ML042010250
| ML042010250 | |
| Person / Time | |
|---|---|
| Site: | Hope Creek  |
| Issue date: | 08/27/2004 |
| From: | Dan Collins NRC/NRR/DLPM/LPD1 |
| To: | Bakken A Public Service Enterprise Group |
| Collins D S, NRR/DLPM, 415-1427 | |
| References | |
| TAC MC2396 | |
| Download: ML042010250 (13) | |
Text
August 27, 2004 Mr. A. Christopher Bakken, III President & Chief Nuclear Officer PSEG Nuclear - X15 P.O. Box 236 Hancocks Bridge, NJ 08038
SUBJECT:
HOPE CREEK NUCLEAR GENERATING STATION - EVALUATION OF RELIEF REQUEST HC-RR-I2-023 (TAC NO. MC2396)
Dear Mr. Bakken:
By letter dated March 23, 2004, as supplemented by letter dated May 18, 2004, PSEG Nuclear, LLC (PSEG or the licensee) submitted a proposed alternative to the requirements of Section XI of the American Society of Mechanical Engineers Boiler and Pressure Vessel Code (ASME Code) under the provisions of Title 10 of the Code of Federal Regulations (10 CFR),
Section 50.55a(a)(3)(ii) for the Hope Creek Nuclear Generating Station (Hope Creek).
Specifically, Relief Request HC-RR-I2-023 proposed an alternative to ASME Code Section XI Leakage Testing following maintenance on the J and P main steam safety relief valves and Control Rod Drive Mechanism O-rings due to hardship or unusual difficulty without a compensating increase in the level of quality and safety in performing the test at normal full-power conditions. The request for relief is for a single time only. On March 30, 2004, the U.S. Nuclear Regulatory Commission (NRC) staff granted verbal authorization to PSEG for the relief request, to be followed up by the staffs final review and written evaluation.
Based on the information provided, the NRC staff concludes that compliance with the specified requirements would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety, as described in Relief Request HC-RR-I2-023. The NRC staff also concludes that the proposed alternative will provide reasonable assurance of pressure boundary integrity. Therefore, the NRC staff authorizes the proposed alternative, pursuant to 10 CFR 50.55a(a)(3)(ii), on a one-time basis only.
A. Christopher Bakken, III
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The NRC staffs Safety Evaluation is enclosed. If you have any questions, please contact G. Edward Miller, at 301-415-2481.
Sincerely,
/RA/
Daniel S. Collins, Acting Chief, Section 2 Project Directorate I Division of Licensing Project Management Office of Nuclear Reactor Regulation Docket No. 50-354
Enclosure:
As stated cc w/encl: See next page
ML042010250 See previous concurrence OFFICE PDI-2/PE PDI-2/LA EMCB/SC(A)*
OGC**
PDI-2/SC(A)
NAME GMiller CRaynor MMitchell HMcGurren DCollins DATE 08/23/04 08/23/04 06/13/04 8/23/04 08/27/04
Hope Creek Generating Station cc:
Mr. John T. Carlin Vice President - Nuclear Assessment PSEG Nuclear - N10 P.O. Box 236 Hancocks Bridge, NJ 08038 Mr. David F. Garchow Vice President - Engineering/Technical Support PSEG Nuclear - N28 P.O. Box 236 Hancocks Bridge, NJ 08038 Mr. Michael Brothers Vice President - Site Operations PSEG Nuclear - N10 P.O. Box 236 Hancocks Bridge, NJ 08038 Mr. James A. Hutton Plant Manager PSEG Nuclear - X15 P.O. Box 236 Hancocks Bridge, NJ 08038 Mr. Steven Mannon Acting Manager - Nuclear Safety and Licensing PSEG Nuclear - N21 P.O. Box 236 Hancocks Bridge, NJ 08038 Jeffrie J. Keenan, Esquire PSEG Nuclear - N21 P.O. Box 236 Hancocks Bridge, NJ 08038 Ms. R. A. Kankus Joint Owner Affairs Exelon Generation Company, LLC Nuclear Group Headquarters KSA1-E 200 Exelon Way Kennett Square, PA 19348 Lower Alloways Creek Township c/o Mary O. Henderson, Clerk Municipal Building, P.O. Box 157 Hancocks Bridge, NJ 08038 Dr. Jill Lipoti, Asst. Director Radiation Protection Programs NJ Department of Environmental Protection and Energy CN 415 Trenton, NJ 08625-0415 Brian Beam Board of Public Utilities 2 Gateway Center, Tenth Floor Newark, NJ 07102 Regional Administrator, Region I U.S. Nuclear Regulatory Commission 475 Allendale Road King of Prussia, PA 19406 Senior Resident Inspector Hope Creek Generating Station U.S. Nuclear Regulatory Commission Drawer 0509 Hancocks Bridge, NJ 08038
SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION REQUEST FOR RELIEF HC-RR-I2-023 SECOND 10-YEAR INSERVICE INSPECTION INTERVAL HOPE CREEK NUCLEAR GENERATING STATION PSEG NUCLEAR LLC DOCKET NO. 50-354
1.0 INTRODUCTION
By letter dated March 23, 2004, as supplemented by letter dated May 18, 2004, PSEG Nuclear, LLC (PSEG or the licensee) submitted a proposed alternative to the requirements of Section XI of the American Society of Mechanical Engineers Boiler and Pressure Vessel Code (ASME Code) under the provisions of Title 10 of the Code of Federal Regulations (10 CFR),
Section 50.55a(a)(3)(ii) for the Hope Creek Nuclear Generating Station (Hope Creek).
Specifically, Relief Request HC-RR-I2-023 proposed an alternative to ASME Code Section XI Leakage Testing following maintenance on the J and P main steam safety relief valves and Control Rod Drive Mechanism O-rings due to hardship and unusual difficulty in performing the test at normal full power conditions. The request for relief is for a single time only. On March 30, 2004, the U.S. Nuclear Regulatory Commission (NRC or the Commission) staff granted verbal authorization to PSEG for the relief request, to be followed up by the staffs final review and written evaluation.
2.0 REGULATORY EVALUATION
Inservice inspection (ISI) of ASME Code Class 1, 2, and 3 components is performed in accordance with Section XI of the ASME Code and applicable addenda, as required by 10 CFR 50.55a(g), except where specific relief has been granted by the Commission pursuant to 10 CFR 50.55a(g)(6)(i). Section 50.55a(a)(3) of 10 CFR states that alternatives to the requirements of paragraph (g) may be used, when authorized by the NRC, if (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 pre-service examination requirements, set forth in the ASME Code,Section XI, Rules for Inservice 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 examination of components and system pressure tests conducted during the first ten-year 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 interval, subject to the limitations and modifications listed therein. The applicable ASME Code edition of record for the second 10-year ISI interval for Hope Creek is the 1989 Edition of the ASME Boiler and Pressure Vessel Code,Section XI. The licensee invoked ASME Code Case N-389-1, Alternative Rules for Repairs, Replacement, or Modifications,Section XI, Division 1 which is approved for general use in Regulatory Guide (RG) 1.147, Revision 13, Inservice Inspection Code Case Acceptability ASME Section XI, Division 1. ASME Code Case N-389-1 allows a licensee to use editions and addenda of Section XI, Division 1, subsequent to those specified in the Owners Inservice Inspection Program for repair, replacement or modification. Specific provisions within the edition or addenda other than those in the Owners Inservice Inspection Program may be used, provided all related requirements are met. The edition or addenda shall have been accepted by the enforcement and regulatory authorities having jurisdiction at the plant site. ASME Code Case N-389-1 shall appear on the NIS-2 form. For repair/replacement activities, the licensee incorporated the 1995 Edition with 1996 Addenda of the ASME Code Section XI, Division 1.
3.0 TECHNICAL EVALUATION
3.1 ASME Code components affected:
The specific Class 1 Components that are affected by this relief request are as follows:
Main steam safety relief valves (SRVs) J and P assemblies, and Control rod drive mechanism (CRDM) O Rings.
3.2 Code requirements for which an alternative is proposed:
The licensee, in its submittal, identified the following Code requirements:
ASME Section XI, 1989 Edition, is the code of record for Hope Creek Generating Stations Second Ten-Year ISI Program Interval.
The 1995 Edition of American Society of Mechanical Engineers (ASME)Section XI with the 1996 Addenda, paragraph IWA-5120(a) states: Items subjected to repair/replacement activities shall be pressure tested when required by IWA-4500(a).
Paragraph IWA-4540(c) states: Mechanical joints made in installation of pressure retaining items shall be pressure tested when required by IWA-5211(a).
Paragraph IWA-5211(a) states: A system leakage test conducted during operation at nominal operating pressure, or when pressurized to nominal operating pressure and temperature.
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Paragraph IWB-5210(b) states: 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.
ASME Section XI, Table IWB-2500, Examination Category B-P, Item B15.10, requires a system leakage test of the Reactor Pressure Retaining Boundary (such as after component replacement).
IWB-5221(a) requires that the system leakage test shall be conducted at a test pressure not less than the normal operating pressure associated with 100% rated reactor power.
3.3 ASME Code for which an alternative is proposed:
Pursuant to 10 CFR 50.55a(a)(3)(ii), the licensee proposed a one-time only alternative to the required system leakage test under IWA-4550(c), because performing the ASME Code-required test at a test pressure not less than the normal operating pressure associated with 100% rated thermal power would result in a hardship or unusual difficulty without a compensating increase in the level of quality and safety.
3.4 Licensee's basis for relief:
The licensee provided the following justification for use of the alternative:
PSEG Nuclear, LLC (PSEG) Hope Creek Generating Station completed their eleventh refueling outage in May 2003. During the refueling outage PSEG completed the system leakage test required by American Society of Mechanical Engineers (ASME)Section XI, Table IWB-2500-1, Category B-P, Item 15.10 and 10 CFR Part 50 Appendix G, Section IV.A.2.d. Subsequent to the restart, the J and P main steam SRVs have indicated leakage, as determined by higher than normal temperatures in their respective discharge tailpipes. In addition, higher than anticipated leakage from several CRDM flanges has been noted.
PSEG has decided to conduct a planned unit shutdown and enter a maintenance outage to replace the affected SRV assemblies. The SRV assemblies are connected to the main steam piping with a bolted, mechanical joint. In addition several CRDM O-rings will be replaced. Replacing SRV assemblies is considered a Repair-Replacement activity under the rules of ASME Section XI, 1995 Edition with the 1996 Addenda.
Following repair-replacement, a system leakage test is required by IWA-4540(c). O-ring replacement on CRDMs is considered maintenance and, of itself, is exempt from the ASME Section XI pressure testing requirements, but since it will involve the opening and closing of the Reactor Coolant Pressure Boundary (RCPB), a system leakage test would nonetheless be performed to assure leakage integrity. The system leakage test at the nominal pressure associated with the reactor at 100% power would be approximately 1005 psig.
PSEG has identified three methods for performing the system leakage test on the mechanical joints associated with the repair-replacement activity that meet the requirements identified above. Several conditions associated with such testing
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represent an imposition on personnel safety and challenges to the normal mode and manner of equipment operation.
Method No. 1 would perform the pressure test and VT-2 exam during normal startup procedures. During normal startup with normal power ascension, nominal operating pressure of 1005 psig is reached at a reactor power level of approximately 100%. If access to containment were permitted at this power level, personnel would be exposed to excessive radiation levels, including significant exposure to neutron radiation fields, which is contrary to the current station ALARA [as low as reasonably achievable]
practices.
Establishing the 1005 psig test condition at a more moderate power level (e.g. during plant startup at approximately 7% reactor power) and in the manner needed to address radiation concerns would require altering the normal operational mode of the steam pressure control system.
During the performance of plant startup procedures, the Electro-Hydraulic Control (EHC) pressure regulator setpoint is established within normal operational ranges (approximately 920 psig). The primary function is to regulate the main steam system pressures as sensed near the inlet of the high-pressure turbine. Reactor pressure control at the nominal 1005 psig is achieved at higher reactor power levels as a function of the pressure control system and the induced differential pressure across the main steam isolation valves and main steam piping.
While it is technically feasible to manipulate these controls to establish the nominal system pressure of 1005 psig at lower power levels, this process may introduce new operational challenges and may require additional analyses. Although reactor pressure during low-power operation is sometimes raised from 920 psig to 950 psig to perform scram-time testing, it has not been previously raised to 1005 psig under these conditions. The lack of experience and predictability of setting pressure regulators outside the normal range of operation could adversely impact personnel and reactor safety.
Method No. 2 implements the use of the reactor pressure boundary leakage test which meets the requirements of Table IWB-2500-1, Category B-P, Item 15.10: the reactor pressure vessel (RPV) is filled with coolant and the steam lines are flooded to provide a water-solid condition. Use of this method would result in multiple operational challenges.
During a maintenance outage, decay heat and the reactor recirculation pumps would provide pressurization for the test. To support the pressurization evolution, the normal decay heat removal system, residual-heat removal (RHR) shutdown cooling, would be required to be removed from service and isolated from the vessel to be pressurized.
This system automatically isolates at 82 psig. Thus, the remaining system available for decay heat removal is the reactor water cleanup system (RWCU).
The application of the ANSI/ANS [American National Standards Institute/American Nuclear Society] -1994 decay heat code results in a significant level of decay heat load.
The ratio of decay heat input versus the heat removal capacity provided by [the] RWCU
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[system] is approximately 4:1. Therefore, the decay heat generated by the reactor core will surpass the capacity of RWCU [system]. The heat up rate of the vessel water will cause the temperatures to surpass 212 BF prior to the initiation of the inspections. This would violate Hope Creek Generating Station Technical Specifications.
Method No. 2 would present several operational challenges. The pressure increase would be obtained by balancing the flow into the vessel, which is provided by the control rod drive (CRD) system, with the flow out of the vessel provided by the RWCU system via the drain flow control valve and flow controller. This is the method used during refueling outages to complete the RPV system leakage test. A failure of a non-safety related component, such as the drain valve or flow controller, would cause the interruption of drain flow and would cause the RPV pressure to increase. The RPV pressure would increase until operator action would require the operating CRD pump to be tripped.
Due to the amount of decay heat being generated and the RWCU systems heat removal capacity, it is questionable whether the RPV would depressurize and may in fact continue to pressurize until further operator action would be required to depressurize the RPV. Operator actions may include one or more of the following: reestablishing RWCU drain flow if the failure mechanism was no longer present; opening the main steam line drain valves, SRVs, or head vent line. Any of these actions could cause a rapid depressurization transient on the RPV.
Extensive valve manipulations, system lineups, and procedural controls are required in order to heat up and pressurize the primary system to establish the necessary test pressure, during plant outage conditions, without the withdrawal of control rods. This test is expected to take greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of outage time, and the additional valve lineups and system reconfigurations necessary to support this test impose an additional challenge to the affected systems. A normal plant startup then occurs, after completion and subsequent recovery from the test procedure.
Method No. 3 would maintain the RPV at its normal level of +/-35 inches and use decay heat to produce sufficient steam pressure to conduct the test at nominal operating temperature. At the projected time of shutdown for the March 2004 maintenance outage, PSEG will have a run time of approximately 10 months since startup from the Cycle 11 refueling outage. The maintenance of SRV assemblies and CRD mechanisms is projected to be complete within 11 days after plant shutdown. While the decay heat load is too high for the water-solid method discussed above, there is not sufficient decay heat available to perform the test within a reasonable time period to support completion of the maintenance outage. It would require approximately 37 hours4.282407e-4 days <br />0.0103 hours <br />6.117725e-5 weeks <br />1.40785e-5 months <br />, after 5 days of decay, to reach the pressure of 1005 psig needed to perform the test required by the
[ASME] Code based upon decay heat projections and the current schedule is for approximately 11 days.
During a similar but much shorter 2003 maintenance shutdown to replace gaskets on the SRV assemblies, the decay heat method was used to pressurize the system for testing. The testing, although performed successfully, proved to be an extreme challenge to the operators to maintain level, pressure and temperature rate.
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Each of the methods discussed above presents a hardship or unusual difficulty to PSEG.
3.5 Licensees Proposed Alternative to the Code Requirements:
The licensees submittal proposed the following alternative:
PSEG proposes to perform a VT-2 examination on the mechanical joints of the SRV assemblies and CRD flanges during the normal operational start-up sequence at a minimum of 900 psig following a 10 minute hold time (for uninsulated components) in lieu of the nominal operating pressure associated with 100% reactor power (approximately 1005 psig).
The use of the normal method of Reactor start-up represents the safest approach to controlling the reactor pressurization and heat-up evolution. Application of this alternative test maintains reasonable levels of personnel safety and reduces the opportunity for the introduction of undesirable operational challenges.
Requiring normal operating temperature and pressure sub-critical core conditions prior to conducting a normal plant start-up will result in additional thermal cycling of the reactor vessel. This would represent an unnecessary challenge to the vessel from both a fatigue usage and brittle fracture margin perspective.
Examinations of the affected portions of the RCPB are reasonably expected to be performed successfully, even under core critical conditions, since access and ambient temperatures are not significantly different prior to and following criticality. Radiation exposure for the small scope of examinations performed at low power levels is not a concern.
Maintaining applicable Mode conditions (i.e. no core criticality) to conduct this pressure test of the RCPB can result in an unnecessary cycling of the RCPB and unnecessary operation of associated components due to Mode limitations. This can contribute to degradation of the structural components, which is contradictory to the goal of safe operation.
While PSEG does not expect that leakage will occur, any leakage at the bolted connection would be related to the differential pressure across the connection. A reduction in test pressure is less than 10%, and is not, therefore, expected to affect the ability of the VT-2 examination to detect leakage at the bolted connection.
In the event that leakage would occur at the mechanical joints at higher pressures associated with 100% reactor power, leakage from these mechanical connections would be detected by the drywell monitoring systems, which include drywell pressure monitoring, the containment atmosphere monitoring (CAM) system, and the drywell floor drain sumps. Leakage monitoring is required by PSEG Hope Creek Technical Specifications.
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In addition, if there is an unplanned shutdown with a drywell entry before the next refueling outage, another inspection of these bolted connections will be performed to look for any evidence of leakage.
This alternative method for a system leakage test is particularly applicable for the PSEG Hope Creek maintenance mini-outage, which is of limited scope, and where the only components on the primary system that are being replaced are the main steam J and P SRV assemblies and CRDM O-rings attached via mechanical connections.
In letter (LR-NO4-0137) [March 23, 2004] we [PSEG] indicated that a VT-2 examination on the mechanical joints of the SRV assemblies and CRD flanges would be performed during the normal operational start-up sequence at a minimum of 900 psig following a 10 minute hold time (for uninsulated components) in lieu of the nominal operating pressure associated with 100% reactor power (approximately 1005 psig). This one time only test was performed with the insulation removed and then reinstalled after completion of the test.
PSEG believes this alternative will provide an acceptable verification of the integrity of the mechanical joints without unnecessary radiation exposure and operational challenges.
3.6 NRC Staff's Evaluation:
The ASME Code,Section XI requires that system leakage tests be conducted at a test pressure not less that the nominal operation pressure associated with 100% rated thermal power. Relief is being requested from the ASME Code required system leakage test at nominal operation pressure following the replacement of the main steam SRVs J and P assemblies and O-rings for seven CRDMs. The O-ring replacement on CRDMs is a maintenance activity and is exempt from the ASME Code Section XI pressure testing requirements. However, since the RCPB will be opened and closed, the licensee will perform a system leakage test on the CRDMs to assure leakage integrity.
The main steam SRVs cannot be isolated from the reactor vessel. The licensee considered three other alternative methods for performing the system leakage test on the mechanical joints associated with the repair/replacement of the replaced J and P main steam SRVs and O-ring replacement on the seven CRDMs.
For Method No. 1, the licensee considered performing the pressure test and VT-2 exam during normal startup procedures at the nominal operating pressure of 1005 psig. With the reactor power level at approximately 100%, personnel would be exposed to excessive radiation levels which is contrary to current ALARA practices. Performing the VT-2 exam at 1005 psig with the power level at approximately 7% would require altering the normal operational mode of the steam pressure control system. The licensee noted it was technically feasible to manipulate these controls to establish the nominal system pressure of 1005 psig at lower levels. However, this procedure could cause new operational challenges and require additional analyses.
Although reactor pressure during low-power operation is sometimes raised from 920 psig to 950 psig to perform scram-time testing, the licensee has not previously raised the pressure of the reactor to 1005 psig under these conditions. Therefore, the licensee has not had experience in performing the testing under these condition nor have they had the experience to
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predict the setting of the pressure regulators outside the normal range of operation. Therefore, testing under these conditions could adversely impact personnel and reactor safety.
For Method No. 2, the licensee considered flooding the steam lines to provide a water-solid condition that would meet the ASME Code requirements. However, this method would result in multiple operational challenges in that the decay heat and the reactor recirculation pumps would be providing pressurization for the test. The normal decay heat removal system, RHR shutdown cooling, automatically isolates at 82 psig. Therefore, the remaining system available for decay heat removal would be the RWCU system. Due to the heat load and lessened heat removal capability, the heat-up rate of the vessel water would cause the temperatures to exceed 212 BF prior to the inspections. The higher temperature would violate the Hope Creek Technical Specifications (TSs).
In Method No. 2, pressure increases would have to be controlled by the manipulation of the flow into and out of the vessel, which are provided by the CRD system and the RWCU systems via the drain flow valve and flow controller, respectively. The licensee noted that this method could cause a failure of a non-safety related component, such as the drain valve or flow controller, which would cause the interruption of drain flow. These failures would result in an increase in RPV pressure, requiring operator action to end the transient.
Furthermore, because of the amount of decay heat being generated and the heat removal capacity of the RWCU system, the RPV could continue to pressurize above 1005 psig, requiring operator action to depressurize the RPV. The actions by the operator could include reestablishing RWCU system drain flow (if the failure mechanism was no longer present), or opening the main steam line drain valves, SRVs, or head vent line which could result in a rapid depressurization transient on the RPV.
Method No. 2 would also require the licensee to manipulate valves, lineup systems, and establish procedural controls in order to heat up and pressurize the primary system to establish the necessary test pressure, during plant outage conditions without the withdrawal of control rods.
For Method No. 3, the licensee would maintain the RPV at its normal level of approximately 35 inches and use decay heat to produce sufficient steam pressure to conduct the test at nominal operating temperature. The licensee noted that at the projected time of shutdown for the March 2004 maintenance outage, the plant would have had a run time of approximately 10 months since the Cycle 11 refueling outage. The licensee determined that the maintenance of the SRV assemblies and CRD mechanisms would take approximately 11 days after the plant is shutdown.
Although the decay heat load is too high for the water-solid method discussed in Method No. 2, there would not be sufficient decay heat available to perform the test using Method No. 3 within the maintenance outage.
As an alternative to the ASME Code requirements, the licensee proposed to perform a VT-2 examination on the mechanical joints of the SRV assemblies and CRD flanges during the normal operational start-up sequence at a minimum of 900 psig following a ten minute hold time for uninsulated components in lieu of the nominal operating pressure associated with 100%
reactor power. The valves bolted connection is normally insulated; however, to facilitate the
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leakage test the insulation will be removed. After performance of the test, the insulation will be reinstalled. The use of the licensees proposed alternative provides the safest approach to controlling the reactor pressurization. Furthermore, the proposed alternative maintains reasonable levels of personnel safety, reduces the probability of undesirable operational challenges, and protects the vessel from both a fatigue usage and brittle fracture margin perspective.
The licensee noted that it does not expect that leakage will occur and any leakage at the bolted connection would be related to the differential pressure across the connection. The reduction in test pressure of less than 10%, is not expected to affect the ability of the examiners to detect leakage at the bolted connections. If there is leakage at the mechanical joints at higher pressures associated with 100% reactor power, the leakage would be detected by the drywell monitoring systems, which include drywell pressure monitoring, the containment atmosphere monitoring system, and the drywell floor drain sumps. The Hope Creek TSs require continuous drywell leakage monitoring. Therefore, the staff finds that the proposed alternative will provide reasonable assurance of pressure boundary integrity. Additionally, the licensee stated that if there is an unplanned shutdown with a drywell entry before the next refueling outage, it will inspect the subject bolted connections for any evidence of leakage.
The staff, therefore, finds that compliance with the ASME Code would result in a hardship or unusual difficulty without a compensating increase in the level of quality and safety.
4.0 CONCLUSION
Based on the above evaluation, the NRC staff has determined that performing the leakage test at 1005 psig in compliance with the ASME Code would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety. Therefore, pursuant to 10 CFR 50.55a(a)(3)(ii), the proposed alternative HC-RR-I2-023 is authorized for the subject J and P main steam SRV and CRDM O-rings at Hope Creek on a one-time basis.
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: T. McLellan Date: August 27, 2004