak Rate Test Frequencies (CAC Nos. MF9687 and MF9688; EPID L-2017-LLA-0228) (RS-17-060)," dated June 29, 2018 (ML18137A271)

51.

NUREG-1801, Generic Aging Lessons Learned (GALL Report)

52.

Letter from Maurice Heath (NRC) to James Scarola (CP&L), "Issuance of Renewed Facility Operating License Nos. DPR-71 and DPR-62 for Brunswick Steam Electric Plant, Units 1 and 2, dated June 26, 2006 (ML061660358)

53.

Letter from B.L. Mozafari (NRC) to Mr. J.S. Keenan (BSEP), Brunswick Steam Electric Plant Units 1 and 2 - Issuance of Amendment Re: Extended Power Uprate (TAC Nos.

MB2700 and MB2701), dated May 31, 2002 (ML021430551)

RA-18-0149 Enclosure Proposed Technical Specification Changes (Mark-Up) Unit 1

Programs and Manuals 5.5 Brunswick Unit 1 5.0-15 Amendment No. 278 5.5 Programs and Manuals 5.5.11 Safety Function Determination Program (SFDP) (continued)

c.

The SFDP identifies where a loss of safety function exists. If a loss of safety function is determined to exist by this program, the appropriate Conditions and Required Actions of the LCO in which the loss of safety function exists are required to be entered.

5.5.12 Primary Containment Leakage Rate Testing Program A primary containment leakage rate testing program shall establish requirements to implement the leakage rate testing of the primary containment as required by 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B as modified by approved exemptions. This program shall be in accordance with the guidelines contained in Regulatory Guide 1.163, September 1995 NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J,"

Revision 3-A, dated July 2012, and the Limitations and Conditions specified in NEI 94-01, Revision 2-A, dated October 2008, as modified by the following exceptions:

a.

The visual examination of concrete surfaces intended to fulfill the requirements of 10 CFR 50, Appendix J, Option B testing, will be performed in accordance with the requirements of and frequency specified by the ASME Section XI Code, Subsection IWL, except where relief has been authorized by the NRC.

b.

The visual examination of the metallic shell, penetrations, and appurtenances intended to fulfill the requirements of 10 CFR 50, Appendix J, Option B, will be performed in accordance with the requirements of and frequency specified by the ASME Section XI Code, Subsection IWE, except where relief has been authorized by the NRC.

c.

Following air lock door seal replacement, performance of door seal leakage rate testing with the gap between the door seals pressurized to 10 psig instead of air lock testing at Pa as specified in Nuclear Energy Institute Guideline 94-01, Revision 03-A;

d.

Reduced duration Type A tests may be performed using the criteria and Total Time method specified in Bechtel Topical Report BN-TOP-1, Revision 1.

e.

Performance of Type C leak rate testing of the hydrogen and oxygen monitor isolation valves is not required; and (continued)

Programs and Manuals 5.5 Brunswick Unit 1 5.0-16 Amendment No. 278 5.5 Programs and Manuals 5.5.12 Primary Containment Leakage Rate Testing Program (continued)

f.

Performance of Type C leak rate testing of the main steam isolation valves at a pressure less than Pa instead of leak rate testing at Pa as specified in ANSI/ANS 56.8-19942002.

The peak calculated primary containment internal pressure for the design basis loss of coolant accident, Pa, is 49 psig.

The maximum allowable primary containment leakage rate, La, shall be 0.5% of primary containment air weight per day at Pa.

Leakage rate acceptance criteria are:

a.

Primary containment leakage rate acceptance criterion is 1.0 La.

During the first unit startup following testing in accordance with this program, the leakage rate acceptance criteria are < 0.60 La for Type B and C tests and 0.75 La for Type A tests.

b.

Air lock testing acceptance criteria are:

1)

Overall air lock leakage rate is 0.05 La when tested at Pa.

2)

For each air lock door, leakage rate is 5 scfh when the gap between the door seals is pressurized to 10 psig.

The provisions of SR 3.0.3 are applicable to the Primary Containment Leakage Rate Testing Program frequencies.

5.5.13 Control Room Envelope Habitability Program A Control Room Envelope (CRE) Habitability Program shall be established and implemented to ensure that CRE habitability is maintained such that, with an OPERABLE Control Room Emergency Ventilation (CREV) System, CRE occupants can control the reactor safely under normal conditions and maintain it in a safe condition following a radiological event, hazardous chemical release, or a smoke challenge. The program shall ensure that adequate radiation protection is provided to permit occupancy of the CRE under design basis accident (DBA) conditions without personnel receiving radiation exposures in excess of 5 rem TEDE for the duration of the accident. The program shall include the following elements:

(continued)

RA-18-0149 Enclosure Proposed Technical Specification Changes (Mark-Up) Unit 2

Programs and Manuals 5.5 Brunswick Unit 2 5.0-15 Amendment No. 306 5.5 Programs and Manuals 5.5.11 Safety Function Determination Program (SFDP) (continued)

c.

The SFDP identifies where a loss of safety function exists. If a loss of safety function is determined to exist by this program, the appropriate Conditions and Required Actions of the LCO in which the loss of safety function exists are required to be entered.

5.5.12 Primary Containment Leakage Rate Testing Program A primary containment leakage rate testing program shall establish requirements to implement the leakage rate testing of the primary containment as required by 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B as modified by approved exemptions. This program shall be in accordance with the guidelines contained in Regulatory Guide 1.163, September 1995, NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J," Revision 3-A, dated July 2012, and the Limitations and Conditions specified in NEI 94-01, Revision 2-A, dated October 2008, as modified by the following exceptions:

a.

The visual examination of concrete surfaces intended to fulfill the requirements of 10 CFR 50, Appendix J, Option B testing, will be performed in accordance with the requirements of and frequency specified by the ASME Section XI Code, Subsection IWL, except where relief has been authorized by the NRC.

b.

The visual examination of the metallic shell, penetrations, and appurtenances intended to fulfill the requirements of 10 CFR 50, Appendix J, Option B, will be performed in accordance with the requirements of and frequency specified by the ASME Section XI Code, Subsection IWE, except where relief has been authorized by the NRC.

c.

Following air lock door seal replacement, performance of door seal leakage rate testing with the gap between the door seals pressurized to 10 psig instead of air lock testing at Pa as specified in Nuclear Energy Institute Guideline 94-01, Revision 03-A;

d.

Reduced duration Type A tests may be performed using the criteria and Total Time method specified in Bechtel Topical Report BN-TOP-1, Revision 1.

e.

Performance of Type C leak rate testing of the hydrogen and oxygen monitor isolation valves is not required; and (continued)

Programs and Manuals 5.5 Brunswick Unit 2 5.0-16 Amendment No. 306 5.5 Programs and Manuals 5.5.12 Primary Containment Leakage Rate Testing Program (continued)

f.

Performance of Type C leak rate testing of the main steam isolation valves at a pressure less than Pa instead of leak rate testing at Pa as specified in ANSI/ANS 56.8-19942002.

The peak calculated primary containment internal pressure for the design basis loss of coolant accident, Pa, is 49 psig.

The maximum allowable primary containment leakage rate, La, shall be 0.5% of primary containment air weight per day at Pa.

Leakage rate acceptance criteria are:

a.

Primary containment leakage rate acceptance criterion is 1.0 La.

During the first unit startup following testing in accordance with this program, the leakage rate acceptance criteria are < 0.60 La for Type B and C tests and 0.75 La for Type A tests.

b.

Air lock testing acceptance criteria are:

1)

Overall air lock leakage rate is 0.05 La when tested at Pa.

2)

For each air lock door, leakage rate is 5 scfh when the gap between the door seals is pressurized to 10 psig.

The provisions of SR 3.0.3 are applicable to the Primary Containment Leakage Rate Testing Program frequencies.

5.5.13 Control Room Envelope Habitability Program A Control Room Envelope (CRE) Habitability Program shall be established and implemented to ensure that CRE habitability is maintained such that, with an OPERABLE Control Room Emergency Ventilation (CREV) System, CRE occupants can control the reactor safely under normal conditions and maintain it in a safe condition following a radiological event, hazardous chemical release, or a smoke challenge. The program shall ensure that adequate radiation protection is provided to permit occupancy of the CRE under design basis accident (DBA) conditions without personnel receiving radiation exposures in excess of 5 rem TEDE for the duration of the accident. The program shall include the following elements:

(continued)

RA-18-0149 Enclosure Revised (Typed) Technical Specification Pages Unit 1

Programs and Manuals 5.5 Brunswick Unit 1 5.0-15 Amendment No. 278 5.5 Programs and Manuals 5.5.11 Safety Function Determination Program (SFDP) (continued)

c.

The SFDP identifies where a loss of safety function exists. If a loss of safety function is determined to exist by this program, the appropriate Conditions and Required Actions of the LCO in which the loss of safety function exists are required to be entered.

5.5.12 Primary Containment Leakage Rate Testing Program A primary containment leakage rate testing program shall establish requirements to implement the leakage rate testing of the primary containment as required by 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B as modified by approved exemptions. This program shall be in accordance with the guidelines contained in NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J," Revision 3-A, dated July 2012, and the Limitations and Conditions specified in NEI 94-01, Revision 2-A, dated October 2008, as modified by the following exceptions:

a.

The visual examination of concrete surfaces intended to fulfill the requirements of 10 CFR 50, Appendix J, Option B testing, will be performed in accordance with the requirements of and frequency specified by the ASME Section XI Code, Subsection IWL, except where relief has been authorized by the NRC.

b.

The visual examination of the metallic shell, penetrations, and appurtenances intended to fulfill the requirements of 10 CFR 50, Appendix J, Option B, will be performed in accordance with the requirements of and frequency specified by the ASME Section XI Code, Subsection IWE, except where relief has been authorized by the NRC.

c.

Following air lock door seal replacement, performance of door seal leakage rate testing with the gap between the door seals pressurized to 10 psig instead of air lock testing at Pa as specified in Nuclear Energy Institute Guideline 94-01, Revision 3-A;

d.

Reduced duration Type A tests may be performed using the criteria and Total Time method specified in Bechtel Topical Report BN-TOP-1, Revision 1.

e.

Performance of Type C leak rate testing of the hydrogen and oxygen monitor isolation valves is not required; and (continued)

Programs and Manuals 5.5 Brunswick Unit 1 5.0-16 Amendment No. 278 5.5 Programs and Manuals 5.5.12 Primary Containment Leakage Rate Testing Program (continued)

f.

Performance of Type C leak rate testing of the main steam isolation valves at a pressure less than Pa instead of leak rate testing at Pa as specified in ANSI/ANS 56.8-2002.

The peak calculated primary containment internal pressure for the design basis loss of coolant accident, Pa, is 49 psig.

The maximum allowable primary containment leakage rate, La, shall be 0.5% of primary containment air weight per day at Pa.

Leakage rate acceptance criteria are:

a.

Primary containment leakage rate acceptance criterion is 1.0 La.

During the first unit startup following testing in accordance with this program, the leakage rate acceptance criteria are < 0.60 La for Type B and C tests and 0.75 La for Type A tests.

b.

Air lock testing acceptance criteria are:

1)

Overall air lock leakage rate is 0.05 La when tested at Pa.

2)

For each air lock door, leakage rate is 5 scfh when the gap between the door seals is pressurized to 10 psig.

The provisions of SR 3.0.3 are applicable to the Primary Containment Leakage Rate Testing Program frequencies.

5.5.13 Control Room Envelope Habitability Program A Control Room Envelope (CRE) Habitability Program shall be established and implemented to ensure that CRE habitability is maintained such that, with an OPERABLE Control Room Emergency Ventilation (CREV) System, CRE occupants can control the reactor safely under normal conditions and maintain it in a safe condition following a radiological event, hazardous chemical release, or a smoke challenge. The program shall ensure that adequate radiation protection is provided to permit occupancy of the CRE under design basis accident (DBA) conditions without personnel receiving radiation exposures in excess of 5 rem TEDE for the duration of the accident. The program shall include the following elements:

(continued)

RA-18-0149 Enclosure Revised (Typed) Technical Specification Pages Unit 2

Programs and Manuals 5.5 Brunswick Unit 2 5.0-15 Amendment No. 306 5.5 Programs and Manuals 5.5.11 Safety Function Determination Program (SFDP) (continued)

c.

The SFDP identifies where a loss of safety function exists. If a loss of safety function is determined to exist by this program, the appropriate Conditions and Required Actions of the LCO in which the loss of safety function exists are required to be entered.

5.5.12 Primary Containment Leakage Rate Testing Program A primary containment leakage rate testing program shall establish requirements to implement the leakage rate testing of the primary containment as required by 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B as modified by approved exemptions. This program shall be in accordance with the guidelines contained in NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J," Revision 3-A, dated July 2012, and the Limitations and Conditions specified in NEI 94-01, Revision 2-A, dated October 2008, as modified by the following exceptions:

a.

The visual examination of concrete surfaces intended to fulfill the requirements of 10 CFR 50, Appendix J, Option B testing, will be performed in accordance with the requirements of and frequency specified by the ASME Section XI Code, Subsection IWL, except where relief has been authorized by the NRC.

b.

The visual examination of the metallic shell, penetrations, and appurtenances intended to fulfill the requirements of 10 CFR 50, Appendix J, Option B, will be performed in accordance with the requirements of and frequency specified by the ASME Section XI Code, Subsection IWE, except where relief has been authorized by the NRC.

c.

Following air lock door seal replacement, performance of door seal leakage rate testing with the gap between the door seals pressurized to 10 psig instead of air lock testing at Pa as specified in Nuclear Energy Institute Guideline 94-01, Revision 3-A;

d.

Reduced duration Type A tests may be performed using the criteria and Total Time method specified in Bechtel Topical Report BN-TOP-1, Revision 1.

e.

Performance of Type C leak rate testing of the hydrogen and oxygen monitor isolation valves is not required; and (continued)

Programs and Manuals 5.5 Brunswick Unit 2 5.0-16 Amendment No. 306 5.5 Programs and Manuals 5.5.12 Primary Containment Leakage Rate Testing Program (continued)

f.

Performance of Type C leak rate testing of the main steam isolation valves at a pressure less than Pa instead of leak rate testing at Pa as specified in ANSI/ANS 56.8-2002.

The peak calculated primary containment internal pressure for the design basis loss of coolant accident, Pa, is 49 psig.

The maximum allowable primary containment leakage rate, La, shall be 0.5% of primary containment air weight per day at Pa.

Leakage rate acceptance criteria are:

a.

Primary containment leakage rate acceptance criterion is 1.0 La.

During the first unit startup following testing in accordance with this program, the leakage rate acceptance criteria are < 0.60 La for Type B and C tests and 0.75 La for Type A tests.

b.

Air lock testing acceptance criteria are:

1)

Overall air lock leakage rate is 0.05 La when tested at Pa.

2)

For each air lock door, leakage rate is 5 scfh when the gap between the door seals is pressurized to 10 psig.

The provisions of SR 3.0.3 are applicable to the Primary Containment Leakage Rate Testing Program frequencies.

5.5.13 Control Room Envelope Habitability Program A Control Room Envelope (CRE) Habitability Program shall be established and implemented to ensure that CRE habitability is maintained such that, with an OPERABLE Control Room Emergency Ventilation (CREV) System, CRE occupants can control the reactor safely under normal conditions and maintain it in a safe condition following a radiological event, hazardous chemical release, or a smoke challenge. The program shall ensure that adequate radiation protection is provided to permit occupancy of the CRE under design basis accident (DBA) conditions without personnel receiving radiation exposures in excess of 5 rem TEDE for the duration of the accident. The program shall include the following elements:

(continued)

RA-18-0149 Enclosure Proposed Technical Specification Bases Pages (Mark-Up)

Unit 1 (For Information Only)

Primary Containment B 3.6.1.1 Brunswick Unit 1 B 3.6.1.1-4 Revision No. 57 BASES (continued)

SURVEILLANCE SR 3.6.1.1.1 REQUIREMENTS Maintaining the primary containment OPERABLE requires compliance with the visual examinations and leakage rate test requirements of the Primary Containment Leakage Rate Testing Program. The primary containment concrete examinations may be performed during either power operation, e.g., performed concurrently with other primary containment inspection-related activities, or during a maintenance or refueling outage. The visual examinations of penetrations on the exterior of the containment and appurtenances may be performed concurrently with other primary containment inspection-related activities, or during a maintenance or refueling outage. The visual examinations of the metallic shell, as well as penetrations on the interior of the containment, are performed during maintenance or refueling outages since this is the only time these areas are fully accessible. The Primary Containment Leakage Rate Testing Program has been established in accordance with 10 CFR 50.54(o) to implement the requirements of 10 CFR Part 50, Appendix J, Option B (Ref. 3). The Primary Containment Leakage Rate Testing Program also conforms with Regulatory Guide 1.163 (Ref. 6) and Nuclear Energy Institute (NEI) 94-01 (Ref. 7) except for the following:

a.

BNP may use the criteria and Total Time method specified in Bechtel Topical Report BN-TOP-1 (Ref. 8) for calculating the primary containment leakage during reduced duration Type A testing. This is an exemption from the requirements of 10 CFR 50 Appendix J (Ref. 3) which, in accordance with NEI 94-01 (Ref. 7),

requires the methods for calculating primary containment leakage described in ANSI/ANS 56.8-1994 2002 (Ref. 9). The basis for this exemption is described in References 10 and 11.

b.

Type C testing is not required for the hydrogen and oxygen monitor isolation valves. This is an exemption from the requirements of 10 CFR 50 Appendix J (Ref. 3). The basis for this exemption is described in Reference 12.

Failure to meet air lock leakage limits (SR 3.6.1.2.1) or main steam isolation valve leakage (SR 3.6.1.3.9) does not necessarily result in a failure of this SR. The impact of the failure to meet SR 3.6.1.2.1 must be evaluated against the Type A, B, and C acceptance criteria of the Primary Containment Leakage Rate Testing Program, and failure to meet SR 3.6.1.3.9 must be evaluated against Type A acceptance criteria of the Primary Containment Leakage Rate Testing Program.

As left leakage prior to the first startup after performing required leakage testing is required to be < 0.6 La for combined Type B and C leakage, and 0.75 La for overall Type A leakage. At all other times between required (continued)

Primary Containment B 3.6.1.1 Brunswick Unit 1 B 3.6.1.1-5 Revision No. 94 BASES SURVEILLANCE SR 3.6.1.1.1 (continued)

REQUIREMENTS (continued) leakage rate tests, the acceptance criteria is based on an overall Type A leakage limit of 1.0 La. At 1.0 La the offsite dose consequences are bounded by the assumptions of the safety analysis. The Frequency is required by the Primary Containment Leakage Rate Testing Program.

SR Frequencies are as required by the Containment Leakage Rate Testing Program. These periodic testing requirements verify that the containment leakage rate does not exceed the leakage rate assumed in the safety analysis.

SR 3.6.1.1.2 Maintaining the pressure suppression function of primary containment requires limiting the leakage from the drywell to the suppression chamber.

Thus, if an event were to occur that pressurized the drywell, the steam would be directed through the downcomers into the suppression pool.

This SR measures drywell to suppression chamber differential pressure during a 10 minute period to ensure that the leakage paths that would bypass the suppression pool (downcomers) are within allowable limits.

Satisfactory performance of this SR can be achieved by establishing a known differential pressure between the drywell and the suppression chamber and verifying that the differential pressure between the suppression chamber and the drywell does not decrease by more than 0.25 inch of water per minute over a 10 minute period. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

REFERENCES

1.

UFSAR, Section 6.2.

2.

UFSAR, Section 15.6.

3.

10 CFR 50, Appendix J, Option B.

4.

NEDC-33039P, Safety Analysis Report for Brunswick Steam Electric Plant Units 1 and 2, Extended Power Uprate, August 2001.

5.

10 CFR 50.36(c)(2)(ii).

6.

NRC Regulatory Guide 1.163, Performance-Based Containment Leak-Rate Testing Program, September 1995.(Not Used)

7.

Nuclear Energy Institute (NEI) 94-01, Industry Guideline for Implementing Performance-Based Option of 10 CFR 50 Appendix J, July 26, 1995 Revision 3-A, dated July 2012, and the Limitations and Conditions specified in NEI 94-01, Revision 2-A, dated October 2008.

(continued)

Primary Containment B 3.6.1.1 Brunswick Unit 1 B 3.6.1.1-6 Revision No. 57 BASES REFERENCES

8.

Bechtel Topical Report BN-TOP-1, Revision 1, November 1, 1972.

(continued)

9.

ANSI/ANS 56.8-19942002.

10.

NRC SER; Issuance of Amendment No. 181 to Facility Operating License No. DPR-71 and Amendment No. 213 to Facility Operating License No. DPR-62 Regarding 10 CFR 50 Appendix J, Option B - Brunswick Steam Electric Plant, Units 1 and 2 (BSEP 95-0316) (TAC Nos. M93679 and M93680); dated February 1, 1996.

11.

NRC SER, Exemption from the Requirements of Appendix J for Brunswick Steam Electric Plant, Units 1 and 2, dated February 17, 1988.

12.

NRC SER, Technical Exemption from the Requirements of Appendix J, dated May 12, 1987.

Primary Containment Air Lock B 3.6.1.2 Brunswick Unit 1 B 3.6.1.2-7 Revision No. 46 BASES (continued)

SURVEILLANCE SR 3.6.1.2.1 REQUIREMENTS Maintaining the primary containment air lock OPERABLE requires compliance with the leakage rate test requirements of the Primary Containment Leakage Rate Testing Program. The Primary Containment Leakage Rate Testing Program has been established in accordance with 10 CFR 50.54(o) to implement the requirements of 10 CFR Part 50, Appendix J, Option B (Ref. 4), and conforms with Regulatory Guide 1.163 (Ref. 5) and Nuclear Energy Institute (NEI) 94-01 (Ref. 6) except for the following:

a.

The local leak rate testing requirements of the primary containment air lock doors may be modified to perform the tests at a pressure less than Pa following replacement of the air lock door seals. This is an exception from the requirements of NEI 94-01 (Ref. 6). The basis for this exception is described in Reference 7.

This SR reflects the leakage rate testing requirements with respect to air lock leakage (Type B leakage tests). The acceptance criteria were established as a small fraction of the total allowable primary containment leakage. The periodic testing requirements verify that the air lock leakage does not exceed the allowed fraction of the overall primary containment leakage rate. The Frequency is required by the Primary Containment Leakage Rate Testing Program.

The SR has been modified by two Notes. Note 1 states that an inoperable air lock door does not invalidate the previous successful performance of the overall air lock leakage test. This is considered reasonable since either air lock door is capable of providing a fission product barrier in the event of a DBA. Note 2 has been added to this SR, requiring results to be evaluated against the acceptance criteria which are applicable to SR 3.6.1.1.1. This ensures that air lock leakage is properly accounted for in determining the combined Type B and C primary containment leakage rate.

(continued)

Primary Containment Air Lock B 3.6.1.2 Brunswick Unit 1 B 3.6.1.2-8 Revision No. 94 BASES SURVEILLANCE SR 3.6.1.2.2 REQUIREMENTS (continued)

The air lock interlock mechanism is designed to prevent simultaneous opening of both doors in the air lock. Since both the inner and outer doors of the air lock are designed to withstand the maximum expected post accident primary containment pressure, closure of either door will support primary containment OPERABILITY. Thus, the interlock feature supports primary containment OPERABILITY while the air lock is being used for personnel transit in and out of the containment. Periodic testing of this interlock demonstrates that the interlock will function as designed and that simultaneous inner and outer door opening will not inadvertently occur. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

REFERENCES

1.

UFSAR, Section 3.8.2.4.3.2.

2.

NEDC-33039P, Safety Analysis Report for Brunswick Units 1 and 2 Extended Power Uprate, August 2001.

3.

10 CFR 50.36(c)(2)(ii).

4.

10 CFR 50, Appendix J, Option B.

5.

NRC Regulatory Guide 1.163, Performance-Based Containment Leak-Rate Testing Program, September 1995.(Not Used)

6.

Nuclear Energy Institute (NEI) 94-01, Industry Guideline for Implementing Performance-Based Option of 10 CFR 50 Appendix J, July 26, 1995 Revision 3-A, dated July 2012, and the Limitations and Conditions specified in NEI 94-01, Revision 2-A, dated October 2008.

7.

NRC SER, Brunswick 1 & 2 - Amendments No. 10 and 36 to Operating Licenses Revising Technical Specifications to Grant Exemptions from Specific Requirements of 10 CFR 50 Appendix J, dated November 8, 1977.

PCIVs B 3.6.1.3 Brunswick Unit 1 B 3.6.1.3-13 Revision No. 95 BASES SURVEILLANCE SR 3.6.1.3.8 REQUIREMENTS (continued)

The TIP shear isolation valves are actuated by explosive charges. An in place functional test is not possible with this design. The explosive squib is removed and tested to provide assurance that the valves will actuate when required. The replacement charge for the explosive squib shall be from the same manufactured batch as the one fired or from another batch that has been certified by having one of the batch successfully fired. The Frequency of this SR is in accordance with the requirements of the INSERVICE TESTING PROGRAM.

SR 3.6.1.3.9 The analyses in References 2, 6, 7, and 8 are based on leakage that is less than the specified leakage rate. Leakage through each main steam line must be 100 scfh when tested at Pt (25 psig). The combined leakage rate for all four mains steam lines must be 150 scfh when tested at 25 psig in accordance with the Primary Containment Leakage Rate Testing Program. The Primary Containment Leakage Rate Testing Program has been established in accordance with 10 CFR 50.54(o) to implement the requirements of 10 CFR Part 50, Appendix J, Option B (Ref. 9), and conforms with Regulatory Guide 1.163 (Ref. 10) and Nuclear Energy Institute (NEI) 94-01 (Ref. 11) except for the following:

a.

Local leak rate testing of the MSIVs may be performed at a pressure less than Pa. This is an exemption from the requirements of 10 CFR 50 Appendix J (Ref. 9). The basis for this exemption is described in Reference 12.

The Frequency is required by the Primary Containment Leakage Rate Testing Program.

(continued)

PCIVs B 3.6.1.3 Brunswick Unit 1 B 3.6.1.3-14 Revision No. 74 BASES REFERENCES

1.

UFSAR, Chapter 15.

2.

NEDC-32466P, Power Uprate Safety Analysis Report for Brunswick Steam Electric Plant Units 1 and 2, September 1995.

3.

10 CFR 50.36(c)(2)(ii).

4.

Technical Requirements Manual.

5.

NEDO-32977-A, "Excess Flow Check Valve Testing Relaxation,"

June 2000.

6.

UFSAR, Section 15.2.3.

7.

NRC letter, Brunswick Steam Electric Plant, Units 1 and 2 -

Issuance of Amendment Re: Alternative Source Term, May 30, 2002.

8.

BNP Calculation No. BNP-RAD-007, Rev. 1B, DBA-LOCA Radiological Dose With Alternate Source Term.

9.

10 CFR 50, Appendix J, Option B.

10.

NRC Regulatory Guide 1.163, Performance-Based Containment Leak-Rate Testing Program, September 1995.(Not Used)

11.

Nuclear Energy Institute (NEI) 94-01, Industry Guideline for Implementing Performance-Based Option of 10 CFR 50 Appendix J, July 26, 1995 Revision 3-A, dated July 2012, and the Limitations and Conditions specified in NEI 94-01, Revision 2-A, dated October 2008.

12.

NRC SER, Brunswick 1 & 2 - Amendments No. 10 and 36 to Operating Licenses Revising Technical Specifications to Grant Exemptions from Specific Requirements of 10 CFR 50 Appendix J, dated November 8, 1977.

RA-18-0149 Enclosure BSEP Evaluation of Risk Significance of Permanent ILRT Evaluation

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Total loss of containment heat removal scenarios where gradual containment pressurization helps to satisfy the NPSH requirements for long-term use of an injection system from a source inside of containment (for example, BWR suppression pool).

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v t e Letter Sequence Request
EPID:L-2019-LLA-0031, License Amendment Request to Revise Units 1 and 2 Technical Specification 5.5.12 for Permanent Extension of Type a and Type C Leak Rate Test Frequencies (Approved, Closed)
Initiation Request, Request Acceptance Administration Questions 25 June 2019 27 June 2019 Answers 25 July 2019 Results Approval Other:
MONTHYEAR2019-06-25 [Table View]

RA-18-0148, License Amendment Request to Revise Units 1 and 2 Technical Specification 5.5.12 for Permanent Extension of Type a and Type C Leak Rate Test Frequencies

Text

Subject:

Enclosure:

SUBJECT:

SUMMARY

3.0 TECHNICAL EVALUATION

4.0 REGULATORY EVALUATION

5.0 ENVIRONMENTAL CONSIDERATION

6.0 REFERENCES

SUMMARY

3.0 TECHNICAL EVALUATION

Response

Response

Response

Response

Response

Response

Response

4.0 REGULATORY EVALUATION

5.0 ENVIRONMENTAL CONSIDERATION

6.0 REFERENCES

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RA-18-0148, License Amendment Request to Revise Units 1 and 2 Technical Specification 5.5.12 for Permanent Extension of Type a and Type C Leak Rate Test Frequencies

Text

Subject:

Enclosure:

SUBJECT:

SUMMARY

3.0 TECHNICAL EVALUATION

4.0 REGULATORY EVALUATION

5.0 ENVIRONMENTAL CONSIDERATION

6.0 REFERENCES

SUMMARY

3.0 TECHNICAL EVALUATION

Response

Response

Response

Response

Response

Response

Response

4.0 REGULATORY EVALUATION

5.0 ENVIRONMENTAL CONSIDERATION

6.0 REFERENCES

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