L-PI-14-085, 10CFR 50.55a Requests Associated with the Fifth Ten-Year Interval for the Inservice Inspection Program

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10CFR 50.55a Requests Associated with the Fifth Ten-Year Interval for the Inservice Inspection Program
ML14258A073
Person / Time
Site: Prairie Island  Xcel Energy icon.png
Issue date: 09/15/2014
From: Davison K
Northern States Power Co, Xcel Energy
To:
Document Control Desk, Office of Nuclear Reactor Regulation
References
L-PI-14-085
Download: ML14258A073 (25)
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Text

Xcel Energy SEP .1 5 2014 L-PI-14-085 10 CFR 50.55a U S Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001 Prairie Island Nuclear Generating Plant Units 1 and 2 Dockets 50-282 and 50-306 Renewed License Nos. DPR-42 and DPR-60 10 CFR 50.55a Requests Associated with the Fifth Ten-Year Interval for the lnservice Inspection Program Pursuant to 10 CFR 50.55a, Northern States Power Company, a Minnesota corporation, doing business as Xcel Energy (hereafter "NSPM"), hereby requests NRC approval of 10 CFR 50.55a Requests numbered 1-RR-5-1, 2-RR-5-1, 1-RR-5-2, 2-RR-5-2, 1-RR 3, 2-RR-5-3, 1-RR-5-5, 2-RR-5-5, 1-RR-5-6, and 2-RR-5-6 for the fifth ten-year interval for the Prairie Island Nuclear Generating Plant (PINGP), Units 1 and 2, lnservice Inspection (lSI) Program. The details of these 10 CFR 50.55a requests are provided in the enclosure to this letter. Requests 1-RR-5-1, 2-RR-5-1, 1-RR-5-2, and 2-RR-5-2 were previously approved by the NRC for the PINGP fourth ten-year lSI Program interval; requests 1-RR-5-6 and 2-RR-5-6 were recently submitted for NRC review and approval for the PINGP fourth ten-year lSI Program interval; the correlation of previous request numbers is shown on page 1 of the enclosure. The remaining requests are new for the PINGP fifth ten-year lSI Program interval.

NSPM requests approval of these 10 CFR 50.55a requests by September 15, 2015, to support examinations in the first unit refueling outage in the PINGP fifth ten-year lSI Program interval.

If there are any questions or if additional information is needed, please contact Mr. Dale Vincent, P.E., at 651-267-1736.

1717 Wakonade Drive East

  • Welch, Minnesota 55089-9642 Telephone: 651.388.1121

Document Control Desk Page 2 Summary of Commitments This letter contains no new commitments and no revisions to existing commitments.

Kevin Davison 1 Site Vice President, Prairie Island Nuclear Generating Plant Northern States Power Company - Minnesota Enclosures (1) cc: Administrator, Region Ill, USNRC Project Manager, PINGP, USNRC Resident Inspector, PINGP, USNRC

Enclosure 10 CFR 50.55a Requests (RR) Associated with Prairie Island Nuclear Generating Plant (PINGP) Fifth Ten-Year lntervallnservice Inspection (lSI) Program Pursuant to 10 CFR 50.55a, Northern States Power Company, a Minnesota corporation, doing business as Xcel Energy (hereafter "NSPM"), hereby requests NRC approval of 10 CFR 50.55a Requests listed in the table below for the fifth ten-year interval for the Prairie Island Nuclear Generating Plant (PINGP), Units 1 and 2, lnservice Inspection (lSI) Program.

Fifth Title Fourth Interval Interval RRNo. RRNo.

1-RR-5-1 Reactor Vessel Head Leak-off Line 1-RR-4-4 2-RR-5-1 2-RR-4-4 1-RR-5-2 Alternative Pressure Testing for Buried Components 1-RR-4-7 2-RR-5-2 2-RR-4-7 1-RR-5-3 Alternative Requirements for Bolting Affected by Borated Water Not 2-RR-5-3 Leakage Applicable 1-RR-5-5 Alternative Requirements for Pad Reinforcement of Class 2 Not 2-RR-5-5 and 3 Moderate Energy Carbon Steel Piping Applicable 1-RR-5-6 Alternative Requirements for Pressure Testing Safety Injection 1-RR-4-9 2-RR-5-6 (SI) Accumulator Nitrogen Piping in Containment 2-RR-4-9 Page 1 of 23 0 CFR 50.55a Requests 10 CFR 50.55a Request 1-RR-5-1 Rev. 0 (PINGP Unit 1)

I 10 CFR 50.55a Request 2-RR-5-1 Rev. 0 (PINGP Unit 2)

I Reactor Vessel Head Leak-off Line Proposed Alternative in Accordance with 10 CFR 50.55a (a)(3)(ii)

Hardship or Unusual Difficulty without Compensating Increase in Level of Quality or Safety

1. American Society of Mechanical Engineers (ASME) Code Component(s)

Affected Code Class: 1

Reference:

Table IWB-2500-1 Examination Category: B-P Item Number: B15.20

Description:

Nominal pipe size (NPS) 1 inch reactor vessel flange leak-off connection from reactor vessel flange to 3/8Jnch reducers Component Number: Unit 1: Line Nos. 1-RC-9A and -9B Unit 2: Line Nos. 1-2RC-9A and -9B

2. Applicable Code Edition and Addenda

PINGP Units 1 and 2 will start the Fifth 10-Year lnservice Inspection (lSI) Program interval on December 21, 2014, and is required to follow the ASME Boiler and Pressure Vessel Code,Section XI, "Rules for lnservice Inspection of Nuclear Power Plant Components," (ASME Section XI), 2007 Edition through the 2008 Addenda.

3. Applicable Code Requirement

The 2007 Edition through the 2008 Addenda of ASME Section XI contains Table IWB-2500-1, Examination Category B-P, and Item Number B15.20 which requires a system leakage test meeting the requirements of IWB-5220. The pressure test frequency is once per inspection interval.

IWB-5221 states "The system leakage test shall be conducted at a pressure not less than the pressure corresponding to 100% rated reactor power."

4. Reason for Request

lnservice inspection of ASME Code Class 1, 2, and 3 components is performed in accordance with Section XI of the ASME Boiler and Pressure Vessel Code (ASME Code) and applicable addenda as required by 10 CFR 50.55a(g), except where specific written relief has been granted by the NRC pursuant to Page 2 of 23 0 CFR 50.55a Requests 1-RR-5-1 and 2-RR-5-1 (continued) 10 CFR 50.55a(g)(6)(i). 10 CFR 50.55a(a)(3) states that alternatives to the requirements of paragraph (g) may be used, when authorized by the NRC, if the licensee demonstrated that (i) the proposed alternatives would provide an acceptable level of quality and safety or (ii) compliance with the specified requirements would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety.

Pursuant to 10 CFR 50.55a(g)(4), ASME Code Class 1, 2, and 3 components (including supports) shall meet the requirements, except the design and access provisions and the preservice examination requirements, set forth in the ASME Code,Section XI, "Rules for lnservice Inspection of Nuclear Power Plant Components", to the extent practical within the limitations of design, geometry, and materials of construction of the components. The regulation requires that inservice examination of components and system pressure test conducted during the first 10-year inspection interval and subsequent intervals comply with the requirements in the latest edition and addenda of Section XI of the ASME Code incorporated by reference in 10 CFR 50.55a(b) 12 months prior to the start of the 120-month (10 year) interval (or optional ASME code cases listed in NRC Regulatory Guide 1.147, Revision 16, that are incorporated by reference in 10 CFR 50.55a(b)), subject to the conditions listed therein. The code of record for the fifth 10-year interval for PINGP is the 2007 Edition through the 2008 Addenda of Section XI.

The reactor pressure vessel head flange leakage detection system consists of two lines piped to a common temperature element. One line is piped from the space between the two concentric reactor vessel flange 0-rings and the other is piped from outside the second 0-ring. Leakage is indicated by a control room temperature alarm at 140 °F. Manipulation of the associated valves allows the plant operators to determine if potential leakage is past the inner 0-ring, or past both 0-rings.

The configuration of this system precludes manual testing while the vessel head is removed because the odd configuration of the vessel taps, combined with the small size of the tap and the high test pressure requirement (2235 psig minimum), which prevent the taps in the flange from being temporarily plugged. Failure of this seal could possibly cause ejection of the device used for plugging the vessel taps. Machining, installing and removing the plugs or pressure connections would require significant time at the vessel flange and excessive dose. The plug or pressure connection itself would also introduce a foreign material exclusion issue at the edge of the open reactor vessel. Plugging or installing a connection would require machining threads in each flange opening with a concern over chips that may become a foreign material threat for fuel integrity or in the lines themselves.

The top head of the vessel contains two grooves that hold the 0-rings. The 0-rings are held in place by a series of retainer clips. The retainer clips are contained in a recessed cavity in the top head. If a pressure test was performed from the leak-off line side with the head on, the inner 0-ring would be pressurized in a direction opposite to Page 3 of 23 0 CFR 50.55a Requests 1-RR-5-1 and 2-RR-5-1 (continued) its normal operation. This test pressure would result in a net inward force on the 0-ring that would tend to push it into the recessed cavity that houses the retainer clips. The 0-ring material includes a thin silver plating and could very likely be damaged by this deformation into the recessed areas on the top head.

The use of a pneumatic test performed at a minimum of 2235 psig would represent an unnecessary safety risk for the inspectors and test engineers in the unlikely event of a test failure, due to the large amount of stored energy contained in air pressurized to 2235 psig. System leakage testing of these lines at power is not an option because the lines will only be pressurized in the event of a failure of the inner 0-ring. The following Figure 1 provides the configuration of the two seals and respective leak-off lines.

Figure 1 1-:----REACTOO HEAD FLANGe 0 RINGS REACTOR VESSEl.: CLAIIOO LEAK*OETECTION TIJilES _..-'

TO RCOT

5. Proposed Alternative and Basis for Use Pursuant to 10 CFR 50.55a(a)(3)(ii), relief is requested from the provisions of Table IWB-2500-1, Category B-P, Item No. 815.20, on the basis that compliance with the specified requirements would result in a hardship or unusual difficulty without a compensating increase in the level of quality and safety. NSPM proposes to perform a VT-2 visual examination of accessible portions of the reactor vessel flange leak-off Page 4 of 23 0 CFR 50.55a Requests 1-RR-5-1 and 2-RR-5-1 (continued) lines during the regularly scheduled Class 1 system pressure test that is performed following each refueling outage (in lieu of the code required frequency of each inspection interval). The reactor vessel flange leak-off lines will not be pressurized, during the VT-2 visual examinations. However, the examination will be conducted subsequent to pressurization of the reactor vessel flange leak-off lines with borated water during the refueling operations. During refueling operations, the reactor vessel flange leak-off lines are pressurized due to the static head in the reactor cavity to approximately 10 psig. Since borated water leaves a crystalline residue, the proposed VT-2 visual examination each refueling outage provides reasonable assurance of structural integrity since through-wall leakage in the reactor vessel flange leak-off lines will be promptly detected and corrected in accordance with IWA-4000.

NSPM proposes to perform VT-2 examination of the unpressurized reactor vessel flange leak-off lines each refueling outage as an alternative to the requirement to perform pressurized VT-2 examination once each 10-year inspection interval as required by Table IWB-2500-1, Category B-P, item 815.20.

6. Duration Of Proposed Alternative Relief is requested for the fifth 10-year inspection interval of the lnservice Inspection Program for PINGP Units 1 and 2. The fifth interval is effective for Units 1 and 2 from December 21, 2014 through December 20, 2024.
7. Precedents
1. Diablo Canyon Power Plant, Unit Nos. 1 and 2, Docket Nos. 50-275 and 50-323, "Relief Request No. RVFLNG-INT3- U1 & U2- Alternative to ASME Code,Section XI Pressure Test Requirements for Class 1 Reactor Vessel Flange Leakoff Lines", (TAG Nos. MF0408 and MF0409), dated September 12, 2013 (ML13192A354).
2. Prairie Island Nuclear Generating Plant, Units 1 and 2, Docket Nos. 50-282 and 50-306, "Evaluation of Relief Request Nos. 1-RR-4-4 and 2-RR-4-4 for the Fourth 10-Year lnservice Inspection Interval", (TAG Nos. MC3663 and MC3664) dated April27, 2005 (ML050960187).

Page 5 of 23 0 CFR 50.55a Requests 10 CFR 50.55a Request 1-RR-5-2, Rev. 0 (PINGP Unit 1) 10 CFR 50.55a Request 2-RR-5-2, Rev. 0 (PINGP Unit 2)

Alternative Pressure Testing for Buried Components Proposed Alternative in Accordance with 10 CFR 50.55a (a)(3)(ii)

Hardship or Unusual Difficulty without Compensating Increase in Level of Quality or Safety

1. ASME Code Component(s) Affected Code Class: 3

Reference:

IWA-5244 Examination Category: D-B Item Number: D2.10

Description:

Class 3 Buried Pressure Retaining Components Component Number: Lines 30-CL-20 and 30-CL-23

2. Applicable Code Edition and Addenda

PINGP Units 1 and 2 will start the Fifth 10-Year lSI Program interval on December 21, 2014 and is required to follow the ASME Boiler and Pressure Vessel Code,Section XI, "Rules for lnservice Inspection of Nuclear Power Plant Components," (ASME Section XI), 2007 Edition through the 2008 Addenda.

3. Applicable Code Requirement

ASME Section XI, 2007 Edition through the 2008 Addenda of ASME Section XI, IWD-2500 Table IWD-2500-1 requires a system leakage test of the pressure retaining boundary of Class 3 components once each inspection period of the lSI 10-year interval. The system pressure tests and visual examinations shall be conducted in accordance with IWA-5000 and IWD-5000. A portion of the cooling water (CL) system is buried and IWA-5244, "Buried Components" applies which provides the requirements for those components that are buried.

IWA-5244(a) states, "For buried components surrounded by an annulus, the VT-2 visual examination shall consist of an examination for evidence of leakage at each end of the annulus and at low point drains."

IWA-5244(b) states:

For buried components where a VT-2 visual examination cannot be performed, the examination requirement is satisfied by the following:

Page 6 of 23 0 CFR 50.55a Requests 1-RR-5-2 and 2-RR-5-2 (continued)

(1) The system pressure test for buried components that are isolable by means of valves shall consist of a test that determines the rate of pressure loss.

Alternatively, the test may determine the change in flow between the ends of the buried components. The acceptable rate of pressure loss or flow shall be established by the Owner.

(2) The system pressure test for nonisolable buried components shall consist of a test to confirm that flow during operation is not impaired.

(3) Test personnel need not be qualified for VT-2 visual examination.

4. Reason for Request

lnservice inspection of ASME Code Class 1, 2, and 3 components is performed in accordance with Section XI of the ASME Boiler and Pressure Vessel Code (ASME Code) and applicable addenda as required by 10 CFR 50.55a(g), except where specific written relief has been granted by the NRC pursuant to 10 CFR 50.55a(g)(6)(i). 10 CFR 50.55a(a)(3) states that alternatives to the requirements of paragraph (g) may be used, when authorized by the NRC, if the licensee demonstrated that (i) the proposed alternatives would provide an acceptable level of quality and safety or (ii) compliance with the specified requirements would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety.

Pursuant to 10 CFR 50.55a(g)(4), ASME Code Class 1, 2, and 3 components (including supports) shall meet the requirements, except the design and access provisions and the preservice examination requirements, set forth in the ASME Code,Section XI, "Rules for lnservice Inspection of Nuclear Power Plant Components, "to the extent practical within the limitations of design, geometry, and materials of construction of the components. The regulations require that inservice examinations of components and system pressure tests conducted during the first 10-year inspection interval and subsequent intervals comply with the requirements in the latest edition and addenda of Section XI of the ASME Code incorporated by reference in 10 CFR 50.55a(b) 12 months prior to the start of the 120-month (10 year) interval (or optional ASME code cases listed in NRC Regulatory Guide 1.147, Revision 16, that are incorporated by reference in 10 CFR 50.55a(b)), subject to the conditions listed therein. The code of record for the fifth 10-year interval for PINGP is the 2007 Edition through the 2008 Addenda of Section XI.

The CL system is designed to provide redundant cooling water supplies with isolation valves to auxiliary feedwater pumps, Unit 1 emergency diesel generators, air compressors, component cooling water heat exchangers, containment fan-coil units, and the Auxiliary Building unit coolers. Two diesel driven CL pumps (DDCLP) and a vertical motor driven CL pump (MDCLP) are located in the CL Screen House. A supply ring header which is shared by Units 1 and 2 can be isolated automatically to provide two redundant independent sources of CL for all essential services. One-half of the essential services for each unit are supplied from each side of the isolable loop.

Page 7 of 23 0 CFR 50.55a Requests 1-RR-5-2 and 2-RR-5-2 (continued)

Each side of the loop is designed to supply the needs for all essential services for both units. Thus, failure of one side of the loop still provides for the operation of all equipment required for the safe shutdown of both units. PINGP Technical Specification (TS) 3.7.8 requires both trains of CL to be operable in Modes 1, 2, 3 and 4. A single train may be inoperable for 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />; both trains may be inoperable only if both units are in Mode 5 (cold shutdown). As such, taking the CL headers out of service to perform internal examination or install components and instrumentation to facilitate testing presents a hardship, as it requires both units to be shutdown.

A portion of the CL supply ring header extends underground from the Screen House to the Turbine Building. Part of this buried piping is under the Administration Building.

These lines of buried piping are CL lines 30-CL-20 and 30-CL-23. No branch lines are buried. The total approximate length of buried piping is 200 feet. This piping is protected by a cathodic protection system.

Instrumentation upstream of the buried piping consists of pressure indication at the discharge of the CL pumps. No flow instrument exists upstream on the supply header.

Downstream of the buried piping a flow meter exists on the main header in the Turbine Building. Isolation of the buried portion of piping would include two 18" butterfly valves and two 24" butterfly valves on each supply line. These valves were only intended to provide isolation for maintenance activities with only static system pressure and not normal operating pressure as required by IWD-5221. This position is supported by an ASME Section XI interpretation Xl-1-07 -28 which states:

Question: Does the requirement of IWA-5244(b)(2) apply to buried components with valves that are not capable of isolating the portion of the component under test?

Reply: Yes In 1992, a modification replaced the underground portions of piping with 30" diameter,

%inch thick, A-106 carbon steel piping. An epoxy interior coat was applied for additional protection to prolong pipe life. A portion of the CL supply header was not excavated during this modification. Those portions of the CL piping embedded in concrete at the Screen House and short segments of pipe at the Administration Building and Turbine Building interface were left in place and a weld overlay added in localized areas.

The CL buried piping does not have an annulus and is not accessible for examination without excavation. Based on the absence of an annulus and the fact that the lines are isolable, IWA-5244(b)(1) applies to the CL buried piping. This subparagraph requires either a test to determine the rate of pressure loss, or a test to determine the change in flow between the ends of the buried components.

To implement a pressure loss test, closure of several large butterfly valves would be required to isolate the buried portions of piping. This would isolate one CL supply Page 8 of 23 0 CFR 50.55a Requests 1-RR-5-2 and 2-RR-5-2 (continued) header. Isolating one CL supply header requires entry into the Technical Specification (TS) 3.7.8 Condition B (TS 3.7.8 B). The required action forTS 3.7.8 B requires restoration of the supply headers in 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. Entering TS 3. 7.8 B requires Unit 1 to enter the applicable conditions and required actions of TS 3.8.1 for the Unit 1 emergency diesel generator made inoperable by the CL system inoperability. Entering TS 3.7.8 B also requires Units 1 and 2 to enter the applicable conditions and required actions of TS 3.4.6 for residual heat removal loops made inoperable by CL system inoperability, if the unit is in Mode 4. In addition to placing the units in an undesirable condition, the butterfly valves required for isolation of the supply header are not expected to provide an adequate test boundary necessary to conduct a pressure decay test. Extensive maintenance or system modification would be required to perform an adequate pressure decay test, as it would be necessary to either replace the existing butterfly valves with those of better leakage characteristics or to install blind flanges.

The other test option provided by the Code is a change in flow test. However, the CL supply headers were not designed with plant instrumentation and flow orifices on the exposed ends of piping, which are required to determine the change in flow rates. In addition, sufficient lengths of accessible straight pipe for reliable use of ultrasonic flow meters do not exist. Installation of permanent flow instruments would require system modifications. For these reasons, the configuration of the CL system will not allow determining the change in flow between the ends of the buried piping.

Performing the specified examinations or testing would require either excavating the buried piping, entering multiple TS action statements, or performing major modifications to system piping. Therefore, compliance with the specified requirements is a hardship without a compensating increase in the level of quality and safety.

5. Proposed Alternative and Basis for Use Pursuant to 10 CFR 50.55a(a)(3)(ii), relief is requested from the provisions of IWA-5244(b)(1), on the basis that compliance with the specified requirements would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety. NSPM proposes to use the alternative requirements of Code Case N-776 which allows confirmation that flow during operation is not impaired to verify the integrity of the buried piping and performing a VT-2 visual examination to identify evidence of leakage on ground surfaces in the vicinity of the buried components and in areas where leakage might be channeled or accumulated.

The confirmation that flow is not impaired will be accomplished during quarterly pump testing. The safeguards CL pumps (12 and 22 DDCLP, and 121 MDCLP) are tested quarterly per the requirements of the lnservice Testing (1ST) Program. During these tests, the flow and pressure of the CL pumps are plotted against a test reference value.

The pressure is recorded at the discharge of the pump and flow measurements are recorded in the Turbine Building.

Page 9 of 23

Enclosure- I 0 CFR 50.55a Requests 1-RR-5-2 and 2-RR-5-2 (continued)

Head and flow rate are interdependent variables, which together define the pump hydraulic performance. As the pump degrades, the total discharge head will decrease at the reference flow rate. However, due to the location of the flow rate instruments (downstream of the buried piping), a decrease in pump head during testing may also indicate leakage from the CL system between the pump discharge and flow meter in the turbine building. A leak in the underground portion of the CL header would result in reduced pump performance on the pump curve. Satisfactory quarterly 1ST testing of the CL pump will verify the integrity of the buried piping.

If the performance of a CL pump drops below the reference range on the performance curve, and the cause of the deviation is not attributed to the test instruments being used, corrective actions will be initiated to evaluate the cause of the reduced performance as required by the PINGP 1ST Program. If the pump performance falls into the action range, the pump would be declared inoperable and further corrective actions (i.e., maintenance on the pump, system walk downs, etc.) would be initiated to restore the pump and/or system to an operable status.

If a pump is declared inoperable and later determined that the pump met applicable criteria, a further investigation into the cause of the apparent reduced performance would be performed. This could include aligning one of the other safeguards pumps to the affected header supply piping. Downstream flow and pump head during performance of these surveillance procedures are trended as part of the 1ST Program.

In addition to the periodic pump testing, a visual examination of the ground surface areas (includes surfaces of asphalt or other pavement materials) above the buried CL piping shall be performed on a refueling cycle basis. The system shall have been in operation at nominal operating conditions for at least 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to performing the VT-2 visual examination. VT-2 visual examinations of ground surface areas are capable of detecting through-wall leakage in buried components. This VT-2 visual examination along with the pump testing provides reasonable assurance of the structural and leak-tight integrity of the buried CL piping.

As an alternative to the requirements of IWA-5244 for buried pipe, NSPM requests approval to use the proposed Code Case N-776 to:

1) Perform a test that confirms that flow during operation is not impaired on the buried portion of CL piping in conjunction with the quarterly testing of the CL pumps, and
2) Perform a VT-2 visual examination of the ground surface areas above the buried CL piping as this will detect significant through-wall leakage if present and will provide reasonable assurance of operational readiness.

Page 10 of 23 0 CFR 50.55a Requests 1-RR-5-2 and 2-RR-5-2 (continued)

6. Duration of Proposed Alternative Relief is requested for the fifth 10-year inspection interval of the lSI Program for PINGP Units 1 and 2. The fifth interval is effective for Units 1 and 2 from December 21, 2014 through December 20, 2024.
7. Precedents
1. Duane Arnold Energy Center, Docket No. 50-331, "Reliefs from the Requirements of the ASME Boiler and Pressure Vessel Code for the Fourth 10-Year lnservice Inspection Interval" (specifically NDE-R007), dated March 1, 2013 (TAC No. ME7246) (ML13051A266).
2. Prairie Island Nuclear Generating Plant, Units 1 and 2, Docket Nos. 50-282 and 50-306, "Relief Request from ASME Code,Section XI, lnservice Inspection Program Relief Requests Nos. 1-RR-4-7 and 2-RR-4-7", dated October 31, 2007 (TAC Nos. MD3809 and MD3810) (ML072780026).

Page 11 of 23 0 CFR 50.55a Requests 10 CFR 50.55a Request 1-RR-5-3, Rev. 0 (PINGP Unit 1) 10 CFR 50.55a Request 2-RR-5-3, Rev. 0 (PINGP Unit 2)

Alternative Requirements for Bolting Affected by Borated Water Leakage Proposed Alternative in Accordance with 10 CFR 50.55a (a)(3)(i)

Alternate Provides Acceptable Level of Quality and Safety

1. ASME Code Component(s) Affected Code Class: 1, 2, and 3

Reference:

IWA-5250(a)(2)

Examination Category: B-P, C-H, and D-B Item Number: B15.10, B15.20, C7.10, and D2.10

Description:

Bolted Connections in Borated Systems Component Number: N/A

2. Applicable Code Edition and Addenda

PINGP Units 1 and 2 will start the Fifth 10-Year lSI Program interval on December 21, 2014 and is required to follow the ASME Boiler and Pressure Vessel Code,Section XI, "Rules for lnservice Inspection of Nuclear Power Plant Components," (ASME Section XI), 2007 Edition through the 2008 Addenda.

3. Applicable Code Requirement

Leakage identified during the pressure tests performed in accordance with Examination Categories B-P, CH and D-B is subject to corrective action to meet the requirements of IWA-5250, "Corrective Action". IWA-5250(a)(2) indicates that if leakage occurs at bolted connections in a system borated for the purpose of controlling reactivity, one of the bolts shall be removed and VT-3 examined and evaluated in accordance with IWA-31 00. The bolt removed shall be the one closest to the source of leakage. If the removed bolt has evidence of degradation, all of the remaining bolting in the connection is required to be removed, VT-3 examined and evaluated in accordance with IWA-31 00. As an alternative to IWA-5250(a)(2), IWA-5251, "Alternative Corrective Action for Leakage Identified at Bolted Connections", contains provisions for correcting the leak and performing an evaluation of joint integrity in lieu of removing the bolt for VT-3 examination.

4. Reason for Request

Pursuant to 10 CFR 50.55a(a)(3)(i), relief is requested from the requirements of ASME Section XI, IWA-5250(a)(2), on the basis that the proposed alternative provides an acceptable level of quality and safety.

Page 12 of 23 0 CFR 50.55a Requests 1-RR-5-3 and 2-RR-5-3 (continued)

5. Proposed Alternative and Basis for Use Proposed Alternative When a leak is identified at a bolted connection in systems borated for the purpose of controlling reactivity, NSPM proposes to either meet the requirements of IWA-5250(a)(2) or IWA-5251; or, stop the leak, address the cause of the leak using the NSPM corrective action program, and replace all of the bolting at the connection in accordance with IWA-4000. A VT-3 examination of the removed bolting will not be performed as all of the bolting will be discarded and not reused.

When implementing IWA-5250(a)(2), a VT-1 visual examination will be performed in lieu of the required VT-3 visual examination.

Basis for Use ASME Section XI Code Case N-775 was approved by the ASME on June 24, 2010 and published in Supplement 2 of the Nuclear Code Case Book. This code case provides an alternative to IWA-5250(a)(2). The code case requires the following to be completed:

(a.)Corrective action shall be taken to stop the leak. The cause of the leakage shall be addressed in accordance with the Owner's corrective action program.

(b.)AII pressure retaining bolting at the leaking connection shall be replaced in accordance with IWA-4000 (IWA-7000 in the 1989 Edition with the 1990 Addenda and earlier editions and addenda). VT -3 visual examination of the removed bolting is not required.

The fundamental purpose of performing the VT-3 of the bolt closest to the leak on systems borated for the purpose of controlling reactivity is to determine the condition of the remaining bolting which may affect the integrity of the connection. For those systems that are borated, leakage in contact with carbon steel bolting may corrode the bolting material and cause degradation. If all of the bolts are replaced, and the cause of any degradation is determined and addressed by the corrective action program, then the integrity of the connection is ensured. Taking corrective action to stop the leak and replacing all pressure retaining bolting provides reasonable assurance of structural integrity.

The performance of a VT-1 visual examination as an alternative to the required VT-3 visual examination provides an acceptable level of quality and safety.

As an alternative to the requirements of IWA-5250(a)(2) for corrective action of leakage at bolted connections in borated systems, NSPM requests approval to use the proposed Code Case N-775 to:

Page 13 of 23 0 CFR 50.55a Requests 1-RR-5-3 and 2-RR-5-3 (continued)

(a.) Take corrective action to stop the leak and address the cause of the leakage in the NSPM Corrective Action Program.

(b.) Replace all pressure retaining bolting at the leaking connection in accordance with IWA-4000.

6. Duration of Proposed Alternative Relief is requested for the fifth 10-year inspection interval of the In service Inspection Program for PINGP Units 1 and 2. The fifth interval is effective for Units 1 and 2 from December 21, 2014 through December 20, 2024 or until Code Case N-775 is approved by the NRC in Regulatory Guide 1.147. At that time Code Case N-775 will be applied to PINGP as approved by the NRC with any conditions identified.
7. Precedents Point Beach Nuclear Plant, Units 1 and 2, Docket Nos. 50-266 and 50-301, "Evaluation of Relief Requests RR-2 and RR-3", dated November 15, 2012 (TAC Nos. ME7974 and ME7975) (ML12286A104).

Page 14 of 23 0 CFR 50.55a Requests 10 CFR 50.55a Request 1-RR-5-5, Rev. 0 {PINGP Unit 1) 10 CFR 50.55a Request 2-RR-5-5, Rev. 0 {PINGP Unit 2)

Alternative Requirements for Pad Reinforcement of Class 2 and 3 Moderate Energy Carbon Steel Piping Proposed Alternative in Accordance with 10 CFR 50.55a {a)(3)(ii)

Hardship or Unusual Difficulty without Compensating Increase in Level of Quality or Safety

1. ASME Code Component{s) Affected Code Class: 2 and 3

Reference:

IWA-4400 Examination Category: N/A Item Number: N/A

Description:

Use of Code Case N-789 Component Number: N/A

2. Applicable Code Edition and Addenda

PINGP Units 1 and 2 will start the Fifth 10-Year lnservice Inspection (lSI) Program interval on December 21, 2014, and is required to follow the ASME Boiler and Pressure Vessel Code,Section XI, "Rules for lnservice Inspection of Nuclear Power Plant Components," (ASME Section XI), 2007 Edition through the 2008 Addenda.

3. Applicable Code Requirements ASME Section XI, IWA-4400 provides requirements for welding, brazing, metal removal, and installation of repair/replacement activities.

4. Reason for Request

Pursuant to 10 CFR 50.55a(a)(3)(ii), NSPM requests proposed alternatives from the requirement for replacement or internal weld repair of wall thinning conditions resulting from degradation in Class 2 and 3 moderate energy carbon steel raw water 1 piping systems (see Table 2 for systems identified within scope of this request) in accordance with IWA-4000. Such degradation may be the result of mechanisms such as localized erosion, corrosion, cavitation, and pitting, but excluded are conditions involving flow-accelerated corrosion (FAC), corrosion-assisted cracking, or any form of cracking. IWA-4000 requires repair/replacement 1

Raw water is defined as water such as from a river, lake, or well or brackish/salt water- used in plant equipment, area coolers, and heat exchangers. In many plants it is referred to as "service water."

Page 15 of 23 0 CFR 50.55a Requests 1-RR-5-5 and 2-RR-5-5 (continued) activities in accordance with the Owner's Requirements and the original or later construction code.

The primary reason for this request is to permit installation of a technically sound temporary repair to provide adequate time for evaluation, design, material procurement, planning, and scheduling of appropriate permanent repair/replacement activity of the defective piping, considering the impact on system availability, maintenance rule applicability, and availability of replacement materials.

Table 2 System Code System lSI Class CL Cooling Water 2 and 3

5. Proposed Alternative and Basis for Use NSPM proposes to implement the requirements of ASME Code Case N-789, "Alternative Requirements for Pad Reinforcement of Class 2 and 3 Moderate-Energy Carbon Steel Piping for Raw Water Service,Section XI, Division 1,"as a temporary repair of degradation in Class 2 and 3 moderate energy raw water piping systems resulting from mechanisms such as localized erosion, corrosion, cavitation, or pitting, but excluding conditions involving flow-accelerated corrosion (FAG), corrosion-assisted cracking, or any form of cracking. These types of defects are typically identified by small leaks in the piping system or by pre-emptive non-code required examinations performed to monitor the degradation mechanisms.

The alternative repair technique described in ASME Code Case N-789 involves the application of a metal reinforcing pad welded to the exterior of the piping system.

Reinforcing pads may be a pressure pad or pressure plus structural pad as defined Code Case N-789. This repair technique will be utilized when it is determined that this temporary repair method is suitable for the particular defect or degradation being resolved.

This code case invokes the design requirements of the original construction code or ASME Code, Section Ill. Reconciliation and use of editions and addenda of ASME Section Ill will be in accordance with ASME Section XI, IWA-4220, and only editions and addenda of ASME Section Ill that have been accepted by 10 CFR 50.55a may be used. The Code of Record for PINGP is the 2007 Edition through the 2008 Addenda of ASME Section XI, which will be used when applying the various IWA paragraphs of Section XI unless specific regulatory relief to use other editions or addenda is approved.

The code case requires the cause of the degradation to be determined, and the extent and rate of degradation in the piping to be evaluated to ensure that there are no other unacceptable locations within the surrounding area that could affect the integrity of the Page 16 of 23 0 CFR 50.55a Requests 1-RR-5-5 and 2-RR-5-5 (continued) repaired piping. The area of evaluation will be dependent on the degradation mechanism present. A baseline thickness examination will be performed for a completed structural pad (as defined by Code Case N-789), attachment welds, and surrounding area. For the next three months, monthly thickness monitoring will be performed, with subsequent frequency based on the results of this monitoring, but at a minimum of quarterly. Areas containing pressure pads (as defined by Code Case N-789) shall be visually observed at least once per month to monitor for evidence of leakage. If the areas containing pressure pads are not accessible for direct observation, then monitoring will be accomplished by visual assessment of surrounding areas or ground surface areas above pressure pads on buried piping, or monitoring of leakage collections system, if available.

The repair will be considered to have a maximum service life of the time until the next refueling outage, when a permanent repair/replacement activity shall be performed.

Additional requirements for design of reinforcement pads, installation, examination, pressure testing, and inservice monitoring are provided in ASME Code Case N-789.

Based on the above justification, the use of ASME Code Case N-789 for pad reinforcement will apply when compliance with the specified Code requirements would result in hardship or unusual difficulty without a compensating increase of quality and safety, such as requiring the plant to be shut down or challenging the Completion Time for a TS Required Action to complete a code repair.

All other ASME Section XI requirements for which relief was not specifically requested and authorized by the NRC staff will remain applicable including third party review by the Authorized Nuclear lnservice Inspector.

Performing permanent code repair/replacement in lieu of implementing this 10 CFR 50.55a Request would in some cases necessitate longer periods in TS Required Actions which challenge the TS Completion Time, putting the plant at higher safety risks than warranted compared with the short time necessary to install a technically sound pad reinforcement repair. Without the use of this Code Case in some situations, plant shut down may be necessary to perform a code repair/replacement activity.

Application of a reinforcing pad in accordance with the requirements of Code Case N-789 and additional conditions of this request provides reasonable assurance of structural integrity of thinned areas of class 2 and 3 moderate energy carbon steel piping in raw water service.

ASME Code Case N-789 was approved by the ASME Board on Nuclear Codes and Standards on June 25, 2011; however, it has not been incorporated into NRC Regulatory Guide 1.147, "lnservice Inspection Code Case Acceptability, ASME Section XI, Division 1,"and thus is not available for application at nuclear power plants without specific NRC approval.

Page 17 of 23 0 CFR 50.55a Requests 1-RR-5-5 and 2-RR-5-5 (continued)

As an alternative to replacement or internal weld repair in accordance with IWA-4400, NSPM requests approval to use the proposed Code Case N-789 with conditions as noted in this request.

6. Duration of Proposed Alternative Relief is requested for the fifth 10-year inspection interval of the lnservice Inspection Program for PINGP Units 1 and 2. The fifth 10-year inspection interval is effective for Units 1 and 2 from December 21, 2014 through December 20, 2024 or until Code Case N-789 is approved by the NRC in Regulatory Guide 1.147. At that time PINGP will use Code Case N-789 as approved by the NRC with any conditions identified.

Any reinforcing pads installed before the end of the fifth 10-year inservice inspection interval will be removed during the next refueling outage, even if that refueling outage occurs after the end of the 10-year interval.

7. Precedents
1. Exelon Generation- Request to use American Society of Mechanical Engineers Boiler and Pressure Vessel Code Case N-789, "Alternative Requirements for Pad Reinforcement of Class 2 and 3 Moderate-Energy Carbon Steel Piping for Raw Water Service,Section XI, Division 1", dated May 10, 2012 (TAC Nos.

ME7303 through ME7319) (ML12121A637).

2. A similar repair relief request (RR-3-43) was approved for Indian Point Nuclear Generating Unit No. 3, Docket 50-286, "Relief Request (RR) No. RR-3-43 for Temporary Non-Code Repair of Service Water Pipe (TAC No. MD6831)", dated February 22, 2008 (ML080280073).

Page 18 of 23 0 CFR 50.55a Requests 10 CFR 50.55a Request 1-RR-5-6, Rev. 0 (PINGP Unit 1) 10 CFR 50.55a Request 2-RR-5-6, Rev. 0 (PINGP Unit 2)

Alternative Requirements for Pressure Testing 51 Accumulator Nitrogen Piping in Containment Proposed Alternative in Accordance with 10 CFR 50.55a (a)(3)(i)

Alternate Provides Acceptable Level of Quality and Safety

1. ASME Code Component(s) Affected Code Class: 2

Reference:

IWC-5200 Examination Category: C-H Item Number: C7.10

Description:

Sl Accumulator Nitrogen Piping inside the Containment Vessel Component Number: Unit 1: Line No. 1-SI-19C Unit 2: Line No. 1-2SI-19A

2. Applicable Code Edition and Addenda

PINGP Units 1 and 2 will start the Fifth 10-Year lSI Program interval on December 21, 2014, and is required to follow the ASME Boiler and Pressure Vessel Code,Section XI, "Rules for lnservice Inspection of Nuclear Power Plant Components," (ASME Section XI), 2007 Edition through the 2008 Addenda.

3. Applicable Code Requirements The 2007 Edition through the 2008 Addenda of ASME Section XI contain Table IWC-2500-1, Examination Category C-H, and Item Number C7.10 which requires a system leakage test meeting the requirements of IWC-5200. The pressure test frequency is once per inspection period.

IWC-521 0 states:

(a) Pressure retaining components shall be tested at the frequency stated in, and visually examined by the methods specified in Table IWC-2500-1, Examination Category C-H.

(b)(1) The system pressure tests and visual examinations shall be conducted in accordance with IWA-5000 and this Article. The contained fluid in the system shall serve as the pressurizing medium. (2) Alternatively, steam systems may use either water or gas as the pressurizing medium. When gas is the pressurizing medium, Page 19 of 23 0 CFR 50.55a Requests 1-RR-5-6 and 2-RR-5-6 (continued) the test procedure shall include methods for detection and location of through-wall leakage from components of the system tested.

4. Reason for Request

The Sl Accumulator nitrogen piping in containment is used to charge the Sl system accumulators. The nitrogen supply valve, nitrogen containment isolation valve, and nitrogen valves to each accumulator are briefly opened to pressurize the Sl accumulators to approximately 750 psig at the beginning of each fuel cycle. The containment nitrogen isolation valve and nitrogen valves to the accumulators are normally closed and only opened under administrative control. The nitrogen piping in containment is 1 inch nominal pipe size (NPS) schedule 80, stainless steel in Unit 1 and carbon steel in Unit 2. See Figure 2 and Figure 3 below.

For the first inspection period and most of the second inspection period of the fourth 10-year lSI interval the nitrogen piping upstream of the nitrogen valves to each accumulator was considered ASME Section XI non-code class. Therefore, the nitrogen piping upstream of the accumulator control valves was not pressure tested in the first two periods of the current fourth 10-year lSI interval.

In the 2010 to 2011 time frame, the nitrogen lines to the accumulators in containment were reclassified as ASME Section XI Code Class 2 by the site Q-List Validation Project. The lines were assigned safety functions of: maintain system pressure boundary (nitrogen); accumulator safety injection; and maintain containment operability.

Pressure testing the lines in accordance with the code is complicated by the fact that the "contained fluid in the system" per the requirements of IWC-5210(b)(1) is a colorless gas and would not show visual indication of leakage. Pressure testing with water is complicated by the fact much of the piping is not readily accessible. In addition, a pressure test with water on a system designed for gas raises concerns with potential water hammer and drainage.

5. Proposed Alternative and Basis for Use Proposed Alternative:

As an alternative to the requirements of IWC-5210, NSPM proposes to perform local leak rate testing (LLRT) of the containment nitrogen lines to the accumulators once each period per approved site procedures. The LLRT administrative leakage limit is 4000 cc/min at 46 psig, the containment internal design pressure which exceeds the calculated containment internal pressure for the design basis loss of coolant accident.

Leakage above the 4000 cc/min limit would require additional actions to determine the source of the leakage. Although the primary purpose of LLRT is to test containment isolation valves (CV-31440, CV-31441, CV-31444 and CV-31242 for Unit 1, and CV-Page 20 of 23 0 CFR 50.55a Requests 1-RR-5-6 and 2-RR-5-6 (continued) 31554, CV-31511, CV-31512 and CV-31244 for Unit 2), it also tests the nitrogen piping from the containment isolation valve to the nitrogen valves to each accumulator. The remaining code class nitrogen piping from the accumulator valves (CV-31441, CV-31444, CV-31511, and CV-31512) to the accumulators will be tested in accordance with code requirements.

Performance of LLRT once each inspection period provides an acceptable level of quality and safety. The nitrogen lines to the accumulators are only placed in service when charging the accumulators at the beginning of each fuel cycle prior to power operation. At power operation the nitrogen to accumulator lines are isolated at both Sl accumulators and just outside the containment shield building by administratively controlled control valves. As such, the nitrogen charging lines have no active role in the prevention or mitigation of an accident. The nitrogen piping pressure boundary safety functions, maintain system pressure boundary (nitrogen) and maintain containment operability, are adequately tested by periodic LLRT. No degradation of the lines is expected since they provide inert gas service. As such, there is no significant risk of corrosion, cracking or other degradation.

Basis for Relief:

Pursuant to 10 CFR 50.55a(a)(3)(i), relief is requested from the requirements of ASME Section XI, IWA-5210 on the basis that the proposed alternative provides an acceptable level of quality and safety.

As an alternative to the requirements of IWC-5200 for pressure testing containment nitrogen lines, NSPM requests approval to perform the LLRT once each period at a pressure of 46 psig with an acceptance criteria of no more than 4000 cc/min leakage.

6. Duration of Proposed Alternative Relief is requested for the fifth 10-year inspection interval of the lnservice Inspection Program for PINGP Units 1 and 2. The fifth lSI Program interval is effective for Units 1 and 2 from December 21, 2014 through December 20, 2024.
7. Precedents
1. NSPM recently submitted this 10 CFR 50.55a request for the Prairie Island Nuclear Generating Plant, Units 1 and 2, Docket Nos. 50-282 and 50-306, fourth 10-year lSI interval by letter titled "1 0 CFR 50.55a Requests 1-RR-4-9, 2-RR-4-9 and 2-RR-4-1 0 Associated with the Fourth Ten-Year Interval for the lnservice Inspection Program", dated September 3, 2014. (ML14247A639)

Page 21 of 23 0 CFR 50.55a Requests 1-RR-5-6 and 2-RR-5-6 (continued)

Figure 2 Unit 1 Nitrogen to Accumulators Sketch Rl:-12-1 I

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s Page 22 of 23 0 CFR 50.55a Requests 1-RR-5-6 and 2-RR-5-6 (continued)

Figure 3 Unit 2 Nitrogen to Accumulators Sketch I VeNT I

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Page 23 of 23

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