ML20134K758

License Amendment Request Under Exigent Circumstances for One-Time Revision to Technical Specification 3.5.1 to Reduce Minimum Allowed Accumulator Pressures

ML20134K758
Person / Time
Site:	South Texas
Issue date:	05/13/2020
From:	Schaefer M South Texas
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
NOC-AE-20003734
Download: ML20134K758 (21)

Text

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Nuclear Operating Company

- - Ill . -

S 0 11th Texas Proiect Electric Generating Station PO. 8oK 289 Wadsworth. Texas 7748]

May 13, 2020 NOC-AE-20003734 10 CFR 50.90 10 CFR 50.91 (a)(6)

STI: 35016797 ATTN: Document Control Desk U.S. Nuclear Regulatory Commission Washington, DC 20555-0001 South Texas Project Unit 1 Docket No. 50-498 License Amendment Request Under Exigent Circumstances for One-Time Revision To Technical Specification 3.5.1 to Reduce Minimum Allowed Accumulator Pressures Pursuant to 10 CFR 50.90, STP Nuclear Operating Company (STPNOC) hereby requests an amendment to the Technical Specifications for South Texas Project (STP), Unit 1. The proposed amendment would modify Technical Specification 3.5.1 to allow Unit 1 to operate with all three Safety Injection (SI) Accumulators at a reduced minimum allowed pressure for the remainder of Unit 1 Cycle 23. This one-time change would support deferral of repairs until the next Unit 1 refueling outage. The Enclosure to this letter provides a description of the proposed change.

The proposed amendment is being requested on an exigent basis pursuant to 10 CFR 50.91 (a)(6). The emergent condition necessitating this request for exigency was caused by increased valve leakage during startup from Unit 1 refueling outage 1RE22 . After considering several options to address the condition , STPNOC determined that the safest solution was to isolate Unit 1 SI Accumulator 1A and then request approval of a Technical Specification change to reduce the minimum allowed cover gas pressure for the accumulators prior to restoration.

Because STP Unit 1 will reach the backstop Risk-Informed Completion Time allowed by Technical Specifications on May 29, 2020, STPNOC has determined that the need for this License Amendment Request is exigent. The proposed change is necessary to prevent frequent cycling of safety-related equipment or a reactor shutdown to make repairs, both of which would result in increased risk without a commensurate increase in safety.

STP requests approval of the proposed amendment by May 28, 2020. When approved, this amendment would be implemented within 14 days.

The proposed amendment does not involve a significant hazards consideration under the standards set forth in 10 CFR 50.92(c).

In accordance with 10 CFR 50.91 (b), "State Consultation," STPNOC is notifying the State of Texas of this license amendment request by transmitting a copy of this letter and Enclosure to the designated State Official. The proposed amendment has been reviewed and approved by the STPNOC Plant Operations Review Committee and has undergone an independent organizational unit review.

NOC-AE-20003734 Page 2 of 2 There are no regulatory commitments in this amendment request.

If there are any questions or if additional information is needed, please contact Wendy Brost at (361) 972-8516 or me at (361) 972-7888.

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

Executed on /231()

b,- t I Schaefer Site Vice President

Enclosure:

Evaluation of the Proposed Change cc:

Regional Administrator, Region IV U.S. Nuclear Regulatory Commission 1600E. Lamar Boulevard Arlington, TX 76011-4511

Enclosure NOC-AE-20003734 Page 1 of 15 ENCLOSURE Evaluation of the Proposed Change

Subject:

License Amendment Request Under Exigent Circumstances for One-Time Revision to Technical Specification 3.5.1 to Reduce Minimum Allowed Accumulator Pressures 1

SUMMARY

DESCRIPTION 2 DETAILED DESCRIPTION 2.1 System Design and Operation 2.2 Current Technical Specification Requirements 2.3 Circumstances Establishing Need for the Proposed Exigent Amendment 2.4 Description of the Proposed Change 3 TECHNICAL EVALUATION 3.1 Evaluation Summary 3.2 Large Break LOCA Peak Clad Temperature (PCT) 3.3 Small Break LOCA PCT 3.4 LOCA Dose Analyses Summary 3.5 Containment Analysis for Peak Pressures and Temperature 3.6 Containment Equipment Qualification Peak Pressure and Temperature 3.7 Containment Subcompartment Integrity 3.8 Post-LOCA Long-Term Cooling and Subcriticality and Hot Leg Switchover Time 3.9 MSLB Hot Zero Power Departure from Nucleate Boiling (DNB) 3.10 Other Non-LOCA Transients 3.11 Nitrogen Gas Accumulation 3.12 Conclusions 4 REGULATORY EVALUATION 4.1 Applicable Regulatory Requirements/Criteria 4.2 No Significant Hazards Consideration Determination Analysis 4.3 Conclusions 5 ENVIRONMENTAL CONSIDERATIONS 6 REFERENCES ATTACHMENTS:

1. Technical Specification Page Markup

2. Retyped Technical Specification Page

Enclosure NOC-AE-20003734 Page 2 of 15 1

SUMMARY

DESCRIPTION In accordance with 10 CFR 50.90, South Texas Project Nuclear Operating Company (STPNOC) requests an amendment to the Technical Specifications for the South Texas Project Electric Generating Station (STPEGS).

The proposed change would modify Technical Specification 3/4.5.1, Accumulators, to allow Unit 1 to operate with all three Safety Injection (SI) Accumulators at reduced minimum pressures through the end of Unit 1 Cycle 23. Specifically, a footnote would be added to Technical Specification Surveillance Requirement 4.5.1.1.a.1) to reduce the lower pressure limit for the accumulator nitrogen cover-pressure from 590 psig to 500 psig during Unit 1 Cycle 23. This would allow STP to resolve an emergent valve leakage issue while maintaining all three SI Accumulators operable and having no significant adverse impact to the Residual Heat Removal (RHR) or Low-Head Safety Injection (LHSI) systems.

2 DETAILED DESCRIPTION 2.1 System Design and Operation STP Unit 1 has three Emergency Core Cooling System (ECCS) Accumulators. The safety function of the accumulators is described in Section 6.3.2 of the STP Updated Final Safety Analysis Report (UFSAR).

The accumulators are pressure vessels partially filled with borated water and pressurized with nitrogen gas. One accumulator is attached to each of the cold legs of loops 1, 2, and 3 of the Reactor Coolant System (RCS). During normal operation, each accumulator is isolated from the RCS by two check valves in series. The nitrogen cover gas pressure is less than that of the RCS so that when the RCS pressure decreases below the tank pressure, the check valves open and the accumulators inject borated water into the RCS cold legs.

Accumulator pressure is monitored by indicators and alarms. To maintain accumulator operability per Technical Specifications, operators can take actions as required to maintain accumulator borated water volume and nitrogen cover gas pressure.

Valve RH-0032A is an 8-inch swing check valve located between the A-Train LHSI and the RCS Loop 1A cold leg. Following a safety injection signal, check valve RH-0032A prevents backflow from High-Head Safety Injection (HHSI) Pump 1A when RCS pressure is above the shutoff head of the LHSI pump. This check valve also serves as an RCS pressure isolation valve in series with the downstream check valve SI-0038A to provide a pressure boundary between the RCS and the RHR system. The Technical Specification 3.4.6.2 Limiting Condition for Operation (LCO) is being met with the leakage through check valve RH-0032A.

Valve RH-0031A is the A-Train RHR discharge isolation motor-operated valve (MOV) located between the A-Train LHSI and the RCS Loop 1A cold leg. Valve SI-0039A is the SI Accumulator 1A outlet MOV. Included below for information only is a simplified system drawing showing the components discussed in this Enclosure.

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Enclosure NOC-AE-20003734 Page 4 of 15 2.2 Current Technical Specifications Requirements Technical Specification 3.5.1 states that each SI system accumulator is required to be operable while the plant is in Operational Modes 1 and 2 and in Mode 3 with pressurizer pressure greater than 1000 psig.

Per Technical Specification Surveillance Requirement 4.5.1.1.a.1), each accumulator shall be demonstrated operable at a frequency in accordance with the Surveillance Frequency Control Program by verifying the nitrogen cover-pressure is at or between 590 psig and 670 psig.

2.3 Circumstances Establishing Need for the Proposed Exigent Amendment The proposed amendment is being requested on an exigent basis pursuant to 10 CFR 50.91(a)(6).

STP identified a significant increase in leakage through check valve RH-0032A, the LHSI Train A to Loop 1A Cold Leg check valve, during startup from Unit 1 refueling outage 1RE22.

STP identified that SI Accumulator 1A was losing inventory at approximately 6 gallons per hour (144 gallons per day) through check valve RH-0032A, which was transporting accumulator water to the RHR system through the A-Train RHR discharge header. STP cannot maintain the RHR and LHSI systems below the relief valve setpoints without performing excessive manipulations of safety-related components required to vent the RHR system and refill SI Accumulator 1A. These actions could lead to equipment failure and an unplanned shutdown.

STP isolated SI Accumulator 1A to stop the leakage as a temporary solution, but per the requirements of Technical Specifications, Unit 1 can only remain in this configuration for 30 days, which is the backstop Risk Informed Completion Time (RICT) allowed per Technical Specification 6.8.3.k, Configuration Risk Management Program.

STP determined that the safest solution is to request approval of a Technical Specification change to reduce the minimum allowed cover gas pressure for the accumulators. After reaching this decision, STP has endeavored to submit this amendment request as expeditiously as possible, while keeping in mind the need for the request to be complete, accurate, and with sufficient detail to allow the NRC to perform a review. Because STP Unit 1 will reach the backstop RICT on May 29, 2020, STPNOC has determined that the need for this LAR is exigent and does not allow for the standard public comment period.

2.4 Description of the Proposed Change The proposed change would modify Technical Specifications by adding a footnote to Technical Specification Surveillance Requirement 4.5.1.1.a.1) to reduce the minimum allowed nitrogen cover-pressure for the Unit 1 accumulators to 500 psig for the remainder of Unit 1 Cycle 23.

3 TECHNICAL EVALUATION The accumulators are pressure vessels partially filled with borated water and pressurized with nitrogen gas. During normal operation, each accumulator is isolated from the RCS by two check valves in series. Should the RCS pressure fall below the accumulator pressure, the check valves open and borated water is forced into the RCS.

STPNOC determined that the proposed change to reduce the minimum allowed cover gas pressure for the accumulators should be applicable to all three Unit 1 accumulators. Based on the historical performance of the common-header nitrogen supply that pressurizes the SI accumulators in Units 1

Enclosure NOC-AE-20003734 Page 5 of 15 and 2, STPNOC believes that it would be difficult, and potentially an operator burden, to maintain the accumulators at different pressures. When attempting to pressurize an accumulator, the nitrogen supply system will almost always pressurize the accumulator with the least pressure due to the performance limitations of the supply valves. If STP were to attempt to maintain the accumulators at different pressures, the plant would run the risk of increasing the pressure in the accumulator with lower pressure and potentially lift an RHR relief valve. Maintaining all the accumulators at the same reduced pressure eliminates this potential.

3.1 Evaluation Summary STP performed an evaluation of the impact of the reduced minimum accumulator pressure on Design Basis Accident (DBA) analyses and associated variables. A summary of the results of the analysis compared to the design basis values is shown below. Specific discussions for each component of the evaluation follow in this section.

Value with Design Basis Accident Current Analysis of accumulator Limiting Value or Variable Record Value pressures at 500 psig Large Break Loss of 2200°F Cooling Accident 2123°F 2126°F (10 CFR 50.46 (LOCA) Peak Clad (UFSAR Table 15.6-21)

Acceptance Criterion)

Temperature (PCT) 2200°F 1612°F Small Break LOCA PCT No change (10 CFR 50.46 (UFSAR Table 15.6-23)

Acceptance Criterion) 40.1 psig 56.5 psig Containment Analysis (UFSAR Table 6.2.1.1- 40.3 psig (Containment Design Peak Pressure

2) Pressure)

Containment Pressure 41.2 psig for Containment (Technical Specification No change 41.2 psig Integrated Leak Rate Bases 3/4.6.1.2)

Test (ILRT)

No impact. Main Steam Line Break (MSLB) analysis is limiting and is not Containment Analysis impacted by the change in the cover gas pressure for all SI Peak Temperature accumulators.

Containment Equipment 40.1 psig 45.0 psig Qualification (EQ) Peak (UFSAR Table 6.2.1.1- 40.3 psig (EQ Design Criteria)

Pressure 2)

Containment Equipment 299°F (due to MSLB, 330°F Qualification Peak UFSAR Table 6.2.1.1- No change (EQ Design Criteria)

Temperature 14)

No impact. Leak-before-break (LBB) methodology eliminates 8-inch, 10-Containment inch, and 12-inch accumulator lines, which includes the RHR line up to Subcompartment the isolation valve nearest to the RCS (first isolation valve). (UFSAR Integrity Analysis 6.2.1.2.3.3., 6.2.1.2.3.5)

Enclosure NOC-AE-20003734 Page 6 of 15 Value with Design Basis Accident Current Analysis of accumulator Limiting Value or Variable Record Value pressures at 500 psig Post-LOCA Long-Term Cooling and 5.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> 5.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> Subcriticality Hot Leg No change (UFSAR 6.3.2.5) (analyzed value)

Recirculation Switchover Time Main Steam Line Break (MSLB) Hot Zero Power No DNB Departure from No change N/A (USFAR 15.1.5.4)

Nucleate Boiling (DNB)

Analysis The analyses discussed in UFSAR Sections 15.1-15.5 are not mitigated Other Non-LOCA by accumulator injection and RCS pressure remains above 600 psig, so Transients they are not impacted.

Nitrogen Gas No impact to Design Basis Accidents Accumulation 3.2 Large Break LOCA Peak Clad Temperature (PCT)

The large break LOCA (LBLOCA) analysis of record for STP Unit 1 is licensed with the 1981 Westinghouse LBLOCA Evaluation Model with BASH (BASH-EM) and is described in Section15.6.5.4.1 of the UFSAR. UFSAR Section 15.6.5.4.1 describes the use of the LOCBART Transient Extension Method (LTEM) to evaluate the effects of fuel pellet thermal conductivity degradation (TCD) on PCT.

The BASH-EM and LTEM models are described in WCAP-12055-P-A, Revision 2 and WCAP-12066-P-A, Revision 2, Addendum 3-A, Revision 1.

An evaluation was performed to address the reduction in the Technical Specification minimum accumulator cover gas pressure from 590 psig to 500 psig and to estimate the effect of this change on the PCT in accordance with 10 CFR 50.46. This evaluation complies with the NRC conditions and limitations for LTEM.

A qualitative LBLOCA evaluation concluded that the reduced accumulator cover gas pressure is minor and mainly limited to small timing changes due to the delay in accumulator injection. An estimate of the effect for this change was determined by rerunning the limiting PCT case using the reduced accumulator cover gas pressure minus uncertainties (475 psig),

leading to an estimated PCT impact of 3°F. The evaluation has been conducted pursuant to the requirements of 10 CFR 50.46 and concludes that the accumulator pressure change does not exacerbate downcomer boiling. The use of the BASH-EM to conduct this evaluation complies with the NRC conditions and limitations for BASH-EM.

Per 10 CFR 50.46, the acceptance criterion for PCT is 2200°F. The current PCT is 2123°F (UFSAR Table 15.6-21) and will increase to 2126°F for Unit 1 Cycle 23. Therefore, sufficient margin exists.

Enclosure NOC-AE-20003734 Page 7 of 15 3.3 Small Break LOCA PCT The small break LOCA (SBLOCA) analysis of record was completed using the NOTRUMP Evaluation Model and is described in UFSAR Section 15.6.5.4.1:

Based upon the results of the LOCA sensitivity studies, the limiting small break was found to be less than a 10-inch-diameter rupture of the RCS cold leg. Therefore, a range of small break analyses are presented which establishes the most limiting break size. From these calculations, the 2-inch equivalent diameter break was found to be limiting. The 1.5-inch break cases were shown to result in no core uncovery.

The above break spectrum analysis also considered a 3-inch fault size. Note that none of these scenarios were mitigated by accumulator injection.

UFSAR Section 6.3.3 addresses SBLOCA transients which may rely on accumulator injection for mitigation purposes. Specifically:

The analysis of the RCS depressurization and water level transients further shows that for a break of approximately 4.0 in. equivalent diameter, the transient is turned around and the core is recovering prior to accumulator injection. For a 4.5-in.

equivalent diameter break, the core remains uncovered with a decreasing level until accumulator action. Thus, the maximum break size showing core recovery prior to accumulator injection is approximately 4.0 in. equivalent diameter. Accumulator injection commences when pressure reaches approximately 600 psig; i.e.,

approximately 1,100 seconds from the time of the break for the 4.0-inch-break size.

The limiting transient, which is a 2-inch SBLOCA (UFSAR Section 15.6.5), does not rely on accumulator injection for mitigation purposes. The larger non-limiting SBLOCAs (greater than 3-inch piping) remain bounded by the limiting 2-inch SBLOCA. Therefore, the accumulator cover gas pressure reduction to 500 psig will have no impact on the SBLOCA analysis and has a 0°F effect on PCT. The statements presented in the UFSAR with regard to accumulator performance for SBLOCA remain valid.

3.4 LOCA Dose Analyses Summary The spectrum of small break LOCA transients analyzed are not impacted by lowering the accumulator pressure to 500 psig. The current analyses performed at 600 psia are not mitigated by accumulator injection because the RCS pressure remains above 600 psia during the transient. A re-analysis at 500 psig would give the same results.

The Large Break LOCA transient is impacted by lowering the accumulator pressure to 500 psig. The reduction in accumulator pressure causes a delay in injection resulting in an increase in PCT. The injection delay also impacts the mass and energy releases resulting in an increase in peak containment pressure and an increase in peak sump water temperature.

The impact to radiological dose from these impacts are evaluated below.

The analyzed PCT will increase from 2123°F to 2126°F from the proposed change in accumulator pressure. This result remains below the 10 CFR 50.46 acceptance criterion of 2200°F. There is no impact to the Large Break LOCA dose analysis from the change to PCT.

The small change in peak containment pressure will not impact the radiological analyses.

The new peak pressure remains below the ILRT containment pressure from Technical Specifications. As such, the containment leak rates used in the DBA LOCA remain bounding.

The LBLOCA thermal hydraulic analysis showed a peak sump water temperature increase from 274.1°F to 274.3°F. This can impact the sump pH analysis for the elemental iodine

Enclosure NOC-AE-20003734 Page 8 of 15 decontamination factor used in the LBLOCA dose analysis. Review of the LBLOCA dose analysis and related sump pH calculation bounds peak sump water temperature up to 275°F, therefore the elemental iodine decontamination factor used in the LBLOCA dose analysis and the LBLOCA dose analysis results are not impacted.

In summary, the reduction of cover gas pressure for all SI accumulators to 500 psig has no impact on the assumptions, inputs or results of the LOCA dose analysis. The current LOCA analysis is bounding.

3.5 Containment Analysis for Peak Pressures and Temperature The Containment design basis is to limit the offsite radiation dose to levels less than the regulatory limit. The design maximum Containment leakage rate supports this requirement and credits the performance of Engineered Safety Feature systems.

The Containment analysis is performed to determine the peak pressure, temperature, and temperature profile following DBAs. The limiting DBAs are LOCA and MSLB, which are described in UFSAR Section 6.2.1. A spectrum of accidents is postulated to determine Containment peak pressure and temperature. The analysis assumes that each accident occurs concurrently with a loss of offsite power and the most limiting single active failure.

For Containment analyses, LOCA is limiting for peak containment pressure and MSLB is limiting for peak containment temperature and the temperature profile used for safety-grade equipment qualification (EQ).

The limiting LOCA is the double-ended hot leg guillotine break. A mass and energy release analysis was performed with the reduced cover gas pressure of 500 psig for all SI accumulators. The results show that the accumulator injection is delayed by less than 2 seconds, which increases the containment peak pressure by 0.2 psi. Therefore, the containment peak pressure given in UFSAR Table 6.2.1.1-2 changes from 40.1 psig to 40.3 psig. The containment design pressure is 56.5 psig (UFSAR Table 6.2.1.1-2) and the containment ILRT pressure (Pa) is 41.2 psig (Technical Specification Bases 3/4.6.1.2).

Therefore, adequate margin exists.

The MSLB is not impacted by the 500 psig accumulator pressure because the RCS pressure remains sufficiently high (greater than 1000 psig) such that the accumulators do not inject.

Therefore, the Containment peak temperature does not change from the current value of 299°F (UFSAR Table 6.2.1.1-14).

In summary, there is no adverse impact to the Containment design pressure and structural pressures and temperatures with the change in cover gas pressure for the SI accumulators.

In addition, the Containment ILRT pressure (Pa) is not impacted.

3.6 Containment Equipment Qualification Peak Pressure and Temperature For Containment Equipment Qualification, the peak pressure used is 45 psig and the peak temperature used is 330°F. The containment temperature profile from the revised Containment LOCA analysis remains within the equipment qualification profile. Therefore, adequate margin exists.

In summary, there is no adverse impact to the Containment Equipment Qualification pressures and temperatures with the change in cover gas pressure for the SI accumulators.

3.7 Containment Subcompartment Integrity For the Containment Subcompartment Integrity analysis, double-ended ruptures of the RHR piping were assumed to occur between the hot leg piping and the first isolation valve in the

Enclosure NOC-AE-20003734 Page 9 of 15 12-inch section of the RHR piping. The remainder of the RHR piping is not modeled because of break exclusion due to Arbitrary Intermediate Breaks (UFSAR Section 6.2.1.2.3.3). As discussed in UFSAR Section 6.2.1.2.3.5, the large bore lines eliminated by the arbitrary intermediate break leak-before-break (LBB) methodology eliminated the 8-inch, 10-inch, and 12-inch accumulator lines, which include a portion of the RHR lines (i.e., up to the first isolation valve closest to the RCS).

NRC approval of the LBB analysis for the large bore lines is documented in the STP Safety Evaluation Report (SER), Supplement 4, Section 3.6, Protection Against Dynamic Effects Associated with the Postulated Rupture of Piping. In the SER, the NRC concluded that the dynamic effects of large ruptures in the accumulator piping at STP could be excluded as a design basis. Since the accumulator lines are excluded, there is no impact.

3.8 Post-LOCA Long-Term Cooling and Subcriticality and Hot Leg Switchover Time The post-LOCA analysis models the contribution of the accumulators in the subcriticality analysis and boric acid precipitation control analysis. Boron precipitation in the reactor vessel is prevented by a backflush of cooling water through the core to reduce boil-off and the resulting increase in concentration of boric acid in the water remaining in the reactor vessel. This is accomplished by initiation of hot leg recirculation at about 5.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> following a LOCA (UFSAR 6.3.2.5).

The minimum accumulator cover gas pressure is not used in the post-LOCA long term cooling (LTC) analysis of record, and therefore, it is not impacted by the reduction in the minimum accumulator cover gas pressure. The LTC analysis of record includes post-LOCA decay heat removal along with subcriticality checks and boric acid precipitation control calculations to determine the time that hot leg recirculation should be initiated to mitigate the concern for boric acid precipitation in the reactor vessel. As such, post-LOCA subcriticality, decay heat removal and hot leg recirculation are not impacted by the reduction in the minimum accumulator cover gas pressure.

3.9 MSLB Hot Zero Power Departure from Nucleate Boiling (DNB)

The MSLB analysis is performed to demonstrate that the core remains in place and intact assuming a stuck Rod Cluster Control Assembly (RCCA), with or without offsite power, and assuming a single failure in the SI System.

With regard to DNB, conditions at either hot full power or hot zero power may be limiting. A cycle-specific evaluation is performed as part of the fuel reload process and the results are documented in the reload safety evaluation. The major rupture of a steam line is the most limiting cooldown transient and, thus, is analyzed at zero power.

Although DNB and possible clad perforation following a steam pipe rupture are not necessarily unacceptable, the analyses of record show that no departure from nucleate boiling occurs for any rupture, assuming the most reactive RCCA is stuck in its fully withdrawn position (UFSAR Section 15.1.5.4).

An evaluation of the MSLB analyses was performed to address the reduction in the Technical Specification minimum accumulator cover gas pressure from 590 psig to 500 psig. The results showed that the RCS pressure remains higher than that which would allow accumulator injection. Therefore, the reduced accumulator pressure will not adversely impact the steamline break analyses of record. Consequently, the assumptions and results of the radiological dose analyses are not impacted.

Enclosure NOC-AE-20003734 Page 10 of 15 3.10 Other Non-LOCA Transients The analyses for non-LOCA transients discussed in UFSAR Sections 15.1-15.5 are not impacted by lowering the minimum accumulator pressure to 500 psig. These analyses are not mitigated by accumulator injection and RCS pressure remains above 600 psig during these transients. Consequently, the assumptions and results of the radiological analyses (qualitative or quantitative) are not impacted by this change.

3.11 Nitrogen Gas Accumulation In the proposed configuration with lower minimum accumulator pressures, the LHSI/RHR header will be allowed to pressurize to approximately 500 psig to 536 psig. The new pressure boundary relative to the accumulator will become check valve SI-0030A. STP considered the following gas void scenarios to support the evaluation for the proposed amendment:

1) Gas which can come out of solution in the LHSI/RHR discharge header during LOCA depressurization before the LHSI pump starts. Specifically, this is the volume of piping downstream of check valve SI-0030A to the accumulator tee check valve RH-0032A (Volume A).

2) Gas which can come out of solution upstream of check valve SI-0030A when the system is in stand-by. Specifically, this is the volume of piping upstream of check valve SI-0030A which includes the LHSI pump, discharge, and suction piping (Volume B).

3) Gas which can come out of solution when the RHR system is depressurized. This scenario is for situations where the RHR system is used for normal plant cooldown, post-accident cooldown, and RHR inservice surveillance testing. Specifically, this applies to the volume of piping in RHR loop A upstream of check valve RH-0065A and in the 4-inch minimum-flow line that connects to the LHSI/RHR common header downstream of the RHR heat exchanger (Volume C) as well as a large portion of Volume A.

Gas could come out of solution in Volume A during a LOCA depressurization event before the LHSI pump is in operation due to timing of the SI signal, emergency diesel generator start, and Engineered Safety Feature bus sequencing delays. In this case, all of the gas may not come completely out of solution, it would coalesce into larger voids, and it is likely that some of the gas phase will be homogenous or stratified with the liquid phase as flow starts in the header. If larger voids formed in this configuration, the resulting pressure waves would likely be dissipated into the RCS. Given that the injection check valves will be open, there would be no closed downstream pressure boundary to support gas compression events such as water hammer.

In SBLOCA scenarios, it is anticipated the LHSI/RHR header will remain filled with water until RCS pressure drops below 536 psig. At this point, voiding could start to occur but the LHSI pump will already be in operation. For the SBLOCA, the time-rate-of-change on RCS pressure, and therefore RHR/LHSI header pressure, is more gradual than it would be for LBLOCA. In contrast to the pump-start case described above, for the SBLOCA, the flow into the RHR/LHSI header will be gradual when the LHSI pump shut-off pressure is reached. No delays in safety injection are expected due to the small gas void size that could develop while the system is depressurizing.

Although no leakage is anticipated across check valve SI-0030A, a void could develop while the system is in standby because LHSI system pressure upstream of SI-0030A is at RWST pressure (Volume B). Should an SI signal be actuated, the LHSI pump will start and could cause a rapid void compression in that portion of the system if RCS pressure remains high.

Based on the piping arrangement, any potential void upstream of check valve SI-0030A will

Enclosure NOC-AE-20003734 Page 11 of 15 likely remain in the adjacent pump discharge piping and not migrate to the lower elevation LHSI pump suction. Additionally, as a result of the proximity to the LHSI pump, the potential water inertia for gas compression would be minimized.

As stated above, in the proposed configuration the new pressure boundary relative to the accumulator will become check valve SI-0030A. STP will use the Gas Accumulation Management Program to document this boundary check valve and establish a monitoring plan. Ultrasonic Testing will be employed to ensure that any potential gas intrusion remains less than the volume that would challenge the ability of the system to perform its design functions. This includes quantifying any gas volume at this location and comparing it to the pre-established acceptance criteria or removing the gas using static or dynamic venting.

The principle concern with respect to Volume C containing nitrogen gas saturated liquid would occur during RHR operation, either during a plant cooldown or surveillance testing.

During initiation of RHR cooldown, the expected system pressure would be approximately 300 psia, and the maximum possible gas release during depressurization to this pressure is expected to remain small. For surveillance testing, the RHR system is operated using the minimum-flow line as a closed loop. During testing, depressurization to approximately 35 psia is expected.

The presence of gas accumulation in the RHR system during RHR pump start events leads to two distinct potential situations:

1) A gas void size large enough that void compression causes inertial deceleration of the accelerating water column. This yields an oscillating pressure response but no propagating water hammer event.

2) A gas void size small enough that the accelerating water column impacts the fluid on the other side of the void. This situation leads to propagating water hammer pressures, the magnitude of which are dictated by the velocity of the approaching columns at impact.

The gas void size at which the transition between inertial and water hammer response occurs can be estimated based on treating the gas bubble as an isentropic compression spring mass operating on the approaching water column. This approach suggests several possible void sizes depending on the system pressure; however, only minor peak water hammer pressures are expected. These results suggest that the impacts of gas accumulation in the RHR system would be expected to be benign and unlikely to challenge relief valve actuation or impart significant forces on the piping and supports.

3.12 Conclusions The proposed amendment will not affect the design basis for the accumulators as described in the UFSAR. There are no changes to the UFSAR Chapter 15 safety analyses or assumptions regarding the accumulators. The proposed one-time change reducing the allowed minimum Unit 1 accumulator pressures does not adversely affect the design basis of the plant. The proposed change will have no significant impact on the capability of the Unit 1 accumulators to perform their design basis function.

4 REGULATORY EVALUATION 4.1 Applicable Regulatory Requirements/Criteria With the implementation of the proposed change, STP Unit 1 would continue to meet applicable design criteria. The accumulator size, water volume, and nitrogen cover gas pressure are designed such that a minimum of two accumulators delivering to two unaffected

Enclosure NOC-AE-20003734 Page 12 of 15 loops, and one HHSI and one LHSI pump delivering to an unaffected loop, will assure adequate core cooling in the event of a design basis LOCA.

The accumulators are part of the ECCS, therefore compliance with 10 CFR 50.46 must be assessed and maintained considering the impact of this proposed amendment.

STP evaluated the impact of the proposed amendment on the requirements of 10 CFR 50.46 with regard to the ability of the ECCS to mitigate the consequences of a spectrum of LOCAs as well as on the environmental qualifications of impacted equipment.

The Technical Specification 3.5.1 requirements ensure that the following acceptance criteria established for the ECCS by 10 CFR 50.46 will be met following a LOCA:

1) Maximum fuel element cladding temperature is less than or equal to 2200°F;

2) Maximum cladding oxidation is less than or equal to 0.17 times the total cladding thickness before oxidation;

3) Maximum hydrogen generation from a zirconium water reaction is less than or equal to 0.01 times the hypothetical amount that would be generated if all of the metal in the cladding cylinders surrounding the fuel, excluding the cladding surrounding the plenum volume, were to react, and;

4) Core is maintained in a coolable geometry.

5) Long-term cooling is maintained.

The results of STPs technical evaluation, summarized in Section 3, show that the proposed amendment will not significantly impact the capabilities of the ECCS following a LOCA and the 10 CFR 50.46 acceptance criteria would continue to be met.

STP Unit 1 will remain within the scope of the Technical Specification LCOs and would continue to comply with the requirements of the Action statements as governed by 10 CFR 50.36. The proposed amendment would allow STP to resolve the emergent valve leakage issue while maintaining all three SI accumulators operable and having no significant adverse impact on the RHR or LHSI systems.

STP also evaluated the impact of the proposed amendment on the applicable General Design Criteria (GDC) related to the ECCS.

STP evaluated the impact of the proposed amendment on GDC 4 as it relates to dynamic effects associated with flow instabilities and loads (e.g. water hammer).The proposed amendment does not significantly impact the ability of the ECCS to accommodate the effects of the environmental conditions associated with normal operation, maintenance, testing and postulated accident conditions including consideration of the dynamic effects of flow instabilities and the loadings caused by water hammer events. STP has design features and operating procedures designed to prevent damaging water hammer due to such mechanisms as voided discharge lines and water entrainment in steam lines. The requirements of GDC 4 would continue to be met, providing assurance that dynamic effects of events such as flow instabilities and water hammer will not adversely affect the fundamental integrity and capability of the ECCS systems to provide core cooling in the event of accidents.

STP evaluated the impact of the proposed amendment on GDC 27 as it relates to the system design having the capability to ensure the core is maintained cool under postulated accident conditions. The proposed amendment does not significantly impact the ability of the ECCS to actuate and provide rapid injection of borated water to ensure reactor shutdown and

Enclosure NOC-AE-20003734 Page 13 of 15 adequate core cooling. The requirements of GDC 27 would continue to be met, ensuring that the ECCS is able to provide a means to safely shutdown the core and maintain it in a coolable geometry under postulated accident conditions.

STP evaluated the impact of the proposed amendment on GDC 35 as it relates to the ECCS being designed to provide an abundance of core cooling to transfer heat from the core at a rate so that fuel and clad damage will not interfere with continued effective core cooling. The proposed amendment does not significantly impact the ability of the ECCS to remain capable of cooling the core in the event of a failure of any single active component during the short-term immediately following an accident, or a single active or passive failure during the long-term recirculation cooling phase following an accident. The requirements of GDC 35 would continue to be met, ensuring that the ECCS, assuming a single failure, can provide core cooling under accident conditions sufficient to maintain the core in a coolable geometry and the production of hydrogen due to reaction of water with the fuel cladding is minimized.

4.2 No Significant Hazards Consideration Determination Analysis The proposed change would modify the South Texas Project (STP) Nuclear Operating Company (STPNOC) Technical Specifications by adding a footnote to Technical Specification Surveillance Requirement 4.5.1.1.a.1 to reduce the minimum allowed nitrogen cover-pressure for STP Unit 1 Safety Injection Accumulators for the remainder of STP Unit 1 Cycle 23. The change is necessary to address an emergent plant condition.

STPNOC has evaluated whether a significant hazards consideration is involved with the proposed amendment by focusing on the three standards set forth in 10 CFR 50.92, "Issuance of amendment," as discussed below:

1) Does the proposed amendment involve a significant increase in the probability or consequences of an accident previously evaluated?

Response: No.

The proposed change reducing the lower pressure limit for the accumulators does not affect the design basis of the plant - this change will have no significant impact on the capability of the accumulators to perform their design basis function. The overall protection system performance will remain within the bounds of the accident analyses documented in Chapter 15 of the STP Updated Final Safety Analysis Report (UFSAR).

The change does not affect other structures, systems and components of the plant or change plant operations, design functions or analysis that verifies design functions. The accumulators are not a precursor to any accident previously evaluated. The change results in an insignificant increase in the consequences of the safety analyses and STP Unit 1 will remain within licensing basis limits. The accumulators will continue to function in a manner consistent with safety analyses assumptions and the plant design basis.

There will be no degradation in the performance of, or an increase in the number of challenges to, equipment assumed to function during any postulated accident.

Therefore, the proposed change does not involve a significant increase in the probability or consequences of an accident previously evaluated.

2) Does the proposed amendment create the possibility of a new or different kind of accident from any accident previously evaluated?

Response: No.

The proposed change does not involve a physical alteration to the plant or a change in the methods governing normal plant operation - no new or different type of equipment

Enclosure NOC-AE-20003734 Page 14 of 15 will be installed. The proposed change does not adversely affect the design function or operation of any structures, systems, or components important to safety. No new accident scenarios, transient precursors, failure mechanisms, or limiting single failures are introduced because of the proposed change. Safety systems continue to function in the same manner and there is no reliance on additional systems or procedures. The accumulators are passive components that are not accident initiators. Lowering the accumulator pressure would not create a new or different kind of accident. The malfunction of safety-related equipment, assumed to be operable in the accident analyses, would not result from the proposed change. No new failure mode has been created and no new equipment performance burdens are imposed.

Therefore, the proposed change does not create the possibility of a new or different kind of accident from any accident previously evaluated.

3) Does the proposed amendment involve a significant reduction in a margin of safety?

Response: No.

The proposed change affects the margins related to Peak Clad Temperature, Containment Peak Pressure, and Containment Equipment Qualification Peak Pressure.

The analysis of these parameters determined that the margins to the design basis and safety limits were slightly reduced, however the design bases and safety limits were not impacted. The performance of the accumulators remains within design basis limits and the accident analyses safety limits.

Therefore, the proposed change does not involve a significant reduction in a margin of safety.

Based on the above, STPNOC concludes that the proposed amendment does not involve a 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.

4.3 Conclusions In conclusion, 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 ENVIRONMENTAL CONSIDERATIONS 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 a significant increase in the amounts of any effluents that may be released offsite, or (iii) a significant increase in individual or cumulative occupational radiation exposure. Accordingly, the proposed amendment meets the eligibility 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.

Enclosure NOC-AE-20003734 Page 15 of 15 6 REFERENCES 6.1 South Texas Project Updated Final Safety Analysis Report, Revision 20 6.2 NUREG-0781, "Safety Evaluation Report Related to the Operation of South Texas Project, Units 1 and 2," Appendix G, Safety Evaluation for the Elimination of Arbitrary Intermediate Pipe Breaks, April 1986 6.3 NUREG-0781, Safety Evaluation Report Related to the Operation of South Texas Project, Units 1 and 2, Supplement No. 4, Section 3.6, Protection Against Dynamic Effects Associated with the Postulated Rupture of Piping, July 1987 6.4 WCAP-12055-P-A, Rev. 2, The 1981 Version of the Westinghouse ECCS Evaluation Model Using the BASH Code, March 1987 6.5 WCAP-12066-P-A, Rev. 2, Addendum 3-A Rev. 1, Incorporation of the LOCBART Transient Extension Method in to the 1981 Westinghouse Large Break LOCA Evaluation Model with BASH (BASH-EM), October 2007 6.6 10 CFR 50.46, Acceptance criteria for emergency core cooling systems for light-water nuclear power reactors 6.7 10 CFR 50 Appendix A, General Design Criterion 4, Environmental and dynamic effects design bases 6.8 10 CFR 50 Appendix A, General Design Criterion 27, Combined reactivity control systems capability 6.9 10 CFR 50 Appendix A, General Design Criterion 35, Emergency core cooling

Enclosure NOC-AE-20003734 Attachment 1 Attachment 1 Technical Specification Page Markup

3/4.5 EMERGENCY CORE COOLING SYSTEMS 3/4.5.1 ACCUMULATORS LIMITING CONDITION FOR OPERATION 3.5.1 Each Safety Injection System accumulator shall be OPERABLE APPLICABILITY: MODES 1 and 2 MODE 3 with pressurizer pressure > 1000 psig ACTION:

a. With one accumulator inoperable, except as a result of boron concentration outside the required limits, within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> restore the inoperable accumulator to OPERABLE status or apply the requirements of the CRMP, or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and reduce pressurizer pressure to less than 1000 psig within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

b. With more than one accumulator inoperable, except as a result boron concentration outside the required limits, within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> restore at least two accumulators to OPERABLE status or apply the requirements of the GRMP, or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and reduce pressurizer pressure to less than 1000 psig within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

c. With the boron concentration of one accumulator outside the required limit, within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> restore the boron concentration to within the required limits or apply the requirements of the CRMP, or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and reduce pressurizer pressure to less than 1000 psig within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

d. With the boron concentrations of more than one accumulator outside the required limit, within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> restore the boron concentration of at least two accumulators to within the required limits or apply the requirements of the CRMP, or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and reduce pressurizer pressure to less than 1000 psig within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

SURVEILLANCE REQUIREMENTS 4.5.1.1 Each accumulator shall be demonstrated OPERABLE:

a. At a frequency in accordance with the Surveillance Frequency Control Program by:

1) Verifying the contained borated water volume is 8800 gallons and 9100 gallons and nitrogen cover-pressure is 590 psig1 and 670 psig, and

2) Verifying that each accumulator isolation valve is open.

b. At a frequency in accordance with the Surveillance Frequency Control Program and within 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />s* after each solution volume increase of greater than or equal to 1% of tank volume that is not the result of addition from the RWST by verifying the boron concentration of the accumulator solution is 2700 ppm and 3000 ppm, and

c. At a frequency in accordance with the Surveillance Frequency Control Program when the RCS pressure is above 1000 psig by verifying that power to the isolation valve operator is removed.

• The 6 hr. SR is only required to be performed for affected accumulators.

1 For Unit 1 only, the nitrogen cover-pressure is verified to be 500 psig for the remainder of Unit 1 Cycle 23.

SOUTH TEXAS - UNITS 1 & 2 3/4 5-1 Unit 1 Amendment No. 51,54,59,135 179 188 Unit 2 Amendment No. 40.43.47,124 166 175

Enclosure NOC-AE-20003734 Attachment 2 Attachment 2 Retyped Technical Specification Page

3/4.5 EMERGENCY CORE COOLING SYSTEMS 3/4.5.1 ACCUMULATORS LIMITING CONDITION FOR OPERATION 3.5.1 Each Safety Injection System accumulator shall be OPERABLE APPLICABILITY: MODES 1 and 2 MODE 3 with pressurizer pressure > 1000 psig ACTION:

a. With one accumulator inoperable, except as a result of boron concentration outside the required limits, within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> restore the inoperable accumulator to OPERABLE status or apply the requirements of the CRMP, or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and reduce pressurizer pressure to less than 1000 psig within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

b. With more than one accumulator inoperable, except as a result boron concentration outside the required limits, within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> restore at least two accumulators to OPERABLE status or apply the requirements of the GRMP, or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and reduce pressurizer pressure to less than 1000 psig within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

c. With the boron concentration of one accumulator outside the required limit, within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> restore the boron concentration to within the required limits or apply the requirements of the CRMP, or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and reduce pressurizer pressure to less than 1000 psig within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

d. With the boron concentrations of more than one accumulator outside the required limit, within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> restore the boron concentration of at least two accumulators to within the required limits or apply the requirements of the CRMP, or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and reduce pressurizer pressure to less than 1000 psig within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

SURVEILLANCE REQUIREMENTS 4.5.1.1 Each accumulator shall be demonstrated OPERABLE:

a. At a frequency in accordance with the Surveillance Frequency Control Program by:

1) Verifying the contained borated water volume is 8800 gallons and 9100 gallons and nitrogen cover-pressure is 590 psig1 and 670 psig, and

2) Verifying that each accumulator isolation valve is open.

b. At a frequency in accordance with the Surveillance Frequency Control Program and within 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />s*

after each solution volume increase of greater than or equal to 1% of tank volume that is not the result of addition from the RWST by verifying the boron concentration of the accumulator solution is 2700 ppm and 3000 ppm, and

c. At a frequency in accordance with the Surveillance Frequency Control Program when the RCS pressure is above 1000 psig by verifying that power to the isolation valve operator is removed.

• The 6 hr. SR is only required to be performed for affected accumulators.

1 For Unit 1 only, the nitrogen cover-pressure is verified to be 500 psig for the remainder of Unit 1 Cycle 23.

SOUTH TEXAS - UNITS 1 & 2 3/4 5-1 Unit 1 Amendment No. 51,54,59,135 179 188 Unit 2 Amendment No. 40.43.47,124 166 175