ML13011A158

Relief Request from the Requirements of the ASME Code

ML13011A158
Person / Time
Site:	Millstone
Issue date:	01/23/2013
From:	George Wilson Plant Licensing Branch 1
To:	Heacock D Dominion Nuclear Connecticut
Kim J NRR/DORL/LPL1-1 301-415-4125
References
TAC ME9013, TAC ME9014
Download: ML13011A158 (18)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 January 23, 2013 Mr. David A. Heacock President and Chief Nuclear Officer Dominion Nuclear Connecticut, Inc.

Innsbrook Technical Center 5000 Dominion Boulevard Glen Allen, VA 23060-6711

SUBJECT:

MILLSTONE POWER STATION, UNIT NOS. 2 AND 3 - RELIEF FROM THE REQUIREMENTS OF THE ASME CODE (TAC NOS. ME9013 AND ME9014)

Dear Mr. Heacock:

By letter dated July 5,2012, as supplemented by letter dated December 20,2012, Dominion Nuclear Connecticut, Inc. (the licensee), submitted a request to the Nuclear Regulatory Commission (NRC) for relief from certain American Society of Mechanical Engineers Boiler and Pressure Vessel Code (ASME Code),Section XI requirements at Millstone Power Station, Unit Nos. 2 and 3 (MPS2 and MPS3). Relief Request RR-04-09 for MPS2 is applicable to the fourth 10-year inservice inspection (lSI) interval and Relief Request IR-3-15 for MPS3 is applicable to the third 10-year lSI interval.

Specifically, pursuant to Title 10 of the Code of Federal Regulations (10 CFR) paragraph 50.55a(a)(3)(ii), the licensee requested to use alternative methods for performing the system leakage testing as required by ASME Code Section XI, Table IWD-2500-1 and IWD-5220 for the piping segments of the Service Water System (SWS) located in the confined space of the intake structure bays.

The NRC staff has determined that the proposed alternative provides reasonable assurance of structural integrity and leak tightness of the subject SW piping. The NRC staff finds that complying with the specified ASME Code requirement would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety. Accordingly, the NRC staff concludes that the licensee has adequately addressed all of the regUlatory requirements set forth in 10 CFR 50.55a(a)(3)(ii) and is in compliance with the requirements of the ASME Code,Section XI, for which relief was not requested. Therefore, the NRC authorizes the use of Relief Request RR-04-09 at the MPS2 for the duration of the fourth 10-year lSI interval, which ends on March 31, 2020, and Relief Request IR-3-15 at the MPS3 for the third 10-year lSI interval, which ends on April 22,2019.

All other ASME Code,Section XI requirements for which relief has not been specifically requested and approved in this relief request remain applicable, including third-party review by the Authorized Nuclear Inservice Inspector.

D. Heacock

- 2 If you have any questions, please contact the Millstone Power Station Project Manager, James Kim, at (301) 415-4125.

Sincerely,

~~~

Plant Licensing Branch 1-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket Nos. 50-336 and 50-423

Enclosure:

As stated cc w/encl: Distribution via Listserv

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELIEF REQUESTS RR-04-09 AND IR-3-15 DOMINION NUCLEAR CONNECTICUT, INC.

MILLSTONE POWER STATION, UNIT NOS. 2 AND 3 DOCKET NOS. 50-336 AND 50-423

1.0 INTRODUCTION

By letter dated July 5, 2012 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML121910350), as supplemented by letter dated December 20,2012 (ADAMS Accession No. ML13002A049), Dominion Nuclear Connecticut, Inc. (the licensee),

submitted a request to the Nuclear Regulatory Commission (NRC) for relief from certain American Society of Mechanical Engineers Boiler and Pressure Vessel Code (ASME Code),

Section XI requirements at Millstone Power Station, Unit Nos. 2 and 3 (MPS2 and MPS3).

Relief Request RR-04-09 for MPS2 is applicable to the fourth 10-year inservice inspection (lSI) interval and Relief Request IR-3-15 for MPS3 is applicable to the third 10-year lSI interval.

Specifically, pursuant to Title 10 of the Code of Federal Regulations (10 CFR) paragraph 50.55a(a)(3)(ii), the licensee requested to use alternative methods for performing the system leakage testing as required by ASME Code,Section XI, Table IWD-2500-1 and IWD-5220 for the piping segments of the Service Water System (SWS) located in the confined space of the intake structure bays.

2.0 REGULATORY REQUIREMENTS The lSI of the ASME Code Class 1, 2, and 3 components is to be performed in accordance with the requirements of Section XI, "Rules for Inservice Inspection of Nuclear Power Plant Components," of the ASME Code and applicable editions and addenda as required by 10 CFR 50.55a(g), except where specific written relief has been granted by the Commission.

Pursuant to 10 CFR 50.55a(g)(4), ASME Code Class 1, 2, and 3 components (including supports) must meet the requirements, except the design and access provisions and the preservice examination requirements, set forth in the ASME Code,Section XI, to the extent practical within the limitations of design. geometry. and materials of construction of the components.

Enclosure

- 2 Pursuant to 10 CFR 50.55a(a)(3), alternatives to requirements may be authorized by the NRC if the licensee demonstrates that: (i) the proposed alternatives provide an acceptable level of quality and safety or OJ) compliance with the specified requirements would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety. The licensee requested authorization of an alternative to the requirements of the 2004 Edition of ASME Code,Section XI, Table IWD-2500-1, Examination Category D-B, and IWD-5220 pursuant to 10 CFR 50.55a(a)(3)(ii).

3.0 TECHNICAL EVALUATION

3.1 MPS2 Relief Request RR-04-09 3.1.1 ASME Code Components Affected The affected pipe segments consist of two trains of 24-inch Service Water System (SWS) supply piping located in the intake structure bays. The line numbers are 24"-JGD-1 and 24"-KE-1 as shown in Piping & Instrumentation Drawing (P&ID) 25203-26008, Sheet 2, of the relief request. The piping material consists of spools that are A-106, Grade B carbon steel, spools that are 6% Molybdenum Stainless Steel (UNS N08367) also known as AL-6XN, and spools that are Cast Ductile-Iron. The subject piping is classified as ASME Class 3, Examination Category D-B, and Item Number D2.10 in accordance with the ASME Code,Section XI, Table IWD-2500-1.

The relief request contains an excerpt of P&ID 25203-26008, Sheet 2 and Piping Isometric Drawings 25203-20150 Sheet 679 and 25203-20150 Sheet 1080 for information only, with the subject piping clouded for identification.

3.1.2 Applicable Code Edition and Addenda ASME Code,Section XI, 2004 Edition (No Addenda).

3.1.3 Applicable Code Requirement In its letter dated July 5,2012, the licensee stated:

The 2004 Edition of ASME Code,Section XI, Table IWD-2500-1, Examination Category D-B and IWD-5220 requires, for Class 3 piping, a VT-2 visual examination be performed during a system leakage test conducted at the pressure obtained while the system is in-service performing its normal operating function. The leakage test is required to be performed once each inspection period.

3.1.4. Reason for Request The licensee requested approval of alternative methods for performing the system leakage testing as required by ASME Section XI, Table IWD-2500-1 and IWD-5220 for the "A" and liB" train piping segments of the MPS2 SWS located in the normally inaccessible confined space of the intake structure bays.

- 3 8y letter dated July 5, 2012, the licensee stated that:

The subject "A" train piping segment runs vertically through the floor of the service water pump cubicle for a distance of 7.5 feet and then travels horizontally through four intake structure bays for a distance of approximately 69 feet until it passes through the outer wall of the intake structure, where it continues underground to the turbine building. Approximately 10.5 feet of this piping has been upgraded to to piping material with 6% molybdenum stainless steel (UNS N08367), also known as AL-6XN. The remaining piping is approximately 64.5 feet of A-1 06, Grade 8 carbon steel externally coated with Carbomastic 14, and 1.5 feet of cast ductile-iron piping, both internally lined with an Insituform CIPP (Cured In-place Pipe) epoxy impregnated material applied to enhance long-term life.

The subject "8" train piping segment runs vertically through the floor of the service water pump cubicle for a distance of 8 feet and then travels horizontally through one intake structure bay for a distance of approximately 14 feet until it passes through the outer wall of the intake structure, where it then continues underground to the turbine building. Approximately 19.5 feet of this piping has been upgraded to piping material with 6% molybdenum stainless steel (UNS N08367). The remaining piping is approximately 2.5 feet of cast ductile-iron piping, internally lined with an Insituform CIPP epoxy impregnated material applied to enhance long-term life.

The underground portions of the SWS piping are the subject of a similar request (RR-04-05) submitted [and approved by the NRC (ADAMS Accession No. ML111870600)] for the current fourth 1 O-year inspection interval and therefore, are not included as part of this request.

Visual examination of the subject piping requires entry into each of the four intake structure bays. There is limited access to each bay from an access hatch that is located in the intake structure floor. Personnel entry into this confined space requires each bay to be removed from service along with associated SWS pumps, Circulating Water pumps, Screen Wash pumps and traveling debris screens. There are no platforms located in the bays. Scaffolding has to be erected in each bay to access the piping to safely perform the examination.

Erecting the scaffolding is difficult because of safety risks associated with moving personnel and materials into the confined space of the bay areas. Two of the bays contain structural steel that can support scaffolding being erected over the water in the bay. The remaining two bays require scaffolding to be erected from the floor of the bay up to the subject piping which requires each bay to be completely isolated and drained.

- 4 During spring 2011, significant work was performed to stage and prepare two of the four bays to support planned maintenance activities. The work was performed in the two bays which contain structural steel which will support scaffold. Scaffold was erected to allow personnel access to support a piping upgrade to AL-6XN material on the "B" train piping in the "0" bay and major Circulating Water pump work in the "A" bay. Additionally, since the scaffold allowed access, a VT-2 visual examination was performed on the subject piping located in those bays and did not identify leakage or piping degradation.

3.1.5. Proposed Alternative and Basis for Use (as stated by the licensee)

Dominion Nuclear Connecticut, Inc. (DNC) proposes to use, as an alternative to the requirements of [the ASIVIE Code, Section XI], IWD-5220, a verification of unimpaired flow to provide an acceptable level of quality and safety. For the segment of the subject pipe, periodic flow testing will be performed in accordance with Inservice Test (1ST) Program surveillance procedures. These surveillance procedures require flow to be measured, recorded and compared to established acceptance criteria to provide the assurance that flow is not impaired during operation.

Flow testing of the three MPS2 SWS pumps is performed quarterly and uses an established minimum flow rate specified in the 1ST procedures as the acceptance criteria for the pressure testing of the associated SWS pipe segments. The flow rate is currently specified as 10,300 gallons per minute (gpm).

During 1ST surveillances, if the minimum flows are not achieved, the pump{s) would be declared inoperable and a condition report initiated in accordance with the Millstone Power Station Corrective Action Program, with further corrective actions, as required, to restore the pump{s) and/or system to an operable status.

Additionally, internal visual inspection on the subject pipe segments periodically during plant refueling outages to ensure the piping and lining are not experiencing unacceptable degradation. The most recent internal visual inspections were performed in fall 2009 for "A" train and spring 2011 for "B" train with no unsatisfactory conditions identified.

3.1.6. Duration of Proposed Alternative (as stated by the licensee)

The relief is requested for the duration of the fourth 1 O-year inservice inspection interval, which began on April 1, 2010, and is scheduled to end on March 31, 2020.

- 5 3.2

NRC Staff Evaluation

3.2.1 The Affected Pipe Segments In its letter dated December 20, 2012, the licensee provided additional clarification and information on the scope of affected pipe segments covered under the relief request. The licensee stated that:

The three service water pumps discharge to the header 24"-JGD-1 that is divided into "A" and "8" trains and transition into the downstream 24"-KE-1 pipe segments.

There are seven bolted flange connections associated with the "A" train and four bolted flange connections associated with the "8" train of the affected pipe segments. There are no valves present within the affected pipe segments.

Upgrade of the piping to austenitic stainless steel (AL6XN) was implemented as a result of preemptive mitigation measures. There has been no degradation observed in the affected pipe segments since the upgrade.

The nominal wall thickness of the 24"-JGD-1 piping is 0.375 inches. The nominal wall thickness of the 24"-KE-1 piping is 0.410 inches. The normal operating pressure is 45 psig. The normal operating temperature range is 33 degrees F to 75 degrees F.

Other than the pipe segments covered under this relief request and the buried piping covered under the previously approved Relief Request RR-04-05, the code-required visual examination will be performed on the remaining portions of 24"-JGD-1 and 24"-KE-1 [that are not covered in the relief request] when conducting the system leakage test in accordance with the ASME Code,Section XI,IWD-5000.

The NRC staff notes that the licensee will perform ASME-required system leakage test in accordance with Table IWD-2500-1 and IWD-5220 for the SW piping including the subject pipe segment once every inspection period. However, during the system leakage test, the licensee will not perform VT-2 visual examination of the affected pipe segments, which is a deviation from the ASME Code. In lieu of this deviation, the licensee proposed to use the flow test of the SW pumps as an alternative to demonstrate the structural integrity of the affected pipe segments.

3.2.2 Flow Test Procedures The NRC staff noted that the 2004 edition of the ASME Code,Section XI, Table IWD-2500-1 requires the licensee to perform a system leakage test in accordance with IWD-5220 and a VT-2 visual examination once each inspection period for the affected piping segments. The ASME Code,Section XI, IWD-5221 states that the system leakage test shall be conducted at the system pressure obtained while the system, or portion of the system, is in service performing its normal operating function or at the system pressure developed during a test

- 6 conducted to verify system operability (e.g., to demonstrate system safety function or satisfy technical specification surveillance requirements). In lieu of the system leakage test and associated VT-2 visual examination, the proposed alternative would use the flow test performed quarterly for the SW pumps to demonstrate the structural integrity of the affected pipe segments.

The ASME Code system leakage testing or the proposed flow test requires coolant flowing through the entire length of SW piping. However, portions of the SW piping are not covered by the relief request. The relief request applies only to the pipe segments inside the intake structure bays. The NRC staff noted that a large leak in the pipe segments that are not covered by the relief request may mask a small leak in the affected pipe segments that are covered by the relief request. In addition, a flow rate reduction could be caused by factors other than pipe cracks (e.g., a pump or valve malfunction, leaking bolt joints, valve in-line leakage, or internal foreign object obstruction). The NRC staff questioned how a pipe through wall leakage can be distinguished from aforementioned leakage sources (e.g., valve in-line or bolted connection leakage) during the flow test. The NRC staff asked the licensee to discuss how the location and amount of leakage is determined without a visual examination of the affected pipe segments, how to determine a decreased flow rate that is caused by a crack in the affected pipe segments, and how the subject piping is monitored for leakage during normal operation.

In its letter dated December 20, 2012, the licensee stated:

During testing of a service water pump, flow is measured using a single flow instrument, located in the Turbine Building, for measurement of total flow. If the flow instrument is not available or does not meet accuracy requirements, the flow is measured using a combined total flow measurement from four heat exchanger flow instruments. During the test, the flow is set to 10,500 [gallons per minute]

gpm nominal (10,300 gpm minimum acceptable flow rate), stabilized, and observed for 2 minutes. Then, pump vibrations are measured, and pump discharge and suction pressures are measured and used to determine differential pressure. [The licensee also measures pump discharge and suction pressures to determine differential pressure.] The flow instruments, in combination, measure within 2% of total flow. This is an accuracy of roughly 200 gpm. If a test is performed and there is 200 gpm leakage or more (unmonitored flow because the flow meters are downstream of the intake structure), this would be observed as reduced, indicated, differential pressure across the service water pump that would be entered into the Corrective Action Program (CAP) and investigated to determine the cause. Operators are in the vicinity of the SW pumps during the testing. Any significant flow from leakage would likely be audible to the operators during the testing. Instruments used for differential pressure are also accurate within 2%.

Flow rate is required to be held constant for two minutes before readings are taken. During that time, conditions are observed by the operators and any out of-ordinary conditions are noted. The pumps are centrifugal and performance follows a typical centrifugal pump curve. If a leak occurs, as indicated above, this would be unmonitored flow and would be observed as reduced differential

- 7 pressure across the service water pump that would be entered into the CAP and investigated to determine the cause.

Flow testing is performed in conjunction with quarterly testing of the service water pumps. If the pump failed to meet the acceptance criteria [of 10,300 gpm] during the flow test, the pump would be declared inoperable and entered into the CAP.

There are several contributors could cause the pumps to fail to meet the acceptance criteria. Investigation to determine the cause of the flow reduction would be identified as part of the CAP plan for this condition. Further corrective actions such as maintenance of the pump and system walkdowns, etc. would be initiated as required to restore the pump and/or system to operable status.

Leakage identified during system walkdowns of accessible piping and components not covered in this request would be evaluated and repaired, as required. If during the investigation, it is suspected that there may be leakage occurring from the subject piping [addressed by this request], the necessary actions would be taken to gain access to this normally inaccessible piping for visual inspection, as required.

With regard to the normal operation, the licensee stated that:

There are no indication alarms in the control room to monitor for reduced flow; however, during normal operation the total service header flow indication for each train is available to be viewed real-time from the plant process computer [ in the control room.] Additionally, in intake structure is walked down daily (once each shift) during plant equipment operator rounds. Any significant flow from leakage will likely be audible to the operators during these rounds.

The NRC staff finds that the licensee's flow testing program is adequate to determine potential through wall leakage from the affected pipe segments because the licensee's CAP contains procedures requiring corrective actions to be performed to determine the source of the leakage, regardless of the source. Therefore, the NRC staff finds that the licensee will properly identify the pipe through wall leakage, if it occurs, and take corrective actions in accordance with its CAP.

3.2.3 Pipe Inside Surface Inspection The licensee periodically performs internal visual inspections on the subject pipe segments during refueling outages as stated in Section 5.2 of the relief request. However, it appears to the NRC staff that Train A and Train B SW piping were inspected every other refueling outage (approximate every 3 years), not every refueling outage. The NRC staff questioned whether this inspection frequency is adequate to ensure the structural integrity of the subject pipe segments. The NRC staff further questioned whether the inside surface of the entire length of the Train A and Train B pipe (24"-JGD-1 and 24"-KE-1) is visually inspected during each plant refueling outage, including the pipe segments covered by the relief request. The NRC staff asked the licensee to discuss its internal visual inspection, including the method and acceptance criteria.

- 8 In its letter dated December 20, 2012, the licensee stated:

The entire inside surface of each train of 24"-JGD-1 and 24"-KE-1 for each train are visually inspected on al alternating basis each refueling outage. Therefore, each train is inspected every other refueling outage.

The internal visual inspection remotely using a robotic crawler unit fitted with a high resolution pan and tilt camera. Any identified conditions such as erosion, corrosion, macrofouling, biofouling, or other degraded piping/liner material condition are evaluated by Engineering for acceptance or corrective actions as required.

The internal visual inspection of the subject piping is conducted every other refueling outage [in fall 2009 for "A" train and spring 2011 for "B" train]. Based on the history of the inspection results, the inspection frequency has been determined to be adequate to ensure structural integrity of the subject piping This frequency is consistent with that which would be required for the ASME Code leakage test.

The NRC staff finds that the frequency of internal visual examination every other refueling outage is consistent with the requirements of the 2004 edition of the ASME Code,Section XI, Table IWD-2500-1, and, therefore, is acceptable. The NRC staff finds that, in addition to the flow test, the periodic internal visual inspection of each SW train will provide additional assurance on the structural integrity of the affected pipe segments.

3.2.4 Hardship In its letter dated December 20,2012, the licensee reiterated that:

Personnel entry into the confined space of the intake bays with equipment operational is considered a personnel safety hazard; therefore, equipment is required to be removed from service and tagged out prior to entry. Additionally, due to the physical configuration of the intake structure, each of the five bays requires draining to erect the scaffolding needed to access these bays. Draining the bays also requires equipment to be taken out of service to preclude damage to the service water pumps that could occur with the bays drained. Unavailability of safety-related service water pumps puts the station at a greater operational risk since it removes the availability of redundant equipment, introducing a reduction in the safety margin of the plant. Performing the code-required visual examination would require equipment to be taken out of service for an extended period of time while the bays are being drained and scaffolding erected for inspection. Placing the plant in a condition where safety-related service water is out of service for an extended period of time, resulting in increased operational risk, is considered a hardship without a compensating increase in the level of quality and safety.

- 9 The NRC staff finds that the licensee has provided valid arguments to demonstrate that complying with the specified ASME Code requirement would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety.

In summary, the NRC staff finds that the proposed alternative in Relief Request RR-04-09 for MSP2 will provide reasonable assurance of the structural integrity of the affected piping because (1) the flow test procedures will be able to detect the potential leakage in the affected pipe segments in the intake structure bays, (2) the licensee performs visual examinations on the inside surface of the affected pipe segments every other refueling outage which would detect potential pipe degradation, and (3) the licensee will perform system walkdowns of the accessible areas of the intake structure during every shift which will identify significant leakage.

3.3 Millstone Unit 3 Relief Request IR-3-15 3.3.1. ASME Code Components Affected The affected piping is "B" train, 30-inch SWS supply piping located in the intake structure bays and the line number is 3-SWP-030-3-3 as shown in Piping & Instrumentation Drawing (P&ID)

P&ID 25212-26933 Sheet 1 of the relief request.

The piping material is SB-127 (Monel). The affected pipe segments are classified as ASME Code Class 3, Examination Category D-B, Item Number D2.1 0, in accordance with the ASME Code,Section XI, Table IWD-2500-1.

The relief request contains an excerpt of P&ID 25212-26933 Sheet 1 and Piping Isometric Drawing 25212-21041 Sheet 9 for information only, with the subject piping clouded for identification.

3.3.2. Applicable Code Edition and Addenda ASME Section XI, 2004 Edition (No Addenda) 3.3.3. Applicable Code Requirement The 2004 Edition of ASME Code,Section XI, Table IWD-2500-1, Examination Category D-B and IWD-5220 requires, for Class 3 piping, a VT-2 visual examination be performed during a system leakage test conducted at the pressure obtained while the system is in-service performing its normal operating function. The leakage test is required to be performed once each inspection period.

3.3.4. Reason for Request The licensee requested approval of alternative methods for performing the leakage testing, as required by ASME Section XI, Table IWD-2500-1 and IWD-5220, for the piping segment of the MPS3 SWS located in the confined space of the intake structure bays.

In its letter dated July 5,2012, the licensee stated:

The subject piping is the common "B" train SWS header piping that runs vertically through the floor of the liB" SWS pump cubicle for a distance of 11 feet

- 10 and then travels horizontally through five intake bays for a distance of approximately 88 feet in this normally inaccessible area until it enters and passes through the accessible area of the intake structure chlorine room. The piping continues underground to the auxiliary building. The piping located in the chlorine room is subject to the required VT-2 examination.

The downstream underground portion of the SWS piping is the subject of a similar request (lR-3-07) previously approved for this current third 10-year inspection interval and therefore, is not included as part of this request.

Visual examination of this piping requires entry into each of the five intake structure bays. There is limited access to each bay from an access hatch that is located in the intake structure floor. Personnel entry into this confined space requires each bay to be taken out of service along with the associated SWS pumps, Circulating Water pumps, Screen Wash pumps and intake structure traveling debris screens. There are small platforms located at the base of the bay access ladders; however, they are not sufficient to adequately perform the examination. Scaffolding has to be erected in each bay to provide the examiner a safe means to access the piping within sufficient distance to perform the examination. Erecting the scaffolding is difficult because of safety risks associated with moving personnel and materials into the confined space of the bay areas. Due to the physical arrangement of the intake structure, the scaffolding in each bay has to be erected from the floor of the bay up to the subject piping, which requires each bay to be completely isolated and drained.

3.3.5. Proposed Alternative and Basis for Use (as stated by licensee)

DNC proposes to use, as an alternative to the requirements of [the ASME Code,Section XI,] IWD-5220, a verification of unimpaired flow to provide an acceptable level of quality and safety. For the segment of the subject pipe, periodic flow testing will be performed in accordance with Inservice Test (1ST) Program surveillance procedures [in lieu of the ASME required system leakage test].

These surveillance procedures require flow to be measured, recorded and compared to established acceptance criteria to provide the assurance that flow is not impaired during operation.

Flow testing of the four MPS3 SWS pumps is performed quarterly and uses an established minimum flow rate specified in the 1ST procedures as the acceptance criteria for the pressure testing of the associated SWS pipe segment. The flow rate is currently specified as 8820 gallons per minute (gpm).

During the 1ST surveillances, if the minimum flows cannot be achieved, the pump(s) would be declared inoperable and a condition report initiated in accordance with the Millstone Power Station Corrective Action Program with further corrective actions, as required, to restore the pump(s) and/or system to an operable status.

- 11 Additionally, internal visual inspection is performed on the subject piping periodically during plant refueling outages to ensure the piping is not experiencing unacceptable degradation. The most recent internal visual inspection was performed in April 2010, with no unsatisfactory conditions identified.

3.3.6 Duration of Proposed Alternative (as stated by licensee)

The relief is requested for the duration of the third 1 O-year inservice inspection interval, which began on April 23,2009, and is scheduled to end on April 22, 2019.

3.4 NRC STAFF EVALUATION 3.4.1 The Affected Pipe Segments Section 1 of the relief request specifies the affected components as "8" Train 30-inch SW system supply piping located in the intake structure bays. However, Section 4 of the relief request describes a pipe segment that runs vertically through the j:loor of the "8" service water system pump cubicle, travels horizontally through five intake bays, passes through the accessible area of the intake structure chlorine room, and continues underground to the auxiliary building. The NRC staff questioned why the pipe segment inside the intake structure chlorine room is covered in the relief request if the pipe is accessible for inspection.

In the December 20, 2012 letter, the licensee clarified that:

The piping inside the chlorine room is accessible for examination and is not part of this request. The accessible piping was only discussed in the request to provide additional information on the location of the subject piping in relationship to other portions of the service water system.

There is no coating or lining on the inside or outside surface of the subject piping.

The[pipe] material is S8-127 (Monel) which is a highly corrosion resistant material and well suited for this environment. There are no bolted joints or valves in this subject piping segment.

There has been no significant degradation, repairs or upgrades to the piping.

Minor internal pitting was observed in the early 1990s due to mussel growth issues which were resolved during that timeframe. This pitting has not progressed any further since that time.

The nominal wall thickness is 0.375 inches. The normal operating pressure is 44 psig. The normal operating temperature range is 33 degrees F to 75 degrees F.

Other than the pipe segments covered under the relief request, the required visual examination will be performed on the remaining portion of line 3-SWP-030 3-3 (that is not covered by the relief request) when conducting the system leakage test in accordance with the ASME Code,Section XI, IWD-5220.

- 12 The NRC staff notes that the licensee will perform ASME-required system leakage test in accordance with Table IWO-2S00-1 and IWO-S220 for the SW piping including the subject pipe segment once every inspection period. However, during the system leakage test, the licensee will not perform VT-2 visual examination of the affected pipe segments, which is a deviation from the ASME Code. In lieu of this deviation, the licensee proposed to use the flow test of the SW pumps as an alternative to demonstrate the structural integrity of the affected pipe segments.

3.4.2 Flow Test Procedures The 2004 edition of the ASME Code,Section XI, Table IWO-2S00-1 requires the licensee to perform a system leakage test in accordance with IWO-S220 with a VT -2 visual examination once each inspection period for the affected piping segments. The ASME Code,Section XI, IWO-S221 states that the system leakage test shall be conducted at the system pressure obtained while the system, or portion of the system, is in service performing its normal operating function or at the system pressure developed during a test conducted to verify system operability (e.g., to demonstrate system safety function or satisfy technical specification surveillance requirements). In lieu of the system leakage test and associated visual examination, the proposed alternative would use the flow test performed quarterly to demonstrate the structural integrity of the affected pipe segments.

The ASME Code system leakage testing or proposed flow test requires coolant flowing through the entire length of SW piping. However, portions of the SW piping are not covered by the relief request. The relief request applies only to the pipe segments inside the intake structure bays.

The NRC staff noted that a large leak in the pipe segments that are not covered by the relief request may mask a small leak in the affected pipe segments that are covered by the relief request. In addition, a flow rate reduction could be caused by factors other than pipe cracks (e.g., a pump or valve malfunction, leaking bolt joints, valve in-line leakage, or internal foreign object obstruction). The NRC staff questioned how a pipe through wall leakage can be distinguished from aforementioned leakage sources (e.g., valve in-line leakage or bolted connection leakage) during the flow test. The NRC staff asked the licensee to discuss how the location and amount of leakage is determined without a visual examination of the affected pipe segments, how to determine a decreased flow rate that is caused by a crack in the affected pipe segments, and how the subject piping is monitored for leakage during normal operation.

By letter dated December 20, 2012, the licensee stated:

Periodic flow testing is performed quarterly for each service water pump as required by ITS Program test surveillance procedures. Both the "B" and "0" pumps provide flow to the subject piping of the "B" train header; therefore, this line is subject to two flow tests quarterly [and these flow tests are performed in conjunction with quarterly testing of the SW pumps].

Flow testing is performed in conjunction with quarterly testing of the service water pumps. Testing is performed by throttling flow through one of two heat exchangers to obtain the reference flow conditions of 8820 to 9180 gpm. Total flow is measured based on the sum of several branch line flow indicators (depending on the heat exchangers in service). Flow is throttled until the

- 13 reference conditions are reached and then stabilized for two minutes. Flow and pump discharge pressure are recorded. Suction pressure is calculated based on the water height in the pump bay. Pressure is measured as the pump discharge.

A total flow indicator is not installed. Flow in the downstream branch lines is summed to determine the total flow. Because flow is throttled to a repeatable reference value, a specific leak rate is not available. If the flow rate cannot be achieved or the associated differential pressure at reference conditions is not achieved, the pump test would be considered unsatisfactory. The corrective action program (CAP) would be used to determine the cause of the deviation.

The minimum acceptable flow rate is 8820 gpm. Accuracy of the analog flow and pressure indicators is within +/- 2% of full scale. Digital flow instruments are within 2% of reading.

The licensee clarified that if the SW pump failed to meet the acceptance criteria of 8,820 gpm during the flow test, the SW pump would be declared inoperable and entered into the CAP. The licensee would investigate the cause of the flow reduction as part of the CAP plan and initiate further corrective actions such as maintenance of the pump and system walkdowns as required to restoring the pump and/or system to operable status. The licensee would evaluate leakage identified during system walkdowns of accessible piping and components not covered in this request and perform repairs as required. If during the investigation it is suspected that there may be leakage occurring from the piping addressed by this request, the necessary actions would be taken to gain access to this normally inaccessible piping for visual inspection, as required.

With regard to normal operation, the licensee stated that the control room has no indication alarms to monitor for reduced flow. However, the licensee monitors and trends weekly the local flow indicators during normal operation. Any significant decrease in flow would be observed and evaluated. Additionally, the plant equipment operator performs walkdowns of accessible areas of the intake structure once each shift. Any significant flow from leakage of the subject piping would likely be audible to the operator during these rounds.

The NRC staff finds that the licensee's flow testing program is adequate to determine potential through wall leakage from the affected pipe segments because the licensee's CAP contains procedures requiring corrective actions to be performed to determine the source of the leakage, regardless of the source. Therefore, the NRC staff finds that the licensee will properly identify the pipe through wall leakage, if occurred, and take corrective actions in accordance with its CAP.

3.4.3 Pipe Inside Surface Inspection The licensee periodically performs internal visual inspection on the subject pipe segments during refueling outages as stated in Section 5.2 of the relief request. The NRC staff asked the licensee to discuss whether the inside surface of the entire length of line 3-SWP-030-3-3 is visually inspected, how the internal visual inspection is conducted, and how often the internal visual inspection is performed.

- 14 In the December 20, 2012 letter, the licensee stated:

The entire inside surface of 3-SWP-030-3-3 is visually inspected, including the pipe segments covered by this relief request.

The most recent internal visual inspection was performed in April 2010, with no unsatisfactory conditions identified. The licensee also stated:

The internal visual inspection is performed remotely using a robotic crawler unit fitted with a high resolution pan and tilt camera. Any identified conditions such as erosion, corrosion, macrofouling, biofouling, or other degraded piping material condition are evaluated by Engineering for acceptance or corrective actions as required.

The internal visual inspection of the subject piping is conducted every other refueling outage. The inspection frequency has been determined to be adequate to ensure structural integrity of the subject piping based on the history of the inspection results. This frequency is also consistent with that which would be required for the ASME Code leakage test.

The NRC staff finds that the frequency of internal visual examination of the subject piping based on every other refueling outage is consistent with the requirements of the 2004 edition of the ASME Code,Section XI, Table IWD-2S00-1, and, therefore, is acceptable. The NRC staff finds that, in addition to the flow test, the periodic internal visual inspection will provide additional assurance on the structural integrity of the affected piping.

3.4.4 Hardship In the December 20,2012 letter, the licensee reiterated that Personnel entry into the confined space of the intake bays with equipment operational is considered a personnel safety hazard; therefore, equipment is required to be removed from service and tagged out prior to entry. Additionally, due to the physical configuration of the intake structure, each of the five bays requires draining to erect the scaffolding needed to access these bays. Draining the bays also requires equipment to be removed from service to preclude damage to the service water pumps that could occur with the bays drained. The licensee explained that unavailability of safety-related service water pumps places the station at a greater operational risk since it removes the availability of redundant equipment, introducing a reduction in the safety margin of the plant.

Placing the plant in a condition where safety-related service water is out of service for an extended period of time, resulting in increased operational risk, is considered a hardship without a compensating increase in the level of quality and safety. The NRC staff finds that the licensee has provided valid arguments to demonstrate that complying with the specified ASME Code requirement would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety.

- 15 In summary, the NRC staff finds that the proposed alternative in Relief Request IR-3-15 will provide reasonable assurance of the structural integrity and leak tightness of the affected piping because (1) the flow test procedures will be able to detect the potential leakage in the affected pipe segments in the intake structure bays, (2) the licensee performs visual examinations on the inside surface of the affected pipe segments every other refueling outages which would detect potential pipe degradation, and (3) the licensee walkdowns of the accessible areas of the intake structure during every shift which will identify significant leak~ge.

4.0 CONCLUSION

Based on the discussion above, the NRC staff determines that the proposed alternative provides reasonable assurance of structural integrity and leak tightness of the subject SW piping. The NRC staff finds that complying with the specified ASME Code requirement would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety. Accordingly, the NRC staff concludes that the licensee has adequately addressed all of the regulatory requirements set forth in 10 CFR 50.55a(a){3)(ii) and is in compliance with the requirements of the ASME Code,Section XI for which relief was not requested. Therefore, the NRC authorizes the use of Relief Request RR-04-09 at the MPS2 for the duration of the fourth 10-year lSI interval which ends on March 31,2020, and Relief Request IR-3-15 at the MPS3 for the third 1 O-year lSI interval which ends on April 22, 2019.

All other ASME Code,Section XI requirements for which relief was not specifically requested and approved in this relief request remain applicable, including third party review by the Authorized Nuclear Inservice Inspector.

Principal Contributor: J. Tsao Date: January 23, 2013

D. Heacock

- 2 If you have any questions, please contact the Millstone Power Station Project Manager, James Kim, at (301) 415-4125.

Docket Nos. 50-336 and 50-423

Enclosure:

As stated cc w/encl: Distribution via Listserv DISTRIBUTION:

PUBLIC LPL1-1 Reading File RidsNrrDorlLpl1-1 RidsNrrPMMillstone RidsNrrLAKGoldstein RidsAcrsAcnw_MailCTR RidsNrrDorlDpr RidsRgn1 MailCenter RidsNrrDeEpnb RidsOgcRp JTsao, NRR Sincerely, IRA!

George A. Wilson, Chief Plant Licensing Branch 1-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation a e J anuary 4 2013 ADAMS ACCESSION NO. ML13011A158

• S ee memo d t J

. OFFICE LPL 1-1/PM LPL1-1/LA EPNB/BC(A)

LPL1-1/BC NAME JKim KGoldstein KHoffman*

GWilson DATE 01/22/13 01/18/13 01/04/13 01/23/13 OFFICIAL RECORD COPY