BSEP 08-0010, Relief Requests Associated with the Fourth 10-Year Inservice Inspection Interval

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Relief Requests Associated with the Fourth 10-Year Inservice Inspection Interval
ML080450249
Person / Time
Site: Brunswick  Duke Energy icon.png
Issue date: 02/06/2008
From: Ivey R
Progress Energy Carolinas
To:
Document Control Desk, Office of Nuclear Reactor Regulation
References
BSEP 08-0010
Download: ML080450249 (54)
v • d • e


Text

Progress Energy 10 CFR 50.55a(a)(3)(i)

FEB 0 6 2008 10 CFR 50.55a(a)(3)(ii)

SERIAL: BSEP 08-0010 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001

Subject:

Brunswick Steam Electric Plant, Unit Nos. I and 2 Docket Nos. 50-325 and 50-324/License Nos. DPR-71 and DPR-62 Relief Requests Associated With the Fourth 10-Year Inservice Inspection Interval

Reference:

Letter from Randy C. Ivey (CP&L), Request for Approval of Risk-Informed Inservice Inspection Program for the Fourth 10-Year Interval, dated December 19, 2007 [ADAMS Accession Number ML073620362]

Ladies and Gentlemen:

In accordance with 10 CFR 50.55a(a)(3)(i) and 10 CFR 50.55a(a)(3)(ii), Carolina Power &

Light Company (CP&L), now doing business asProgress Energy Carolinas, Inc., requests approval of five relief requests associated with the fourth 10-year Inservice Inspection (ISI)

Program for the Brunswick Steam Electric Plant (BSEP), Unit Nos. 1 and 2. The fourth 10-year ISI interval will begin on May 11, 2008, and will conclude on May 10, 2018.

A listing of the relief requests associated with the fourth 10-year ISI Program is provided in Enclosure 1. One request for relief, a risk-informed inservice inspection alternative, was previously submitted to the NRC by letter dated December 19, 2007. The remaining relief requests associated with the fourth 10-year ISI interval are provided in Enclosure 2.

Approval of Relief Request ISI-01 is requested by May 9, 2008, to allow application of the proposed alternative to emergent repair/replacement activities beginning with the new 10-year interval. Approval of Relief Request ISI-03 is also requested by May 9, 2008, to avoid a conflict between the requirements of the ASME Code and the plant's Technical Requirements Manuals. Approval of Relief Requests PT-01, PT-02, and CIP-01 are requested by December 1, 2008, to support inservice inspection activities scheduled for the spring 2009 refueling outage for BSEP, Unit 2. Approval of Relief Request ISI-02, previously submitted December 19, 2007;is also requested by December 1, 2008, to support inservice inspection activities scheduled for the spring 2009 refueling outage for BSEP, Unit 2.

Progress Energy Carolinas, Inc.

Brunswick Nuclear Plant PO Box 10429 Southport, NC 28461 A N -7

Document Control Desk BSEP 08-0010 / Page 2 No regulatory commitments are contained in this letter. Please refer any questions regarding this submittal to Ms. Annette H. Pope, Supervisor - Licensing/Regulatory Programs, at (910) 457-2184.

Sincerely, Randy C.7Ivey Manager - Support Services Brunswick Steam Electric Plant

Document Control Desk BSEP 08-0010 / Page 3 WRM/wrm

Enclosures:

1. List of Fourth Inservice Inspection (ISI) Program Relief Requests
2. Fourth Inservice Inspection (ISI) Program Relief Requests cc (with enclosures):

U. S. Nuclear Regulatory Commission, Region II ATTN: Mr. Victor M. McCree, Regional Administrator (Acting)

Sam Nunn Atlanta Federal Center 61 Forsyth Street, SW, Suite 23T85 Atlanta, GA 30303-8931 U. S. Nuclear Regulatory Commission ATTN: Mr. Joseph D. Austin, NRC Senior Resident Inspector 8470 River Road Southport, NC 28461-8869 U. S. Nuclear Regulatory Commission (Electronic Copy Only)

ATTN: Mr. Stewart N. Bailey (Mail Stop OWFN 8B1) 11555 Rockville Pike Rockville, MD 20852-2738 Chair - North Carolina Utilities Commission P.O. Box 29510 Raleigh, NC 27626-0510 Mr. Jack Given, Bureau Chief North Carolina Department of Labor Boiler Safety Bureau 1101 Mail Service Center Raleigh, NC 27699-1101

BSEP 08-0010 Enclosure 1 Page 1 of 1 List of Fourth Inservice Inspection (ISI) Program Relief Requests Relief Requested Request Revision Status Approval Summary ISI-01 0 Enclosed 5/9/08 Request to use ASME Code Case N-686, "Alternate Requirements for Visual Examinations" ISI-02 0 Submitted 12/1/08 Alternative to use a Risk-separately by Informed Inservice letter dated Inspection (RI-ISI) Program December 19, for examination of Class 1 2007 piping components

[ML073620362]

ISI-03 0 Enclosed 5/9/08 Alternative for Class 1, 2, and 3 Safety-Related Snubbers PT-01 0 Enclosed 12/1/08 Alternative for pressure testing of Class 1 drain, vent, test, and/or fill lines PT-02 0 Enclosed 12/1/08 Alternative for system leakage testing of the Standby Gas Treatment

-System CIP-01 0 Enclosed 12/1/08 Alternative to use NEI 94-01 leakage testing requirements following containment repairs, replacements, or modifications

BSEP 08-0010 Enclosure 2 Fourth Inservice Inspection (ISI) Program Relief Requests Brunswick Steam Electric Plant, Unit Nos. 1 and 2

BSEP 08-0010 Enclosure 2 10 CFR 50.55a Request Number ISI-01 Proposed Alternative In Accordance with 10 CFR 50.55a(a)(3)(i)

- Acceptable Level of Quality and Safety -

1. ASME Code Components Affected Code Class: Class 1, 2, and 3 Category: Not Applicable Systems: See Attachment 1 Affected Components: See Attachment 1

2. Applicable Code Edition and Addenda

The Code of Record for the fourth 10-year inservice inspection interval at the Brunswick Steam Electric Plant (BSEP), Units 1 and 2, is the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code,Section XI, 2001 Edition with 2003 Addenda.

The fourth 10-year inservice inspection interval begins May 11, 2008, and will conclude on May 10, 2018.

3. Applicable Code Requirement

The Special Erratum to the 2003 Addenda restored paragraphs IWA-2210 through IWA-2216 to their 2002 Addenda version. The affected paragraphs address requirements associated with the performance of VT-1, VT-2, and VT-3 visual examinations.

4. Reason for Request

ASME Code Case N-686 provides an acceptable alternative to the above requirements.

These alternative requirements were approved by ASME on February 14, 2003. In October 2007, this Case was incorporated into Revision 15 of Regulatory Guide 1.147 with no limitations.

Although approved in Regulatory Guide 1.147, ASME Code Case N-686 cannot be used since its applicability does not include the 2001 Edition with 2003 Addenda. Therefore, this request is needed to allow the use of ASME Code Case N-686 during the fourth inspection interval.

ISI-01 Page 1 of 5

BSEP 08-0010 Enclosure 2

5. Proposed Alternative and Basis for Use Proposed Alternative Use of the acceptable alternative requirements specified in Case N-686 for performing VT-1, VT-2, and VT-3 visual examinations.

Basis for Use Although the applicability of ASME Code Case N-686 did not include the 2001 Edition with 2003 Addenda, Carolina Power & Light Company (CP&L) has determined that the alternative requirements of ASME Code Case N-686 will provide an acceptance level of quality and safety for the followings reasons:

1. There is no significant difference in VT-I requirements that are included in 2001 Edition with 2003 Addenda, and those stated in ASME Code Case.N-686. The only difference in the VT-I examination is that the metric system for distance has been rounded off (i.e., slightly different numbers) in ASME Code Case N-686.
2. ASME Code Case N-686 removes the requirements for illumination and examination distance for VT-2 examinations as specified in Table IWA-2210-1.

Experience has shown, however, that there are Other effective techniques and tools for locating leakage. For example, when water is illuminated with a flashlight it has a "mirror effect" or shiny reflective area, allowing leaks to be located from distance greater than six feet. Therefore, a VT-2 examination using a flashlight provides a level of quality equivalent to performing the examination with general illumination of 15 foot-candles. Experience has also shown that leakage canbe detected effectively at distances greater than the Code-required maximum distance criteria. For an examiner to be within six feet of the surfaces being examined may require the erection of scaffolding to perform a system pressure test because the piping runs for certain systems may be 20 to 30 feet above the floor. The plant personnel required to erect and take down the scaffolding, or the additional plant personnel required to perform remote examinations (e.g., personnel to install or hold a light source if the examiner uses binoculars), would receive unnecessary radiation exposure.

3. A VT-3 examination is conducted to determine the general mechanical and structural condition of a component or a component support. Table IWA-22 10-1 requires the examiner to be within four feet of the surfaces being examined or use remote examination equipment that provides demonstrated equivalent resolution.

ASME Code Case N-686 eliminates the maximum direct examination distance requirement. Although deleted in the case, experience has shown that such conditions and degradation can be detected effectively at distances greater than the Code-required maximum distance criteria. Again, the piping runs for certain systems may be 20 to 30 feet above the floor. This would require the erection of scaffolding to perform a visual examination of a component support. In addition, ISI-01 Page 2 of 5

BSEP 08-0010 Enclosure 2 as discussed above, the use of remote examination equipment involves more plant personnel.

4. The nuclear industry has over 30 years of experience performing visual examinations to the less prescriptive requirements for proximity and illumination, and examiners are fully qualified in accordance with IWA-2300, "Qualifications of Nondestructive Examination Personnel." Experience, training, and qualifications Of visual examiners provide reasonable assurance that they will apply the appropriate illumination and distance requirements required to perform quality examinations.

Based on above, CP&L has concluded that an equivalent level of quality and safety can be achieved by performing VT-2 examinations at distances in excess of six feet with no specified illumination level and VT-3 examinations at distances in excess of four feet.

These time-pro'ven methods for conducting visual examinations will continue to provide reasonable assurance of structural integrity while preventing plant personnel from receiving excessive radiation exposure. For these reasons, CP&L requests authorization to use the acceptable alternative requirements specified in ASME Code Case N-686.

CP&L has concluded that the implementation of these alternative requirements will provide an acceptance level of quality and safety pursuant to 10 CFR 50.55a(a)(3)(i).

6., Duration of Proposed Alternative Use of the alternative is proposed for the fourth 10-year inservice inspection interval which will begin on May 11, 2008, and will conclude on May 10, 2018.

7. Precedents
1. Safety Evaluation for Cooper Nuclear Station, Fourth 10-Year Interval Inservice Inspection Request for Relief RI-37, ADAMS Accession Number ML062000107.
2. Safety Evaluation of Relief Requests for the Fourth 10-Year Interval of the Inservice Inspection Program - Duane Arnold Energy Center, ADAMS Accession Number ML070090357.
8. References
1. Title 10 of the Code of Federal Regulations, Part 50, Section 55a, Codes and Standards (i.e., 10 CFR 50.55a).
2. ASME Code Case N-686, Alternative Requirements for Visual Examinations, VT-1, VT-2, and VT-3,Section XI, Division 1.

ISI-01 Page 3 of 5

BSEP 08-0010, Enclosure 2

3. ASME Code,Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, 2001 Edition with 2003 Addenda.
4. NRC Regulatory Guide 1.147, Revision 15, Inservice Inspection Code Case Acceptability, ASME Section XI, Division 1, October 2007.

ISI-01 Page 4 of 5

BSEP 08-0010 Enclosure 2 Attachment 1 Systems and Components Components Systems ISI Class 1 ISI Class 2 ISI Class 3 Containment Isolation:

Containment Atmosphere Control (2070) V" Drywell Drains (6235 and 6240) V" Hydrogen Monitoring (2070) V Instrument Air Supply (6135) V/

Post Accident Sampling (2117) 1/I Reactor Building Sampling (2115) V" Torus Drain (2190) V/

Traversing Incore Probe (1050) V/

Control Rod Drive Hydraulic (1070) V V Core Spray (2035) V ,V" Nuclear Steam Supply (1005) V Fuel Pool Cooling (7.110) V/

High Pressure Coolant Injection (2095) V V Reactor Building Close Cooling Water (4070) V" Reactor Coolant Recirculation (2020) V/ V" Reactor Core Isolation Cooling (2100) V V Reactor Water Cleanup (2010) V Residual Heat Removal (2045) V V Standby Gas Treatment (7071) ¢"

Standby Liquid Control (2040) V V Service Water (4060) V ISI-01 Page 5 of 5

BSEP 08-0010 Enclosure 2 10 CFR 50.55a Request Number ISI-03 Proposed Alternative In Accordance with 10 CFR 50.55a(a)(3)(i)

- Acceptable Level of Quality and Safety -

1. ASME Code Components Affected Code Class: Class 1, 2, and 3 Category: Not Applicable Systems: Not Applicable Affected Components: Class 1, 2, and 3 Safety-Related Snubbers

2. Applicable Code Edition and Addenda

The Code of Record for the fourth 10-year inservice inspection interval at the Brunswick Steam Electric Plant (BSEP), Units 1 and 2, is the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code,Section XI, 2001 Edition with 2003 Addenda.

The fourth 10-year inservice inspection interval begins May 11, 2008, and will conclude on May 10, 2018.

3. Applicable Code Requirement

Paragraph IWF-1220, Snubber Inspection Requirements, requires the inservice inspection requirements for snubbers be in accordance with the requirements of Article IWF-5000.

Article IWF-5000, Inservice Inspection Requirements for Snubbers, requires preservice and inservice examinations and tests to be performed in accordance with the ASME /

American National Standards Institute (ANSI) Operation and Maintenance Code (OM),

Part 4 (1987 with OMa-1988).

4. Reason for Request

During the third inspection interval, a request for relief was granted to implement the alternative requirements outlined in the Technical Review Manual (TRM) for BSEP, Units 1 and 2. The alternative requirements specified in the TRM are consistent with the guidance provided in Generic Letter (GL) 90-09 and have been demonstrated to provide an acceptable level of quality and safety.

ISI-03 Page 1 of 3

BSEP 08-0010 Enclosure 2 The overlap of the visual examination program required by ASME Code,Section XI and the existing TRM snubber program for ISI classified snubbers presents an unnecessary redundancy without a compensating increase in the level of quality and safety. For this reason, this request is to continue using the alternative requirements Outlined in the TRM snubber program.

5. Proposed Alternative and Basis for Use Proposed Alternative Carolina Power & Light Company (CP&L) proposes to use the alternative requirements specified in the TRM snubber program, Section 3.21, for preservice and inservice examinations and tests. The alternative requirements will also be applied to the preservice examination and testing of snubbers that are repaired or replaced.

Basis for Use The current TRM snubber program, Section 3.21, provides a comprehensive program for visual examination and functional testing requirements of safety related and non-safety related snubbers. This program was implemented during the previous inspection interval and has been demonstrated to provide an acceptable level of quality and safety.

In addition, the TRM snubber program provides for a level of quality and safety equal to or greater than that of the requirements specified in Article IWF-5000 (i.e.,

ASME/ANSI OM, Part 4). For example, ASME/ANSI OM, Part 4 provides for failure mode grouping of snubbers which fail visual examination, meaning only those snubbers identified as being in that group would require shortened inspection intervals. Under the TRM snubber program, all snubbers in the population would be placed in a shortened inspection interval. As such, the TRM snubber program is more conservative in corrective action than the OM Part 4 requirements.

The functional test plan required by ASME/ANSI OM, Part 4 also includes failure mode groups. The use of failure mode grouping is required even for a single failure, and in some cases allows for the failed snubber to be reclassified as acceptable with no further testing. This test plan is not conservative for the large snubber population which exists at BSEP (i.e., approximately 500 snubbers per unit) when compared to the TRM snubber program. The TRM snubber program requires supplemental testing for all failures until the desired confidence level is assured, with no allowances to reclassify failed snubbers.

Based on above, CP&L has concluded that an equivalent level of quality and safety can be achieved by the continued implementation of the TRM snubber program. This time-proven program for conducting examinations and tests will continue to provide confidence in snubber operability while preventing plant personnel from receiving excessive radiation exposure. For these reasons, authorization is requested to continue using the alternative requirements outlined in the TRM snubber program. CP&L has ISI-03 Page 2 of 3

BSEP 08-0010 Enclosure 2 concluded that the continued implementation of these alternative requirements will provide an Acceptance level of quality and safety pursuant to 10 CFR 50.55a(a)(3)(i).

6. Duration of Proposed Alternative Use of the alternative is proposed for the fourth 10-year inservice inspection interval which will begin on May 11, 2008, and will conclude on May 10, 2018.
7. Precedents
1. Approval for Third 10-Year Interval Inservice Inspection Program Request for Relief for the Brunswick Steam Electric Plant, dated May 4, 1999.
8. References
1. Title 10 of the Code of Federal Regulations, Part 50, Section 55a, Codes and Standards (i.e., 10 CFR 50.55a).
2. ASME Code,Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, 2001 Edition with 2003 Addenda.
3. ASME/ANSI Operation and Maintenance Code, Part 4, Examination and Performance Testing of Nuclear Power Plant Dynamic Restraints (Snubbers),

1987 with OMa-1988.

4. Generic Letter 90-09, Alternative Requirements for Snubber Visual Inspection Intervals and Corrective Actions, December 11, 1990.
5. Technical Requirements Manual, Brunswick Steam Electric Plant. Unit No. 1 and 2.

ISI-03 Page 3 of 3

BSEP 08-0010 Enclosure 2 10 CFR 50.55a Request Number PT-01 Proposed Alternative In Accordance with 10 CFR 50.55a(a)(3)(ii)

- Compliance Results in Hardship'or Unusual Difficulty -

1. ASME Code Components Affected Code Class: Class 1 Category: B-P, All Pressure Retaining Components System: Reactor Coolant Pressure Boundary (RCPB)

Affected Components: See Attachment 1 for a listing of affected components

2. Applicable Code Edition and Addenda

The Code of Record for the fourth 10-year inservice inspection interval at the Brunswick Steam Electric Plant (BSEP), Units 1 and 2, is the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code,Section XI, 2001 Edition with 2003 Addenda.

The fourth 10-year inservice inspection interval begins May 11, 2008, and will conclude on May 10, 2018.

3. Applicable Code Requirement

The ASME Code,Section XI, paragraph IWB-5222(b) requires the pressure retaining boundary during the system leakage test extend to all Class 1 components within the system boundary.

4. Reason for Request

The drain, vent, test, and/or fill lines within the RCPB are typical one-inch nominal pipe size or less. These connections include two manual isolation valves whose purpose is to satisfy the design requirement for double isolation of the RCPB. During normal operation, these manual isolation valves are maintained in the closed or locked-closed position. Thus, components downstream of the first isolation valve are not subjected to reactor coolant system pressure unless leakage through the inboard valves occurs.

As stated above, Code requirements would require test pressurization to extend to all Class 1 pressure retaining components within the system boundary. To comply with this requirement, Carolina Power & Light Company (CP&L) would be required to the open PT-01 Page 1 of 21

BSEP 08-0010 Enclosure 2 the first isolation valve. Having the first isolation valve open during the pressure test would defeat the design requirement for double isolation of the RCPB. As such, this non-standard configuration would increase the risk for inventory loss. Because of the potential for inventory loss, this configuration also creates safety concerns for the personnel performing the visual examination.

In addition, opening the first manual isolation valve will create a hardship in regards to personnel exposure and contamination. Opening these valves will require personnel to enter radiation fields to position the valves for the test, restore the valves following the test, and to perform the required independent valve position verification. Since these valves are typically located in close proximity to the main RCPB piping, CP&L estimates the dose associated with this effort as approximately one Rem per unit. Because of the location of these valves, the risk for personnel contamination increases.

Based on CP&L's evaluation of this Code requirement,'. opening the first isolation valve to allow pressurization of the downstream components will not increase the level of qualify or safety at the plant. As such, placing the plant and personnel at risk is unwarranted.

For this reason, CP&L requests relief from the requirement of the ASME Code, Section Xl, paragraph IWB-5222(b).

5. Proposed Alternative and Basis for Use Proposed Alternative The VT-2 visual examination of the components downstream of the isolation valves listed in Attachment 1 will extend to and include the second closed valve at the boundary extremity. This visual examination will be performed with the isolation valves in their normal operating position.

Basis for Use Because of the potential safety concerns and hardships, the proposed alternative will provide an acceptable level of safety and quality based for the following reasons:

1. The piping, fittings, and valves within these lines were designed and constructed to the highest standards. The components were designed for pressures and temperatures greater than they experience during normal operation. They were constructed to standards commensurate to the requirements of the ASME Code,Section III for Class 1 components. Because of these high standards, there is reasonable assurance that leakage integrity will be maintained during normal operation.
2. The proposed alternative is a proven method for assuring leakage integrity. This alternative is the same requirement that is used during the Code required system leakage test which is performed every refueling outage.

PT-01 Page 2 of 21

BSEP 08-0010 Enclosure 2

3. Only the isolable portion of these connections will not be pressurized during the test. Since these lines are in the same configuration during normal operation, approving this alternative poses no new safety concerns. As outlined in the alternative requirement, the VT-2 visual examination will extend to and include the second closed valve at the boundary extremity.
4. Not pressurizing component connections, piping, and valves that are one-inch nominal pipe size and smaller during a system leakage test, is an acceptable practice per the ASME Code,Section XI. Following a repair/replacement activity, a system leakage test is exempt for these small diameter components per paragraph IWA-4540(b).

In summary, extending the system pressure to the components downstream of the first normally closed isolation valve is a hardship and poses safety concerns for the plant and personnel. The components affected by this relief request were designed and constructed to the highest standards available. The test configuration of these components is the same as they experience during normal operations and Code required system leakage test. In additional, extending the test pressure to these components once per ten years is unjustifiable considering these same components would be exempt from pressure testing if repaired or replaced. For these reasons, approving the use of the proposed alternative will provide an acceptable level of safety and quality.

6. Duration of Proposed Alternative Use of the alternative is proposed for the fourth 10-year inservice inspection interval which will begin on May 11, 2008, and will conclude on May 10, 2018.
7. Precedents This proposed alternative is similar, but not identical, to a relief request approved for the third 10-year Inspection Interval in a letter dated February 12, 2007, ADAMS Accession Number ML070360418.
8. References
1. Title 10 of the Code of Federal Regulations, Part 50, Section 55a, Codes and Standards (i.e., 10 CFR 50.55a).
2. ASME Code,Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, 2001 Edition with 2003 Addenda.

PT-01 Page 3 of 21

BSEP 08-0010 Enclosure 2 GENERAL FIRST ISOLATION NORMAL LOCATION VALVE DESCRIPTION POSITION DRAWING:

B21-FOOI RX Inboard High Point Vent Valve Locked Closed Figure: 14 B21-V1 8 B21-FOI IA Inboard Body Drain Valve Closed Figure: 2 B21 -V20 B21 -F010A Inboard Body Drain Valve Closed Figure: 2 B21 -V23 B21 -F011B Inboard Body Drain Valve Closed. Figure: 3 B21-V25 B2 I-F01OB Inboard Body Drain Valve Closed Figure: 3 B21-V160 Test valve for Excess Flow Check Valve Closed Figure: 9 B21-IV-2456 (Pen. X-49A-A)

B21-V 161 Test valve for Excess Flow Check Valve Locked Closed Figure: 10 B21-IV-2455 (Pen. X-49B-A)

B2 I-V 167 B21-F016 Test Inboard Isolation Valve Locked Closed Figure: 5 B32-F025A B32-F023A Vent Root Valve Closed Figure: 7 B32-F025B B32-F023B Vent Root Valve Closed Figure: 8 B32-F027A B32-F023A Inboard Drain Valve Closed Figure: 7 B32-F027B B32-F023B Inboard Drain Valve Closed Figure: 8 B32-F029 Reactor Pressure Vessel Drain Inboard Valve Closed Figure: 15 B32-F034A B32-F03 1A Inboard Vent Valve Closed Figure: 7 B32-F034B B32-F03 1B Inboard Vent Valve Closed Figure: 8 B32-F036A B32-F03 IA Inboard Body Drain Valve Closed Figure: 7 B32-F036B B32-F03 IB Inboard Body Drain Valve Closed Figure: 8 B32-F046A B32-F043A Inboard Root Valve Closed Figure: 7 B32-F046B B32-F043B Inboard Root Valve Closed Figure: 8 B32-F048A B32-F043A Inboard Body Drain Valve Closed Figure: 7 B32-F048B B32-F043B Inboard Body Drain Valve Closed Figure: 8 B32-V36 B32-F032A Vent Root Valve Closed Figure: 7 B32-V38 B32-F032B Vent Root Valve Closed Figure: 8 B32-FO51A Reactor Recirculation Loop A Inboard Drain (HW) Closed Figure: 7 B32-FO51 B Reactor Recirculation Loop B Inboard Drain (HW) Closed Figure: 8 C41-V8 C4 1-F007 Inboard Test Isolation Valve Locked Closed Figure: 16 I-Ell-V112 E11-F060A Inboard Body Drain Valve Closed Figure: 11 PT-01 Page 4 of 21

BSEP 08-0010 Enclosure 2 GENERAL FIRST ISOLATION NORMAL LOCATION VALVE DESCRIPTION POSITION DRAWING:

El l-V117 E l1 -F050A Inboard Body Drain Valve Closed Figure: 11 El l-V130 E 11-F050B Inboard Body Drain Valve Closed Figure: 12 I-El I-V132 ElI-F060B Inboard Body Drain Valve Closed Figure: 12 El 1-V82 El -FO I5A Inboard Body Drain Valve Locked Closed Figure: 11 Eli-V169 E I I-FO 15B Inboard Body Drain Valve Locked Closed Figure: 12 El l-V5000 ElI-F009 Inboard LLRT Test Connection Locked Closed Figure: 13 E2 I-V27 E2 I-FO06A Downstream Inboard Body Drain Valve Closed Figure: 1 E21-V39 E21-FO06B Downstream Inboard Body Drain Valve Closed Figure: 1 2-E21-V41 Core Spray Div II Inboard Vent Valve Closed Figure: 1 E2 I-V67 E21 -FO07A Inboard Body Drain Valve Closed Figure: 1 E21-V69 E2 I-FO07B Inboard Body Drain Valve Closed Figure: 1 E41-V174 E4 1-F002 Inboard ISI Test Valve Locked Closed Figure: 4 E51-VIOI E51-F007 Inboard ISI Test Valve Locked Closed Figure: 6 G3 1-F002 RWCU Inlet Line Test Valve Locked Closed Figure: 15 PT-01 Page 5 of 21

BSEP 08-0010 Enclosure 2 Figure 1 - Core Spray (CS) A and B Loops DRYWELL PENETRATION X-16B EL.62'-9" AZ. 280°

  • V74
  • V73 DRYWELL PENETRATION X-16A EL.67-9" AZ. 790
  • Unit 1 only
    • Unit 2 only PT-01 Page 6 of 21

BSEP 08-0010 Enclosure 2 Figure 2 - Feedwater A Loop a-00

-U.I I F006 V55 2.18-900 V159 v10 PT-01 Page 7 of 21

BSEP 08-0010 Enclosure 2 Figure 3 - Feedwater B Loop PT-01 Page 8 of 21

BSEP 08-0010 Enclosure 2 Figure 4 - High Pressure Coolant Injection (HPCI) Steam Line PENETRATION X-70B EL. 36'-0" AZ. 2310 PT-0.1 Page 9 of 21

BSEP 08-0010 Enclosure 2 Figure 5 - Primary Steam A Line

-PRIMARY CONTAINMENT F013B PRIMARY STEAM LINE "A' DRYWELL PEN. X-7A EL. 22'-4", AZ. 50 PRIMARY STEAM LINE "B" DRYWELL PEN. X-8 EL. 20'-2 '/2,AZ. 00 I

V168 PRIMARY STEAM LINE "C" PRIMARY STEAM LINE "D" PT-01 Page 10 of 21

BSEP 08-0010 Enclosure 2 Figure 6 - Reactor Core Isolation Cooling (RCIC) Steam Line DRYWELL PENETRATION V86 F043D X-72E EL. 36'-0" AZ. 244o DRYWELL PENETRATION X-72F

/EL. 36-0" AZ. 2440 S/--DRYWELL PENETRATION ON X-61E EL. 36'-0" AZ. 900 DRYWELL' PENETRATION X-61F EL. 36'-0" AZ. 900 DRYWELL PENETRATION X-10 EL. 23'-6" AZ. 1850 PT-01 Page 11 of 21

BSEP 08-0010 Enclosure 2 Figure 7 - Reactor Recirculation A Loop PT-01 Page 12 of 21

BSEP 08-0010 Enclosure 2 Figure 8 - Reactor Recirculation B Loop EF. EL. 5'-0"

  • Unit Two Only PT-01 Page 13 of 21

BSEP 08-0010 Enclosure 2 Figure 9 - Nuclear Steam Supply Instrumentation

\RACORVESE

- EL. 36'-0" AZ. 2700

.,_.EL. 38'-0" AZ. 2700 X-728 PT-01 Page 14 of 21

BSEP 08-0010 Enclosure 2 Figure 10 - Nuclear Steam Supply Instrumentation EL. 86'-0" AZ. 315V-REACTOR VESSEL

-N11A

-- N16A 21NSA 821-723 EL. 380-AZ. 80' EL. 41'-6" "f-AZ. 900'-

X-68F EL. 3-o" AZ. 80W Jet Pumps X-61A SLC '

PT-01 Page 15 of 21

BSEP 08-0010 Enclosure 2 Figure 11 - Residual Heat Removal (RHR) A Loop, r----- - - ------------- I N2A r- - -N28

- - - ------- *N2C I ---------------------

- N2D I -I- - N2E II I " "- NI II1 III PRIMARY CONTAINMENT REACTOR

- -PRESSURE VESSEL II GRTG. EL 38'0-0 Eu=*1 . I I REIR~

RAL9ALQflf-~

V114 ,PUMPl CI1 :

tV3 2 [*I I i F060A I0V1I X-13A EL. 23-6" AZ. 1600 1`06VA 1-4 I F II 14---- ..j - -

  • UnitOne Only PT-01 Page 16 of 21

BSEP 08-0010 Enclosure 2 Figure 12 - Residual Heat Removal (RHR) B Loop REACTOR GRTG. EL. 38'-0" RECIRC.

PUMP

CO01B u - m--

Pl CONTAINMENT LC-- -

V128 EL. 30'-0" V

- AZ 2700 IF060B 2

---- -- L----------4-4--------- 28 I F031B 87-24-900-.

I -

EL. 23'-6" AZ 2000 GRTG. EL. 17'-0"

  • UNIT I ONLY PT-01 Page 17 of 21

BSEP 08-0010 Enclosure 2 Figure 13 - Residual Heat Removal (RHR) Shutdown Cooling V103 PT-01 Page 18 of 21

BSEP 08-0010 Enclosure 2 Figure 14 - RPV Closure Head Vent Lines CONTAINMENT F002 44-2-602 46-2-600 44-2-602

,47-1-602

-PRIMARY STEAM UNE"A" V83 706-3"463 PT-01 Page 19 of 21

BSEP 08-0010 Enclosure 2 Figure 15 - Reactor Water Cleanup (RWCU)

DRYWELL I y y y y y y '>ý y PENETRATION X-1 4 EL. 62'-9 AZ. 2450 K

LF0 27 *LFO01 F* 004 1-6-603-"

K

-*-PRIMARY CONTAINMENT G31 REACTOR Eli VESSEL IRHR (403 F10-20-603 F067 -

- o050 "A"LOOP RECIRCULATION SUCTION LINE 16-2-603 2-600 IRC GI F029 F030 B32 PT-01 Page 20 of 21

BSEP 08-0010 Enclosure 2 Figure 16 - Standby Liquid Control (SLC)

"DRYWELL EL. 71'-0" -PEN. X-42 AZ. 2100 1I/2" PT-O1 Page 21 of 21

BSEP 08-0010 Enclosure 2 10 CFR 50.55a Request Number PT-02 Proposed Alternative In Accordance with 10 CFR 50.55a(a)(3)(i)

- Acceptable Level of Quality and Safety -

1. ASME Code Components Affected Code Class: Class 2 Category: C-H, All Pressure-retaining Components Systems: Standby Gas Treatment (SGT)

Affected Components: See Attachment 2 for affected components

2. Applicable Code Edition and Addenda

The Code of Record for the fourth 10-year inservice inspection interval at the Brunswick Steam Electric Plant (BSEP), Units 1 and 2, is the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code,Section XI, 2001 Edition with 2003 Addenda.

The fourth 10-year inservice inspection interval begins May 11, 2008, and will conclude on May 10, 2018.

3. Applicable Code Requirement

The ASME Code, Subarticle IWC-2500, requires that Class 2 components be examined and pressure tested as specified in Table IWC-2500-1, Examination Category C-H.

Examination Category C-H of Table IWC-2500-1 requires that pressure-retaining components be subjected to a system leakage test and visually (i.e., VT-2) examined once per inspection period.

4. Reason for Request General System Description The SGT System and supporting system components consists of suction piping, two parallel 100 percent capacity filter trains and blowers, and a discharge vent (i.e., see Attachment 1 for a simple diagram).

The SGT System and supporting system components perform several functions following a design basis Loss-of-Coolant Accident (LOCA) and during other conditions when the PT-02 Page 1 of 10

BSEP 08-0010 Enclosure 2 Reactor Building Ventilation System is isolated. Their safety related functions include:

(1) maintaining the Secondary Containment structure at a negative pressure of 0.25 inches of water by controlled venting of the building atmosphere at a rate of 100 percent of the structure volume per day, and (2) removing the halogens and other fission products from the atmosphere vented from the Drywell and/or Suppression Chamber following a LOCA. These components also perform several non-safety related functions.

During normal plant operation, the SGT System is in a standby mode and aligned to take suction on the Reactor Building atmosphere in case an automatic start signal is received.

In the unlikely event this system is needed for mitigation of a potential release, the system would be aligned to draw the radioactive material from either primary or secondary containment through a series of HEPA/charcoal filters. Once drawn through the filters, the material would be exhausted to an elevated release point (i.e., 100-meter tall plant stack). During normal operation, the affected components will experience minimal pressures.

System Code Classification and System Leakage Test The SGT System and supporting system components are used to satisfy General Design Criteria 41, Containment Atmosphere Cleanup, and classified as an Engineered Safety Feature System. These safety-related components were constructed to standards commensurate to ASME Section III Code, Class 2. For these reasons, the safety-related components associated with the SGT System and supporting system components have been classified as ISI Class 2 and included in the ISI Program. Their inclusion followed the guidance provided in Standard Review Plan, Section 6.6, Inservice Inspection of Class 2 and 3 Components.

As required by IWC-2500 of the ASME Code,Section XI, these ISI Class 2 components are to be examined and pressure tested as specified in Table IWC-2500-1. Per the requirement of Table IWC-2500-1 (i.e., Examination Category C-H), pressure-retaining components are to be periodically pressure tested and visually (i.e., VT-2) examined once per inspection period. The extent of the examination is defined in IWC-5222.

The purpose of the system leakage test is to periodically pressurize the system and to provide a systematic approach to locate evidence of leakage. This is accomplished by operating the system in its normal lineup under system operating pressure. Once the system, operation pressure is maintained for the specified hold time, a visual (i.e., VT-2) examination is performed.

The purpose of the visual (i.e., VT-2) examination is to locate leakage or evidence of leakage from the pressure-retaining components. The methodology for specifying this type of visual examination is that the examiner would be able to observe any source of leakage or evidence of structural distress during the pressure test.

PT-02 Page 2 of 10

BSEP 08-0010 Enclosure 2 With most ISI Class 2 systems, this type of visual examination is beneficial. Unlike the affected components, other ISI Class 2 system components contain water or steam and are pressurized during the system leakage test. As such, leakage can be observed during the pressure test.

For the affected components, observing leakage during a system leakage test is unlikely since they will only experience minimal or negative pressure during the test. During a system leakage test, the SGT System will take suction on the Reactor Building atmosphere. Once a fan blower is started, the test medium (i.e., Reactor Building atmosphere) is drawn through one of the filter banks and exhausted to the plant stack.

Because the fan blower is creating suction to draw the atmosphere through the filters, the components upstream of the fan blower will experience little-to-no pressure during the system leakage test. In the unlikely event that a structural distress had occurred, the process fluid would not escape since it would be drawn into the system.

Since the fan blower is exhausting the filtered atmosphere to the stack, the components downstream of the blower could be slightly pressurized during the test. Again, it would be unlikely that leakage Would be detected during the test since it is an open-path to the plant stack and the test medium would take the path of least resistance.

In summary, the purpose of the system leakage test is to pressurize the affected boundary to allow the detection of leakage caused by structural distress. Because of how this system operates, the Code-required system leakage test does not provide an affective method to detect leakage. As such, the performance of this test and visual examination provides no compensating increase in quality and safety.

5. Proposed Alternative and Basis for Use Proposed Alternative Perform a structural integrity visual examination of the accessible pressure-retaining boundary, as defined in IWC-5222, during each refueling outage.

Basis for Use Carolina Power & Light Company (CP&L) has determined that the proposed alternative will provide an acceptable level of quality and safety for the following reasons:

1. Since the system leakage test is not an affective method for identifying structural distress, CP&L will perform a structural integrity visual examination of accessible pressure retaining boundary each refueling outage. CP&L considers this structural
  • integrity visual examination a superior and proven method for identifying potential degradation. Similar visual examinations are also performed on other safety significant components (e.g., components classified as Class MC).

PT-02 Page 3 of 10

BSEP 08-0010 Enclosure 2 Performing a structural integrity visual examination once each refueling outage would detect and correct potential degradation. The performance of this visual examination is also considered an acceptable alternative to the current test frequency specified in the ASME Code, which is once every inspection period (i.e.,

approximately every other refueling outage).

This visual examination is a more comprehensive inspection and an acceptable alternative to the Code requirement for the following reasons:

a. The structural integrity visual examination will be controlled in accordance with a plant approved process and will be performed by qualified personnel. The plant approved process will delineate examination methods that will allow the detection of degradation mechanisms and timely correction of any unacceptable indications.
b. Certified and properly trained personnel will perform the structural integrity visual examinations. Personnel performing these examinations will be certified in accordance with the applicable requirements of IWA-2300. This level of certification will ensure that the capability and visual acuity of the personnel is sufficient to detect evidence of potential degradation.
c. For those components whose external surfaces are inaccessible for direct line of sight inspection, the surrounding areas will be inspected for evidence of structural distress. In addition, CP&L will perform an evaluation of acceptability of these inaccessible areas when degradation exists in accessible surfaces that could indicate the presence of or result in degradation of an inaccessible area. Since the ASME Code,Section XI, does not address the evaluation of inaccessible areas, this as an enhancement to maintain the integrity of these components.
d. Any evidence of structural distress identified during the structural integrity visual examination will be recorded and dispositioned. If correction actions are needed, they will be performed in accordance with an approved procedure and documented.
2. Not performing the system leakage test or the visual (i.e., VT-2) examination of the SGT System and supporting system components will not compromise quality or safety.

The SGT System and supporting system components were designed and constructed and tested commensurate to ASME Code,Section III, Class 2 and for seismic forces in accordance with seismic class I requirements.

In addition to the non-destructive examinations performed on the components by their manufacturer, each butt weld associated with this piping had a surface and PT-02 Page 4 of 10

BSEP 08-0010 Enclosure 2 volumetric examination performed. Following completion of the construction, the piping was also hydrostatically tested. As such, these components were constructed and tested to high quality standards.

The temperature and pressure design parameters for the Containment Atmospheric Control (CAC) System piping are 300'F and 62 psig, respectively. The temperature and pressure design parameters for the SGT System are 150F and 5 psig, respectively. The design of these components also includes allowance for corrosion and/or erosion for the specified design life. The large bore piping was constructed to an American National Standards Institute (ANSI) rating of 150 pounds, using carbon steel with a nominal thickness of 0.375 inch.

During routine operation of this system, the affected components are not subject to a harsh environment. These components are located inside the Reactor Building and are not exposed to any environment that would be harmful to carbon steel materials. Since the process medium is the Reactor Building atmosphere during normal plant operation, the interior surfaces of these components are also not subject to a harsh environment. Although some condensation may be present, these components were designed with adequate corrosion margin. Any such condensation would be expected to collect in the bottom interior of these components. If this condensation were to result in sufficient corrosion to cause structural distress of these components, this distress would be expected to be observable on the accessible portions of the piping components during the structural integrity visual examinations.

Because of the operational characteristics of the SGT System, the affected components are subject to minimal distress during operation. During normal plant operation, this system is typically only operated to perform required surveillance tests.

These surveillance tests are performed as quickly as possible to minimize system unavailability. Because of the low operationpressures and operating time, operational related distress of these components is considered minimal.

In addition to the proposed structural integrity visual examinations, these components are periodically tested commensurate with the safety function to be performed. The operability of these safety-related components is assured by the performance of a series of surveillance requirements specified in BSEP, Unit 1 and 2 Technical Specification Surveillance Requirements 3.6.4.3.1, 3.6.4.3.2, and 3.6.4.3.3. These surveillance requirements demonstrate acceptable operation of this system by verifying system flow, differential pressure across the various filters including the heaters and moisture separators, mechanical efficiency of the filters, the ability of the heaters to maintain relative humidity, and the ability of the charcoal to remove the appropriate amount of radionuclide. Since these requirements are verified with the system in operation, the test results are an indicator of actual system performance and operability. In addition to these PT-02 Page 5 of 10

BSEP 08-0010 Enclosure 2 periodic surveillance test, plant operators conduct routine checks of the areas containing these components. These operational checks include monitoring the status of all equipment in the area and identification of any type of leaks, abnormal sounds, or other equipment changes.

3. The SGT System is classified as a standby system under the Maintenance Rule (i.e.,

10 CFR 50.65) based on the classification as safety related and the design function of mitigating the consequences of design basis accidents and transients.

Performance monitoring groups, along with performance criteria, have been established for the affected components. Using this criterion, the System Engineer periodically monitors performance data to evaluate the effectiveness of maintenance. This data is reviewed at a frequency commensurate with the safety significance of the system.

In addition to assessing performance data, the structural condition of these systems is also periodically monitored as part of the Maintenance Rule Program. This condition monitoring inspection is outlined in a approved plant procedure and is consisted with the guidance provided in Revision 2 of Regulatory Guide 1.160, "Monitoring the Effectiveness of Maintenance at Nuclear Power Plants" and NUMARC 93-01, "Industry Guidelines for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants."

Any structural or component not meeting the established performance criteria will be evaluated for (a)(1) classification and goal setting.

Since the system operability is verified by surveillance requirements and performance of the proposed structural integrity visual examinations each refueling outage, there is no safety significance associated with not performing the system leakage test or the visual (i.e., VT-2) examination. Because of the SGT System operating characteristics, the performance of the system leakage test is not an effective method for assuring integrity of these components. As such, the described alternative will provide an acceptance level of quality and safety pursuant to 10 CFR 50.55a(a)(3)(i).

6. Duration of Proposed Alternative Use of the alternative is proposed for the fourth 10-year inservice inspection interval which will begin on May 11, 2008, and will conclude on May 10, 2018.
7. Precedents This proposed alternative is similar, but not identical, to a relief request approved for the third 10-year Inspection Interval in a letter dated February 7, 2001 (i.e., ADAMS Accession Number ML010380479).

PT-02 Page 6 ofl0

BSEP 08-0010 Enclosure 2

8. References
1. Title 10 of the Code of Federal Regulations, Part 50, Section 55a, Codes and Standards (i.e., 10 CFR 50.55a).
2. ASME Code,Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, 2001 Edition with 2003 Addenda.

PT-02 Page 7 of 10

BSEP 08-0010 Enclosure 2 Attachment 1 System Flow Diagram ILAFVRB

!4-4-M D.kw

- maw raw -~ -~

U W-TEfi Train A

'S S.W..W- Ch.*.

F- HPCI M41-V2 Train8 D04WV-FhiRCIC PT-02 Page 8 of 10

BSEP 08-0010 Enclosure 2 Attachment 2 Affected Components Line No. General Description SGT-1-18 SGT inlet piping from valves CAC-V8, -V22, -V10, -V23, SGT-2-18 -V50, and E41-V60 SGT-2A-18 The discharge piping from the filter banks (A/B) extending to SGT-3-18 the plant stack SGT-3A-18 SGT-4-18 SGT-4A-18 SGT-5-18 SGT-5A-18 SGT-6-24 SGT-6A-24 SGT-8-24 SGT-9-24 SGT-10-30 SGT-11-18 SGT-7-24-159A E41-44-2-152 High Pressure Coolant Injection (HPIC) piping from valve V60 (Barometric Condenser vacuum pump discharge)

CAC- 16-2-152 (V22) Containment Atmosphere Control (CAC) piping extending CAC-'17-2-152 (V23) from the Drywell and Suppression Chamber penetration sleeve to the SGT piping CAC-42-3-152 (V49)

CAC-42-4-152 (V50 CAC-6-18-152 (V9 & V1O)

CAC-5-20-152 (V7& V8)

CAC-75-8-152 (V216)

PT-02 Page 9 of 10

BSEP 08-0010 Enclosure 2 Attachment 2 Affected Components Line No. General Description Miscellaneous Lines Instrument lines extending to and including the first root valve that will isolate the instrument.

Vent, test, and drain lines extending to and including the first normally closed Valve.

PT-02 Page 10 of 10

BSEP 08-0010 Enclosure 2 10 CFR 50.55a Request Number CIP-01 Proposed Alternative In Accordance with 10 CFR 50.55a(a)(3)(i)

- Acceptable Level of Quality and Safety -

1. ASME Code Components Affected Code Class: Class MC Category: E-A, Containment Surfaces System: Pressure Suppression System (Drywell, Suppression Chamber, Vent System)

Affected Components: See Attachment 1 for a listing of affected components

2. Applicable Code Edition and Addenda

The Code of Record for the fourth 10-year inservice inspection interval at the Brunswick Steam Electric Plant (BSEP), Units 1 and 2, is the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code,Section XI, 2001 Edition with 2003 Addenda.

The fourth 10-year inservice inspection interval begins May 11, 2008, and will conclude on May 10, 2018.

3. Applicable Code Requirement

The ASME Code,Section XI, paragraph IWE-5221 requires repair/replacement activities performed on the pressure retaining boundary of Class MC or Class CC components be subjected to a pneumatic leakage test in accordance with the provisions of Title 10, Part 50 of the Code of Federal Regulations (10 CFR 50), Appendix J, Paragraph IV.A

4. Reason for Request

By reference to paragraph IV.A of Appendix J, paragraph IWE-5221 of the ASME Code,Section XI, requires the prescriptive testing requirements of 10 CFR Part 50, Appendix J, Option A to be performed following a repair/replacement activities.

The Technical Specifications for BSEP Units 1 and 2 were amended to permit the use of 10 CFR 50, Appendix J, Option B for Type A, B, and C testing. Option B of Appendix J also has requirements for leakage rate testing following repairs, replacements, and modifications that affect the containment leakage integrity.

CIP-01 Page 1 of 10

BSEP 08-0010 Enclosure 2

5. Proposed Alternative and Basis for Use Proposed Alternative Repair, replacement, or modification activities, that affect the containment leakage integrity of the components identified in Attachment 1, will be subjected to the applicable leakage rate testing requirements specified in Nuclear Energy Institute (NEI) 94-01.

Basis for Use Compliance with 10 CFR 50, Appendix J provides assurance that components associated with primary containment do not exceed the allowable leakage rate values specified in the Technical Specifications and Bases. The allowable leakage rate is determined so that the leakage assumed in the safety analyses is not exceeded.

In 1992, the NRC published a notice in the Federal Register (i.e., 57 FR 4166) discussing a planned initiative to eliminate requirements marginal to safety which impose a significant regulatory burden. Appendix J of 10 CFR 50 was considered for this initiative, and the NRC undertook a study of the possible changes to this regulation. The results of this study are reported in NUREG- 1493, "Performance-Based Containment Leak-Test Program."

Based on the results of this study, the NRC developed'a performance based approach to containment leakage rate testing. This performance based approach was incorporated into Appendix J as Option B. The use of Option B became effective in 1995 and allowed licensees to voluntarily replace the existing prescriptive testing requirements i.e., (now referred to as Option A) of Appendix J.

Regulatory Guide 1.163 was developed as a method acceptable to the NRC staff for implementing Option B of 10 CFR 50, Appendix J. This regulatory guide states that NEI 94-01 provides acceptable methods for complying with Option B.

Option B requires that the regulatory guide or other implementation documents used by a licensee to develop a performance based leakage testing program be included in the plant Technical Specifications.

By letter dated February 1, 1996, the NRC staff approved the issuance of Amendment No. 181 and Amendment No. 213 for Unit 1 and Unit 2 Technical Specifications, respectively. These amendments permitted the use of Option B for Type A, B, and C testing.

The amendment to 10 CFR 50, Appendix J and the issuance of the Technical Specifications amendments acknowledged the Option B testing program as an acceptable alternative to the prescriptive (i.e., Option A) requirements. For this reason, containment repair, replacement, or modification activities will be subjected to the leakage rate testing requirements specified in NEI 94-01 (i.e., Option B). Subjecting these activities to the requirements of Option B will be consistent with the plant's Technical Specifications, and CIP-01 Page 2 of 10

BSEP 08-0010 Enclosure 2 will also provide an acceptable level of quality and safety pursuant to 10 CFR 50.55a(a)(3)(i).

6. Duration of Proposed Alternative Use of the alternative is proposed for the fourth 10-yea'r inservice inspection interval which will begin on May 11, 2008, and will conclude on May 10, 2018.
7. Precedents None
8. References
1. 10 CFR 50, Appendix J, Option A, Prescriptive Requirements.
2. 10 CFR 50, Appendix J, Option B, Performance Based Requirements.
3. Regulatory Guide 1.163, Performance Based Containment Leak Test Program.
4. NUREG-1493, Performance Base Leak Test Program.
5. NEI 94-10, Industry Guideline for Implementing Performance Based Option of 10 CFR 50, Appendix J.
6. ASME Code,Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, 2001 Edition with 2003 Addenda.
7. NRC letter from David C. Trimble (NRC), 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), February 1, 1996.

CIP-01 Page 3 of 10

BSEP 08-0010 Enclosure 2 Component Description Component Description No. No.

DW-H Drywell Head DW-X1O1D Electrical Penetration DW-H-BC Drywell-to-Drywell Head DW-X1O1E Spare Penetration

- Bolted Connection DW-ML-1 Drywell Metallic Liner DW-X1O1F Electrical Penetration DW-ML-2 Drywell Metallic Liner DW-X102A Electrical Penetration DW-ML-3 Drywell Metallic Liner DW-X102B Electrical Penetration DW-ML-4 Drywell Metallic Liner DW-X102C Electrical Penetration DW-ML-5 Drywell Metallic Liner DW-X102D Spare Penetration DW-ML-6 Drywell Metallic Liner DW-X102E Electrical Penetration DW-ML-7 Drywel' Metallic Liner DW-X102F Electrical Penetration DW-ML-8 Drywell Metallic Liner DW-X102G Spare Penetration DW-ML-8a Drywell Metallic Liner DW-XI 02H Electrical Penetration (Bottom Flange &

Stiffeners)

DW-X1 Equipment Hatch DW-X103A Electrical Penetration I)W-X1-BC Equipment Hatch - Bolted DW-X103B Electrical Penetration Connection DW-X2 Personnel Airlock DW-X103C Spare Penetration I)W-X2-BC Personnel Airlock-to- DW-X104A Electrical Penetration Penetration Sleeve -

Bolted Connection DW-X3A Spare Penetration DW-X104B Electrical Penetration D)W-X3A-BC Spare Penetration Sleeve - DW-X104C Electrical Penetration Bolted Connection DW-X4 Drywell Head Access DW-X104D Spare Penetration Hatch I )W-X4-BC Drywell Head Access DW-X104E Electrical Penetration Hatch - Bolted Connection DW-X5A Vent Line To Penetration DW-X104F Electrical Penetration X201A DW-X5B Vent Line To Penetration DW-X104G Electrical Penetration X201B CIP-01 Page 4 of 10

BSEP 08-0010 Enclosure 2 Component Description Component Description No. No.

DW-X5C Vent Line To Penetration DW-X105A Spare Penetration X201C DW-X5D Vent Line To Penetration DW-X105B Electrical Penetration X201D DW-X5E Vent Line To Penetration DW-X105C Electrical Penetration X201E DW-X5F Vent Line To Penetration DW-X105D Electrical Penetration X201F DW-X5G Vent Line To Penetration DW-X105E Electrical Penetration X201G DW-X5H Vent Line To Penetration DW-X105F Drywell Pressure X201H Penetration DW-X6 CRD Removal Hatch DW-X105G Electrical Penetration DW-X6-BC CRD Removal Hatch - DW-X105H Electrical Penetration Bolted Connection DW-X7A Main Steam Penetration - DW-X105J Electrical Penetration A Line DW-X7B Main Steam Penetration - DW-X105K Electrical Penetration B Line DW-X7C Main Steam Penetration - SC-X200A South Torus Access Hatch C Line DW-X7D Main Steam Penetration - SC-X200A- South Torus Access Hatch -

D Line BC Bolted Connection DW-X8 Main Steam / Condensate SC-X200B North Torus Access Hatch Drains Penetration DW-X9A Feedwater Penetration - A SC-X200B- North Torus Access Hatch -

Loop BC Bolted Connection DW-X9B Feedwater Penetration - B SC-X203 Spare Penetration Loop DW-XIO RCIC Steam Penetration SC-X206A H2&02/Suppression Pool Level Penetration DW-X11 HPCI Steam Penetration SC-X206B Suppression Pool Level/Spare Penetration.

DW-X12 ,RHR Pump Shutdown SC-X206C Suppression Pool Supply Penetration Level/Spare Penetration CIP-01 Page 5 of 10

BSEP 08-0010 Enclosure 2 Component Description Component Description No. No.

DW-X13A RHR-LPCI to Reactor SC-X206D Suppression Pool Penetration - A Loop Level/Spare Penetration DW-X13B RHR-LPCI to Reactor SC-X209A PASS/Spare Penetration Penetration - B Loop DW-X14 RWCU Supply SC-X209B H2&02/Spare Penetration Penetration DW-X15 Spare Penetration SC-X21OA RHR Max Flow Test Line Penetration - A Loop DW-X16A CS Discharge Penetration SC-X210B RHR Max Flow Test Line

- A Loop Penetration - B Loop DW-X16B CS Injection Penetration - SC-X211A RHR Suppression Spray B Loop Penetration - A Loop DW-X17 Abandoned RHR Head SC-X211B RHR Suppression Spray Spray Penetration Penetration - B Loop DW-X18 Floor Drain Pump SC-X212 RCIC Turbine Exhaust Discharge Penetration Penetration DW-X19 Equipment Drain Pump SC-X214 HPCI Turbine Exhaust Discharge Penetration Penetration DW-X20 Spare Penetration SC-X216 RCIC Vacuum Breaker Penetration DW-X21 Spare Penetration SC-X217 Spare Penetration DW-X22 Power Operator Test SC-X218 HPCI Vacuum Breaker Penetration Penetration DW-X23 RBCCW Pump Supply SC-X221 Spare Penetration Penetration DW-X24 RBCCW Pump Return SC-X222 HPCI Exhaust Drain Pot Penetration Penetration DW-X35A TIP Drives Penetration SC-X223A CS Test Line Penetration - A Loop DW-X35B TIP Drives Penetration SC-X223B CS Test Line Penetration -

B Loop DW-X35C TIP Drives Penetration SC-X224 RCIC Pump Suction Penetration DW-X35D TIP Drives Penetration SC-X225A RHR Pump Suction Penetration - A Loop CIP-O1 Page 6 of 10

BSEP 08-0010 Enclosure 2 Component Description Component Description No. No.

DW-X35E TIP Purge Line SC-X225B RHR Pump Suction Penetration Penetration - B Loop DW-X36 Spare Penetration SC-X226 HPCI Pump Suction Penetration DW-X37A CRD Insert Penetration SC-X227A CS Pump Suction Penetration - A Loop

.DW-X37B CRD Insert Penetration SC-X227B CS Pump Suction Penetration - B Loop DW-X37C CRD Insert Penetration SC-X229A Spare Penetration DW-X37D CRD Insert Penetration SC-X229B Spare Penetration DW-X38A CRD Withdraw SC-X229C Spare Penetration Penetration DW-X38B CRD Withdraw SC-X230 Spare Penetration Penetration DW-X38C CRD Withdraw SC-X232A Electrical Penetration Penetration DW-X38D CRD Withdraw SC-X232B Electrical Penetration Penetration DW-X39A RHR Containment Spray SC-X232C Electrical Penetration Penetration - A Loop DW-X39B RHR Containment Spray SC-X232D Electrical Penetration Penetration - B Loop DW-X42 SLC Penetration SC-X240 Spare Penetration DW-X43 Spare Penetration SC-X241 Instrument Penetration DW-X45 Spare Penetration SC-X242 Spare Penetration DW-X47 Spare Penetration SC-X243 Instrument Penetration DW-X48 Spare Penetration SC-X244 Instrument Penetration DW-X49A RPV Level & Pressure SC-X245 Instrument Penetration Penetration DW-X49B RPV Level & Pressure SC-ML-B1 Suppression Chamber Penetration Metallic Liner (Above &

Below Water Line)

CIP-01 Page 7 of 10

BSEP 08-0010 Enclosure 2 Component Description Component Description No. No.

DW-X51 Drywell Pressure SC-ML-B2 Suppression Chamber Penetration Metallic Liner (Above &

Below Water Line)

DW-X52 N2 Backup Penetration SC-ML-B3 Suppression Chamber Metallic Liner (Above &

Below Water Line)

DW-X53 RPV Level & Pressure SC-ML-B4 Suppression Chamber Penetration Metallic Liner (Above &

Below Water Line)

DW-X54 Steam Flow/Rad Monitor SC-ML-B5 Suppression Chamber Penetration Metallic Liner (Above &

Below Water Line)

DW-X55 Instrument Air Penetration SC-ML-B6 Suppression Chamber Metallic Liner (Above &

Below Water Line)

DW-X56 Steam Flow/Sample Line SC-ML-B7 Suppression Chamber Penetration Metallic Liner (Above &

Below Water Line)

DW-X57 H2&02/Drywell Pressure SC-ML-B8 Suppression Chamber Penetration Metallic Liner (Above &

Below Water Line)

DW-X58 Jet Pump Flow SC-ML-B9 Suppression Chamber Penetration Metallic Liner (Above &

Below Water Line)

DW-X59 Jet Pump Flow SC-ML-B10 Suppression Chamber Penetration Metallic Liner (Above &

Below Water Line)

DW-X60 HPCI Steam/H2&02 SC-ML-Bl1 Suppression Chamber Monitor Penetration Metallic Liner (Above &

Below Water Line)

DW-X61 RCIC Steam/Core SC-ML-B12 Suppression Chamber Pressure Penetration Metallic Liner (Above &

Below Water Line)

DW-X62 Recirc Pump A Seal Purge SC-ML-B13 Suppression Chamber Penetration Metallic Liner (Above &

Below Water Line)

CIP-01 Page 8 of 10

BSEP 08-0010 Enclosure 2 Component Description Component Description No. No.

DW-X65 Spare Penetration SC-ML-B14 Suppression Chamber Metallic Liner (Above &

Below Water Line)

DW-X68 Spare Penetration SC-ML-B15 Suppression Chamber Metallic Liner (Above &

Below Water Line)

DW-X69 RPV Level & Pressure SC-ML-B 16 Suppression Chamber Penetration Metallic Liner (Above &

Below Water Line)

DW-X70 HPCI Steam Flow SC-VH-B1 Vent Header Penetration DW-X71 Instrument Air Penetration SC-VH-B2 Vent Header DW-X72 RCIC Steam SC-VH-B3 Vent Header Pressure/Core Pressure Penetration DW-X73 H2&02 Monitor/CS SC-VH-B4 Vent Header Sparger Pressure Penetration DW-X74 Jet Pump Flows SC-VH-B5 Vent Header Penetration DW-X75 Jet Pump Flows SC-VH-B6 Vent Header Penetration DW-X76 Stream Line Flow/Rad SC-VH-B7 Vent Header Monitor Penetration DW-X77 Stream Line Flow/Recirc SC-VH-B8 Vent Header Pump Sample Penetration DW-X78 Recirc Pump B Seal Purge SC-VH-B9 Vent Header Penetration DW-X79 Spare Penetration SC-VH-B10 Vent Header DW-X80 Spare Penetration SC-VH-B11 Vent Header DW-X81 Spare Penetration SC-VH-B12 Vent Header DW-X82 CS Sparger/RPV Level SC-VH-B 13 Vent Header Penetration DW-X83 RPV Level/Drywell Level SC-VH-B14 Vent Header

& Pressure Penetration CIP-01 Page 9 of 10

BSEP 08-0010 Enclosure 2 Component Description Component Description No. No.

DW-X 1OOA Electrical Penetration SC-VH-B 15 Vent Header DW-XI100B Electrical Penetration SC-VH-BC Vent Header Manway -

Bolted Connection DW-X1OOC Electrical Penetration SC-VH-B16 Vent Header DW-X1OOD Electrical Penetration SC-EB-B1 Vent Line DW-X5E/X201E Expansion Bellow DW-X1OOE Electrical Penetration SC-EB-B3 Vent Line DW-X5F/X201F Expansion Bellow DW-X1OOF Electrical Penetration SC-EB-B5 Vent Line DW-X5G/X201G Expansion Bellow DW-X1OOG Electrical Penetration SC-EB-B7 Vent Line DW-X5H/X201H Expansion Bellow DW-X1OOH Electrical Penetration SC-EB-B9 Vent Line DW-X5A/X201A Expansion Bellow DW-X1O1A Electrical Penetration SC-EB-B 11 Vent Line DW-X5B/X201B Expansion Bellow DW-X101B Spare Penetration SC-EB-B13 Vent Line DW-X5C/X201C Expansion Bellow DW-X1O1C Electrical Penetration SC-EB-B15 Vent Line DW-X5D/X201D Expansion Bellow CIP-01 Page 10 of 10

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