ML051660179

Supplement to Request for a License Amendment to Support Replacement of Steam Generators and Uprated Power Operations in Plants and Associated Administrative Changes for Unit 2

ML051660179
Person / Time
Site:	Palo Verde
Issue date:	06/03/2005
From:	Mauldin D Arizona Public Service Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
102-05287-CDM/TNW/RAB
Download: ML051660179 (34)

Text

1AAS 10 CFR 50.90 Palo Verde Nuclear Generating Station David Mauldin Vice President Nuclear Engineering and Support Tel: 623-393-5553 Fax: 623-393-6077 Mail Station 7605 PO Box 52034 Phoenix, Arizona 85072-2034 102-05287-CDM/TNW/RAB June 3, 2005 ATTN: Document Control Desk U. S. Nuclear Regulatory Commission Washington, DC 20555-0001

References:

1. Letter No. 102-05116-CDM/TNW/RAB, dated July 9, 2004, from C. D.

Mauldin, APS, to U. S. Nuclear Regulatory Commission, "Request for a License Amendment to Support Replacement of Steam Generators and Uprated Power Operations in Units 1 and 3, and Associated Administrative Changes for Unit 2"

2. Technical Manual for the CENTS Code, CENPD-282-P-A, Revision 1, dated April 2004.

3. Letter No. 102-04641-CDM/RAB, dated December 21, 2001, from C.

D. Mauldin, APS to U. S. Nuclear Regulatory Commission, "Request for a License Amendment to Support Replacement of Steam Generators and Uprated Power Operations" for Unit 2

4. Letter dated from B. M. Pham, USNRC, to G. R. Overbeck, "Palo Verde Nuclear Generating Station, Unit 2 (PVNGS-2) - Issuance of Amendment on Replacement of Steam Generators and Uprated Power Operations (TAC NO. MB3696)

Subject:

Palo Verde Nuclear Generating station (PVNGS)

Units I and 3, Docket Nos. STN 50-528 and STN 50-530 Supplement to Request for a License Amendment to Support Replacement of Steam Generators and Uprated Power Operations in Units I and 3 and Associated Administrative Changes for Unit 2 This letter supplements and revises information provided in Reference 1, Attachment 4.

The information provided in this submittal consists of two parts:

1. Changes in the results of the events that were described in Section 6.3 of of Reference 1 as a result of an error discovered in CENTS code input (Enclosure 2).

2. Replacement information for Section 6.3.6.3.3 of Attachment 4 of Reference"1 to reflect the revised Steam Generator Tube Rupture with Loss of Offsite Power A member of the STARS (Strategic Teaming and Resource Sharing) Alliance Callaway

• Comanche Peak

• Diablo Canyon

• Palo Verde

• South Texas Project

• Wolf Creek

U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Supplement to Request for a License Amendment to Support Replacement of Steam Generators and Uprated Power Operations In Units 1 and 3 and Associated Administrative Changes for Unit 2 Page 2 (SGTRLOP) analysis that corrected the error in CENTS code input (Item 1 above), and the CENTS output that is used as the criterion for steam generator fill (Enclosure 3).

In the process of verifying the PVNGS input basedeck for Reference 2, an error in the input value for the secondary (shell) side volume of the Replacement Steam Generators (RSGs) was discovered. This error necessitated a review of safety analyses prepared in support of PVNGS Units 1 and 3 Power Uprate Licensing Report (PURLR)

(Reference 1) in addition to the impact review on the current operating units. During this review, a deficiency in the criterion based on a specific CENTS code output that is used for determining steam generator fill was also discovered. These two issues required a reanalysis of the Steam Generator Tube Rupture with Loss of Offsite Power (SGTRLOP) event.

The first issue was the discrepancy in secondary (shell) side volume of the RSG between the as-designed and as-built dimensions. The safety analyses that were prepared in support of Reference 3, and subsequently verified to be applicable to the request for licensing amendment for PUR of PVNGS Units 1 and 3 (Reference 1),

utilized as-designed RSG dimensions. Following the as-designed configuration, some minor internals were modified in the RSGs resulting in approximately a 2% reduction in the secondary side volume of the steam generators. For all of the events with the exception of SGTRLOP event, the impact of this change on safety analyses was determined to be insignificant and not affecting the conclusions presented in References 1 and 3. However, APS concluded that, although the magnitude of this error does not affect the conclusions, it slightly changes the reported results for some accident analyses that are sensitive to the RSG volume, and is providing the updated information to the NRC for the safety evaluation of the amendment requested in Reference 1. The detailed discussion of the investigated events and the changes to results are presented in Enclosure 2 of this submittal. For the SGTRLOP event, however, the conclusions drawn in Section 6.3.6.3.3 of Attachment 4 to Reference 1 and Attachment 6 to Reference 3 were found to be invalidated by the RSG volume error, requiring a revision to the analysis.

The second issue was discovered during the review and re-analysis of the SGTRLOP event for the error described in the previous paragraph. This discrepancy involved a specific CENTS output that is tracked for determining the remaining steam space in steam generators. APS discovered that the CENTS output which indicates the remaining steam space in the generator included a portion of main steam lines, namely the section from the steam generator nozzles to the main steam isolation valves (MSIV).

Thus, when the output indicated that there was still a steam space left in the steam generators, the steam generators may already have been filled, and some liquid inventory may have spilled into the main steam lines. As a result of the evaluation of

U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Supplement to Request for a License Amendment to Support Replacement of Steam Generators and Uprated Power Operations In Units 1 and 3 and Associated Administrative Changes for Unit 2 Page 3 this discovery, the SGTRLOP event was found to result in steam generators being overfilled, independent of the RSG volume error described earlier, contrary to the conclusions drawn in Section 6.3.6.3.3 of Attachment 4 to Reference 1 and Attachment 6 to Reference 3. Therefore, the SGTRLOP event analysis was revised to correct both errors. A detailed description of the revised SGTRLOP event analysis and the information to replace Section 6.3.6.3.3 of Reference 1 are provided in Enclosure 3.

No commitments are being made to the NRC by this letter Should you have any questions, please contact Mr. Thomas N. Weber at (623) 393-5764.

Sincerely CDM/TNW/RAB

Enclosures:

1. Notarized Affidavit

2. Evaluation of the Error Identified in the RSG Shell Side Volume Calculations and the Results of the Review of Safety Analyses Performed in Support of PVNGS Power Uprate

3. Reasons for, and the Results of, the Revised Postulated Steam Generator Tube Rupture with Loss of Offsite Power (SGTRLOP) Event Analysis

Attachment:

Revisions to Reference 1, Attachment 4, Section 6.3.6.3.3 cc:

B. S. Mallet NRC Region IV Regional Administrator M. B. Fields NRC NRR Project Manager G. G. Warnick NRC Senior Resident Inspector for PVNGS A. V. Godwin Arizona Radiation Regulatory Agency (ARRA)

STATE OF ARIZONA

)

) ss.

COUNTY OF MARICOPA )

1, David Mauldin, represent that I am Vice President Nuclear Engineering and Support, Arizona Public Service Company (APS), that the foregoing document has been signed by me on behalf of APS with full authority to do so, and that to the best of my knowledge and belief, the statements made therein are true and correct.

David Mauldin Sworn To Before Me This '31a' Day Of.

. 2005.

C)

Notary olic L

SUSIE LYNN ERGISH Notary Public - Arizona O,,

Marlopa County

/ y Comm.

Expre Jul 14.2007 Notary Commission Stamp

ENCLOSURE 2 Evaluation of the Error Identified in the RSG Shell Side Volume Calculations and the Results of the Review of Safety Analyses Performed in Support of PVNGS Power Uprate.

This enclosure describes the evaluation of the error identified in RSG shell side volume calculations and the results of the review of safety analyses performed in support of PVNGS Power Uprate.

1.0

==

Introduction:==

The safety analyses prepared in support of PVNGS Unit 2 Power Uprate Licensing Report (PURLR), Attachment 6 to Reference 3, and subsequently verified to be applicable to the request for a license amendment in Reference 1, utilized as-designed RSG dimensions. During fabrication, the as-designed configuration for some internal components was modified in the Unit 2 RSGs, which are essentially identical to the RSGs for Units 1 and 3. These changes resulted in approximately 2% reduction (9808 ft3 vs. 10021 ft3) in the secondary (shell) side volume of the RSGs. In general, the volume reduction occurring in steam region of the steam generators results in compression of steam more quickly, thus affecting the rate of pressurization and level changes in the secondary system. On the other hand, the volume reduction in the liquid region results in less liquid inventory available for primary-to-secondary heat transfer, and thus causes a change in the pressure response for both primary and secondary systems. However, the impact of a 2% or less reduction on shell side volume is insignificant considering the volume calculations are performed under "cold" conditions, and the thermal expansion of steam generators under NOP/NOT conditions would totally or partially compensate the error. Nevertheless, the reported results for the events that are sensitive to the initial steam generator inventory would be slightly affected if it is conservatively assumed that thermal expansion does not take place.

Therefore, the accident analyses were reviewed to determine the changes on reported values in Attachment 4, Section 6.3 of Reference 1 and Attachment 6, Section 6.3 of Reference 3.

2. 0 Review and Results:

The review of the Chapter 15 Safety Analyses presented in Section 6.3 of Attachment 4 of Reference 1 and Attachment 6 of Reference 3 can be categorized into two groups based on their sensitivity to the initial and transient steam generator inventory. For the events that are not sensitive to the initial steam generator secondary side volume, the volume reduction does not affect the results. For the events that are sensitive to the initial steam generator inventory, a reduction in the steam generator volume may result in either adverse or benign consequences. For the Increased Heat Removal by the Secondary System events that are sensitive to the initial steam generator inventory, such as Main Steam Line Break events, the reduction in steam generator volume results in benign consequences since the reduced secondary system inventory causes less cooldown in the RCS. Thus, the reported values for those events are bounding.

The Decreased Heat Removal by the Secondary System events, and the CEA Ejection I

event that is analyzed for the RCS Peak Pressure, are also sensitive to the initial steam generator volume in both liquid and steam region for the reasons given in the previous section. Therefore, the events were evaluated with the corrected steam generator volumes to determine the dominant effect. Table 1 presents the results for the limiting Loss of Condenser Vacuum (LOCV) and Small Feedwater Line Break (SFWLB) events.

The CEA Ejection event that was presented in References 1 and 3 assumed a lower initial inventory in the steam generators than that allowed by the plant protection system, thus the results that were provided previously are bounding.

TABLE 1.

RSG Differential Volume Evaluation Results Original Results Corrected Results Peak Time of Peak Time of Acceptance Description Pressure Peak Pressure Peak Criterion (psia)

Pressure (psia)

Pressure (psia)

(sec)

(sec)

LOCV RCS 2739 9.61 2740.5 9.63 2750 Pressure LOCV SG 1389 14.2 1388.5 13.9 1397 Pressure SFWLB RCS 2706 21.48 2707.4 21.03 2750 Pressure The FWLB, LOCV, and CEA Ejection events also establish the basis for Technical Specification 3.7.1, Main Steam Safety Valves, which limits the power level based on operable MSSVs. The evaluation performed for maximum allowable power with one or more MSSV inoperable showed that allowable power levels listed in TS Table 3.7.1-1 are still valid.

Steam Generator Tube Rupture (SGTR) events were also reviewed because of the impact of the change in the initial steam generator level for both dose and SG overfill consequences. The SGTR with LOP and a single failure of an Atmospheric Dump Valve (ADV) sticking open (SGTRLOPSF) event is the limiting SGTR event with respect to dose consequences. However, because of the reviewed and approved operator actions, such as maintaining level in the affected steam generator, the SGTRLOPSF event results are not adversely impacted. Impact on the limiting SGTR event for the steam generator overfill (SGTRLOP) is determined to be adverse since the magnitude 2

of this error would have caused enough reduction in steam space volume in the steam generator dome to invalidate the safety analysis. In addition, during the evaluation of the SGTRLOP event, it was discovered that a deficiency in the specific CENTS code output that is used as the criterion for determining steam generator fill existed.

Therefore, the SGTRLOP event was reanalyzed with respect to steam generator overfill, using the correct steam generator volume and corrected steam space indication. The new analysis is presented in Enclosure 3.

3.0

==

Conclusion:==

The error discovered in the RSG shell side volume (2% reduction from the originally calculated design value) does not affect the conclusions drawn in PVNGS PUR submittal (Reference 1) with the exception of SGTRLOP event which is reanalyzed. The error results in minor adverse changes in the reported results for RCS peak pressure for the Increased Heat Removal by the Secondary System events, however, no event exceeds the acceptance criteria. Other events are either not sensitive to the error on steam generator secondary side volume, or the previously reported values bound the change due to the error.

3

ENCLOSURE 3 Reasons for, and the Results of, the Revised Postulated Steam Generator Tube Rupture with Loss of Offsite Power (SGTRLOP) Event Analysis This enclosure describes the reasons for, and the results of, the revised postulated Steam Generator Tube Rupture with Loss of Offsite Power (SGTRLOP) event analysis.

1.0 Introduction APS has analyzed the SGTRLOP event to address UFSAR Chapter 15, Accident Analyses licensing basis acceptance criterion for steam generator overfill to demonstrate that the liquid inventory of the steam generator does not spill into the main steam lines, thus preventing the failure of main steam lines with respect to the concerns described in Generic Letter 89-19. The SGTRLOP event was analyzed for PVNGS operation at 3990 MWt Rated Thermal Power with RSGs in support of the PVNGS Unit 2 PUR licensing amendment request (Reference 3). Subsequently, that analysis was evaluated and found to be applicable for Units 1 and 3 PUR with RSG as reported in Reference 1. The analysis demonstrated that the steam generators would not overfill during the SGTRLOP event.

During an internal review of the safety analyses described in Attachment 4 of Reference 1 to address the impact of the error in steam generator shell side volume (see ), APS engineers also discovered a deficiency in the criterion that is used for determining the steam generator overfill. This deficiency involved a specific CENTS output that is tracked for determining the remaining steam space in the steam generators. It was found that the CENTS output that lists the remaining steam space in the generator included the portion of the main steam lines from the steam generator nozzles to the main steam isolation valves (MSIVs). Thus, when the output indicated that there is still a steam space left in the steam generators, the steam generators would have already been filled, and some liquid would have spilled into the main steam lines. As a result of this discovery and the error in the RSG shell side volume, the SGTRLOP event was determined to result in steam generators being filled, invalidating conclusions drawn in References 1 and 3. Therefore, the SGTRLOP event analysis was revised.

The revised analysis verifies that the steam generators do not overfill, and prevention of the failure of main steam lines continues to be satisfied for operation at 3990 MWt with RSGs. The reanalysis of the SGTRLOP event is described in the following sections in detail.

2.0 Evaluation The revised SGTRLOP analysis utilized current approved methodology. The analysis corrected the criterion for determining steam generator overfill. The steam generator shell side volume was also corrected with respect to the error described in Enclosure 2.

In addition, several changes were made to the input parameters and operator actions in the revised SGTRLOP event analysis. These changes involve corrections to input parameters for identified errors, removal of discretionary conservatism from input parameters, incorporation of changes to the plant procedures and design documents.

I Also, some operator action timings are changed as a result of the changes noted above, since the SGTR events credit approved operator actions whose timings are based on applicable criteria and symptoms as described in the Emergency Operating Procedure (EOP) guidelines.

The analytical changes were evaluated in accordance with 10 CFR 50.59, and were determined to not require NRC staff review and approval. The changes were determined to be not "adverse" as defined in NEI 96-07, Revision 1, Guidelines for 10 CFR 50.59 Implementation. However, the transient simulation and input and assumptions of the event that were presented in Section 6.3.6.3.3 of Reference 1 (which noted that no change to the previously reviewed and approved analysis of Reference 3) are impacted, and necessitated this supplement to Reference 1. The following subsections describe the changes made to Section 6.3.6.3.3 of Reference 1 due to the revised analysis. Attachment 1 presents the replacement and added pages for Reference 1. Tables and Figures are numbered to correspond to those provide in Reference 3.

2.1 RCS Cooldown Rate The revised analysis assumes a faster cooldown rate than the original analysis. A faster cooldown rate during the earlier phase of the mitigation is the key contributor to successful and timely primary-to-secondary leak isolation. Fundamentally, higher cooldown rates result in higher Subcooling Margin (SCM) which allows for a greater primary pressure reduction and hence zeroing out of the leak by faster equalization of the primary and secondary system pressures. The following differences in different phases of the simulation are noted:

• Start of the cooldown to the isolation of the affected SG - The revised analysis assumed a 990F/hr cooldown rate vs. 800F/hr assumed in the original analysis.

• SG isolation to the shutdown cooling (SDC) entry conditions - The revised analysis simulated a cooldown rate of 59.90F/hr during the first hour, 740F/hr in the next hour and the overall average rate of 31.6 0F/hr for entire phase. For the similar periods, the original analysis simulated cooldown rates of - 41 'F/hr during the first hour, 480F/hr, for the next hour, and the overall average rate of 300F/hr.

The cooldown rates utilized in the revised analysis are consistent with Technical Specification 3.4.3, RCS Pressure and Temperature (P/T) Limits, and credible operator actions based on the instructions provided in SGTR EOP and SGTR EOP technical guidelines.

2.2 Hot Leg Temperature Criterion for Steam Generator Isolation The revised analysis changed the hot leg temperature criterion for SG isolation to 5300 F from 5150F that was used in the original analysis. The original analysis selected a conservative temperature compared to the temperature specified in the EOP. This change in the revised analysis was made to simulate conditions which may aggravate 2

SG overfill while maintaining sufficient conservatisms with respect to EOP value of 5400F.

2.3 Instrumentation Uncertainty for Subcooling Margin The revised analysis modified the timing of change in the containment conditions from normal to harsh affecting the instrumentation uncertainty on temperature measurement that is used by the operators to maintain the subcooling margin (SCM). The original analysis conservatively invoked a harsh containment condition at 50 minutes into the event which resulted in large instrumentation uncertainty for the temperature used for SCM criterion very early into the event. In essence, this resulted in inhibiting the necessary primary pressure reduction required to equalize primary and secondary pressures and thereby isolate the primary-to-secondary leak. The revised analysis used normal instrumentation uncertainty for the first 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> into the event changing to the harsh conditions afterwards. This was based on the justification that, for the same magnitude of steaming conditions, containment conditions would not become harsh before 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> into the event. By using normal containment conditions and associated instrumentation uncertainty for temperature used for SCM criterion for that duration, the primary-to-secondary leak was isolated much earlier in the revised analysis than the original analysis. This, in turn, resulted in less secondary system inventory thus in benign consequences with respect to SG overfill.

2.4 Initial Core Inlet Temperature Change in initial core inlet temperature from 5680F to 5660F reflects the maximum allowed temperature (plus uncertainties) by the Technical Specification 3.4.1 as approved for PVNGS Unit 2 PUR Amendment #149 (Reference 4). The original analysis was prepared in anticipation of a higher allowable value which was later decreased in the final submittal of the Technical Specification amendment request leading to Amendment #149. The revised analysis changed the initial core inlet temperature simply to match the proposed T.S. 3.4.1 for PVNGS Units 1 and 3, and approved T.S. 3.4.1 for PVNGS Unit 2.

3.0 Conclusion The revised analysis verified that the steam generators do not overfill during a SGTRLOP event, and prevention of failure of main steam lines continues to be satisfied for operation at 3990 MWt with RSGs. Changes affecting Attachment 4, Section 6.3.6.3.3 of Reference 1 are provided in the Attachment to this Enclosure. Tables and Figures are numbered to correspond to those provide in Reference 3.

3

Attachment Revisions to Attachment 4 of Letter No. 102-05116 from APS to USNRC, Dated July 9, 2004

Section 6.3.6.3.3 Steam Generator Tube Rupture with a Loss of Offsite Power Section 6.3.6.3.3.1 Identification of Causes and Event Description As described in UFSAR Section 15.6.3, this transient is similar to that described in the previous section for SGTRLOP single failure with the exception of an ADV remaining open. It assumes that the plant is challenged by a SGTR. The radioactivity from the leaking SG tube mixes with the shell-side water in the affected SG. Before turbine trip, the radioactivity is transported through the turbine to the condenser where the noncondensable radioactive materials would be released via the condenser air removal pumps. Following reactor/turbine trip, the MSSVs open to control the main steam system pressure. The operator can isolate the damaged SG any time after reactor trip occurs. As a result of the LOP which occurs due to the grid instability following the turbine trip, electrical power would be unavailable. The plant would experience a loss of the following:

turbine load,

• normal FW flow,

• forced RCS flow, and

• condenser.

With the SBCS unavailable, NSSS cooldown is accomplished by use of AFW flow and ADVs. Heat removal must be accomplished by natural circulation, resulting in a higher core outlet temperature for much of the transient. The higher core outlet temperature as well as steaming to the atmosphere via use of ADV, contributes to higher offsite doses.

In addition, the affected SG may start filling up due to primary-to-secondary leakage, and secondary liquid inventory may spill into the main steam lines challenging the integrity of the main steam lines. The SGTRLOPSF, that is presented in the previous section, bounds the dose consequences of the SGTRLOP, however the SGTRLOP is the most limiting SGTR event with respect to the SG overfill. Thus, the SGTRLOP event is analyzed in order to confirm that the SG does not experience an overfill condition. The most limiting SGTRLOP event is for a leak flow equivalent to a double-ended rupture of a U-tube at full power conditions.

Section 6.3.6.3.3.2 Acceptance Criteria The acceptance criteria for SGTR events are defined in SRP Section 15.6.3. In addition, the SGTR events should not result in SG overfill.

Section 6.3.6.3.3.3 Description of Analysis The NSSS response to a SGTRLOP event is simulated using the CENTS code.

The input parameters and initial conditions are biased to aggravate SG overfill conditions.

Page 6-34

Section 6.3.6.3.3.3. Transient Simulation The system is initialized at 102% power using the most limiting initial parameters. At time equal zero, the SGTR is simulated by a break at the bottom of the tube sheet at the hot leg side. This causes the pressurizer level and pressure to decrease, letdown flow to go to minimum and the third charging pump to start. Pressurizer level reaches the low pressure level heater cut-off which de-energizes all heaters thus accelerating the primary depressurization. The CPC reactor trip occurs on approach to hot leg saturation, with a turbine trip following within one second of the reactor trip signal. A LOP occurs due to grid instability three seconds after turbine trip.

After reactor trip, stored and fission product decay heat energy must be removed by the RCS and main steam systems. In the absence of forced RCS flow, convective heat transfer out of the reactor core is supported by natural circulation. Initially, the water inventory in the SGs is used to cool down the RCS with the resultant steam released to atmosphere via the MSSVs and ADVs.

The EOPs contain instructions to help the operator manage the cooldown following a SGTR event. Accordingly, the required operator actions to mitigate the effects of the SGTR event, and bring the plant to SCS entry conditions have been simulated based on the EOP guidance and operator feedback. The timing of the operator actions in the model are based on ANS/ANSI-N58.8-1984 which specifies response times for safety related operator actions. The input parameters and initial conditions are biased to aggravate SG overfill conditions.

The major post-trip EOP analysis assumptions regarding operator actions are the following:

1. Preclude challenge to MSSVs.

The analysis assumes operator action to open the ADVs (on both SGs) to preclude a direct challenge to the MSSVs two minutes after the reactor trip. The ADVs are used due to the unavailability of the SBCS due to LOP.

2. Diagnose the event and stabilize the plant.

EOP procedures are oriented towards quickly diagnosing the event and stabilizing the RCS at a temperature that precludes a challenge to the MSSVs. The analysis assumes this diagnosis and stabilization period will take about 21.5 minutes; that is consistent with ANSI/ANS standards for this category of event. Within this period, the operator is assumed to use the ADVs (on both SGs) and the AFW system to maintain the post trip Tcold.

Page 6-34a

3. Cooldown the RCS before isolation of affected SG.

After the 21.5 minute diagnosis and stabilization period, the operators are assumed to cool the RCS at approximately maximum Technical Specification cooldown rate of 1 000F/hr. The cooldown continues via the ADVs on both SGs until the affected Thot reaches the isolation temperature per requirements of the EOPs. A conservatively lower temperature is assumed in the analysis in order to delay isolation of the affected SG. Additionally, during this period, AFW would be delivered to each SG as needed in order to maintain the level in both SGs per the requirements in the EOPs.

4. Manual MSIS.

During the cooldown phase, the operator is assumed to initiate a manual MSIS per EOP guidelines due to LOP.

5. Isolate the affected SG.

The operator is assumed to isolate the affected SG after the affected loop temperature has reached the isolation temperature of 530'F. This isolation criterion is conservative with respect to the EOP guidelines of 5400F. During the cooldown phase, primary pressure is reduced with the aid of the pressurizer head vent which may eventually result in harsh containment conditions. A SCM including the applicable instrumentation uncertainty based on the containment condition is used.

6. Cooldown the RCS.

The analysis assumes that post isolation of the affected SG, cooldown to SCS entry is conducted via feeding and steaming the unaffected SG. The affected SG level begins to approach fill condition. Primary pressure is reduced by throttling HPSI as necessary and use of pressurizer head vents. After the leak is reduced, primary to secondary pressure differential is minimized to less than 50 psid to facilitate leak isolation and to ensure that the reverse leak is kept to a minimum.

The natural circulation cooling with the unaffected loop is maintained less than 320F/hr until the entry conditions for SCS is reached at 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.

7. Maintain adequate RCS inventory, HPSI throttle criteria.

Besides maintaining adequate subcooling, the EOPs require the operator to assure adequate RCS inventory, specifically, to retain minimum specified levels in the pressurizer and the upper head prior to throttling back the HPSI flow. Accordingly, the pressurizer level in the analysis is maintained above the level required by the EOPs.

Section 6.3.6.3.3.4 Input Parameters, Initial Conditions, and Assumptions There are no changes to this section.

Page 6-34b

Table 6.3-51 Parameters Used for SGTRLOP Event for 3990 Mwt PARAMETER Value Initial Core Power (% of rated) 102 Initial Core Inlet Temp (OF) 566 Initial Pressurizer Pressure (psia) 2325 Initial RCS Flow (% of design) 95 Initial Pressurizer Water Level (ft) 21.85 Initial SG Water Level (ft) 25.7 MTC (x104 Ap/°F)

-4.0 FTC Least negative Kinetics minimum 13 CEA Worth at Trip-WRSO (%Ap)

- 8.0 Hot spot gap conductance (Btu/hr-ft2-OF) 518 Plugged SG Tubes 0

SGTR Break Location at the tube sheet Single Failure none LOP yes Section 6.3.6.3.3.5 Results Table 6.3-52 presents a sequence of events for the simulation of the SGTRLOP event.

The representative behaviors of NSSS parameters of significance are presented in the Figures provided in this Attachment.

Page 6-34c

Table 6.3-52 Sequence of Events for the SGTRLOP Event - 3990 Mwt Time (sec)

Event Value 0

SGTR occurs.

43 Letdown control valve reduced to the minimum value (gpm).

78 Backup pressurizer heaters energized (psia).

2275 346 Third charging pump turned on.

414.5 Pressurizer heaters de-energized on low level in 25 the pressurizer (%).

792 Reactor trip reached on CPC hot leg saturation 792

__margin reached (OF).8 793 Trip breakers open.

793.6 Scram CEAs begin falling.

794 MSSVs open (psia).

1227 796 LOP occurs.

801 SG water level reaches AFAS analytical setpoint in 20 unaffected SG (%WR).

811 Pressurizer pressure reaches SIAS setpoint (psia).

1837 811 SIAS generated, safety injection flow initiated.

812 Pressurizer empties.

838 Voids begin to form in the upper head.

847 AFW initiated to unaffected SG (gpm).

650 SG water level reaches AFAS analytical setpoint in 20%

affected SG (%WR).

_________AFW initiated to affected SG (gpm).

859 MSSVs close (psia).

1104 896 Voids collapsed in the upper head.

912 Operator opens one ADV in each SG to prevent cycling of safeties.

921 Pressurizer begins to refill.

Operator takes manual control of the AFW system 1032 and feeds each SG at the rate of 325 gpm and stabilizes the plant.

2081 Operator initiates plant cooldown at the rate of 100

°F/hr, by adjusting the ADVs and using one 650 auxiliary feed water pump per SG (gpm).

2202 Operator opens pressurizer head vents.

Page 6-34d

Time (sec)

Event Value 2324 Operator initiates a manual MSIS.

Operator reduces ADV flow to slow cooldown rate.

2575 Operator throttles back HPSI flow to maintain RCS inventory control.

4252 Operator isolates the affected SG, at the analytical 530 affected loop temperature (OF).

Affected SG dome temperature exceeds affected 5570 loop Thot temperature; eliminates leak flashing in the affected SG.

7488 Onset of reverse heat transfer in the affected loop:

Tcold greater than the loop That.

9442 Operator opens the first unaffected SG ADV full open.

12689 Leak Isolated. Operator action maintains RCS 50 pressure to affected SG AP minimum (psid).

14710 Operator increase AFW to 160 gpm in the 160 unaffected SG (gpm).

25864 SDC entry conditions reached in the unaffected Lessthan 25864

~

loop (psia/ 0F7).3935 25864 Minimum steam space left in the affected SG (ft3) 957 at SDC entry conditions 28800 Operator activates SDC system.

8 hrs 28800 Minimum steam space left in the affected SG (ft3) 426 Section 6.3.6.3.3.6 Conclusions For the SGTRLOP event all acceptance criteria are met. Affected SG does not fill up during the event thus the integrity of the main steam lines are not challenged. Dose consequences at the EAB and LPZ boundaries remain bounded by that documented for the SGTRLOPSF event Page 6-34c

Figure 6.3-224 SGTRLOP Event-Core Power vs. Time (Sheet 3 of 3) 120 100 80 IC e-r-;1 60 40 20 0

0 5760 11520 17280 23040 28800 TIME, seconds Page 6-34f

Figure 6.3-225 SGTRLOP Event-RCS Pressure vs. Time (Sheet 3 of 3) 2400

.I.II.t

.I.

2000 1600-1200 400-400 0

5760 11520 17280 23040 28800 TIIIE, seconds Page 6-34g

Figure 6.3-226 SGTRLOP Event-Affected Loop Coolant Temperatures vs. Time (replaces Sheet 3 of 6) 660 550 ILScd IC0:

P4 I'b

=2 c;

ct 440 330 220 110 0

0 5760 11520 17280 TMllIE, seconds 23040 28800 Page 6-34h

Figure 6.3-226 SGTRLOP Event-Unaffected Loop Coolant Temperatures vs. Time (replaces Sheet 6 of 6) 660 T

ot Tavg 550

-Tin-if 220

\\

110 0

0 5760

,1520 9!

17280 2310 1

2,,! 800 0

5760 11520 17280 23040 28800 TINEl, seconds Page 6-34i

Figure 6.3-227 SGTRLOP Event-Pressurizer Liquid Volume vs. Time (Sheet 3 of 3) 1800 1500

-E or e-LD

D 1200 900 600 300 0

0 5760 11520 17280 TIAM1E, seconds 23040 28800 Page 6-34j

Figure 6.3-229 SGTRLOP Event-RCS Liquid (Sheet 2 of 2)

Mass vs. Time 1000 900 800 E

+:E 0

V) 4-I C

C; 700 9

9**9

• 9.1,9,,.,9 19 1

w

• 9' 9' I 999 I,,,,,,

600 500 400 0

5760 11520 17280 TIME, seconds 23040 28800 Page 6-34k

Figure 6.3-230 SGTRLOP Event-SG Pressure vs. Time (Sheet 3 of 3) 1500 1250

.5 VL I.,

in 1000 750 500 250 0

0 5760 11520 17280 23040 28800 TIME, seconds Page 6-341

Figure 6.3-231 SGTRLOP Event-Tube Leak Rate vs. Time (Sheet 3 of 3) 7 5 60 1

45 30 15-0-

0 5760 11520 17280 23040 28800 TIME, seconds Page 6-34m

Figure 6.3-232 SGTRLOP Event-integrated Tube Leak vs. Time (Sheet 3 of 3) 1500 I

1250 2e 1000 750 U

500-250 0

576010 17......2 0

5760 1 1520 17280 M3M4 29n TINME, seconds Page 6-34n

Figure 6.3-234 SGTRLOP Event-SG Liquid Inventory vs. Time (Sheet 3 of 3) 624 520 E

0 VI 416 312 208 104 0

0 5760 11520 17280 TIME, seconds 23040 28800 Page 6-34o

Figure 6.3-235 SGTRLOP Event-integrated SI Flow vs. Time (Sheet 2 of 2) 1500 1250 E

M CI 1000 750 500 250 0

0 5760 11520 17280 23040 28800 TMlTl, seconds Page 6-34p

Figure 6.3-238 SGTRLOP Event-Integrated ADV Flow vs. Time (Sheet 2 of 2) 1500 1250 E

0 zn 1000 750 500 250 0

0 5760 11520 17280 23D40 28800 TBIE, seconds Page 6-34q

Figure 6.3-239 SGTRLOP Event-Subcooled Margin vs. Time (Sheet 2 of 2) 120 I

100

~

80 60 04 20 0

5760 11520 17280 23040 28800 TIME, seconds Page 6-34r

Figure 6.3-240 SGTRLOP Event-Integrated AFW Flow vs. Time 1500 1250 E

+

C 91:

1000 750 AFFEiCITD S5

/~

/

//

/

.,,,,1,.,,,,,,,1,,,,.1 Soo 250 0

0 5760 11520 17280 23040 28800 TIME, seconds Page 6-34s

Section 6.3.6.4 Radioloqical Consequences of Main Steam Line Failure Outside Containment (BWR)

As described in UFSAR Section 15.6.4, this event is applicable to BWRs only.

Section 6.3.6.5 Loss-of-Coolant Accidents ECCS performance and LOCA are discussed in Section 6.1. Radiological consequences of this event are described in Section 6.4.6.3.

Section 6.3.7 Radioactive Material Release from a Subsystem or Component This section is contained in Reference 6-1, Attachment 6. There are no changes to this section.

Page 6-34t