LR-N24-0030, License Amendment Request to Revise Technical Specification Lift Settings for Reactor Coolant System Safety/Relief Valves

License Amendment Request to Revise Technical Specification Lift Settings for Reactor Coolant System Safety/Relief Valves

ML24180A127
Person / Time
Site:	Hope Creek
Issue date:	06/28/2024
From:	Denight R Public Service Enterprise Group
To:	Office of Nuclear Reactor Regulation, Document Control Desk
Shared Package
ML24180A126	List: LR-N24-0030, License Amendment Request to Revise Technical Specification Lift Settings for Reactor Coolant System Safety/Relief Valves
References
LR-N24-0030, LAR H24-03
Download: ML24180A127 (62)

Text

Robert DeNight HCGS Site Vice President, PSEG Nuclear

PO Box 236 Hancocks Bridge, New Jersey 08038-0221 856-339-5303 robert.denightjr@pseg.com

Attachment 5 Contains Proprietary Information to be Withheld from Public Disclosure Pursuant to 10 CFR 2.390 10 CFR 50.90 LR-N24-0030 LAR H24-03

June 28, 2024

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

Hope Creek Generating Station Renewed Facility Operating License Nos. NPF-57 NRC Docket No. 50-354

Subject:

License Amendment Request to Revise Technical Specification Lift Settings for Reactor Coolant System Safety/Relief Valves

In accordance with the provisions of 10 CFR 50.90, PSEG Nuclear LLC (PSEG) is submitting a request for an amendment to the Technical Specifications (TS) for Hope Creek Generating Station (HCGS).

The proposed change will revise the HCGS Technical Specification (TS) 3/4.4.2.1, Safety/Relief Valves, to modify the code safety valve function lift settings to 1130 psig for all fourteen (14) valves. The proposed amendment would also expand the as-found safety function lift setpoint tolerances that are listed in TS 3/4.4.2.1. This change would be limited to the lower tolerances and would not affect the upper limits. The as-found tolerance band for these valves would be changed from +/- 3% to +3% or -5% of the setpoint. The as-left tolerance band for the safety function lift setpoints will continue to be +/-1% as required by Surveillance Requirement (SR) 4.4.2.2. In addition, as a result of analyses performed in support of this change, SR 4.1.5.c associated with TS 3/4.1.5 Standby Liquid Control System (SLC) is modified to increase the IST test pressure from the current 1255 psig to 1281 psig.

The Enclosure provides a description and assessment of the proposed changes. Attachment 1 provides the existing TS pages marked up to show the proposed changes. Attachment 2 provides changes to the TS Bases, for information only.

contains proprietary information as defined by 10 CFR 2.390, which has been determined to be proprietary by GEH Nuclear Energy. An affidavit supporting this request for withholding from public disclosure is provided in Attachment 4. A non-proprietary version of is provided in Attachment 3. GEH, as the owner of the proprietary information, has executed the Attachment 4 affidavit identifying that the proprietary information has been handled and classified as proprietary, is customarily held in confidence and withheld from public disclosure. GEH requests that the proprietary information in Attachment 5 be withheld from public disclosure, in accordance with the requirements of 10 CFR 2.390(a)(4).

LR-N24-0030 10 CFR 50.90 Page 2

PSEG requests approval of this license amendment request (LAR) by July 31, 2025. Once approved, the amendment shall be implemented during the Fall 2025 refueling outage.

In accordance with 10 CFR 50.91, a copy of this application, with attachments, is being provided to the designated State of New Jersey Official.

There are no regulatory commitments contained in this letter.

If you have any questions or require additional information, please contact Mr. Brian Thomas at brian. thomas@pseg.com.

I declare under penalty of perjury that the foregoing is true and correct.

Executed on --~~/_t_g_(_i. _y __ _

(Date)

Respectfully,

R~¥ Site Vice President Hope Creek Generating Station

Enclosure:

Evaluation of the Proposed Changes : Mark-up of Proposed Technical Specification Pages : Mark-up of Proposed TS Bases Pages : GE-Hitachi (GEH) Nuclear Energy report NEDO-34037, "Safety Review for Hope Creek Generating Station Safety/Relief Valve Setpoint Increase and Tolerance Change," Revision 0, dated May 2024 (Non-Proprietary) : Affidavit from GEH Supporting the Withholding of Information in Attachment 5 from Public Disclosure : GE-Hitachi (GEH) Nuclear Energy NEDC-34037P, "Safety Review for Hope Creek Generating Station Safety/Relief Valve Setpoint Increase and Tolerance Change," Revision 0, dated May 2024 (Proprietary)

cc: Administrator, Region I, NRC Project Manager, NRC NRC Senior Resident Inspector, Hope Creek Ms. A. Pfaff, Manager, NJBNE PSEG Corporate Commitment Tracking Coordinator Site Commitment Tracking Coordinator LR-N24-0030 LAR H24-03

Enclosure

Evaluation of the Proposed Changes

Table of Contents

1.0

SUMMARY

DESCRIPTION.............................................................................................. 1

2.0 DETAILED DESCRIPTION............................................................................................... 1

2.1 System Design and Operation.................................................................................... 1 2.2 Current Technical Specifications Requirements......................................................... 3 2.3 Reason for the Proposed Change............................................................................... 3 2.4 Description of the Proposed Change.......................................................................... 5

3.0 TECHNICAL EVALUATION

.............................................................................................. 5

4.0 REGULATORY EVALUATION

........................................................................................ 13

4.1 Applicable Regulatory Requirements/Criteria........................................................... 13 4.2 Precedents................................................................................................................ 15 4.3 No Significant Hazards Consideration..................................................................... 15 4.4 Conclusion................................................................................................................ 17

5.0 ENVIRONMENTAL CONSIDERATION

.......................................................................... 17

6.0 REFERENCES

................................................................................................................ 18

ATTACHMENTS:

1. Mark-up of Proposed Technical Specification Pages 2: Mark-up of Proposed TS Bases Pages 3: GE-Hitachi (GEH) Nuclear Energy NEDC-34037NP, "Safety Review for Hope Creek Generating Station Safety/Relief Valve Setpoint Increase and Tolerance Change,"

Revision 0, dated May 2024 (Non-Proprietary)

4. GEH Affidavit 5: GE-Hitachi (GEH) Nuclear Energy NEDC-34037P, "Safety Review for Hope Creek Generating Station Safety/Relief Valve Setpoint Increase and Tolerance Change,"

Revision 0, dated May 2024 (Proprietary)

LR-N24-0030 LAR H24-03 Enclosure

1.0

SUMMARY

DESCRIPTION

The proposed change will revise the Hope Creek Generating Station (HCGS) Technical Specification (TS) 3.4.2.1, Safety/Relief Valves (SRV), to change the specified code safety valve function lift settings from the current staggered settings (4 valves @1108 psig +/-3%, 5 valves @1120 psig +/- 3%, and 5 valves @1130 psig +/- 3%) to 1130 psig +3% or -5% for all fourteen (14) valves. The lower as-found tolerance is changed from -3 percent (%) to -5%. The TS 3.4.2.2, Low-Low Set functions, and TS 3.5.1, Automatic Depressurization System (ADS),

related functions of these valves remain unchanged by the proposed activities.

Also, as a result of analyses for this change, Surveillance Requirement (SR) 4.1.5.c associated with TS 3/4.1.5, Standby Liquid Control System (SLC), is modified to increase the test pressure from 1255 psig to 1281 psig.

2.0 DETAILED DESCRIPTION

2.1 System Design and Operation

Safety Relief Valves (SRVs)

Per HCGS Updated Final Safety Analysis Report (UFSAR) Section 5.2.2.4.1, the SRVs have two main protection functions:

1. Overpressure Safety Operation - The valves open automatically to limit a pressure rise, and

2. Depressurization Operation - The Automatic Depressurization System (ADS) valves open automatically as part of the Emergency Core Cooling System (ECCS) for events involving small breaks in the Reactor Coolant Pressure Boundary (RCPB).

Per UFSAR Section 7.6.1.6.2, each SRV is capable of remote-manual operation by a solenoid valve and pneumatic cylinder. The five ADS SR Vs are provided with two solenoid operated valves and a pneumatic operator, while the nine non-ADS SRVs are provided with one solenoid operated valve and a pneumatic operator. Two non-ADS SRVs on opposite sides of the reactor pressure vessel are provided with a low-low set logic that allows these two SRVs to open at setpoints that are lower than the normal SRV spring-set opening and closing setpoints. With respect to the above functions, only the Overpressure Safety Operation function is affected by the pilot lift setpoint. ADS, remote-manual, and low-low set functions of these valves are independent of pilot actuation (the solenoid/pneumatic operators directly actuate the 2 nd stage of the 3-stage model) and therefore are unaffected by the proposed change in pilot setpoint lift pressures or tolerances.

Per TS Bases 3/4.4.2, a function of the SRVs is to prevent the reactor coolant system from being pressurized above the Safety Limit of 1375 psig in accordance with the American Society of Mechanical Engineers (ASME) Code. A total of 13 operable SRVs are required to limit reactor pressure to within ASME III allowable values for the worst-case transient. Sufficient redundancy is provided for the low-low set system such that failure of any one valve to open or close at its reduced setpoint does not violate the design basis.

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The HCGS SRVs also have a safety-related function to limit RCS pressure during postulated Anticipated Transients Without Scram (ATWS) events, and indirect roles to limit reactor pressure in support of injection system functions associated with the High Pressure Coolant Injection (HPCI), Reactor Core Isolation Cooling (RCIC), and Standby Liquid Control (SLC) systems as described in UFSAR Sections 6.3.1.2.1 and 5.4.6.1. Other indirect functions are associated with ensuring fuel limits (i.e., MCPR) are met following transients, and with containment and internal component (i.e., SR V downcomer, sparger, and suppression pool) integrity.

The HCGS SRVs were originally 6 x 10 Target Rock (TR) Model 7567F, two stage safety relief valves. Similar to other nuclear-utility TR 2-stage SRV users, the original HCGS SRVs suffered chronic setpoint drift due to corrosion bonding. To remedy this and to ensure adherence to the

+3% end of the lift setpoint tolerance required by Technical Specifications, HCGS completed replacement of the original Target Rock 2-Stage SRVs with Target Rock 3-Stage Model 0867F SRVs after performing a wide-ranging review of alternate SRV models used in nuclear power plants in the United States as well as outside the US.

The current HCGS models are Hatch Modified TR 3-Stage Model 0867F SRVs with the slowdown modification TR option. The 3-Stage Target Rock SRVs have the same setpoint, capacity, and response time requirements as the 2-Stage SRV. The 3-Stage TR SRV model is in use at several facilities in the US nuclear industry and does not have a history of setpoint drift in excess of +3%.

However, in the conservative direction of the tolerance range (-3%), the 3-stage models at times have been subject to a bellows-relaxation phenomenon which over time lowers its lift setpoint.

Thus, the tolerance band for SRVs is proposed to be changed from +/-3% to +3% or -5% of the safety lift function setpoint. This change only applies to the as-found tolerance band and not to the as-left tolerance band which will remain at +/-1% of the safety function lift setpoint. The as-found tolerances are used for determining operability and to increase sample sizes for testing.

The proposed change relaxes an unnecessarily restrictive surveillance requirement. As discussed further in this document, the proposed change will not impact the reliability of the SRVs or adversely impact their ability to perform their safety function(s). The SRVs are required to meet the American Society of Mechanical Engineers (ASME) Operations and Maintenance (OM) Code limits based on valve type and size to ensure acceptable valve performance (Reference 1).

Standby Liquid Control (SLC) System

The Standby Liquid Control system is designed to automatically initiate upon receipt of a signal from the Redundant Reactivity Control System (RRCS) logic. Low vessel water level (L2), high reactor vessel dome pressure, or manual RRCS actuation starts a 230 second timer. If the core power is not downscale as indicated by the Average Power Range Monitors at the end of this time delay, SLC operation is initiated. The RRCS system will initiate both SLC system pumps during an ATWS event.

The SLC system is needed only in the event that not enough control rods are inserted into the reactor core to accomplish shutdown and cooldown in the normal manner. Normally the reactor scram function of the Control Rod Drive (CRD) System, initiated by the Reactor Protection

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System (RPS) and backed up by the alternate rod insertion (ARI) function, is expected to ensure prompt shutdown of the reactor when required.

Each positive displacement injection SLC pump is sized to inject boron solution into the reactor at the nominal rate of 43 gpm. Per UFSAR Section 9.3.5.1, means are provided by which the functional performance capability of the system components can be verified periodically under conditions approaching actual use requirements. Technical Specifications currently require that a minimum flow requirement of 41.2 gpm, per pump, is demonstrated at a pressure of greater than or equal to 1255 psig.

2.2 Current Technical Specification Requirements

Technical Specification 3/4.4.2, Safety/Relief Valves, states:

3.4.2.1 The safety valve function of at least 13 of the following reactor coolant system safety/relief valves shall be OPERABLE*# with the specified code safety valve functions lift settings:**

4 safety-relief valves @ 1108 psig +/-3%

5 safety-relief valves @ 1120 psig +/-3%

5 safety-relief valves @ 1130 psig +/-3%

Standby Liquid Control System, SR 4.1.5.c states that the standby liquid control system shall be demonstrated OPERABLE by:

c. Demonstrating that, when tested purs uant to the INSERVICE TESTING PROGRAM, the minimum flow requirement of 41.2 gpm, per pump, at a pressure of greater than or equal to 1255 psig is met.

2.3 Reason for the Proposed Change

2.3.1 Reason for Raising Setpoints

The purpose of the proposed SRV lift setpoint change is to increase valve simmer margin (i.e.,

the difference between 100% rated reactor pressure and the SRV lift setpoint) for the upgraded Target Rock 3-Stage 0867F model valves. HCGS station and other BWR operating experience with these newer model valves supports that increased station reliability can be achieved with higher simmer margin, along with other initiatives involving altered maintenance practices, and reduction of steam line dynamic effects. Analyses performed in support of the proposed change show that there is a resulting minimal change in safety margins with the increased lift settings, and all parameters remain within existing safety limits.

With the new TR 3-stage SRV models installed, HCGSs operating experience (OE) to date supports that they are superior to the 2-stage models with respect to maintenance of the safety-related end (+3%) of the technical specification required tolerance, enhancing their reliability to perform their safety-related overpressure functions. However, this OE and the experience of similar BWR users support the position that, due to their more sensitive first stage pilots, the 3-stage models are more prone to and less tolerant of first stage pilot leakage than the previous 2-stage models. HCGS has experienced four reactor shutdowns in the past few years associated with TR 3-stage SRV leakage. Investigation of these leakage-related events associated with

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the replacement 3-stage models supports that their reliability is dependent on several plant-specific parameters including 1) simmer margin which is defined as the difference in pressure between rated reactor pressure (1005 psig in the case of HCGS) and the SRV lift setpoint, 2) maintenance practices that affect tolerances, and 3) steam line velocities which can produce undesirable acoustic and dynamic pressures near or within these valves.

The proposed change associated with this License Amendment Request involves only an increase to SRV simmer margin, by raising the lower tier SRV setpoints (i.e., 1108 psig and 1120 psig) to the higher 1130 psig setpoint. Having the same SRV setpoint applied across all SRVs achieves the design objective of increas ing simmer margin for the HCGS SRVs without any substantial loss of margin to overpressure. Other activities to improve pilot maintenance of these newer models and to reduce system relate d steam line dynamic effects which may also be negatively influencing their reliability are being pursued independent of this LAR, in accordance with other plant procedures/processes.

2.3.2 Reason for Relaxing Tolerance

The as-found SRV tolerances are used for determining operability and to increase sample sizes for SRV testing should the TS tolerance be exceeded. Currently, a partial compliment of SRVs are removed during each refueling outage, bench tested for safety set pressure and replaced with valves certified to have zero seat-to-disc leakage and safety lift setpoint tolerances within

+/-1% of the setpoint as specified in the SR 4.4.2.2. If the as-found lift is outside of +/-3% for one of the SRVs tested from the original sample size, the sample size is increased in accordance with Inservice Testing (IST) Program requirements. The operability of the SRVs is based on the TS acceptance criteria with a setpoint tolerance of +/-3%. If any SRV exceeds the tolerance, a notification for each SRV that exceeds the tolerance is entered into the HCGS Corrective Action Program to evaluate the test failure. In addition, test failures outside of +/-3%

would result in testing additional valves to comply with the ASME OM Code requirements adding additional unplanned scope to the refueling outage.

With respect to the relaxation of the SRV lower tolerance from -3% to -5%, a review of as-found test data for the HCGS SRVs (as well as other industry operating experience with the 3-stage models) (Reference 2) indicates a tendency for minor setpoint drift in the negative direction.

HCGS experience shows that it is the nature of these valves to have drift/variance with an initial as-found low lift pressure (see Section 3.5 for HCGS testing history). This may be attributed to a bellows relaxation phenomenon in which the metal bellows used in the pilot stage of these valves relax somewhat over time when exposed to pressure during the cycle. By relaxing (or expanding), pilot lift will begin at a slightly lower reactor pressure. This has no adverse impact on the Safety (or Spring) mode of operation required by the ASME Code, since lifting will occur earlier and peak pressures will be lower for both ASME and ATWS related events.

No change is being made to the as-left tolerance band required by SR 4.4.2.2. All safety relief valves will continue to be re-certified to meet a +/-1% tolerance prior to returning the valves to service after setpoint testing. The proposed change will not impact the reliability of the SRVs or adversely impact their ability to perform their safety function.

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2.3.3 Reason for SLC SR Change

Due to an increase in the predicted pressure following an ATWS at the time of SLC initiation resulting from the proposed change, the minimum reactor pressure testing requirement of 1255 psig is changed to 1281 psig for the SLC system. The minimum flow requirement remains unchanged.

In support of the proposed changes, HCGS Nuclear Steam Supply System (NSSS) vendor, GE Hitachi Nuclear Energy (GEH) has prepar ed and issued GEH report NEDC-34037P, "Safety Review for Hope Creek Generating Station Safety/Relief Valve Setpoint Increase and Tolerance Change," Revision 0, dated May 2024. A proprietary copy of this report is provided in and a non-proprietary version is provided in Attachment 3. The results of the evaluations in the GEH report determined that the impacts of the setpoint and tolerance changes are acceptable.

2.4 Description of Proposed Change

HCGS TS 3.4.2.1, Limiting Condition for Operation (LCO) is revised as follows:

3.4.2.1 The safety valve function of at least 13 of the following reactor coolant system safety/relief valves shall be OPERABLE*# with the specified code safety valve functions lift settings:**

4 safety-relief valves @ 1108 psig +/-3%

5 safety-relief valves @ 1120 psig +/-3%

5 safety-relief valves @ 1130 psig +/-3%

14 safety-relief valves @ 1130 psig +3% or -5%

SR 4.1.5.c is revised as follows:

c. Demonstrating that, when tested purs uant to the INSERVICE TESTING PROGRAM, the minimum flow requirement of 41.2 gpm, per pump, at a pressure of greater than or equal to 1255 1281 psig is met.

The actual marked-up TS pages are provided in Attachment 1. TS Bases mark ups are provided in Attachment 2 to show the associated TS Bases changes and are provided for information only.

3.0 TECHNICAL EVALUATION

On March 8, 1993, the NRC issued a Safety Evaluation (SE) (Reference 3) for the GE Nuclear Energy Licensing Topical Report (LTR) NEDC-31753P (Reference 4) submitted by the Boiling Water Reactor Owners Group (BWROG). In the SE, the NRC stated that a generic change of setpoint tolerance to +/-3% is acceptable provided that it is evaluated in the analytical bases.

The required analysis was completed for HCGS and the change was approved by the NRC as Amendment 115 (Reference 5).

The current proposed technical specification changes were evaluated using the previously

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accepted methodology of LTR NEDC-31753P (Reference 4), and the associated SE (Reference 3). Conclusions are based on analyses and evaluations performed by both GE Hitachi Nuclear Energy (GEH) and PSEG.

The evaluation of the proposed changes, included 1) a review of all design functions of the SRVs, 2) identification of limiting analyses performed by either PSEG or GEH which credit SRVs for mitigation of pressure-related events, 3) identification of other systems credited as functioning or performing safety functions during high Reactor Coolant System (RCS) pressures, 4) identification of other considerations such as fuel safety limits, and 5) stress-related impacts due to higher SRV flows or setpoint pressures.

The evaluation of the proposed change determined that the following technical aspects of the change need to be addressed:

Simmer and Operating Margin RCS Overpressure Protection (Non-ATWS and ATWS related transients/events)

High Pressure Systems Impact (HPCI, RCIC and SLC)

Other Technical Considerations (Loss of Coolant Accident (LOCA), Containment, Fuel Limits, Downcomer Stresses, Suppression pool)

Surveillance Test History

3.1 Target Rock 3-Stage Model 0867F SRV Simmer and Operating Margin

The purpose of raising the setpoint of the 9 SRVs whose setpoints are either 1108 psig or 1120 psig to 1130 psig is to increase simmer margin on all SRVs to a single value. The simmer margin is defined as the difference between Reactor Operating pressure (1005 psig nominal) and SRV Setpoint. The increase in simmer margin is a manufacturer recommendation that is expected to contribute to a decreased probability of SRV Pilot Stage leakage. Per GE Service Information Letter (SIL) 196 Supplement 3 (Reference 7), the manufacturer recommended simmer margin is 120 psi. Raising the setpoint to 1130 psig will provide HCGS with a simmer margin of 125 psi on all of its SRVs. A uniform simmer margin across all SRVs brings HCGS in line with many of its peer BWRs that use Target Rock SRVs.

The 3-Stage Model 0867F pilot stem begins to move at a pressure lower than its lift setpoint, a pressure called its abutment pressure. The abutment pressure of the HCGS 3-Stage SRVs is greater than or equal to 92% of the setpoint. With an 1108 psig setpoint, and a 92% abutment pressure, the pilot stem begins to move at approximately 1019 psig (assuming no drift). With the +/- 3 % TS tolerance, pilot stem movement could begin below the running normal pressure of 1005 psig, thus, potentially causing pilot stage leakage resulting in the potential for unplanned shutdowns for repair. With the increase of the lower tier 1108 and 1120 psig valves to 1130; simmer margin is improved by 22 psid, and 10 psid, respectively.

Regarding the tolerance change, the purpose of the lower setpoint tolerance is to ensure sufficient margin exists between the normal operating pressure in the system and the point at which the SRVs actuate in the overpressure safety mode. The nominal operating pressure of the reactor pressure vessel is 1005 psig. A lower setpoint value of -5%, applied to the new SRV set pressure of 1130 would allow it to lift at 1073.5 psig. Thus, a margin of 68.5 psig is maintained. With respect to a 92% abutment pressure, with or without the proposed change, the HCGS SRVs may start to lift theoretically below running reactor pressure (e.g., currently at 989 psig for the lowest valves (1108 x.97 x.92); changed to 988 psig with the proposed

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changes (1130 x.95 x.92). However, important to note is that this is only for the as-found condition. The as-left or as-installed setpoint tolerances are unchanged thus the change has a negligible effect on the actual operation of the SRVs. The valves removed for testing are returned with a tolerance of +/-1% prior to being installed for service, thereby returning the margin to the original levels for the existing 1130 psig set valves, and increasing the margin for the currently 1108, and 1120 psig set valves. Thus, normal operating margin is increased overall by the proposed changes.

3.2 Overpressure Protection (ASME and ATWS)

HCGS has previously implemented the single SRV out of service (1 SRVOOS) option. The evaluations discussed below only credit the operation of 13 of the 14 SRVs.

3.2.1 Over-Pressure Limits

The following reactor vessel pressure limits are in effect at HCGS and are unchanged with respect to the proposed change.

HCGS Overpressure Limits Pressure Title Reference

HCGS TS 2.1.3, Safety Limit 1325 psig Technical Specification (adjusts for vessel bottom Safety Limit pressure as measured in the steam dome)

Safety limit as specified in the 1375 psig ASME Code Transient Limit ASME code for pressure transients.

ASME Service Level C limit.

1500 psig Code Limit for ATWS Event Applicable to infrequent events such as ATWS.

3.2.2 Overpressure Evaluation

The following limiting events where SRVs provide plant safety functions were re-evaluated in support of the proposed change. Refer to Sections 3.0 and 7.0 of GEH NEDC-34037 for additional supporting information associated with these evaluations.

Non-ATWS Events ATWS Events

3.2.3 ASME Overpressure Analysis - MSIV Closure Event (SCRAM on high flux)

The ASME overpressure events evaluation was recently re-performed by GEH as part of a separate LAR associated with an effort to transition HCGS to a 24-month fuel cycle (MFC)

(Reference 6). The evaluation confirmed RPV overpressure compliance with the ASME upset code limit (1375 psig) with both an 18-month cycle core configuration and a 24-month cycle core

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configuration with all required SRVs having a code safety valve function lift setpoint of 1130 psig.

The ASME overpressure analyses determined that the MSIV Closure with Flux Scram (MSIVF)

Event is the limiting high pressure transient event. The HCGS Cycle 25 analysis evaluated an MSIV closure event with high-flux scram and calculated a peak reactor vessel pressure of 1289 psig.

The overpressure analyses were re-evaluated at the current licensed power level of 3902 MWt with all SRVs assumed at a lift setpoint pressure of 1130 psig +3% and assuming both 18 and 24 MFCs. Results of these evaluations show that a peak calculated reactor vessel pressure of 1294 psig following an MSIVF Event is limiting. In both cases there is sufficient margin to the TS pressure limit of 1325 psig and the 1375 psig ASME Code limit.

With respect to the change in tolerance to -5%, in any pressurization case, an earlier opening of the SRVs due to lower setpoints would produce improved results and gain margin. SRVs opening earlier would improve the short-term peak vessel pressure response. Therefore, there is no impact on the short-term peak vessel pressure ASME response associated with the lower tolerance change.

3.2.4 Anticipated Transients without SCRAM (ATWS)

The ATWS event evaluation was recently re-performed by GEH as part of a separate LAR associated with an effort to transition HCGS to a 24MFC (Reference 6). This evaluation concluded that use of the 24MFC results bounds t hose using the current 18-month fuel cycle.

Limiting ATWS events were evaluated against acceptance criteria for peak reactor vessel pressure at the ASME Service Level C limit of 1500 psig. The two events with the highest reactor vessel pressures were MSIV closure (with no scram) and pressure regulator failed-open (PRFO with no scram). Peak pressure in the MSIV closure event was 1434 psig, while the peak pressure for the PRFO event was 1468 psig (both events are modeled at the beginning of the operating cycle).

ATWS analyses were re-run at the current licensed power level of 3902 MWt with all SRVs assumed at a lift setpoint pressure of 1130 psig +3%/-5%. Results of these analyses show that the peak pressure following the MSIV closure event is changed to 1441 psig, while the peak pressure for the PRFO event becomes 1473 psig. Both remain below the established 1500 psig acceptance criteria for an ATWS, with adequate margin.

With respect to the change in tolerance to -5%, in any pressurization case, an earlier opening of the SRVs due to lower setpoints would produce improved results and gain RPV pressure margin. The ATWS analysis methodology includes the statistical spreading of SRV opening setpoints around the upper analytical limit (nominal opening setpoint plus the upper SRV tolerance). The upper SRV opening tolerance is not changing, and therefore the statistical spreading of SRV opening setpoints is not impacted. The lower SRV tolerance is not specifically modeled in the ATWS analysis methodology. SRVs opening earlier would improve the short-term peak vessel pressure response. Therefore, there is no impact on the short-term peak vessel pressure ATWS response associated with the lower tolerance change.

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3.3 Impact on Other Systems (HPCI, RCIC, and SLC)

3.3.1 High Pressure Coolant Injection

The function of the HPCI system is described in UFSAR section 6.3.1.2.1. The HPCI system pumps water through one of the core spray spargers and one of the feedwater spargers. The primary purpose of HPCI is to maintain reactor vessel inventory after small breaks that do not depressurize the reactor vessel. The HPCI system is also used to maintain reactor vessel inventory following reactor isolation and coincident failure of the non-ECCS Reactor Core Isolation Cooling (RCIC) System. The HPCI System consists of a steam turbine driven, constant flow pump assembly and associated system piping, valves, controls, and instrumentation.

Per the UFSAR, the HPCI system ensures that the reactor core is not uncovered if there is a small break in the RCPB that does not result in rapid depressurization of the reactor vessel.

This permits the plant to be safely shut down, by maintaining sufficient reactor vessel water inventory while the reactor vessel is depressuriz ed. The HPCI system continues to operate until the reactor vessel is depressurized to the point at which operation of the Low Pressure Coolant Injection (LPCI) and/or core spray systems can maintain core cooling.

The minimum HPCI flow available, 5600 gpm, was used in the accident analysis for simulation of the flow over the high-pressure range, with 2000 to 3000 gpm injecting through the core spray sparger and the remainder through the feed water sparger.

A change in the SRV opening pressure will only affect those pipe break events in which there will be SRV actuations. For large break sizes (LOCA), reactor pressure decreases from the point in which the break initiates; thus, higher SRV setpoints have no effect on HPCI capabilities during these events. For a Steam Line Break outside of containment, NEDC 34037P supports that the change in peak cladding temperature (PCT) due to a higher SRV setpoint would be insignificant.

For the small break LOCA for which HPCI is designed, pressure initially decreases but it peaks later into the event after MSIV closure. This peak corresponds to the setpoint of the first SRV set pressure (1108 psig) in the safety-lift mode. The increase in the SRV opening setpoint to 1130 psig will delay the SRV actuation after MSIV closure, but the effect is insignificant. Per NEDC 34037P, generic evaluations have been performed that analyze and bound the small break LOCA up to an SRV opening setpoint considerably higher than 1130 psig.

Although HPCI, based on safety analyses, is not expected to operate at sustained high pressures, existing PSEG design documents and calculations conservatively show that the HPCI design is capable of delivering 5600 gpm makeup over an operating reactor pressure range of 215 to 1156 psia (200 to 1141 psig). This corresponds to the existing first tier setpoint of 1108 psig with the 3% tolerance applied.

Margins in existing design calculations and NEDC 34037P support that HPCI is fully capable of supplying its design required 5600 gpm at the higher 1130 psig setpoints with a +3% tolerance without any change to the current turbine operating speed limit of 4150 rpm or overspeed trip setpoint. At the design operating speed, HPCI currently has 148 ft of total discharge head (TDH) margin. This margin exceeds the 53 ft of additional TDH needed to accommodate this change. Operation of HPCI up to 4,225 rpm has been evaluated as satisfactory if additional

9 LR-N24-0030 LAR H24-03 Enclosure

testing margin is needed. No credit for Low-Low Set is taken for these evaluations which would add considerably more margin to them. Loss of all HPCI flow during an ATWS has been previously evaluated at the station and any slight decrease in HPCI delivered flow during the ATWS event due to the higher SRV openings is not safety significant and is fully bounded by existing evaluations. Since the HPCI system is flow-controlled to provide 5600 gpm, the small increase in pressure would be compensated for by the HPCI speed control system which would increase turbine speed by several rpm to overcome the pressure.

Regarding the proposed change to the lower end of the SRV tolerance, since the limiting safety analyses are conservatively based on the SRV upper tolerance settings (i.e., +3% setting),

lowering the SRV tolerance range from -3% to -5% does not have an adverse impact on the HPCI system performance.

3.3.2 Reactor Core Isolation Cooling System

Per Section 5.4.6.1 of the UFSAR, the RCIC System is a safety-related system consisting of a steam turbine, turbine driven pump, piping, valves, controls, and instrumentation designed to ensure that sufficient reactor water inventory is maintained in the reactor vessel to allow for adequate core cooling. This prevents reactor fuel from overheating during the following conditions:

1. When the vessel is isolated and maintained in the hot standby condition.

2. When the vessel is isolated and accompanied by loss of coolant flow from the reactor feedwater system.

3. When a complete plant shutdown is started under conditions of loss of the normal feedwater system and before the reactor is depressurized to the level for the operation of the shutdown cooling system.

Similar to HPCI, the RCIC system is designed to deliver its rated flow (in this case 600 gpm) at a conservative reactor pressure corresponding to the lowest SRV setpoint plus 3% (1156 psia).

The design pressure for those portions of the RCIC system interfacing with the reactor, such as the steam supply lines and the turbine, is unaffected since the original design pressure was formulated using the reactor design pressure of 1250 psig. The peak pressure for the pump and the pump discharge lines will not change since the maximum rated speed for the pump does not change.

From a flow-rate standpoint, similar to HPCI, RC IC could experience a 23 psid increase above what was analyzed in design calculations (1164 psig versus an analyzed 1141 psig). This is well within the existing margins discussed within the RCIC hydraulic analysis design calculation.

Per the calculation, at the design operating speed, RCIC currently has 251 ft of TDH margin.

This margin exceeds the 53 ft of additional TDH needed to accommodate this change. Similar to HPCI, no credit for Low-Low Set is taken for these evaluations which would add considerably more margin to them. Thus, the 2% increase in reactor pressure would be offset by this margin and by the fact that additional steam pressure would be available to drive the turbine assembly.

Since the RCIC system is flow-controlled to provide 600 gpm, the small increase in pressure would be compensated for by the RCIC speed control system which would increase turbine speed by several rpm to overcome the pressure.

This conclusion is consistent with NEDC 34037P for the RCIC system which concludes that no changes to turbine speed limits (currently 4499 rpm) and/or overspeed setpoints should be

10 LR-N24-0030 LAR H24-03 Enclosure

needed to support this proposed change. However, operation of RCIC up to 4,650 rpm has been evaluated as satisfactory if additional testing margin is needed. Similar to HPCI, since the limiting RCIC analyses are conservatively based on the SRV upper tolerance settings (i.e., +3%

setting), lowering the SRV tolerance range from -3% to -5% does not have an adverse impact on RCIC system performance.

3.3.3 Standby Liquid Control System

The HCGS SLC pumps are of the positive displacement type and will provide a constant flow-rate regardless of system pressure up to the design pressure of 1400 psig. The SLC pumps are not assumed to be operating until 230 seconds after the initial ATWS event. RCPB pressures are well below 1400 psig at this point. Thus, at any of the subsequent (less than 1400 psig) pressures, SLC is capable of injecting its minimum design flow-rate of 41.2 gpm per pump, therefore, the proposed change does not result in any adverse impact to the SLC system. Per NEDC-34037P, the boron shutdown concentration, nor the injection rate requirement requires change due to the effects of revised SRV lift setpoints.

However, per UFSAR Section 9.3.5.1, means are provided by which the functional performance capability of the system components can be verified periodically under conditions approaching actual use requirements. In support of the proposed change GEH has re-evaluated the SLC pump discharge head that would be present at the time of SLC initiation (230 seconds). Using a nominal pump flowrate of 43 gpm, the required discharge head is 1281 psig.

This consists of a reactor pressure of 1177.3 psig plus 103 psid of system elevation and head loss. Therefore, to ensure that testing is consistent with the SLC system design/licensing basis, the surveillance criteria in SR 4.1.5.c is changed from the current 41.2 gpm at greater than or equal to 1255 psig to 41.2 gpm at greater than or equal to 1281 psig.

Reviews were also performed to assess the impact of the SRV pressure increase to 1130 psig on valves associated with the above systems as well as other valves (i.e., main steam) that may be impacted by an increase in reactor pressure. This assessment has determined that no physical changes are required associated with HPCI, RCIC, or other MOVs.

3.4 Other Technical Considerations (LOCA, Containment, Fuels, Downcomer Stresses, Suppression Pool)

3.4.1 LOCA Analysis

SRV actuation at 1130 psig and a SRV tolerance change to +3%/-5% has no impact on the overall ECCS performance for HCGS. The limiting large break LOCA event remains unaffected by the SRV setpoint increase and SRV tolerance change. The effect of these changes on the small break and the steam line break outside containment LOCA are insignificant and remain bounded by the limiting large break LOCA. The HCGS ECCS LOCA limiting event and associated licensing basis PCT remains unchanged by the SRV setpoint increase and SRV tolerance change.

The LOCA at HCGS credits only the ADS function of the SRVs during a small break. The ADS function is not based on pressure setpoints. During a large break LOCA the reactor is automatically depressurized due to the nature of the event and SRV safety function is not actuated. Therefore, in response to any type of LOCA, there is no adverse impact from raising the current setpoints or lowering the SRV tolerance range from -3% to -5%.

11 LR-N24-0030 LAR H24-03 Enclosure

3.4.2 Containment Analyses

The Containment Analyses were re-evaluated by GEH for the proposed change in SRV setpoints and tolerances. The following considerations are not adversely impacted from transitioning to a single SRV code safety valve function lift setpoint of 1130 psig +3% or -5%:

short-term containment response and hydrodynamic loads, long-term suppression pool temperature for DBA-LOCA and net positive suction head (NPSH) analyses, long-term suppression pool temperature for loss of power and NPSH analyses, intermediate line break accident (IBA) and small line break accident (SBA) analyses for Plant Unique Load Definition (PULD), local suppression pool temperatur e for NUREG-0783 analysis, and the steam line break drywell temperature response for the evaluation of drywell EQ considerations.

3.4.3 Fuel Limits

The Cycle 25 reload pressurization transients were reanalyzed using the single SRV code safety valve function lift setpoint of 1130 psig. The evaluation confirmed that the Cycle 25 Operating Limit Minimum Critical Power Rati o (OLMCPR) limits remained valid and there continued to be margin to the Thermal and Mechanical design limits with the single SRV code safety valve function lift setpoint. The cycle-specific transient reload licensing analyses will provide transient event fuel thermal limits for each fuel-cycle. Hence, the proposed changes will not significantly impact fuel thermal limit considerations.

3.4.4 Downcomer Stresses/Suppression Pool/Other

Evaluation of the proposed changes on downcomer piping, supports, spargers, containment, and suppression pool loads was performed. All were found to be acceptable with consideration of the proposed change associated with this LAR.

The lowering of the allowable setpoint tolerance from -3% to -5% was also evaluated for its potential impacts on the HCGS SRV Low-Low Set logic and Reactor Protection System (RPS) actuation setpoint. The HCGS Low-Low set logic is actuated at 1047 psig +/-2%. The RPS reactor vessel steam dome pressure-high allowable value is 1057 psig. With the proposed change in setpoint and tolerance, the lowest actuation of an SRV would be expected to occur at 1074 psig (1130 x 0.95) which is above both actuation setpoints. Thus, there is no adverse impact to either the Low-Low setpoint function or RPS actuation setpoints associated with this proposed change (i.e., no probability for SRV openings to occur prior to these setpoints being reached). It should be noted that with the current lower tier SRVs at 1108 +/-3%, the lowest theoretical opening setpoint is 1075 psig. With the proposed change there is no significant change (1075 psig versus 1074 psig) to where the lowest theoretical lift will occur.

3.5 Surveillance Test History

Surveillance test results for HCGS 3-Stage SRVs have shown that of 16 tests performed since the installation of the 3-Stage SRVs, 13 show minor setpoint drift in the negative direction. One exceeded the acceptance criteria of -3% in the negative direction. Based on a review of the 16 previous test results shown below for the HCGS 3-Stage SRVS valves, the average drift was -1.42%. The HCGS experience is consistent with another BWRs OE with the 3-stage valves. For the James A FitzPatrick (JAF) station, whose SRVs include testing up to a span of four years between tests (vs three years maximum for HCGS); their average drift from 16 tests

12 LR-N24-0030 LAR H24-03 Enclosure

was -2.28%, of which 5 failed in the negative direction (Reference 4). Both the HCGS and JAF tests support that a -5% tolerance would avoid unnecessarily declaring these valves inoperable and requiring expanded scope testing.

Current Pilot IST As-Found As-Install Removal Approximate SRV Nominal S/N Result Setpoint Found Outage Outage service time Setpoint P/F (PSIG) Drift % (months)

E/1130 1130 116 F 1085 -3.98% R22 R24 36 A/1130 1130 303 P 1103 -2.39% P212 P221 12 K/1108 1108 107 P 1080 -2.53% R22 R24 36 B/1130 1130 39 P 1097 -2.92% R22 R24 36 G/1120 1120 306 P 1094 -2.32% R23 R24 18 M/1108 1108 123 P 1085 -2.08% R22 R24 36 D/1130 1130 28 P 1113 -1.50% R22 R24 36 P/1120 1120 109 P 1103 -1.52% R22 R24 36 F/1108 1108 312 P 1083 -2.26% R23 R24 18 L/1120 1120 86 P 1100 -1.79% R21 R22 18 A/1130 1130 311 P 1111 -1.68% R23 P212 1 H/1108 1108 307 P 1097 -0.99% R23 P213 2 L/1120 1120 86 P 1119 -0.09% R22 R23 18 H/1108 1108 311 P 1116 0.72% P213 P221 11 R/1120 1120 86 P 1135 1.34% P211 R24 18 R/1120 1120 315 P 1135 1.34% R24 P232 11 L/1120 1120 316 P 1095 -2.23% R24 P232 11

3.6 Conclusion

The raising of all fourteen (14) SRV lift setpoints to 1130 +3% / -5% will continue to meet all applicable overpressure related safety functions with margin and continue to support post-accident pressure control necessary for the accomplishment of safety-related functions for other affected plant systems.

4.0 REGULATORY EVALUATION

4.1 Applicable Regulatory Requirements/Criteria

10 CFR 50.36(c) provides that TS will include Limiting Conditions for Operation (LCOs) which are the lowest functional capability or performance levels of equipment required for safe operation of the facility. When a limiting condition for operation of a nuclear reactor is not met, the licensee will shut down the reactor or follow any remedial action permitted by the technical specifications until the condition can be met. The proposed changes maintain the minimum equipment capability of the SRVs and the SLC system required to respond to a DBA or ATWS.

Therefore, the proposed changes are consistent with current regulations.

The following 10 CFR 50, Appendix A, General Design Criteria (GDC) apply to the systems covered by the proposed changes in this amendment application.

13 LR-N24-0030 LAR H24-03 Enclosure

CRITERION 14 - REACTOR COOLANT PRESSURE BOUNDARY

"The reactor coolant pressure boundary shall be designed, fabricated, erected, and tested so as to have an extremely low probability of abnormal leakage, of rapidly propagating failure, and of gross rupture.

CRITERION 15 - REACTOR COOLANT SYSTEM DESIGN

The reactor coolant system and associated auxil iary, control, and protection systems shall be designed with sufficient margin to assure that the design conditions of the reactor coolant pressure boundary are not exceeded during any condition of normal operation, including anticipated operations occurrences.

CRITERION 26REACTIVITY CONTROL SYSTEM REDUNDANCY AND CAPABILITY

Two independent reactivity control systems of diffe rent design principles shall be provided. One of the systems shall use control rods, preferably including a positive means for inserting the rods, and shall be capable of reliably controlling reactivity changes to assure that under conditions of normal operation, including anticipated operational occurrences, and with appropriate margin for malfunctions such as stuck rods, specified acceptable fuel design limits are not exceeded. The second reactivity control system shall be capable of reliably controlling the rate of reactivity changes resulting from planned, normal power changes (including xenon burnout) to assure acceptable fuel design limits are not exceeded. One of the systems shall be capable of holding the reactor core subcritical under cold conditions.

CRITERION 35 - EMERGENCY CORE COOLING

A system to provide abundant emergency core cooling shall be provided. The system safety function shall be to transfer heat from the reactor core following any loss of reactor coolant at a rate such that (1) fuel and clad damage that could interfere with continued effective core cooling is prevented and (2) clad metal-water reaction is limited to negligible amounts.

Suitable redundancy in components and features, and suitable interconnections, leak detection, isolation, and containment capabilities shall be provided to assure that for onsite electric power system operation (assuming offsite power is not available) and for offsite electric power system operation (assuming onsite power is not available) the system safety function can be accomplished, assuming a single failure.

Following implementation of the proposed changes, HCGS will remain in compliance with GDC 14, 15, 26, and 35.

Applicable ASME Code Requirements

The HCGS IST program is currently implemented in accordance with the requirements of the ASME Operation and Maintenance (OM) Code 2012 Edition for the Fourth 10-Year Interval.

The SRVs are Class 1 Category C valves in accordance with the Program. As required by the ASME OM Code, additional valves would be tested if the as-found setpoint of a tested valve from the sample exceeds +/-3% of the nameplate set pressure. If one of these additional valves fails, then all of the main steam SRVs would be removed and tested. The HCGS SRVs will continue to be tested in accordance with these requirements.

14 LR-N24-0030 LAR H24-03 Enclosure

The ASME OM Code Mandatory Appendix I, lnservice Testing of Pressure Relief Devices in Light-Water Reactor Nuclear Power Plants, Guiding Principles, paragraph l-1310(e),

Acceptance Criteria, allows the owner to establish setpoint acceptance criteria for relief valves tested under the IST Program; therefore, no relief will be required with regard to the setpoint tolerance change from -3% to -5%. However, a change to the HCGS technical specifications will be required and is being proposed with this LAR.

4.2 Precedents

The proposed change is similar to the NRC-approv ed license amendments for increasing the SRV lower tolerance band listed below:

1. Letter from B. K. Vaidya (NRC) to B.C. Hanson (Exelon), LaSalle County Station, Units 1 and 2 - Issuance of Amendments to Renewed Facility Operating Licenses Re: License Amendment Request to Revise the Technical Specifications Surveillance Requirement 3.4.4.1 and the Lower Setpoint Tolerances for Safety/Relief Valves (EPID L-2018-LLA-0052), dated December 19, 2018 (ADAMS No. ML18278A030)

2. Letter from L. J. Klos (NRC) to M. E. Reddemann (Energy Northwest), "Columbia Generating Station - Issuance of Amendment Re: To Modify Technical Specifications Surveillance Requirements 3.4.3.1 and 3.4.4.1 Safety/Relief Valve Setpoint Lower Tolerance (CAC No. MF7699)," dated March 9, 2017 (ADAMS Accession No. ML17052A125)

3. Letter from B. K. Vaidya (NRC) to T. S. Rausch (PPL Susquehanna, LLC),

"Susquehanna Steam Electric Station, Units 1 and 2 - Issuance of Amendments Re:

Change to Technical Specifications (TSs) Surveillance Requirements (SRs) 3.4.3.1 to Revise the Lower Surveillance Tolerances (TAC Nos. ME5050 and ME5051)," dated November 17, 2011 (ADAMS Accession No. ML11292A137)

4. Letter from M. Webb (NRC) to P. D. Hinnenkamp (Entergy Operations, Inc.), "River Bend Station, Unit 1 - Issuance of Amendment Re: Modification of the Technical Specification Surveillance Requirements for the Safety/Relief Valves (TAC No.

MB5090), dated February 13, 2003 (ADAMS Accession No. ML030450307)

The proposed change is similar to the NRC approved license amendment listed below for revising the staggered SRV setpoints to a single common setpoint:

1. Letter from Kahtna Jabbour (NRC) (Hatch) to Jack D. Woodard (Georgia Power Company), Issuance of Amendments - Edwin I. Hatch Nuclear Plant, Units 1 and 2 (TAC Nos. M96752 and M96753), dated March 21, 1997. (ADAMS Accession No. ML013030262)

4.3 No Significant Hazards Consideration

PSEG requests an amendment to the Hope Creek Operating License. The proposed change will revise the Hope Creek Generating Station (HCGS) Technical Specification (TS) 3/4.4.2.1, Safety/Relief Valves (SRVs), to modify the code safety valve function lift settings to 1130 psig

+3% or -5% for all fourteen (14) valves. In addition, as a result of analyses performed in

15 LR-N24-0030 LAR H24-03 Enclosure

support of this change, Surveillance Requirement (SR) 4.1.5.c associated with TS 3/4.1.5 Standby Liquid Control System (SLC) is modified to increase the Inservice Testing (IST) test pressure from 1255 psig to 1281 psig.

PSEG has evaluated the proposed changes to the TS using the criteria in 10 CFR 50.92 and determined that the proposed changes do not involve a significant hazards consideration. The following information is provided to support a finding of no significant hazards:

1. Do the proposed changes involve a significant increase in the probability or consequences of an accident previously evaluated?

Response: No.

The SRV setpoints and their tolerances are not an accident initiator, nor is the required pressure at which SLC pump testing is performed. The proposed TS changes related to the SRVs involve changes to their lift setpoints only. The proposed TS changes to SLC involve only test acceptance criteria. There are no other hardware changes or changes to existing structures, systems, or components. The SRVs lift in response to rising reactor pressure during Design Basis Accidents (DBAs) and anticipated transients. As a result of the increased SRV pressure lift points, the SLC pumps are required to inject at slightly increased pressures. Analyses performed in support of this change demonstrate the limits remain met with margin. Evaluations have been performed which consider the consequences of the various transients and accidents with increased SRV setpoints. The evaluations assessed the impact on emergency core cooling system (ECCS) performance, high pressure coolant injection (HPCI) and reactor core isolation cooling (RCIC) performance with no significant increase in the consequences of an accident. As a result, these changes will not increase the probability of an accident previously evaluated nor significantly increase the consequences of an accident previously evaluated.

Therefore, the proposed changes do n o t i n v o lv e a s i g n i f ic a n t in c r e a s e i n th e p robability or consequences of an accident previously evaluated.

2. Do the proposed changes create the possibility of a new or different kind of accident from any accident previously evaluated?

Response: No.

The proposed TS changes to the SRV lift settings and to SLC testing acceptance criteria will not create the possibility of a different type of accident. The proposed changes do not result in any other changes to any structures, systems or components in the plant and hence does not create any new accident initiators.

Since the proposed changes do not create any additional accident initiators for the plant, the proposed changes do not create the possibility of a new or different kind of accident from any accident previously evaluated.

16 LR-N24-0030 LAR H24-03 Enclosure

3. Do the proposed changes involve a significant reduction in a margin of safety?

Response: No.

The margin of safety is established through the design of the plant structures, systems, and components, the parameters within which the plant is operated, and the establishment of the setpoints for the actuation of equipment relied upon to respond to an event. The proposed changes do not modify the safety limits or setpoints at which protective actions are initiated and does not change the requirements governing operati on or availability of safety equipment assumed to operate to preserve the margin of safety. The change in SRV mechanical lift setpoint was evaluated relative to the applicable safety system settings and found to remain acceptable. The proposed changes were evaluated against peak clad temperature limits, ECCS operation, ASME Code overpressurization limits, and containment design limits. All existing limits remain met. Since the SRVs will remain capable of meeting all applicable design basis requirements and maintain the capability to mitigate the consequences of accidents described in the HC UFSAR, the proposed changes were determined to not result in a significant reduction in a margin of safety.

Therefore, the proposed changes do not involve a significant reduction in a margin of safety.

Based upon the above, PSEG concludes that the proposed amendment presents no significant hazards consideration under the standards set forth in 10 CFR 50.92(c), and, accordingly, a finding of no significant hazards consideration is justified.

4.4 Conclusion

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

5.0 ENVIRONMENTAL CONSIDERATION

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

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

17 LR-N24-0030 LAR H24-03 Enclosure

6.0 REFERENCES

1. ASME, OM Code, 2012 Edition.

2. Letter from David T. Gudger (Constellation) James A. FitzPatrick Nuclear Power Plant to U.S. Nuclear Regulatory Commission, Licens e Amendment Request to Modify Technical Specification Surveillance Requirement (SR) 3.4.3.1 Safety Relief Valves (S/RVs) Setpoint Lower Tolerance, dated July 28, 2023. (ADAMS Accession No. ML23209A003)

3. NRC Safety Evaluation for General Electrical Company Topical Report NEDC-31753P, March 8, 1993 (ADAMS Legacy Library Accession No. 9212280273).

4. GE Nuclear Energy Licensing Topical Report NEDC-31753P, BWROG In-Service Pressure Relief Technical Specification Revision Licensing Technical Report, dated July 9, 1990.

(ADAMS Accession No. ML20065P128 - Transmittal Letter)

5. Letter from Richard B. Ennis (NRC) to Harold W. Keiser (PSEG), Hope Creek Generating Station, Issuance of Amendment, Safety Relief Valve Setpoint Tolerance Change (TAC No.

MA1674), Amendment 115, dated February 10, 1999 (ADAMS Accession No. ML011770051).

6. Letter from PSEG to NRC, License Amendment Request - Revise Hope Creek Generating Station Technical Specification to Change Surveillance Intervals to Accommodate a 24-Month Fuel Cycle, dated May 20, 2024 (ADAMS Accession No. ML24141A136)

7. GE Service Information Letter (SIL) 196, Supplement 3, Target Rock Safety/Relief Valve Simmer Margin, August 31, 1977

18 LR-N24-0030 LAR H24-03

Attachment 1

Mark-up of Proposed Technical Specification Pages

The following Technical Specifications pages for Renewed Facility Operating License NPF-57 are affected by this change request:

Technical Specification Page

4.1.5.c, STANDBY LIQUID CONTROL SYSTEM 3/4 1-20

3.4.2.1, SAFETY/RELIEF VALVES 3/4 4-7

1 REACTIVITY CONTROL SYSTEMS

SURVEILLANCE REQUIREMENTS (Continued}

b. In accordance with the Surveillance Frequency Control Program by:

1. Verifying the continuity of the explosive charge.

2. Determining that the available weight of sodium pentaborate is greater than or equal to 5,776 lbs and the concentration of boron in solution is within the limits of Figure 3.1.5-1 by chemical analysis.*

3. Verifying that each valve (manual, power operated or automatic) in the flow path that is not locked, sealed, or otherwise secured in position, is in its correct position.

c. Demonstrating that, when tested pursuant to the INSERVICE TESTING PROGRAM, the minimum flow requirement of 41.2 gpm, per pump, at a pressure of greater than or equal to 1255 psig is met.

d. In accordance with the Surveillance Frequency Control Program by:

1. Initiating one of the standby liquid control system subsystem, including an explosive valve, and verifying that a flow path from the pumps to the reactor pressure vessel is available by pumping demineralized water into the reactor vessel and verifying that the relief valve does not actuate.

The replacement charge for the explosive valve shall be from the same manufactured batch as the one fired or from another batch which has been certified by having one of that batch successfully fired. Both injection subsystems shall be tested in accordance with the Surveillance Frequency Control Program.

2. **Demonstrating that all heat traced piping between the storage tank and the injection pumps is unblocked and then draining and flushing the piping with demineralized water.

3. Demonstrating that the storage tank heaters are OPERABLE by verifying the expected temperature rise of the sodium pentaborate solution in the storage tank after the heaters are energized.

• This test shall also be performed anytime water or boron is added to the solution or when the solution temperature drops below 70°F.

• • This test shall also be performed whenever both heat tracing circuits have been found to be inoperable and may be performed by any series of sequential, overlapping or total flow path steps such that the entire flow path is included.

HOPE CREEK 3/4 1-20 Amendment No. 205 REACTOR COOLANT SYSTEM

3/4.4.2 SAFETY/RELIEF VALVES

SAFETY/RELIEF VALVES

LIMITING CONDITION FOR OPERATION

3.4.2.1 The safety valve function of at least 13 of the following reactor coolant system safety/relief valves shall be OPERABLE*# with the specified code safety valve function lift settings:**

4 safety-relief valves @ 1108 psig +/-3%

5 safety-relief valves @ 1120 psig +/-3%

5 safety-relief valves @ 1130 psig +/-3%

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3.

ACTION:

a. With the safety valve function of two or more of the above listed fourteen safety/relief valves inoperable, be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

b. Deleted

C. Deleted

• SRVs which perform as ADS function must also satisfy the OPERABILITY requirements of Specification 3.5.1, ECCS-Operating.

• • The lift setting pressure shall correspond to ambient conditions of the valves at nominal operating temperatures and pressures.

1. SRVs which perform a low-low set function must also satisfy the OPERABILITY requirements of Specification 3.4.2.2, Safety/Relief Valves Low-Low Set Function.

HOPE CREEK 3/4 4-7 Amendment No. 203 LR-N24-0030 LAR H24-03

Attachment 2

Mark-up of Proposed Technical Specification Bases Pages

The following Technical Specification Bases pages for Renewed Facility Operating License NPF-57 are affected by this change request (information only):

Technical Specification Bases Page

3/4.5.1 ECCS-Operating B 3/4 5-1a

1 3/4.5 EMERGENCY CORE COOLING SYSTEM (ECCS) AND RPV WATER INVENTORY CONTROL

BASES

3/4.5.1 ECCS - OPERATING (Continued)

The high pressure coolant injection (HPCI) system is provided to assure that the reactor core is adequately cooled to limit fuel clad temperature in the event of a small break in the reactor coolant system and loss of coolant which does not result in rapid depressurization of the reactor vessel. The HPCI system permits the reactor to be shut down while maintaining sufficient reactor vessel water level inventory until the vessel is depressurized. The HPCI system continues to operate until reactor vessel pressure is below the pressure at which CSS operation or LPCI mode of the RHR system operation maintains core cooling.

The capacity of the system is selected to provide the required core cooling. The HPCI pump is designed to deliver greater than or equal to 5600 gpm at reactor pressures between 1120 and 200 psig. Initially, water from the condensate storage tank is used instead of injecting water from the suppression pool into the reactor, but no credit is taken in the safety analyses for the condensate storage tank water.

A Note prohibits the application of LCO 3.0.4.b to an inoperable HPCI subsystem. There is an increased risk associated with entering an OPERATIONAL CONDITION or other specified condition in the Applicability with an inoperable HPCI subsystem and the provisions of LCO 3.0.4.b, which allow entry into an OPERATIONAL CONDITION or other specified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable systems and components, should not be applied in this circumstance.

HOPE CREEK B 3/4 5-1a Amendment No. 213 (PSEG Issued)

LR-N24-0030 LAR H24-03

Attachment 3

GE-Hitachi (GEH) Nuclear Energy Report NEDO-34037, Safety Review for Hope Creek Generating Station Safety/Relief Valve Setpoint Increase and Tolerance Change, Revision 0, (Non-Proprietary Version)

1

• HITACHI G1E Hitachi Nucllea r Energy

NEDO-34037 Revision 0 May 2024

Non-Proprietary Information

Safety Review for Hope Creek Generating Station Safety/Relief Valve Setpoint Increase and Tolerance Change

Copyright 202 4 GE-Hitachi Ni clear Energy Americas LL C All Rights Re.served NEDO-34037 Revision 0 Non-Proprietary Information

INFORMATION NOTICE This is a non-proprietary version of the document NEDC-34037P Revision 0, which has the proprietary information removed. Portions of the document that have been removed are indicated by an open and closed bracket as shown here (( )).

IMPORTANT NOTICE REGARDING CONTENTS OF THIS REPORT Please Read Carefully The design, engineering, and other information contained in this document are in accordance with the contract between Public Service Electric and Gas (PSEG) and GE-Hitachi Nuclear Energy Americas, LLC (GEH), and nothing contained in this document shall be construed as changing the contract. The use of this information by anyone for any purpose other than that for which it is intended, is not authorized; and with respect to any unauthorized use, GEH makes no representation or warranty, and assumes no liability as to the completeness, accuracy, or usefulness of the information contained in this document.

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REVISION

SUMMARY

Revision Required Changes to Achieve Revision 0 Initial Issue.

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Table of Contents

Section Page

1.0 Purpose............................................................................................................................ 1 2.0 Analysis Approach.............................................................................................................. 2 3.0 Vessel Overpressure Analysis............................................................................................. 3 3.1 Overpressure Evaluation Approach................................................................................. 3 3.2 Overpressure Analysis Results........................................................................................ 3 4.0 ECCS-LOCA Performance Evaluation............................................................................... 6 4.1 Limiting Break LOCA..................................................................................................... 6 4.2 Small Break LOCA......................................................................................................... 6 4.3 Steam Line Break Outside Containment......................................................................... 7 4.4 SRV Tolerance Change................................................................................................... 7 4.5 Conclusions for the ECCS-LOCA Evaluations............................................................... 7 5.0 High Pressure System Performance.................................................................................... 8 5.1 Effect of Higher SRV Setpoints on HPCI and RCIC Performance................................. 8 5.2 HPCI and RCIC Performance for Loss-of-Feedwater Events......................................... 9 5.3 HPCI Performance for LOCA Events............................................................................. 9 5.4 Standby Liquid Control System...................................................................................... 9 6.0 Containment Evaluation.................................................................................................... 11 6.1 Containment Pressure and Temperature Response....................................................... 11 6.1.1 DBA LOCA............................................................................................................... 11 6.1.2 Loss of Offsite Power................................................................................................ 11 6.1.3 Small Steam Line Breaks.......................................................................................... 11 6.1.4 Intermediate and Small Steam Line Break Accidents............................................... 11 6.1.5 NUREG-0783 Local Suppression Pool Temperature................................................ 12 6.2 LOCA Hydrodynamic Loads and SRV Loads.............................................................. 12 6.2.1 DBA LOCA Hydrodynamic Loads........................................................................... 12 6.2.2 SRV Dynamic Loads................................................................................................. 12 6.2.3 Internal Loads............................................................................................................ 13 6.2.4 External Loads........................................................................................................... 13 6.2.5 Subsequent SRV Actuation....................................................................................... 14

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Table of Contents

Section Page 6.2.6 Effect of a Single SRV Out-of-Service on SRV Loads............................................. 14 6.3 Reactor Coolant Pressure Boundary Piping Evaluation................................................ 14 7.0 ATWS Mitigation Capability............................................................................................ 15 7.1 ATWS Requirements..................................................................................................... 15 7.2 ATWS Evaluation Approach......................................................................................... 15 7.3 ATWS Results............................................................................................................... 16 7.3.1 Peak Vessel Bottom Pressure.................................................................................... 16 7.3.2 Peak Suppression Pool Temperature and Containment Pressure.............................. 16 7.3.3 PCT and Cladding Oxidation.................................................................................... 16 8.0 Nuclear Boiler System Evaluation.................................................................................... 20 8.1 MSL High Steam Flow Analytical Limits..................................................................... 20 8.2 Differential Pressure Across the MSL Flow Restrictors............................................... 20 8.3 MSIV Pressure Drop and Closing Times...................................................................... 20 8.4 SRV Flow Capacity....................................................................................................... 20 8.5 Pneumatic Supplies to the SRVs and MSIVs................................................................ 20 9.0 Conclusions....................................................................................................................... 21 10.0 References......................................................................................................................... 22

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List of Tables

Table Page

Table 3-1 HCGS Key Inputs for Overpressure Analysis........................................................................ 4 Table 3-2 HCGS Key Inputs for Reference 4 Overpressure Analysis................................................... 4 Table 3-3 HCGS Limiting Overpressure Analysis Results.................................................................... 4 Table 7-1 HCGS Key Inputs for ATWS Analysis................................................................................ 18 Table 7-2 Computer Codes for ATWS Analyses................................................................................. 19 Table 7-3 HCGS ATWS Analysis Results........................................................................................... 19

List of Figures

Figure Page

Figure 3-1 Limiting Plant Response to MSIVF Event with 1,130 psig +3%/-5% Nominal SRV Opening Setpoint................................................................................................................... 5

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Acronyms and Abbreviations

Short Form Description ADS Automatic Depressurization System ANS American Nuclear Society ANSI American National Standards Institute

AOO Anticipated Operational Occurrence ARI Alternate Rod Insertion ASD Adjustable Speed Drive ASME American Society of Mechanical Engineers ATWS Anticipated Transient Without Scram

BWR Boiling Water Reactor CLTP Current Licensed Thermal Power DBA Design Basis Accident DEG Double Ended Guillotine ECCS Emergency Core Cooling System

EHC Electro-Hydraulic Control EPU Extended Power Uprate EQ Equipment Qualification GEH GE-Hitachi Nuclear Energy Americas, LLC HCGS Hope Creek Generating Station

HPCI High Pressure Coolant Injection IBA Intermediate Line Break Accident LBPCT Licensing Basis PCT LHGR Linear Heat Generation Rate LLS Low-Low-Set

LOCA Loss-of-Coolant Accident LOP Loss of Offsite Power

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Short Form Description MSIV Main Steam Isolation Valve MSIVC Main Steam Isolation Valve Closure

MSIVF MSIV Closure with Flux Scram MSL Main Steam Line NPSH Net Positive Suction Head NRC Nuclear Regulatory Commission OOS Out-of-Service

PCT Peak Cladding Temperature PSEG Public Service Electric and Gas psia Pounds per square inch absolute psig Pounds per square inch gage PRFO Pressure Regulator Failure - Maximum Demand

RCIC Reactor Core Isolation Cooling rpm Revolutions per minute RPT Recirculating Pump Trip SBA Small Line Break Accident SLCS Standby Liquid Control System

SRV Safety/Relief Valve SRVDL SRV Discharge Line

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1.0 Purpose This report presents the results of an evaluation of the following proposed changes at Hope Creek Generating Station (HCGS):

• Reduce the probability of Safety/Relief Valve (SRV) leakage by increasing simmer margin. Simmer margin is the difference betw een 100% reactor pressure and the pressure at which the SRVs begin to lift.

• Change the SRV tolerance from the current +/-3% to +3%/-5% for the nominal SRV setpoints.

The current Technical Specifications require the reactor coolant system SRVs to be operable with the following specified code safety valve function settings:

4 safety-relief valves @ 1,108 psig +/-3%

5 safety-relief valves @ 1,120 psig +/-3%

5 safety-relief valves @ 1,130 psig +/-3%

The proposed change is to increase the setpoints on all 14 SRVs to 1,130 psig. This change will increase the simmer margin and reduce SRV pilot leakage which may occur over a typical operating cycle.

The effect due to a change in the SRV setpoint tolerance from +/-3% to +3%/-5% has also been evaluated.

The current Technical Specifications require at least 13 of the 14 SRVs to remain operable in their safety mode. This requirement is unchanged. The Technical Specification Low-Low-Set (LLS) function and the emergency core cooling function for the Automatic Depressurization System (ADS) are also unchanged.

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2.0 Analysis Approach The following analyses were performed to determine the acceptability of the proposed SRV performance requirement changes:

• Vessel overpressure

• Emergency Core Cooling System (ECCS)-Loss-of-Coolant Accident (LOCA) performance

• High pressure system performance (Reactor Core Isolation Cooling (RCIC), High Pressure Coolant Injection (HPCI) and Standby Liquid Control System (SLCS))

• Containment response

• Anticipated Transient Without Scram (ATWS) mitigation capability

• Nuclear boiler system performance

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3.0 Vessel Overpressure Analysis The purpose of the evaluation in this section is to assess the effect of revised SRV operating parameters including increasing the SRV lift setpoint to 1,130 psig and updating the opening tolerance to +3%/-5%, consistent with the requirements listed in Table 3-1. Reactor vessel integrity is maintained through adherence to the pressure limits established by the American Society of Mechanical Engineers (ASME) pressure vessel code upset limit (1,375 psig) as well as the dome pressure safety limit (1,325 psig).

3.1 Overpressure Evaluation Approach The analysis was performed using the TRACG Anticipated Operational Occurrence (AOO) methodology (References 1 and 2) at the currently licensed thermal power (3,902 MWt). The limiting overpressure event is the Main Steam Is olation Valve (MSIV) Closure with Flux Scram (MSIVF). For this transient, a failure of the MSIV position scram signal is assumed, and the reactor instead scrams on a subsequent high neutron flux signal due to the collapse of voids following vessel pressurization. The event was analyzed with the methodologies described in References 2 and 3.

The greatest challenge to the ASME upset limit of 1,375 psig is provided by assuming that the SRVs have drifted up to the upper SRV setpoint opening limit with one SRV Out-of-Service (OOS). Evaluation of the vessel pressure response assuming these conditions bounds setpoints lower than the upper limit. Therefore, the analysis supports a SRV tolerance of +3%/-5%.

3.2 Overpressure Analysis Results The limiting event results using the Table 3-1 inputs are provided in Table 3-3 and the event response is shown in Figure 3-1. The results show a 5 psi increase in peak dome pressure and peak vessel pressure compared to Reference 4. The peak vessel pressure remains below the 1,375 psig ASME upset limit.

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Table 3-1 HCGS Key Inputs for Overpressure Analysis

Input Variable Value

SRV Nominal Opening Setpoints 14 SRVs at 1,130 psig

Number of SRVs OOS 1

SRV Opening / Closing Tolerance (%) +3% / -5%

Table 3-2 HCGS Key Inputs for Reference 4 Overpressure Analysis

Input Variable Value

SRV Nominal Opening Setpoints 4 SRVs at 1,108 psig 5 SRVs at 1,120 psig 5 SRVs at 1,130 psig

Number of SRVs OOS1 1

SRV Opening / Closing Tolerance (%) +3% / -3%

Note:

1. SRV with the lowest opening setpoint is considered OOS.

Table 3-3 HCGS Limiting Overpressure Analysis Results

SRV Parameters Peak Dome Pressure (psig) Peak Vessel Pressure (psig)

Table 3-1 1,266 1,294

Table 3-21 1,261 1,289

Note:

1. Results from Reference 4.

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((

))

Figure 3-1 Limiting Plant Response to MSIVF Event with 1,130 psig +3%/-5% Nominal SRV Opening Setpoint

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4.0 ECCS-LOCA Performance Evaluation The HCGS GNF2 ECCS-LOCA analysis (Reference 5) has been reviewed to evaluate the effect of increasing the SRV opening setpoint pressure on the ECCS performance. The SRV opening pressure for all valves will increase to 1,130 psig. A change in the SRV opening pressure will only affect those pipe break events where there will be SRV actuations. The following ECCS-LOCA pipe break scenarios are evaluated:

1. Large break LOCA

2. Small break LOCA

3. Steam line break outside of containment Additionally, the effect of an SRV tolerance change from +/-3% to +3%/-5% on ECCS performance was also evaluated.

The intent of these evaluations is to demonstrate that the limiting break scenario (yielding the highest Peak Cladding Temperature (PCT)) remains unaffected by these SRV setpoint and tolerance changes and that the effect on the ot her break scenarios having a lower PCT would not cause those scenarios to become the limiting break scenario.

4.1 Limiting Break LOCA Based on a review of the results in Reference 5, the limiting break event for HCGS is the Double Ended Guillotine (DEG) recirculation suction line break with battery failure. The reactor vessel rapidly depressurizes during this event. No SRV actuation will occur because the vessel immediately depressurizes. Therefore, an increa se in the SRV opening setpoint will not have any adverse effect on the limiting break analysis result. The limiting PCT remains unchanged due to the SRV opening setpoint increase.

4.2 Small Break LOCA The vessel depressurizes more slowly during a postulated small break LOCA and is expected to pressurize upon vessel isolation. As the event progresses and invent ory is depleted, the low water level ADS setpoint will be reached. If the vessel water level is not recovered by the time the ADS timer (approximately two minutes) has expired, the ADS will actuate, opening several SRVs. The vessel then rapidly depressurizes, permitting the low pressure ECCS to inject into the reactor vessel and restore the normal water level. The inventory loss is significantly less than the limiting LOCA, resulting in a lower PCT than that of the limiting large break LOCA (see Reference 5 for PCT values).

HCGS has implemented recirculation Adjustable Speed Drive (ASD), which lowered the recirculation pump coast down time to three seconds. The effect on the ECCS operation was evaluated in Reference 6. The evaluation concluded that the faster coas t down time would affect the water level due to reduced inertia in the intact loop and resulted in a (( )) in the Licensing Basis PCT (LBPCT). The water level effect would influence the start of the event, but not the overall timing of the event because this is a system component change and not a

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change in ECCS capacity. The PCT (( )) also remains bounded by the limiting large break scenario.

The increase in the SRV opening setpoint to 1,130 psig will delay the SRV actuation after MSIV closure, but the effect is insignificant. Reference 7 analyzes and bounds the small break LOCA up to an SRV opening setpoint (( )) for all Boiling Water Reactors (BWRs). If the SRVs actuate at the higher vessel pr essure, the instantaneous flow rate out of the SRVs is increased due to higher critical flow rate compared to the SRVs at the current setpoint.

The total inventory loss will be similar because th e SRVs will cycle at a different rate at the higher pressure. The difference in vessel inventory at the time of ADS actuation, compared to cases with the current opening setpoint, is negligible. The result is a negligible change in the PCTs for the small break scenarios at the higher SRV opening setpoint pressure, and the small break events will remain bounded by large break scenarios.

4.3 Steam Line Break Outside Containment The steam line break outside of the containment is a postulated DEG break of one main steam line downstream of the MSIVs outside the containment. The vessel is isolated within 5-10 seconds, which then terminates the break flow. The vessel pressure rapidly increases because of the isolation until the SRV opening setpoint is reached.

The effect of the ASD implementation, as discussed with the small break scenario, will not influence the overall operation of the ECCS in this scenario and remains bounded by the large break LOCA.

Reference 5 reports that the limiting large break event bounds th e PCT for this event by a large margin. Reference 7 concludes that the change in PCT due to a higher SRV setpoint will be insignificant, and this event will remain bounded by the limiting large break LOCA event.

4.4 SRV Tolerance Change The previous evaluations have shown that increasing the overall SRV opening setpoint pressure to 1,130 psig has no significant effect on the ECCS performance during any of the LOCA scenarios. A tolerance change from +/-3% to +3%/-5% would also have no significant ECCS effect. No SRV is engaged during the limiting large break LOCA s cenario. The tolerance change would also have no significant effect on ADS activation during the small break or steam line break outside containment scenarios and will remain bounded by the limiting large break LOCA.

4.5 Conclusions for the ECCS-LOCA Evaluations Based on the proceeding evaluation, SRV actuation at 1,130 psig and a SRV tolerance change to

+3%/-5% has no effect on the overall ECCS performance for HCGS. The limiting large break LOCA event remains unaffected by the SRV setpoint increase and SRV tolerance change. The effect of these changes on the small break and the steam line break outside containment LOCA events is insignificant and remains bounded by the limiting large break LOCA. The HCGS ECCS LOCA limiting event and associated licensing basis PCT remains unchanged by the SRV setpoint increase and SRV tolerance change.

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5.0 High Pressure System Performance HPCI and RCIC performance were evaluated for SRV setpoint drift to the upper limit value of 1,164 psig. Operation at the upper limit provides a greater challenge to the HPCI and RCIC piping, pumps, and turbines than SRVs at the new nominal setpoints. These evaluations assure satisfaction of performance requirements for oper ation at both the upper limit and at the new nominal setpoints because operation at the upper limit bounds operation at the proposed nominal setpoints.

Both HPCI and RCIC systems are important in mitigating reactor vessel isolation and loss of feedwater events.

5.1 Effect of Higher SRV Setpoints on HPCI and RCIC Performance Analyses indicate that operation at reactor pressures up to the upper limit is within design limits for system piping, pumps, and turbines for the HPCI and RCIC systems. PSEG should verify compliance with Nuclear Regulatory Commission (NRC) Generic Letter 89-10 (Reference 8) requirements for valves in each of these systems. The HPCI and RCIC pumps are capable of delivering rated system flow with vessel pressures at the upper limit value of 1,164 psig. Based on the HPCI pump performance curves, and site-specific pressure drops, the current maximum turbine speed of 4,150 rpm will deliver rated flow for this system with the reactor pressure at the upper limit. Operation up to 4,225 rpm is acceptable for the HPCI system. Based on the RCIC pump performance curves, the RCIC system can deliver rated flow at 4,499 rpm. Operation up to 4,650 rpm is acceptable for the RCIC system.

At each SRV opening pressure, system pressure greater than rated is required to deliver rated system flow during steady-state operation. Therefore, the margins to the 125% mechanical overspeed trip for the HPCI and RCIC turbines are reduced. Additionally, the high vessel pressures have the potential to reduce the margin to the overspeed trips at the initial speed peak during the startup of the HPCI and RCIC systems. During a HPCI and RCIC start, the turbine governor valves are momentarily full open and therefore, the rate at which the speed increases is temporarily uncontrolled. Eventually, when hydraulic pressures enable the turbine control systems to take over the transient, the governor valve closes to control turbine speeds at the demanded flows. When a steady-state condition is reached, the final turbine speed is that indicated above, adequately within the turbine speed limits of each system.

The potential concern during the startup transient is system availability. If the HPCI and RCIC turbines do trip during the startup, manual actions are required to reset the turbine trips. For HPCI, the turbine can be reset in the control room. For RCIC, the turbine must be reset locally.

Increasing the SRV setpoint pressure will not have any effect on a HPCI or RCIC turbine potential overspeed trip.

The above considerations assume that HPCI and RCIC would initiate and operate when the reactor pressure is at the upper limit. This is a highly unlikely scenario because there is a very low probability that all SRVs will drift high to their upper limits. The conclusions in the LLS discussion documented in Reference 9 remain unchanged. HPCI and RCIC will perform satisfactorily at the current speeds.

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5.2 HPCI and RCIC Performance for Loss-of-Feedwater Events For loss-of-feedwater events that do not isolate the reactor, vessel pressure is maintained by the turbine bypass valves at the Electro-Hydraulic Control (EHC) pressure setpoint. With vessel pressures near that setpoint, HPCI and RCIC operation is not affected by an increase in SRV opening pressures. For MSIV closure events, the SRVs will actuate at the upper limit prior to the reactor water level reaching Level 2. The subsequent SRV actuations will be controlled by the LLS functions. Therefore, vessel pressures will be within the original HPCI and RCIC design pressure range (1,120 psig to 200 psig (HPCI)/150 psig (RCIC)) at the time of HPCI or RCIC initiation.

5.3 HPCI Performance for LOCA Events The licensing basis LOCA evaluations in Reference 5 do not take credit for HPCI operation.

The discussions above demonstrate that SRV setpoint drift up to the upper limit has an insignificant effect on HPCI performance.

5.4 Standby Liquid Control System SLCS is designed to shut down the reactor from rated power condition to cold shutdown in the postulated situation that all or some of the control rods cannot be inserted. It is an automatically operated system (with manual initiation capability) that pumps a sodium pentaborate solution into the vessel in order to provide neutron ab sorption and achieve a subcritical reactor condition.

The following topics are addressed in this evaluation:

• Core shutdown margin

• System performance and hardware

• Suppression pool temperature following limiting ATWS events The boron shutdown concentration of 660 ppm does not change due to the effects of revised SRV operating parameters including increasing the SRV lift setpoint to 1,130 psig and a setpoint tolerance change to +3%/-5%.

The boron injection rate requirement for maintaining the peak suppression pool water temperature limits, following the limiting ATWS event with SLCS injection, is not increased from the effect of the SRV setpoint changes.

Based on the results of the plant-specific ATWS analysis in Section 7.0 considering the SRV setpoint increase and tolerance change, the maximum reactor upper plenum pressure following the limiting ATWS event reaches 1,192 psia during the time the SLCS is analyzed to be in operation. Consequently, there is a corresponding increase in the maximum pump discharge pressure and a decrease in the operating pressure margin for the pump discharge relief valves from Current Licensed Thermal Power (CLTP) operation. The pressure margin for the pump discharge relief valves remains above the minimum value needed to ensure that the relief valves remain closed during system injection. In the event that the SLCS is initiated before the time that the reactor pressure recovers from the first transi ent peak, resulting in opening of the SLCS relief valves, the reactor pressure must reduce sufficiently to ensure SLCS pump relief valve closure.

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Analysis results indicate that the reactor pressure reduces sufficiently from the first transient pressure peak to allow the SLCS pump relief valves to close.

The SLCS ATWS performance is evaluated in Section 7.0 for operation with the SRV setpoint increase and tolerance change. The evaluation shows that the SRV setpoint increase and tolerance change have no adverse effect on the ability of the SLCS to mitigate an ATWS event.

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6.0 Containment Evaluation 6.1 Containment Pressure and Temperature Response 6.1.1 DBA LOCA The effects on the peak containment pressure and temperature response for the short-term Design Basis Accident (DBA) LOCA event and on the peak suppression pool temperature and wetwell pressure for the long-term DBA LOCA were evaluated. Operation with a uniform SRV setpoint and relaxation of the SRV setpoint tolerance or operation with a single SRV OOS has no effect on the DBA LOCA event because the vessel depressurizes without any SRV actuations; therefore, there is no effect on the DBA LOCA containment pressure and temperature and on the DBA LOCA suppression pool temperature and wetwell pressure. The inputs of containment pressure and suppression pool temperature to th e available Net Positive Suction Head (NPSH) analysis are also unaffected.

6.1.2 Loss of Offsite Power The effects on the peak suppression pool temperature and wetwell pressure response for the Loss of Offsite Power (LOP) event were evaluated. The LOP event is a non-break event. There is no normal SRV actuation before the SRV LLS relief logic because the HCGS LLS relief logic is armed when the reactor pressure is above the scram setpoint but below the opening pressure of the first SRV valve bank; therefore, SRV opening is not a requirement to arm the LLS relief logic.

Because LLS is not changed due to the SRV setpoint change and there is no SRV actuation before LLS, the LOP event is not affected by the SRV setpoint change. The inputs of containment pressure and suppression pool temperature to the available NPSH analysis are also unaffected.

6.1.3 Small Steam Line Breaks The given temperature conditions for a small steam line break are based on ((

)) therefore, the small steam line break for Equipment Qualification (EQ) is not affected by transitioning to a single SRV code safety valve function lift setpoint of 1,130 psig with a +3%/-5% tolerance.

6.1.4 Intermediate and Small Steam Line Break Accidents The containment pressure and temperature response for the Intermediate Line Break Accident (IBA) (a liquid line break of 0.1 ft2) and for the Small Line Break Accident (SBA) (a steam line break of 0.01 ft2) were originally evaluated as part of the Mark I containment program and documented in the plant unique load definition report (Reference 10). The results for the IBA and SBA documented in Reference 10 are based on an endpoint-type calculation, which is controlled by the amount of initial stored energy in the primary system and decay heat. There is no increase in the initial primary system stored en ergy or decay heat due to an increase in SRV setpoint tolerance or operation with a single SRV OOS; therefore, there is no change for either

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the IBA or SBA event results as presented in Reference 10. Additionally for the SBA, the Reference 10 drywell temperature response is bounding at a constant temperature of 340 ° F. This bounding drywell temperature value does not change due to an increase in SRV setpoint, setpoint tolerance change or operation with a single SRV OOS.

6.1.5 NUREG-0783 Local Suppression Pool Temperature The NUREG-0783 analysis for the local pool temperature is documented in Reference 11.

Additional evaluations have been performed as part of the Extended Power Uprate (EPU)

(Reference 12). In the NUREG-0783 analysis, ((

] ]. The limiting event does not experience a vessel pressurization transient that results in automatic SRV actuation.

Neither the SRV setpoint and tolerance change nor operation with a single SRV OOS affects the limiting NUREG-0783 event.

6.2 LOCA Hydrodynamic Loads and SRV Loads 6.2.1 DBA LOCA Hydrodynamic Loads The DBA LOCA hydrodynamic loads, such as pool swell, vent thrust, condensation oscillation and chugging are dependent on the containment pressure and temperature response during the DBA LOCA. Because the containment DBA LOCA pressure and temperature responses are not affected by an increase in the SRV setpoint, even when the plant is operating with a single SRV OOS, the DBA LOCA hydrodynamic loads are also unaffected.

6.2.2 SRV Dynamic Loads An increase in the SRV pressure setpoint for all SRVs at a uniform pressure of 1,130 psig with a

+ 3% tolerance may increase the pressure at which the SRVs open. The resulting increase in SRV opening pressure could increase the SRV flow rate, which could result in an increase in the internal SRV dynamic loads pressure, the thrust loads, and the external T-quencher bubble pressure loads.

SRV dynamic loads include:

1) Internal SRV loads: Reaction and thrust loads acting on the SRV Discharge Line (SRVDL) and T-quencher and their supports

2) External SRV loads : Air-bubble pressure loads on submerged pool boundary and air-bubble drag loads on submerged structures.

The effect of the SRV setpoint tolerance relaxation on external air bubble pressure loads is evaluated using the same methods that were used to evaluate the SRV setpoint tolerance in Reference 9. The evaluation is based on the following two key assumptions :

1) ((

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))

As a result, a uniform setpoint pressure of 1,130 psig +3% tolerance for SRVs would result in ((

))

The increased SRV loads are evaluated in Sections 6.2.3 through 6.2.5.

6.2.3 Internal Loads The internal SRV loads include the pressure and thrust loads on the SRVDL, T-quenchers and T-quencher supports. For the T-quencher and the portion of the SRVDL in the wetwell, the thrust load resulting from the expulsion of the water column initially in the SRVDL and T-quencher are dominant.

6.2.3.1 Loads on T-Quenchers and T-Quencher Supports As stated in Section 7.2.3.1.1 of Reference 9, there is an over-prediction in the water clearing thrust loads by (( )) as determined by the RVFOR04 program. This conservatism is much greater than the (( )) due to the SRV setpoint increase; therefore, an increase in the SRV pressure setpoint for all SRVs at a uniform pressure of 1,130 psig does not have an adverse effect on the loads on the quenchers and quencher supports.

6.2.3.2 Loads on SRV Piping in Drywell The (( )) in the RVFOR04 model cannot be used for the loads on SRV piping in the drywell, as stated in Section 7.2.3.1.2 of Reference 9. The effect due to all SRVs at a uniform pressure of 1,130 psig with a +3% tolerance is documented in Section 6.3.

6.2.4 External Loads The external SRV loads on the torus pool include the loads on the torus shell, the loads on the submerged structures in the torus pool, and the torus shell loads that are transmitted to the torus attached piping.

6.2.4.1 Torus Shell, Torus Support Loads, and Torus Attached Piping Containment structures that are affected by the torus shell pressure include the torus shell, torus support structures, and torus attached piping.

As stated in Section 7.2.3.2.1 of Reference 9, there is at least a 21% conservatism in the evaluation of multiple SRV actuations for the torus bubble pressure loads. This conservatism is much greater than (( )) due to the SRV setpoint increase; therefore, an increase in the SRV pressure setpoint for all SRVs at a uniform pressure of 1,130 psig does not have an adverse effect on the loads on the torus shell, torus support and torus attached piping.

6.2.4.2 Submerged Structure Loads As the air and steam/air mixtures are discharged into the suppression pool via SRV, these air bubble formations create acceleration and drag loads that are exerted on the submerged

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structures including the torus vent system penetration, ring girders, vent header supports, and downcomers.

As stated in Section 7.2.3.2.2 of Reference 9, there is at least a 20% conservatism in the SRV loads for the vent system, vent system penetrations, and vent system support structures. This bounds the loads for the SRV setpoint increase by up to 20%; therefore, all SRVs at a uniform pressure of 1,130 psig with a +3% tolerance have no adverse effect on the external SRV loads on the submerged structures.

6.2.5 Subsequent SRV Actuation The loads due to subsequent SRV actuations are primarily dependent on the SRVDL reflood height at the time of SRV opening and SRV setpoints. To mitigate the effects of subsequent SRV actuation, LLS logic is implemented to extend the time between SRV closure and subsequent actuation (Reference 14). The EPU analysis in Reference 12 shows that there is at least 18 seconds to reopen an LLS valve, which is greater than the lower limit of 4 seconds in Reference 14. This time period is sufficient to allow the water leg of the SRV piping to clear as well as to mitigate the thrust loads on the SRV discharge piping.

The (( )) in the SRV flow rate also applies to subsequent actuation loads, as ((

)) While a decrease in the SRV setpoint will result in decreases in the time between valve closure for the first actuation and the subsequent actuation, the change is much less than 18 seconds. In addition, any reduction in SRV setpoint pressure (i.e., -5% tolerance) will result in a reduction of the SRVDL loads due to the reduction in SRV mass flow rate.

6.2.6 Effect of a Single SRV Out-of-Service on SRV Loads Having a single SRV OOS does not have an effect on the SRV dynamic loads. The SRV dynamic loads are driven by ((

)) The SRV discharge line water level is in turn a function of the time between the closure of the valves at the end of the first actuation and the time of the subsequent actuation. Having a single SRV OOS will not affect the valve setpoints or the time between the initial and subsequent valve actuations. As such, having a single SRV OOS has no effect on SRV dynamic loads.

6.3 Reactor Coolant Pressure Boundary Piping Evaluation Analysis done in Table 7-1 of Reference 9 to relax the tolerance of the SRV setpoints found that the SRVs could be set to a higher pressure. ((

)) stress ratios confirm that there is sufficient margin; therefore, the increased SRV setpoint of 1,130 psig

-5%/+3% is acceptable.

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7.0 ATWS Mitigation Capability The purpose of this evaluation is to assess the effect of revised SRV operating parameters including increasing the SRV lift setpoint to 1,130 psig and updating the opening tolerance to

+3%/-5%, consistent with the requirements listed in Table 7-1, on the ATWS limiting licensing basis events.

7.1 ATWS Requirements HCGS meets the following ATWS mitigation equipment requirements defined in 10 CFR 50.62:

1. Installation of an Alternate Rod Insertion (ARI) system;

2. Boron injection equivalent to 86 gpm; and

3. Installation of automatic Recirculating Pump Trip (RPT) logic (i.e., ATWS-RPT).

These three features are included in the HCGS design. Compliance to these requirements ensures the integrity of the reactor vessel pressure boundary, the integrity of fuel and a coolable geometry, and the integrity of the containment. The HCGS specific analysis at CLTP conditions (3,902 MWt) demonstrates that the following ATWS acceptance criteria are met:

1. Peak vessel bottom pressure less than ASME Service Level C limit of 1,500 psig;

2. PCT within the 10 CFR 50.46 limit of 2,200;

3. Peak cladding oxidation within the 10 CFR 50.46 requirement of less than 17%;

4. Peak local suppression pool temperature less than the plant design limit of 217.5; and

5. Peak containment pressure less than the plant design limit of 62 psig.

The effects on peak vessel pressure, peak suppression pool temperature, and containment pressure are explicitly analyzed in the ATWS analysis. The PCT and fuel local cladding oxidation are justified for compliance with the corresponding acceptance criteria based on the margin and historical PCT results consistent with Reference 15.

7.2 ATWS Evaluation Approach The plant response to an ATWS scenario was evaluated. The ATWS analysis takes credit for the ATWS-RPT and SLCS, but assumes the ARI fails. If reactor vessel and fuel integrity are maintained, then the ATWS-RPT setpoint is adequate. If containment integrity is maintained, then the SLCS performance is adequate.

The evaluation analyzes the two potentially limiting licensing basis ATWS events for vessel integrity and containment response: Main Steam Line Isolation Valve Closure (MSIVC) and Pressure Regulator Failure - Maximum Demand (PRFO).

The MSIVC and PRFO events are the most limiting events for the ATWS acceptance criteria.

The MSIVC and PRFO events result in reactor isolation and a large power increase without scram. Due to the reactor isolation, a high demand on the SRVs is required to mitigate the large pressure increase, with all of the energy being directed to the containment and suppression pool.

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These factors combine to make the MSIVC and PRFO events the most limiting for fuel integrity, reactor pressure vessel integrity, and containment integrity.

The key inputs to the ATWS analysis are provided in Table 7-1. These ATWS events are analyzed using the engineering computer codes shown in Table 7-2.

As indicated in Table 7-1, the SRV tolerance is updated to +3% / -5% from +/-3%. The upper SRV opening tolerance is not changing, and therefore the modeled SRV opening setpoint is not affected. The lower SRV tolerance is not specifically modeled in the ATWS analysis methodology. SRVs opening earlier would improve the short-term peak vessel pressure response; therefore, there is no effect on the increased tolerance on the short-term peak vessel pressure. ((

)) The long-term ATWS response is primarily a function of mass and energy released; therefore, the long-term ATWS response would not be affected by a change to the lower SRV tolerance.

7.3 ATWS Results The limiting ATWS results are provided in Table 7-3. The ATWS performance with Table 7-1 SRV parameters is acceptable for HCGS. Each acceptance criterion is discussed in further detail below.

7.3.1 Peak Vessel Bottom Pressure Increasing the SRV opening setpoints will increase the peak vessel bottom pressure. During an ATWS event, the pressure response is above the SRV opening setpoints requiring all credited valves to fully open. The peak vessel bottom pressure is less than ASME Service Level C limit of 1,500 psig.

7.3.2 Peak Suppression Pool Temperature and Containment Pressure The increase in SRV opening setpoint will not significantly affect the long-term ATWS response (suppression pool temperature and containment pressure). The long-term peak suppression pool temperature and containment pressure values are a function of mass and energy released; therefore, margin exists relative to the suppression pool temperature and containment pressure design limits.

7.3.3 PCT and Cladding Oxidation The increase in SRV opening setpoints will have a negligible effect on the PCT results. ((

)) The local fuel conditions do not significantly change with the increase of the SRV opening setpoint ((

)) In addition, Reference 12 calculated a PCT of 1,446 at a power level of 3,952 MWt, which is 50 MWt greater than the HCGS CLTP. The cladding oxidation thickness associated with a PCT less than (( )) is negligible compared to the

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corresponding acceptance criterion. Therefore, the PCT and local cladding oxidation thickness acceptance criteria are met.

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Table 7-1 HCGS Key Inputs for ATWS Analysis

Input Variable Value

Reactor Power (MWt) 3,902

Reactor Dome Pressure (psig) 1,005

SRV Nominal Opening Setpoint (psig) 1,130

SRV Upper Analytical Limit (psig) 1,163.9

SRV Reference Pressure (psig) 1,130

SRV System Capacity (13 valves) at Reference Pressure (Mlbm/hr) 11.71

Number of SRVs 14

Number of SRVs OOS 1

High Pressure ATWS-RPT (psig) 1,101

SRV Opening / Closing Tolerance (%) +3% / -5%

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Table 7-2 Computer Codes for ATWS Analyses

Computer Code Version NRC Approved Comments

ODYN 10 Y Reference 16

PANACEA 11 Y Reference 17

STEMP 04 (1) See Note 1

SHEX 05 Y (2) See Note 2

Notes:

1. The STEMP code uses fundamental mass and energy conservation laws to calculate the suppression pool heatup. The use of STEMP was noted in Reference 18. The code has been used in ATWS applications since that time. There is no formal NRC review and approval of STEMP. The application of this code has been used in previous submittals (References 12 and 15).

2. The application of the methodology in the SHEX code to the containment response is approved by the NRC in the letter to Gary L. Sozzi (GE) from Ashok Thadani (NRC), Use of the SHEX Computer Program and ANSI/ANS 5.1-1979 Decay Heat Source Term for Containment Long-Term Pressure and Temperature Analysis, July 13, 1993 (Reference 19).

Table 7-3 HCGS ATWS Analysis Results

Acceptance Criteria Unit Limit Result

Peak Vessel Pressure psig 1,500 1,473

Peak Local Suppression Pool Temperature1 217.5 215.6

Peak Containment Pressure psig 62 9.5

Peak Cladding Temperature 2,200 <1,600

Local Cladding Oxidation % 17 <17

Note:

1. Corresponds to a bulk suppression pool temperature of 198.6 against a limit of 200.5.

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8.0 Nuclear Boiler System Evaluation 8.1 MSL High Steam Flow Analytical Limits The high steam line flow analytical limits are based upon 140% of rated steam flow. Increasing the SRV opening pressures has no effect on rated steam flow; therefore, there is no effect on the analytical limits.

8.2 Differential Pressure Across the MSL Flow Restrictors The differential pressure across th e Main Steam Line (MSL) flow restrictors is a function of the steam flow rate. Increasing the SRV opening pressures has no effect on rated steam flow; therefore, the differential pressure across the restrictors is unchanged, and there is no effect on the structural integrity of the restrictors and no effect on flow restrictor erosion.

8.3 MSIV Pressure Drop and Closing Times The MSIV pressure drop and closing times are a function of the steam flow rate. Increasing the SRV opening pressures has no effect on rated steam flow; therefore, there is no effect on the MSIV pressure drop and closing times.

8.4 SRV Flow Capacity The flow capacity of each SRV is a function of the dimensions of the valves main disc and seat.

The SRV opening setpoint is controlled by adjustment of the pilot spring which is independent of the valves main disc and seat; therefore, ther e is no effect on SRV flow capacity. The adequacy of the SRV flow capacity for mitigating the effects of overpressure transients is evaluated in Section 3.0, and the effect on ATWS is evaluated in Section 7.0.

8.5 Pneumatic Supplies to the SRVs and MSIVs The SRVs will open and re-close based upon the spring opening set pressure and reseat pressure; therefore, the pneumatic supply to the SRVs is unaffected. The SRV setpoint increase has no effect on the DBA LOCA peak drywell pressure increase because the vessel depressurizes without any SRV actuations; therefore, the closure of the inboard MSIVs and their pneumatic supply are unaffected.

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9.0 Conclusions The proposed changes to the specified SRV function lift settings are satisfactory for HCGS and have no significant effect on plant safety.

The SRV setpoint reconfiguration increases the simmer margin for the SRVs while still protecting overpressure requirements. The analyses in this report support the reconfiguration of all valves to 1,130 psig. All acceptance criteria are met.

The analyses which form the basis for this report support relaxation of the tolerances on the opening setpoints of the SRVs from +/-3% to +3%/-5%. They have also demonstrated that a change to the SRV setpoint upper limit value to 1,130 psig has no significant effect upon plant safety. All calculations and evaluations were performed with one SRV OOS.

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10.0 References

1. GE Hitachi Nuclear Energy, Migration to TRACG04 / PANAC11 from TRACG02 /

PANAC10 for TRACG AOO and ATWS Overpressure Transients, NEDE-32906P Supplement 3-A, Revision 1, April 2010.

2. GE Nuclear Energy, TRACG Application for Anticipated Operational Occurrences (AOO) Transient Analyses, NEDE-32906P-A, Revision 3, September 2006.

3. Global Nuclear Fuel, General Electric Standard Application for Reactor Fuel (GESTAR II), NEDE-24011-P-A-31, November 2020.

4. Global Nuclear Fuel, Supplemental Reload Licensing Report for Hope Creek Reload 24 Cycle 25, 006N6141, Revision 0, September 2022.

5. GE Hitachi Nuclear Energy, Hope Creek Generating Station GNF2 ECCS-LOCA Evaluation, 002N5176, Revision 0, August 2016.

6. GE Hitachi Nuclear Energy, Summary of GEH Anticipated Operational Occurrence (AOO) Transient and Loss of Coolant Accident (LOCA) Analyses with Respect to Adjustable Speed Drive (ASD) Modification in Hope Creek Generating Station, 004N1122, Revision 0, August 2017.

7. GE Nuclear Energy, BWROG In-Service Pressure Relief Technical Specification Revision Licensing Topical Report, NEDC-31753P, February 1990.

8. NRC Generic Letter 89-10, Safety-Related Motor Operated Valve Testing and Surveillance, June 28, 1989.

9. GE Nuclear Energy, Safety Review for Hope Creek Generating Station Safety/Relief Valve Tolerance Analyses, NEDC-32511P, Revision 1, October 1998.

10. General Electric Company, Mark I Containment Program Plant-Unique Load Definition Hope Creek Generating Station: Unit 1, NEDO-24579-1, Revision 1, January 1982.

11. General Electric Company, Hope Creek Generating Station Suppression Pool Temperature Response, NEDC-30154, June 1983.

12. GE Nuclear Energy, Safety Analysis Report for Hope Creek Constant Pressure Power Uprate, NEDC-33076P, Revision 2, August 2006.

13. General Electric Company, Mark I Containment Program Analytical Model for Computing Air Bubble and Boundary Pressures Resulting from an S/RV Discharge Through a T-Quencher Device, NEDE-21878-P, January 1979.

14. General Electric Company, Evaluation of Mark I S/RV Load Cases C3.1, C3.2, C3.3 for the Hope Creek Nuclear Generating Station, NEDC-22200, August 1982.

15. GE Hitachi Nuclear Energy, Safety Analysis Report for Hope Creek Generating Station Thermal Power Optimization, NEDC-33871P, Revision 0, April 2017.

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16. GE Nuclear Energy, Qualification of the One-Dimensional Core Transient Model (ODYN) for Boiling Water Reactors (Supplement 1 - Volume 4), NEDC-24154P-A, Revision 1, February 2000.

17. General Electric Company, Steady-State Nuclear Methods, NEDE-30130-P-A, April 1985.

18. General Electric Company, Assessment of BWR Mitigation of ATWS, Volume I & II (NUREG-0460 Alternate No. 3), NEDE-24222, December 1979.

19. Ashok Thadani (NRC) to Gary L. Sozzi (GE), Use of the SHEX Computer Program and ANSI/ANS 5.1-1979 Decay Heat Source Term for Containment Long-Term Pressure and Temperature Analysis, July 13, 1993. (ADAMS Accession Number ML17179B059).

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Attachment 4

Affidavit from GEH Supporting the Withholding of Information in Attachment 5 from Public Disclosure

1 GE-Hitachi Nuclear Energy Americas, LLC

AFFIDAVIT

I, Lisa K. Schichlein, state as follows:

(1) I am a Senior Licensing Engineer, Regulatory Affairs, GE-Hitachi Nuclear Energy Americas, LLC (GEH), and have been delegated the function of reviewing the information described in paragraph (2) which is sought to be withheld and have been authorized to apply for its withholding.

(2) The information sought to be withheld is contained in GEH proprietary report NEDC-34037P, Safety Review for Hope Creek Generating Station Safety/Relief Valve Setpoint Increase and Tolerance Change, Revision 0, May 2024. GEH proprietary information in NEDC-34037P is identified by a dotted underline inside double square brackets. ((This sentence is an example.{3})). GEH proprietary information in figures and large objects is identified by double square brackets before and after the object. In each case, the superscript notation {3} refers to Paragraph (3) of this affidavit, which provides the basis for the proprietary determination.

(3) In making this application for withholding of proprietary information of which it is the owner or licensee, GEH relies upon the exemption from disclosure set forth in the Freedom of Information Act (FOIA), 5 U.S.C. §552(b)(4), and the Trade Secrets Act, 18 U.S.C.

§1905, and NRC regulations 10 CFR 9.17(a)(4), and 2.390(a)(4) for trade secrets (Exemption 4). The material for which exemption from disclosure is here sought also qualifies under the narrower definition of trade secret, within the meanings assigned to those terms for purposes of FOIA Exemption 4 in, respectively, Critical Mass Energy Project v. Nuclear Regulatory Commission, 975 F.2d 871 (D.C. Cir. 1992), and Public Citizen Health Research Group v. FDA, 704 F.2d 1280 (D.C. Cir. 1983).

(4) The information sought to be withheld is considered to be proprietary for the reasons set forth in paragraphs (4)a and (4)b. Some examples of categories of information that fit into the definition of proprietary information are:

a. Information that discloses a process, method, or apparatus, including supporting data and analyses, where prevention of its use by GEH's competitors without a license from GEH constitutes a competitive economic advantage over other companies;

b. Information that, if used by a competitor, would reduce its expenditure of resources or improve its competitive position in the design, manufacture, shipment, installation, assurance of quality, or licensing of a similar product;

c. Information that reveals aspects of past, present, or future GEH customer-funded development plans and programs, resulting in potential products to GEH;

NEDC-34037P Revision 0 Affidavit Page 1 of 3 GE-Hitachi Nuclear Energy Americas, LLC

d. Information that discloses trade secret or potentially patentable subject matter for which it may be desirable to obtain patent protection.

(5) To address 10 CFR 2.390(b)(4), the information sought to be withheld is being submitted to NRC in confidence. The information is of a sort customarily held in confidence by GEH, and is in fact so held. The information sought to be withheld has, to the best of my knowledge and belief, consistently been held in confidence by GEH, not been disclosed publicly, and not been made available in public sources. All disclosures to third parties, including any required transmittals to the NRC, have been made, or must be made, pursuant to regulatory provisions for proprietary or confidentiality agreements or both that provide for maintaining the information in confidence. The initial designation of this information as proprietary information, and the subsequent steps taken to prevent its unauthorized disclosure, are as set forth in the following paragraphs (6) and (7).

(6) Initial approval of proprietary treatment of a document is made by the manager of the originating component, who is the person most likely to be acquainted with the value and sensitivity of the information in relation to industry knowledge, or who is the person most likely to be subject to the terms under which it was licensed to GEH.

(7) The procedure for approval of external rele ase of such a document typically requires review by the staff manager, project manager, principal scientist, or other equivalent authority for technical content, competitive effect, and determination of the accuracy of the proprietary designation. Disclosures outside GEH are limited to regulatory bodies, customers, and potential customers, and their agents, suppliers, and licensees, and others with a legitimate need for the information, and then only in accordance with appropriate regulatory provisions or proprietary and/or confidentiality agreements.

(8) The information identified in paragraph (2) is classified as proprietary because it contains the detailed GEH methodology for analyses of the GEH Boiling Water Reactor (BWR).

These methods, techniques, and data along with their application to the design, modification, and analyses associated with the fuel analyses were achieved at a significant cost to GEH.

The development of the evaluation processes along with the interpretation and application of the analytical results is derived from th e extensive experience and information databases that constitute major GEH assets.

(9) Public disclosure of the information sought to be withheld is likely to cause substantial harm to GEH's competitive position and foreclose or reduce the availability of profit-making opportunities. The information is part of GEH's comprehensive BWR safety and technology base, and its commercial value extends beyond the original development cost.

The value of the technology base goes beyond the extensive physical database and

NEDC-34037P Revision 0 Affidavit Page 2 of 3 GE-Hitachi Nuclear Energy Americas, LLC

analytical methodology and includes development of the expertise to determine and apply the appropriate evaluation process. In addition, the technology base includes the value derived from providing analyses done with NRC-approved methods.

The research, development, engineering, analytical and NRC review costs comprise a substantial investment of time and money by GEH. The precise value of the expertise to devise an evaluation process and apply the correct analytical methodology is difficult to quantify, but it clearly is substantial. GEH's competitive advantage will be lost if its competitors are able to use the results of the GEH experience to normalize or verify their own process or if they are able to claim an equivalent understanding by demonstrating that they can arrive at the same or similar conclusions.

The value of this information to GEH would be lost if the information were disclosed to the public. Making such information available to competitors without their having been required to undertake a similar expenditure of resources would unfairly provide competitors with a windfall, and deprive GEH of the opportunity to exercise its competitive advantage to seek an adequate return on its large investment in developing and obtaining these very valuable analytical tools.

I declare under penalty of perjury that the foregoing is true and correct.

Executed on this 8th day of May 2024.

Lisa K. Schichlein Senior Licensing Engineer GE-Hitachi Nuclear Energy Americas, LLC 3901 Castle Hayne Road Wilmington, NC 28401 lisa.schichlein@ge.com

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