ML11326A070

License Amendment Request 11-06 Revision to Technical Specification 3.3.5, Loss of Power (LOP) Diesel Generator (DG) Start Instrumentation

ML11326A070
Person / Time
Site:	Diablo Canyon
Issue date:	10/24/2011
From:	Becker J Pacific Gas & Electric Co
To:	Office of Nuclear Reactor Regulation, Document Control Desk
References
OL-DPR-80, OL-DPR-82 LAR 11-06
Download: ML11326A070 (93)

Text

{{#Wiki_filter:Pacific Gas and Electric Company- James R.Becker Diablo Canyon Power Plant Site Vice President Mail Code 104/5/601 P 0. Box 56 Avila Beach, CA 93424 805.545.3462 October 24, 2011 Internal: 691.3462 Fax: 805.545.6445 PG&E Letter DCL-1 1-072 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk 10 CFR 50.90 Washington, D.C. 20555-0001 Diablo Canyon Units 1 and 2 Docket No. 50-275, OL-DPR-80 Docket No. 50-323, OL-DPR-82 License Amendment Request 11-06 Revision to Technical Specification 3.3.5, "Loss of Power (LOP) Diesel Generator (DG) Start Instrumentation"

Reference:

1. PG&E letter DCL-10-1 15, "Licensee Event Report 1-2010-002-02, Potential Loss of Safety-Related Pumps due to Degraded Voltage During Postulated Accidents," dated September 24, 2010.

Dear Commissioners and Staff:

Pursuant to 10 CFR 50.90, Pacific Gas and Electric Company (PG&E) hereby requests approval of the enclosed proposed amendment to Facility Operating License Nos. DPR-80 and DPR-82 for Units 1 and 2 of the Diablo Canyon Power Plant (DCPP) respectively. The enclosed license amendment request (LAR) proposes to revise Technical Specification (TS) 3.3.5, "Loss of Power (LOP) Diesel Generator (DG) Start Instrumentation," revise Final Safety Analysis Report Update (FSARU) Appendix 6.2D and Sections 6.3, 15.3, and 15.4, revise the loss-of-coolant accident (LOCA) control room operator and offsite dose analysis of record described in the FSARU, and provide a new process for revising input values to this analysis. The current TS 3.3.5.3.a Surveillance Requirement (SR) contains loss of voltage Load Shed Allowable Values (AV) that are nonconservative during postulated sustained degraded grid voltage conditions. The changes proposed in this LAR correct the nonconservative first level undervoltage relays (FLUR) TS limits contained in the current TS SR 3.3.5.3. The DCPP Units 1 and 2 safety analyses of record have been evaluated for engineered safety feature (ESF) component actuation time delay that bounds the maximum second level undervoltage relay (SLUR) time delay, and have been determined to remain within the DCPP licensing basis acceptance criteria. The proposed amendment would revise the FSARU to increase ESF component delay times described in the FSARU accident analyses to bound the current maximum SLUR actuation. The proposed amendment would revise the analysis of record for the LOCA control room operator and offsite dose calculations described in the FSARU. The proposed amendment revises inputs to \ A member of the STARS (Strategic Teaming and Resource Sharing) Alliance 0 ý, Callaway

• Comanche Peak
• Diablo Canyon
• Palo Verde
• San Onofre - South Texas Project
• Wolf Creek I

Document Control Desk PG&E Letter DCL-1 1-072 October 24, 2011 Page 2 the LOCA control room operator and offsite doses and does not increase the limiting total control room operator or offsite doses. The proposed amendment would provide a new process for revising input values for the LOCA control room operator and offsite dose analysis. PG&E requests approval of this LAR no later than October 24, 2012. PG&E requests the license amendment(s) be made effective upon NRC issuance, to be implemented during Unit 2 Refueling Outage 17 and Unit 1 Refueling Outage 18. PG&E is making regulatory commitments (as defined by NEI 99-04) in this letter. of the Enclosure summarizes the regulatory commitments made in this letter. This letter includes no revisions to existing regulatory commitments. This letter satisfies a commitment in Reference 1, "PG&E will submit a license amendment request to establish conservative TS SR 3.3.5.3 undervoltage relays settings." In accordance with 10 CFR 50.91, PG&E is notifying the State of California of this LAR by transmitting a copy of this letter and enclosures to the designated State Official. If you have any questions or require additional information, please contact Mr. Tom Baldwin at 805-545-4720. I state under penalty of perjury that the foregoing is true and correct. Executed on October 24, 2011. Since ely, James R. Becker Site Vice President dngd/4955/50353334

Enclosure:

Evaluation of the Proposed Change cc: Diablo Distribution cc/enc: Gary W. Butner, Branch Chief, California Dept of Public Health Elmo E. Collins, NRC Region IV Michael S. Peck, NRC, Senior Resident Inspector James T. Polickoski, NRR Project Manager Alan B. Wang, NRR Project Manager A member of the STARS (Strategic Teaming and Resource Sharing) Alliance Callaway - Comanche Peak - Diablo Canyon - Palo Verde . San Onofre - South Texas Project

• Wolf Creek

Enclosure PG&E Letter DCL-1 1-072 Evaluation of the Proposed Change License Amendment Request 11-06 Revision to Technical Specification 3.3.5, "Loss of Power (LOP) Diesel Generator (DG) Start Instrumentation"

1.

SUMMARY

DESCRIPTION

2. DETAILED DESCRIPTION

3. TECHNICAL EVALUATION 3.1 SR 3.3.5.3 Design Basis 3.2 Evaluation of Impact of SLUR Time Delay on Accident Analysis 3.3 Evaluation of Impact of SLUR Time Delay on LOCA Dose Analysis

4. REGULATORY EVALUATION 4.1 Applicable Regulatory Requirements/Criteria 4.2 Precedent 4.3 Significant Hazards Consideration 4.4 Conclusions

5. ENVIRONMENTAL CONSIDERATION

6. REFERENCES ATTACHMENTS:

1. Proposed Technical Specification Changes (marked-up)

2. Proposed Technical Specification Changes (retyped)

3. Changes to Technical Specification Bases Pages (For Information Only)

4. ,FSARU Markups

5. Commitments

6. PG&E Calculation 357S-DC

7. PG&E Calculation STA-195

Enclosure PG&E Letter DCL-1 1-072 EVALUATION

1.

SUMMARY

DESCRIPTION This letter is a request to amend Operating Licenses DPR-80 and DPR-82 for Units 1 and 2 of the Diablo Canyon Power Plant (DCPP), respectively. The proposed changes would revise the Operating Licenses to revise the Technical Specification (TS) 3.3.5, "Loss of Power (LOP) Diesel Generator (DG) Start Instrumentation." Additionally, the proposed changes would revise the DCPP Units 1 and 2 safety analyses of record to increase the engineered safety feature (ESF) component actuation time delay such that it bounds the maximum second level undervoltage relay (SLUR) time delay. The proposed amendment would revise the analysis of record for the loss-of-coolant accident (LOCA) control room operator and offsite dose analysis described in the Final Safety Analysis Report Update (FSARU). The proposed amendment revises inputs to the LOCA control room operator and offsite doses and does not increase the total limiting control room operator or offsite doses. The proposed amendment would provide a new process for revising input values for the LOCA control room operator and offsite dose analysis. The changes proposed in this license amendment request (LAR) correct the nonconservative first level undervoltage relays (FLUR) TS limits contained in the current TS 3.3.5.3 Surveillance Requirement (SR). The proposed amendments would revise the FSARU to increase ESF component delay times used in the FSARU accident analyses to bound the current maximum SLUR actuation time delay. The NRC provided requirements of the second level of voltage protection for the onsite power system in Reference 1. The changes specified in this LAR are being made to comply with the conditions set forth below:

          "We require that a second level of voltage protection for the onsite power system be provided and that this second level of voltage protection shall satisfy the following requirements...
          "c) The time delay selection shall be based on the following conditions:

(i) The allowable time delay, including margin, shall not exceed the maximum time delay that is assumed in the FSAR accident analyses... (iii) The allowable time duration of a degraded voltage condition at all distribution system levels shall not result in failure of safety systems or components;" 1

Enclosure PG&E Letter DCL-1 1-072 PG&E described its design and how it met these conditions in Reference 2. NUREG-0675 Supplement No. 9, Section 8.1, "Low and or Degraded Grid Voltage Condition", summarized the NRC requirements described in References 1 and 2. The current TS 3.3.5.3 SR contains FLUR TS limits that are nonconservative for protection of ESF components during postulated sustained degraded grid voltage conditions in that some ESF equipment could trip on overcurrent and not be able to restart without operator action (Reference 3). The changes proposed in this LAR correct the nonconservative FLUR TS limits contained in the current TS 3.3.5.3 SR. The change involves the use of three discrete voltage/time delay relays, which allows for independent control of the loss of voltage setpoints. The DCPP Units 1 and 2 safety analyses of record have been evaluated for ESF component actuation time delay that bounds the maximum SLUR time delay, and have been determined to remain within the DCPP licensing basis acceptance criteria. The proposed amendment would also revise the FSARU to increase ESF component delay times described in the FSARU accident analyses to bound the current maximum SLUR actuation time. The proposed amendment would revise the analysis of record for the LOCA control room operator and offsite dose analysis described in the FSARU to increase the assumed containment spray delay time and to increase the assumed time for closure of the control room normal air intake dampers. Additionally, the proposed revision to the control room operator and offsite dose analysis includes more conservative inputs for the containment spray iodine removal rate, control room normal air inflow rate, control room unfiltered infiltration rate, and distance to the Low Population Zone (LPZ) boundary. The proposed amendment would also provide a new process for revising input values for the LOCA control room operator and offsite dose analysis. The implementation plan for the FLUR TS 3.3.5.3.a changes involves new relays and a new relay panel in each 4kV vital bus. To ensure effective planning for this complex change, PG&E will need approval at least three months prior to the start of the implementing refueling outage. Assuming NRC approval by October 21, 2012, the next refueling outage is Unit 2 Refueling Outage 17; starting on February 3, 2013.

2. DETAILED DESCRIPTION Proposed Amendment The following changes are proposed to the TS SR 3.3.5.3:

SR 3.3.5.3.a is revised from:

a. Loss of voltage Diesel Start Allowable Value __0 V with a time delay of ___ 0.8 2

Enclosure PG&E Letter DCL-1 1-072 seconds and __2583 V with a < 10 second time delay. Loss of voltage initiation of load shed with one relay Allowable Value > 0 V with a time delay of *< 4 seconds and >_2583 V with a time delay < 25 seconds and with one relay Allowable Value _ 2870 V, instantaneous. To:

a. Loss of voltage Diesel Start Allowable Value > 0 V with a time delay of_< 0.8 seconds and > 2583 V with a < 10 second time delay.

Loss of voltage initiation of load shed with- relay Allowable Values of: __3328 V for __l_0 sec __3120 V for ___6 sec _Ž2704 V for _<4 sec And one relay Allowable Value of:

       >3411 V, instantaneous The changes to SR 3.3.5.3 involve a change to a TS Allowable Value (AV) setpoint. The control of TS setpoints is addressed in Technical Specifications Task Force (TSTF) Traveler TSTF-493, Revision 4, "Clarify Application of Setpoint Methodology for limiting safety system settings (LSSS) Functions,"

dated January 5, 2010, (ML100060064) and the associated errata "Transmittal of TSTF-493, Revision 4, Errata," dated April 23, 2010, (ML101160026). For TSTF-493, Revision 4, Option A, in which the setpoint values are retained in the TS, the LOP DG Start Instrumentation TS 3.3.5 does not contain any TS changes. TSTF-493, Revision 4, Option A, contains a change to the TS Bases for SR 3.3.5.3 for the LOP DG Start Instrumentation TS 3.3.5. The change to the TS Bases for SR 3.3.5.3 adds the sentence "There is a plant specific program which verifies that the instrument channel functions as required by verifying the as-left and as-found setting are consistent with those established by the setpoint methodology". This revision to the TS Bases for SR 3.3.5.3 is included in this LAR. The TS and TS Bases changes for other TS to address application of setpoint methodology will be made in a separate future LAR for TSTF-493. The proposed change would revise FSARU Sections 6.3.3.7, Tables 6.3-7, 6.2D-1, 6.2D-1 3, 6.2D-1 5, 6.2D-1 7, 6.2D-21, and Appendix 6.2D to state that the Emergency Core Cooling System (ECCS) loss of offsite power (LOOP) flow delay times were evaluated for an increased delay time from 27 seconds to 42 seconds in order to bound the maximum allowable SLUR time delay. The proposed change would revise the LOOP delay time discussed in FSARU 3

Enclosure PG&E Letter DCL-1 1-072 Sections 15.3.1,15.3.6, 15.4.1, and 15.4.10 and FSARU Tables 15.3-1, 15.3-2, 15.4.1-1A, 15.4.1-1 B, 15.4.1-2A, 15.4.1-2B, 1,5.4.1-3A, 15.4.1-3B, 15.4.1-7A, and 15.4.1-7B to state a total safety injection (SI) with LOOP/degraded voltage injection delay time of 42 seconds was evaluated in order to bound the maximum 4.16 kV SLUR actuation time delay. It was determined that the additional ECCS delay due to a 4.16 kV SLUR actuation time delay would have an insignificant effect on the small break loss-of-coolant accident (SBLOCA) thermal hydraulic results. The additional time delay due to 4.16 kV SLUR actuation time delay did lead to an increase in the peak cladding temperature (PCT) penalty for Best Estimate large break loss-of-coolant accident (LBLOCA) that is within the 10 CFR 50.46 acceptance criteria. The proposed amendment would revise the analysis of record for the LOCA control room operator and offsite dose analysis described in the FSARU to bound the maximum potential delays associated with the postulated degraded voltage scenario and include the limiting delays for LOCA initiation to SI signal generation. The proposed increase to the containment leakage doses result from increasing the assumed containment spray delay time from 86.5 seconds to 106 seconds and increasing the assumed times to close the control room normal air intake dampers from 10 seconds for both units to 18 seconds for the unaffected unit and 44.2 seconds for the unit undergoing a LOCA. This revision to the LOCA control room operator and offsite dose analysis uses more conservative inputs for the containment spray iodine removal rate, control room normal air inflow rate, control room unfiltered infiltration rate, and distance to the LPZ boundary. The proposed amendment revises inputs to and does not increase the limiting total control room operator or offsite doses. The proposed amendment would provide a new process for revising input values for the FSARU LOCA control room operator and offsite dose analysis. Plant procedures provide administrative controls for maintaining the recirculation loop leakage input to the total LOCA control room operator and offsite dose analysis in accordance with the TS 5.5.2, "Primary Coolant Sources Outside Containment" Program. Actual measured recirculation loop leakage values are typically much lower than the flow rate limits provided in the FSARU LOCA control room operator and offsite dose analysis. The proposed change would allow for the administratively controlled recirculation loop leakage to be revised to offset changes to other inputs of the control room operator and offsite dose analysis, as long as the total control room operator and offsite dose values are within the applicable 10 CFR 50 Appendix A, GDC 19-1971 and 10 CFR 100 limits. In summary, the FLUR TS limits are revised in TS 3.3.5.3. Additionally, the FSARU is revised to discuss the increased ESF component delay times which bound the maximum SLUR actuation time delay. 4

Enclosure PG&E Letter DCL-1 1-072 TS Bases 3.3.5 is revised to include the proposed changes to the FLUR and to address TSTF-493, Revision 4. The TS Bases changes are included for information only. The proposed TS changes are noted on the marked-up TS page provided in . The proposed retyped TS is provided in Attachment 2. The revised TS Bases is contained for information only in Attachment 3. Existing LOP DG Start Instrumentation The DGs provide a source of emergency power when offsite power is either unavailable or is degraded below a point that would allow safe unit operation. Undervoltage protection will generate an LOP start if a loss of voltage or degraded voltage condition occurs on the 4.16 kV vital bus. There are three LOP start signals, one for each 4.16 kV vital bus. Undervoltage relays are provided on each 4.16 kV Class 1E vital bus for detecting a sustained degraded voltage condition, or a loss of bus voltage. A relay will generate an LOP signal (first level undervoltage type relay setpoint) if the voltage is below equipment protection thresholds for a short time. The DG start relays (one per bus) will generate an LOP signal with AV of equal to or greater than 0 volts with a time delay of equal to or less than 0.8 seconds and equal to or greater than 2583 volts with equal. to or less than a 10 second time delay (Note: This relay is unchanged by this LAR). In addition, the circuit breakers for all loads, except the 4160-480 volt load center transformers, are opened automatically by load shedding relays for first level undervoltage. Each of the vital 4.16 kV buses has a separate pair of load shed sensing FLURs. The relays have a two-out-of-two logic arrangement for each bus to prevent inadvertent tripping of operating loads, either from a, single failure in the potential circuits, or from human error. One relay has an AV of equal to or greater than 2870 volts, instantaneous. The second of the two relays has an inverse time characteristic and AV equal to or greater than 0 V with a time delay of equal to or less than 4 seconds and equal to or greater than 2583 V with a time delay equal to or less than 25 seconds to prevent loss of operating loads during transient voltage dips, and to permit the offsite power sources to pick up the load. Should there be a sustained degraded voltage condition (second level undervoltage), where the voltage of the vital 4.16 kV buses remains at approximately 3785 volts or below, but above the setpoints of the FLUR, the following second level undervoltage actions occur automatically: (1) After an equal to or less than 10-second time delay, the respective DGs will start. (2) After an equal to or less than 20-second time delay, if the undervoltage condition persists, the circuit breakers for all loads to the respective vital 5

Enclosure PG&E Letter DCL-1 1-072 4.16 kV buses, except the 4160-480 volt load center transformer, are opened and sequentially loaded on the DG. Each vital 4.16 kV bus has two SLURs operating with a two-out-of-two logic. Each vital 4.16 kV bus also has two second level undervoltage timers. One timer provides the DG start and the other will initiate load shedding. AV Setpoints The voltage and time delay setpoints protect ESF equipment from loss of function. The allowable time delay, including margin, should not exceed the maximum time delay assumed in the FSARU accident analyses (FSARU Chapter 6 and 15). The selection of these setpoints is such that adequate protection is provided when all sensor and processing time delays are taken into account. The actual nominal setpoint entered into the relays is normally set more conservative than that required by the AV. AVs are specified for each function in the limiting condition for operation (LCO). The nominal setpoints are selected to ensure that the setpoint measured by the surveillance procedure meets the AV if the undervoltage relay is performing as required. If the measured setpoint meets the AV, the undervoltage relay is considered OPERABLE. Operation with a setpoint less conservative than the nominal setpoint, but within the AV, is acceptable provided that operation and testing is consistent with the assumptions of the unit specific setpoint calculation. Each AV specified is more conservative than the analytical limit assumed in the transient and accident analyses in order to account for instrument uncertainties appropriate to the trip function. These uncertainties are defined in DCPP design calculations. The current FLUR TS limits are accepted in NUREG-1 102 for Unit 1 (Reference 4) and NUREG 1132 for Unit 2 (Reference 5). DCPP TS 3.3.5.3 provides a minimum voltage value for the FLUR and SLUR TS limits. PG&E calculation 357S-DC establishes the TS bases, TS minimum voltage and maximum time delay limits and allowable maximum and minimum as-found limits for the FLUR/SLUR calibration acceptance criteria (Reference 6). The current DCPP SBLOCA analysis was accepted in License Amendment 37/36 (Reference 11). The current LBLOCA analysis for Unit 1 was accepted in License Amendment 191 (Reference 12). The current LBLOCA analysis for Unit 2 was accepted in License Amendment 192 (Reference 13). The current loss of coolant accident (LOCA) Mass and Energy and Containment Integrity analyses were reviewed in the initial safety evaluation for the plant operating licenses (Reference 14). The current DCPP LOCA control room operator and offsite dose analysis results are provided in FSARU Table 15.5-63. The DCPP LOCA dose analysis results 6

Enclosure PG&E Letter DCL-1 1-072 were previously reviewed by the NRC in License Amendment 80/79 (Reference 15). PG&E has made changes to the LOCA control room operator and offsite dose analysis that implemented tradeoffs of inputs to maintain total dose at the licensing limits provided in GDC 19-1971 and 10 CFR 100. DCPP has since determined that these changes do not meet the criteria of NEI 96-07 for changes that can be made in accordance with 10 CFR 50.59 without prior NRC approval. NEI 96-07 states that each element of a proposed activity must be screened except in instances where linking elements of an activity is appropriate. If LOCA dose analysis inputs cannot be considered linked elements, then any input change that results in an increase in limiting dose cannot be performed in accordance with 10 CFR 50.59 when the dose analysis results are at the federal limits. See below for a summary of these changes. In 1998, the LOCA control room operator and offsite dose analysis was revised to correct a non conservative assumption for the containment spray delay time. This change resulted in an increase in the containment leakage portions of the calculated control room operator and offsite doses. The recirculation loop leakage dose portions of the control room operator and offsite doses were decreased in order to maintain the total doses at the GDC 19-1971 and 10 CFR 100 limits. In 2004, the LOCA control room operator and offsite dose analysis was revised to increase the allowable closure time of the control room normal air inlet dampers from five seconds to ten seconds. This change resulted in an increase in the containment leakage dose portions of the calculated control room operator and offsite doses. The recirculation loop leakage dose portions were decreased in order to maintain the total doses at the GDC 19-1971 and 10 CFR 100 limits. In 2009, the LOCA control room operator and offsite doses were recalculated to increase the assumed delay for the start of residual heat removal (RHR) pump seal leakage from 23.7 minutes to 24 hours after LOCA initiation. This change resulted in a decrease in the RHR pump seal leakage dose portion of the calculated control room operator and offsite doses. The recirculation loop leakage dose portions were increased in order to maintain the total doses at the GDC 19-1971 and 10 CFR 100 limits. 7

Enclosure PG&E Letter DCL-1 1-072 Purpose for Proposed Amendment This LAR addresses violations received during a Component Design Basis Inspection (CDBI) (Reference 7). The current TS 3.3.5.3 SR contains FLUR TS limits that are nonconservative during postulated non-mechanistic sustained degraded 4.16 kV vital bus voltage conditions. While analyzing the consequences of non-mechanistic scenarios (LOCA and sustained degraded 4.16 kV vital bus voltage) postulated during the CDBI, PG&E concluded both units were in an unanalyzed condition that significantly degraded plant safety, and therefore, reported the condition under 10 CFR 50.72(b)(3)(ii)(B). The postulated condition could have resulted in permanently connected class 1 E pump motors tripping overcurrent relays due to sustained degraded voltage on the startup offsite power source. Given a non-mechanistic voltage degradation condition such that voltage remained above the FLUR setting of equal to or greater than 2583 volts and below the SLU.R setting of equal to or greater than 3785 volts, permanently connected class 1E pump motors would experience this degraded voltage for up to the SLUR time delay relay setting of equal to or less than 20 seconds. Prior to reaching the SLUR time delay setpoint and initiating load transfer to the onsite emergency DGs, operating motors (e.g., auxiliary saltwater pump and component cooling water pumps) could trip on overcurrent. PG&E implemented compensatory measures by changing the FLUR setpoints on the vital buses of both Units 1 and 2, thus protecting safety-related motors from tripping on overcurrent during postulated sustained degraded voltage conditions. Specifically, the FLUR delay time was changed such that load shedding and bus transfer would be initiated prior to time-overcurrent tripping of the individual loads (Reference 3). This LAR establishes conservative TS SR 3.3.5.3.a undervoltage relays settings that will ensure availability of ESF equipment by eliminating the potential for degraded voltage related time-overcurrent trips prior to transfer to the DG. Additionally, during the CDBI it was determined that DCPP did not meet the PG&E commitment that requires that the allowable SLUR time delay, including margin, shall not exceed the maximum time delay that is assumed in the FSARU accident analyses (Reference 1). The existing FSARU Chapters 6 and 15 accident analyses assume that full ECCS injection flow be achieved within 27 seconds after the SI signal is actuated. This includes the time for the DGs to start and reach rated speed, and for all loads to be sequenced. The FSARU analyses are based on a worst-case design basis event concurrent with a loss of offsite power. The effect of the current SLUR time delay setpoint of 20 seconds exceeds the maximum time delay considered in the FSARU accident and LOCA 8

Enclosure PG&E Letter DCL-1 1-072 control room operator and offsite dose analysis assumptions. The SLUR actuation during the postulated sustained degraded voltage conditions and the increase in the ESF delay times represents a malfunction of an structure, system, and component (SSC) with a different result per 10 CFR 50.59 and is being submitted for prior NRC approval. The changes to the LOCA control room operator and offsite dose analysis is considered to be a more than minimal increase in the consequences of an accident previously evaluated in the FSARU per 10 CFR 50.59. The changes proposed in this LAR correct the nonconservative FLU R TS limits contained in the current TS 3.3.5.3 SR. The proposed amendments would revise the FSARU to increase ESF component delay times used in the FSARU accident analyses to bound the current maximum SLUR actuation time delay. The proposed amendment would revise the results for the LOCA control room operator and offsite dose analysis of record described in the FSARU and provides a new process for revising inputs to this analysis.

3. TECHNICAL EVALUATION 3.1 SR 3.3.5.3 Desiqn Basis Revision to FLUR TS SR 3.3.5.3 Limits The load shed sensing FLURs will be replaced. The channel incorporating the time delay will be changed from an inverse time continuous undervoltage function to three discrete voltages and time delays. Figure 1 illustrates the undervoltage protection load shed logic. Figure 2 graphically compares the proposed versus existing setpoint allowable limits. New FLUR TS limits were evaluated in PG&E Design Calculation 357S-DC contained in Attachment 6 to this enclosure.

9

Enclosure PG&E Letter DCL-1 1-072 Figure 1. A block diagram showing the function of each relay and the analytical limits associated with voltage dropout and time delay settings. FLUR Percent of Bus Voltage 27H*T2 (LAnalyticalLimit: 3411 VAC) 82% Load Shed b (Analytical Limit: Ž3328 VAC *10 Sec) 2/2 800/

\ -.2 7H '"T I 1/3A5 75%

LZ(Analytical Limit: 23120 VAC -s 6 Sec) 27H--TIB 65% (Analytical Limit: Ž2704 VAC -* 4 Sec) 27H*T1C

                                                                             - 0%

10

Enclosure PG&E Letter DCL-1 1-072 Figure 2. Graphical comparison of existing and proposed undervoltage setpoint AVs Existing Versus Proposed FLUR Load Shed Limits 100 90 ---.--- Current TS Ch 1 (See Note)

                                                                                                          --- Current TMOD Ch 1 80 (See Note)
                                                                                                   -          Proposed TS Ch 1 70                                 -----------------------------

X

                                                                                                     -----    Current TS Ch2
                              ,n                                                                       -A---  Current TMOD Ch 2 60 U1 50                                                                                               -          Proposed TS Ch 2 0
                                                                                                   -+       - SLUR (No Change)
                                 /

rn4

                               /
                           /                                                                      Note: The existing TS SR 30           i
                         /                                                                        3.3.5.3(a) only defines a
                        /

20 minimum voltage for 4 Sec and 25 Sec. The intermediate points shown 10 / are typical for the actual

                   /                                                                              setpoint response 0            /

0 5 10 Time (Sec) 15 20 25 11

Enclosure PG&E Letter DCL-1 1-072 First Level Undervoltage Load Shed Relays The selection of the FLUR setpoints is based.on the voltage requirements of the ESF loads. The functional safety requirement of the FLURs is to protect ESF equipment from loss of function by initiating the necessary actions required to transfer the safety related buses to the onsite alternating current power sources. The setpoints of the proposed FLUR load shed undervoltage relays, T1A, T1B, Ti C, and T2, have different analytical limits (See Figure 1). T2, which is an instantaneous (i.e. no intentional delay) relay, will continue to function like a permissive for the time delay channel (i.e. T1A, T1 B, and T1C). Load shed will only occur if the bus voltage continues to degrade below the T2 setpoint and further degradation is sensed by T1A, T1B, or T1C undervoltage relays. The three T1 relays are setup in a tiered configuration such that T1A will actuate at the highest voltage but will have the longest time delay of the three, T1 C will have the lowest actuation voltage and the shortest time delay, and T1 B is between the other two. The configuration of three discrete voltage/time delay relays is preferred over a continuous medium inverse voltage time function because it allows for independent control of the loss of voltage setpoint and the coordination with the SLURs. PG&E has analyzed the coordination between motor overcurrent protection settings and the 4.16 kV bus undervoltage protection scheme and verified that the FLUR/SLUR bus undervoltage protection function actuates before individual motor overcurrent protective devices. Thus, a sustained degraded voltage condition will not result in the loss of an ESF function (Reference 8). In order to preclude spurious trips of the offsite power source, the FLUR load shed function will continue to employ a two-out-of-two coincidence logic scheme (i.e., T1A, T1B, T1C plus T2). A PG&E design calculation has analyzed the dynamic response of the immediately available startup offsite power circuit under various accident scenarios and anticipated operational occurrences, including a dual unit trip. This analysis concluded that the preferred power supply has adequate voltage to start and operate the required loads given the proposed setpoints (Reference 9). A PG&E design calculation establishes the TS minimum voltage and maximum time delay limits and allowable maximum and minimum as-found values for the FLUR/SLUR calibration acceptance criteria (Reference 6). The Channel Uncertainty (CU) is calculated as follows: CU =+/-RCA2 + RMTE2 + RD2 + RME2 + RTE2 CU = Channel Uncertainty - The total uncertainty of an instrument channel. This is the minimum allowable difference between the design value and the nominal setpoint value. 12

Enclosure PG&E Letter DCL-1 1-072 RCA = Rack Component or "String" Calibration Accuracy. RMTE = Rack Component or "String" Measuring and Test Equipment Uncertainty. RD = Rack Component or "String" Drift or Stability. RME = Rack Component or "String" Miscellaneous Effects. RTE = Rack Component or "String" Ambient Temperature Effects. The CU is calculated at 95 percent probability of actuation. That means there is a 2.5 percent chance that the relay will actuate below "setpoint - uncertainty" and 2.5 percent chance that the relay will actuate at above "setpoint + uncertainty." Therefore, at the point of concern, which is the lower limit, there is 97.5 percent chance that the relay will actuate above "setpoint - uncertainty." Since the coincident logic for actuation of load shed has to wait until actuation of one of the T1 relays, the lower tail of uncertainty distribution of T1 setpoint will be at 97.5 percent confidence level. The coincident logic is based on the actuation of T1A (Reference 6). The changes to SR 3.3.5.3 involve a change to a TS AV setpoint. The control of TS setpoints is addressed in Technical Specifications Task Force (TSTF) Traveler TSTF-493, Revision 4, "Clarify Application of Setpoint Methodology for LSSS Functions," dated January 5, 2010, (ML100060064) and the associated errata "Transmittal of TSTF-493, Revision 4, Errata," dated April 23, 2010, (ML101160026). The NRC announced the availability of model applications (with model no significant hazards consideration determinations) of the options for plant-specific adoption of TSTF-493, Revision 4, in the Federal Register on May 11, 2010 (FR volume 75, number 90, page 26294). For TSTF-493, Revision 4, Option A, in which the setpoint values are retained in the TS, the LOP DG Start Instrumentation TS 3.3.5 does not contain any TS changes. TSTF-493, Revision 4, Option A, contains a change to the TS Bases for SR 3.3.5.3 for the LOP DG Start Instrumentation TS 3.3.5. The change to the TS Bases for SR 3.3.5.3 adds the sentence "There is a plant specific program which verifies that the instrument channel functions as required by verifying the as-left and as-found setting are consistent with those established by the setpoint methodology." This revision to the TS Bases for SR 3.3.5.3 is included in this LAR. In PG&E Letter DCL-07-002, "License Amendment Request 07-01, Revision to Technical Specifications to Support Steam Generator Replacement," dated January 11, 2007, PG&E made a commitment to the NRC regarding the setpoint methodology. PG&E committed to submit changes related to the setpoint methodology to the NRC once the TSTF-493, "Clarify Application of Setpoint 13

Enclosure PG&E Letter DCL-1 1-072 Methodology for LSSS Functions," is approved by the NRC. The TS and TS Bases changes for other TS to address application of setpoint methodology will be made in a separate future LAR for TSTF-493. The calculation supporting the revised TS SR 3.3.5.3.a limits, 357S-DC, is provided in Attachment 6. The calculation includes the basis for the proposed AV and the limiting acceptable values for the as-found tolerance band and the as-left tolerance band. The acceptable as-found (AAF) values are the larger of the sensor calibration accuracy or the sensor drift plus the sensor measuring and test equipment uncertainty. The acceptable as-left (AAL) values are the larger of the vendor uncertainty or the rack calibration accuracy. The TS setpoints for the FLUR loss of voltage diesel start relays are not changed. For completeness, the TS SR 3.3.5.3 loss of voltage diesel start AV, nominal trip setpoints (NTSP), AAF, and AAL for voltage and time settings are as follows: Relay 27H*B2-27P Low Voltage Diesel Start AV_V1 Greater than or equal to 2583 V (62 percent) AV_T1 Less than or equal to 10 Seconds NTSP_V1 At relay 76.3 V; at bus 2667 V (approximately 64 percent) AAL_V1 At relay +/- 1.48 V; at bus approximately +/- 52 V AAF_V1 At relay +/- 1.53 V; at bus approximately +/- 54 V NTSP T1 4.7 Seconds AAL T1 +/- 0.3 Seconds AAF T1 +/- 0.3 Seconds Relay 27H*B2-27X Loss of Voltage Diesel Start AVV2 Greater than or equal to 0 V (0 percent) AVT2 Less than or equal to 0.8 Seconds NTSPV2 At relay 23.4 V; at bus 818 V (approximately 19.7 percent) AALV2 At relay +/- 0.46 V; at bus approximately +/- 17 V AAFV2 At relay +/- 0.64 V; at bus approximately +/- 22 V NTSP T2 0.65 Seconds AAL T2 +/- 0.05 Seconds AAFT2 +/- 0.05 Seconds Relay 27H*B2-127P Low-Low Voltage Diesel Start is not a TS relay and is not listed here. See Attachment 6. The TS SR 3.3.5.3 loss of voltage initiation of load shed includes one instantaneous load shed relay (27H*T2) that is set at higher voltage with respect to the time delay relays. The instantaneous relay has an AV of 3411 V (82 percent), NTSP of 3448 and higher, an AAL tolerance of +/- 18 V, and AAF 14

Enclosure PG&E Letter DCL-1 1-072 tolerance of +/- 22 V. There are three time delay relays with the following AV, NTSP, AAL, and AAF for voltage and time settings: Relay 27H*T1A Low Voltage Load Shed AV_Vi A Greater than or equal to 3328 V (80 percent) AV_T1A Less than or equal to 10 Seconds NTSP_ViA At relay 96.5 V; at bus 3373 V (approximately 81 percent) AAL_V1A At relay +/- 0.5 V; at bus approximately +/-18 V AAF_ViA At relay +/- 0.62 V; at bus approximately +/- 22 V NTSP T1A 8 Seconds AAL T1A +/- 1 Second AAFT1A +/- 1 Second Relay 27H*T1 B Low-Low Voltage Load Shed AV_Vi B Greater than or equal to 3120 V (75 percent) AV_T 1B Less than or equal to 6 Seconds NTSP_V1B At relay 90.5 V; at bus approximately 3163 V (76 percent) AAL_V 1B At relay +/- 0.5 V; at bus approximately +/- 18 V AAF_V1iB At relay +/- 0.59 V; at bus approximately +/- 21 V NTSP T1B 5 Seconds AALT1B +/- 0.7 Seconds AAFT1B +/- 0.7 Seconds Relay 27H*T1 C Loss of Voltage Load Shed AV VIC Greater than or equal to 2704 V (65 percent) AV TiC Less than or equal to 4 Seconds NTSP ViC At relay 78.6 V; at bus 2747 V (approximately 66 percent) AAL ViC At relay +/- 0.5 V; at bus approximately +/- 18 V AAF ViC At relay +/- 0.54 V; at bus +/- 19 V NTSP TIC 3 Seconds AAL TiC +/- 0.5 Seconds AAFT1C +/- 0.5 Seconds The AV, NTSP, AAL, and AAF values are provided in calculation 357S-DC (Reference 6). At DCPP, setpoints are controlled using a graded approach by following PG&E Inter-Departmental Administrative Procedure (IDAP) CF6.ID1, "Setpoint Control Program," a procedure subject to 10 CFR 50.59. CF6.1D1 requires that electrical setpoints shall be fully documented by a calculation performed using a specified methodology. For DCPP, the Corrective Action Program (CAP) procedure is PG&E Program Directive OM7, "Corrective Action Program," and problems are documented per DCPP IDAP OM7.1D1, "Problem Identification and Resolution." The CAP includes a process to perform a TS operability review, and document as 15

Enclosure PG&E Letter DCL-1 1-072 necessary per DCPP IDAP OM7.1D12, "Operability Determination," and to determine the necessary corrective actions to be taken, including corrective actions to prevent recurrence, per OM7.ID1. An issue is entered as a notification into a computer based tracking program. SR 3.3.5.3 is performed for the SR 3.3.5.3 requirements using surveillance test procedures that are subject to 10 CFR 50.59. The current surveillance test procedures for SR 3.3.5.3, STP M-75F, STP M-75G, and STP M-75H, require that if the as-found data for the setpoints are not within desired, to notify the operations shift foreman and to initiate a notification. The current surveillance test procedures for SR 3.3.5.3 also require that the as-left data shall be within a desired range. The instrument channel cannot be returned to service and declared operable unless the setpoint can be reset to within the as-left setpoint and the evaluation of the channel shows it is functioning as required. In order to ensure control of the setpoints for the proposed changes to TS SR 3.3.5.3 and the TS SR 3.3.5.3 Bases, the 10 CFR 50.59 controlled surveillance test procedures applicable to TS SR 3.3.5.3 will be updated as required as part of implementation of the amendment for each unit. The Actions for the various potential surveillance outcomes will be required as follows: (1) The instrument channel setpoint exceeds the as-left tolerance but is within the as-found tolerance:

• Reset the instrument channel setpoint to within the as-left tolerance;

   " If the instrument channel setpoint cannot be reset to a value that is within the as-left tolerance around the instrument channel setpoint at the completion of the surveillance, if not already inoperable, the instrument channel shall be declared inoperable.

(2) The instrument channel setpoint exceeds the as-found tolerance but is conservative with respect to the TS AV:

   " Reset the instrument channel setpoint to within the as-left tolerance;
   "     If the instrument channel setpoint cannot be reset to a value that is within the as-left tolerance around the instrument channel setpoint at the completion of the surveillance, if not already inoperable, the instrument channel shall be declared inoperable;

• Enter the channel's as-found condition in the CAP for prompt verification that the instrument is functioning as required, and for further evaluation.

Evaluate the channel performance utilizing available information to verify that it is functioning as required before returning the channel to service. 16

Enclosure PG&E Letter DCL-1 1-072 The evaluation .may include an evaluation of magnitude of change per unit time, response of instrument for reset, previous history, etc., to provide confidence that the channel will perform its specified safety function; Document the condition for continued OPERABILITY. (3) The instrument channel setpoint is non-conservative with respect to the TS AV: 0 If not already inoperable, declare the channel inoperable; 0 Reset the instrument channel setpoint to within the as-left tolerance;

• Enter the channel's as-found condition in the CAP for evaluation.

Evaluate the channel performance utilizing available information to verify that it is functioning as required before returning the channel to service. The evaluation may include an evaluation of magnitude of change per unit time, response of instrument for reset, previous history, etc., to provide confidence that the channel will perform its specified safety function. These procedural actions are the minimum actions which the procedures will require and additional actions may be taken. %Theseprocedural actions will apply until procedural actions consistent with a license amendment for TSTF-493, Revision 4, are implemented for all automatic protective devices related to variables having significant safety functions as delineated by 10 CFR 50.36(c)(1)(ii)(A). In addition, the "Equipment Control Guidelines" (ECGs) will be updated as part of implementation of the amendment for each unit to identify the methodologies used to determine the as-found and as-left tolerances. The ECGs are documents controlled under 10 CFR 50.59 and are incorporated into the Final Safety Analysis Report (FSAR) by reference. 3.2 Evaluation of Impact of SLUR Time Delay on Accident Analysis During an NRC CDBI (Reference 7), it was identified that, contrary to license basis requirements summarized in the DCPP SSER 9 Section 8.1, the 230 kV undervoltage relay delay setpoints are not bounded by the current DCPP FSAR accident analyses. SSER 9 states "The allowable time delay, including margin, shall not exceed the maximum time delay that is assumed in the FSAR accident analyses." The plant safety analyses have been evaluated to determine the impact of a longer time delay and determined that the analysis acceptance criteria continues to be met. Postulating a sustained 230 kV degraded voltage results in increasing ESF component delay times beyond what has previously been evaluated. 17

Enclosure PG&E Letter DCL-11-072 Immediately after the successful transfer to the 230 kV offsite power source, the postulation of a non-mechanistic condition is assumed to occur which results in sustained degraded voltage just above the FLUR setpoint and just below the SLUR setpoint. Twenty seconds after the degraded voltage occurs, the 230 kV SLUR actuates and sheds the 4.16 kV electrical loads from the 230 kV System thereby resulting in a LOOP. The emergency diesel generators are already operating at rated speed and connect to the vital 4.16 kV buses and begin to sequence the ESF components onto the appropriate buses. The current DCPP FSAR accident analyses do not model the system response for this scenario and therefore do not bound the ESF component operation times that could occur during this scenario. Consistent with the current safety analysis of record (AOR), the ESF delay evaluations for the postulated sustained undervoltage do not credit any ESF functions to operate until after the SLUR actuation occurs and the diesel generators have loaded onto the 4.16 kV vital buses. As stated in Section 3.1 of this LAR, PG&E has analyzed the coordination between motor overcurrent protection settings and the 4.16 kV bus undervoltage protection scheme and verified that the FLUR/SLUR bus undervoltage protection function actuates before individual motor overcurrent protective devices. Thus, a sustained degraded voltage condition will not result in the loss of an ESF function. The SLUR actuation during the postulated sustained degraded voltage conditions and the increase in the ESF delay times represents a malfunction of an SSC with a different result under 10 CFR 50.59 and is being submitted for prior NRC approval within this LAR. The DCPP Units 1 and 2 safety AOR were evaluated for the increased ESF actuation time delays as listed in Table 1. Table 2 lists all of the DCPP safety analyses and identifies that most of the analyses were not impacted since they do not credit any of these ESF functions for mitigation or are bounding based on assuming a loss of offsite power does not occur. Table 2 also identifies which analyses were not significantly impacted such that the current FSARU analyses remains bounding for the increased ESF delay times. Table 2 identifies that four analyses were evaluated for impact due to the increased ESF delay times, and a summary of these evaluation results has been provided. Consequently, the applicable FSARU sections related to these safety analyses in Appendix 6.2D and Sections 6.3, 15.3, and 15.4 have been updated to reflect the new ESF actuation time delays. 18

Enclosure PG&E Letter DCL-1 1-072 Small Break LOCA The DCPP Units 1 and Unit 2 limiting SBLOCA cases were evaluated for the increased ESF delay time for the auxiliary feed water (AFW) and ECCS injection flow. The core uncovery and PCT for the limiting SBLOCA case occur at 12 to 15 minutes into the event. The slight decrease in ECCS flow due to the 15-second increase in the delay time was determined to be small compared to the total amount of ECCS injection flow that has entered the reactor coolant system (RCS) up to the time of core uncovery. Similarly, the 5-second increase in the AFW actuation time was determined to have a negligible impact on the thermal hydraulic results since the major source of decay heat removal is due to the RCS flow out of the break. Therefore, it was concluded that the increased ECCS and AFW delay times have a negligible impact on the results such that the current SBLOCA 10 CFR 50.46 PCT and core oxidation results remain bounding (Reference 10). Large Break LOCA Both DCPP Units 1 and 2 use a best estimate LBLOCA evaluation methodology for the AOR. The LBLOCA evaluation considered an increase in ECCS injection flow delay time from 27 seconds to 42 seconds. The primary effect of increasing the ECCS delay time is that it can lead to increased duration of fuel heatup periods during the refill and reflood periods. The blowdown remains unaffected since this phase is over before the ECCS injection flow begins. Depending on the break size and the accumulator pressure and volume, the end of the refill and periods and the accumulator injection can vary and create periods with significantly different and/or reduced ECCS injection flow. Because refill ends earlier in cases with larger break sizes, the reflood heatup also begins earlier. With the increased delay time, this can create a period of reduced ECCS injection flow during the beginning of reflood heatup when compared to the' current AOR cases. As a result, the cladding is assumed to go through a period of additional heatup compared to the current cases. This additional heatup period is conservatively assumed to be equal to the time it takes for the delayed ECCS injection flow to compensate for the reduction in initial injection flow water mass compared to the current case. As a result of theincreased ECCS injection flow delay, the fuel rods will experience longer periods of heatup during reflood and this increased temperature is estimated todirectly increase the PCT. In order to quantify this temperature increase, the delay in the end of the refill/reflood periods and the associated heatup rates were calculated. For Unit 1, the evaluation was based on global model runs with an effective break size area greater than the reference transient. These greater break areas will depressurize the RCS faster leading to a more rapid accumulator blowdown and are more likely to result in a delay between the accumulator injection and the start of ECCS injection flow. The cases were selected to evaluate the relative 19

Enclosure PG&E Letter DCL-1 1-072 effects of accumulator volume, accumulator pressure, and break size. The limiting evaluation case for Unit 1 was determined to have a high discharge coefficient (greater effective break size) and minimum accumulator volume which resulted in a faster accumulator blowdown and which created a longer period of reflood with significantly reduced ECCS flow. This evaluation case resulted in a 0 OF penalty for the early Reflood 1 period and an estimated 39 OF penalty for the Reflood 2 period. As shown in Table 3 with these PCT penalties applied to the current 10 CFR 50.46 PCT rackup sheet for Unit 1, the resulting PCT, 1975 IF, still remains well below the 2200 OF limit. Since the Unit 1 AOR oxidation calculations are based on an oxidation transient with a PCT value of 2238 IF, which continues to bound the Unit 1 PCT results, the AOR maximum local oxidation and core-wide oxidation calculations are not impacted and remain valid. Unit 2 uses the newer ASTRUM best estimate LBLOCA methodology, which does not track the individual Reflood 1 and Reflood 2 penalties but only reports one overall reflood penalty. For Unit 2, the evaluation was also based on selecting cases with higher break sizes that depressurize faster and lead to a faster accumulator blowdown that create a greater potential for a delay between accumulator injection and ECCS injection. The evaluation also considered cases with high accumulator pressure or low accumulator volume which could also lead to a faster accumulator blowdown. The evaluation for the limiting case concluded there is a net PCT penalty of 16 OF due to the increased ECCS injection flow delay time. As shown in Table 3 with this PCT penalty applied to the current 10 CFR 50.46 PCT rackup sheet for Unit 2, the resulting PCT, 1888 OF, still remains well below the 2200 OF limit. For the maximum local oxidation it was concluded there would be negligible additional oxidation to the calculated 1.64 percent equivalent cladding reacted (ECR) and that there is still significant margin to the allowable 17 percent acceptance criterion. For the core wide oxidation, it was concluded that there is a small potential increase in hot assembly oxidation and the calculated 0.17 percent value, but that it remains below the 1 percent acceptance criterion. In conclusion, the evaluations for the impact of the increased ECCS injection delay time which bound the SLUR actuation time conclude that the Unit 1 and Unit 2 LBLOCA results remain well within the 10 CFR 50.46 acceptance criteria (Reference 10). LOCA Containment Integrity The evaluation for the increased ESF delay times was based only on the Unit 2 analyses since they bound the Unit 1 results. The increased ESF delay times were evaluated for both the effect on the calculated LOCA mass and energy release and the effect on the containment integrity peak pressure and temperature results. The limiting cases evaluated were the double ended hot leg (DEHL) break and double ended pump suction (DEPS) break with minimum 20

Enclosure PG&E Letter DCL-1 1-072 ECCS since they generate the peak pressure and temperature values currently reported in the DCPP FSARU. The evaluation results for these limiting Unit 2 cases are summarized in Table 4 which shows that the peak pressure for the DEHL break increased 0.3 psi to 41.7 psig and the peak temperature increased 0.5 OF to 262.3 OF. However, these peak values continue to be well within the containment design limits of 47 psig and 271 OF. Additionally, the peak pressure results remain below the value of Pa = 43.5 psig as established in TS 5.5.16, such that there is no impact on the TS or containment leakage rate testing program (Reference 10). Table 1: ESF Delay Times to Bound SLUR Actuation Time Engineered Safeguards Function Current Revised (ESF) FSARU FSARU Delay time Delay Time (sec) (sec) Emergency Core Cooling System 27 42 (ECCS) Injection Flow Containment Fan Cooler Unit (CFCU) 48 52 Heat Removal Auxiliary Feed Water (AFW) Flow 60 65 Containment Spray (CS) Flow 80 100 Note: ESF delay times are relative to the applicable initiating protection signal credited in the safety analysis. Table 2 Summary of FSARU Safety Analysis Impacts for Increased ESF Delays FSAR FSAR Accident Description Not Evaluated Evaluated Section Impacted FSARU for ESF Still Impact Bounding 15.2.1 Rod Cluster Withdrawal from No SI Subcritical (RWFS) 15.2.2 Rod Cluster Withdrawal at Power No SI (RWAP) 15.2.3 Rod Cluster Control Assembly No SI Misoperation 15.2.4 Uncontrolled Boron Dilution No SI 15.2.5 Partial Loss of Forced Reactor No SI Coolant Flow (PLOF) 15.2.6 Startup of an Inactive Reactor No SI Coolant Loop (SUIL) 15.2.7 Loss of External Electrical Load No SI and/or Turbine Trip (LOLITT) 21

Enclosure PG&E Letter DCL-1 1-072 FSAR FSAR Accident Description Not Evaluated Evaluated Section Impacted FSARU for ESF Still Impact Bounding 15.2.8 Loss of Normal Feedwater (LONF) No Sl 15.2.9 Loss of Offsite Power to the Station No Sl Auxiliaries (LOAC) 15.2.10 Excessive Heat Removal Due to No SI Feedwater System Malfunctions (FWM) 15.2.11 Sudden Feedwater Temperature No Sl Reduction (FWTR) 15.2.12 Excessive Load Increase Incident No Sl (ELI) 15.2.13 Accidental Depressurization of the No Sl! Reactor Coolant System (ADRCS) ESF 15.2.14 Accidental Depressurization of the No LOOP Main Steam System (ADMS) 15.2.15 Spurious Operation of the Safety X Injection System at Power (SSI) 15.3.1 Small Break Loss of Reactor X Coolant (SBLOCA) 15.3.2 Minor Secondary System Pipe No LOOP Breaks 15.3.3 Inadvertent Loading of a Fuel No SI Assembly 15.3.4 Complete Loss of Forced Reactor No Sl Coolant Flow 15.3.5 Single Rod Cluster Control No Sl Assembly Withdrawal at Full Power (Single RWAP) 15.4.1 Major Reactor Coolant System Pipe X Ruptures (LBLOCA) 15.4.2.1 Major Secondary System Pipe X Rupture Feed Line Break (FLB) 15.4.2.2 Major Secondary System Pipe X Rupture Main Steam Line Break (MSLB) 15.4.2.3 Major Secondary System Pipe No Sl / Rupture MSLB at power ESF 15.4.3 Steam Generator Tube Rupture X (SGTR) 15.4.4 Single Reactor Coolant Pump No SI Locked Rotor (LR) 22

Enclosure PG&E Letter DCL-1 1-072 FSAR FSAR Accident Description Not Evaluated Evaluated Section Impacted FSARU for ESF Still Impact Bounding 15.4.5 Fuel Handling Accident (FHA) No SI 15.4.6 Rod Cluster Control Assembly No Sl I Ejection (RE) ESF 15.4.7 Rupture of a Waste Gas Decay Tank No Sl 15.4.8 Rupture of a Liquid Holdup Tank No Sl 15.4.9 Rupture of Volume Control Tank No SI 15.4.10 Drop Scenario for Cask Pit No Sl Temporary Rack and Platform App LOCA Mass and Energy X 6.2.D.2 App MSLB Mass and Energy No LOOP 6.2.D.3 App LOCA Containment Integrity X 6.2.D.4.1 App MSLB Containment Integrity No LOOP 6.2.D.4.2 3.6 LOCA Forces No Sl / ESF Table 3 Summary of LBLOCA PCT Penalties for Increased ESF Delay Times Current PCT Penalty Revised PCT AOR PCT for ESF Delay per 10 CFR (OF) (1) (OF) 50.46 (°F) Unit 1 Reflood 1 1990 0 1990 Unit 1 Reflood 2 1936 39 1975 Unit 2 1872 16 1888 (1) Includes AOR plus the current PCT penalties tracked per 10 CFR 50.46. Table 4 LOCA Containment Integrity Results for Increased ESF Delay Times Current FSARU Revised for ESF Delay Break Location Peak Pressure Peak Pressure (psig) (psig) DEHL 41.4 @ 23.8 sec 41.7 @ 23.5 sec DEPS min ECCS 39.8 @ 24.1 sec 39.8 @ 23.5 sec Break Location Peak Temperature Peak Temperature 23

Enclosure PG&E Letter DCL-1 1-072 Current FSARU Revised for ESF Delay (OF) (OF) DEHL 261.8 262.3 DEPS min ECCS 259.3 259.3 Note: Results are based on limiting Unit 2 cases. 3.3 Evaluation of Impact of SLUR Time Delay on LOCA Dose Analysis The LOCADOSE code is used to predict LOCA doses at the control room, the Exclusion Area BoUndary (EAB) and the LPZ. The leakage pathways contributing to dose consist of leakage from the containment, normal leakage from post LOCA recirculation path piping in the Auxiliary Building (termed expected leakage), and leakage from a failed RHR pump seal assumed to occur 24 hours after the LOCA. In addition, operations personnel in the control room are assigned a fixed control room egress/ingress dose. Additional analyses are performed to develop dose rates per gpm of post LOCA recirculation loop leakage in either filtered or unfiltered locations of the Auxiliary Building. The results of these calculations are then used with the available dose margin to federal limits to determine the allowable leakage rates for the administratively controlled ABVS filtered and unfiltered post LOCA recirculation loop leakage. The limiting location provides the acceptance criteria for operational post LOCA recirculation leakage that is routinely identified and tracked via a plant procedure. The proposed change revises inputs to the LOCA control room operator and offsite dose analysis. The increases in the containment leakage inputs are offset by decreases in the recirculation loop leakage such that the total control room operator dose remains within the 10 CFR 50 Appendix A, GDC 19-1971 and 10 (FR 100 limits. The proposed change decreases the total offsite dose, as the recirculation loop leakage is decreased to align with that assumed in the control room operator dose analysis. The recirculation loop leakage is administratively controlled by plant procedures in accordance with TS 5.5.2, Primary Coolant Sources Outside Containment. 24

Enclosure PG&E Letter DCL-1 1-072 Specifically, the proposed change increases the containment leakage input due to the changes discussed below: (1) The proposed revision decreases the containment spray iodine removal rate from 31 hr 1 to 29 hr 1 . (2) The proposed revision decreases the LPZ boundary distance from 10 kilometers to 6 miles for the LOCA LPZ calculation. To be consistent with the 6 mile LPZ boundary distance change, the following LPZ atmospheric dispersion factors (,/Q) are increased: 3 (2)(b)(i) 0-8 hour: from 2.2E-5 to 2.4E-5 s/m 3 (2)(b)(ii) 8-24 hour: from 4.75E-6 to 4.8E-6 s/mi (3) The proposed revision increases the delay time for CS delivery time from 86.5 seconds to 106 seconds (which includes a six second delay from LOCA initiation to SI signal generation). The spray delay time of 86.5 seconds assumed in the AOR is calculated based on time to signal initiation, diesel generator start time, the sequence load time, and containment spray pipe fill time. The 86.5 second delay was reported to the NRC via a routine 10 CFR 50.59 report via PG&E Letter DCL-02-049 dated April 26, 2002 (Reference 16). The 106 second spray delay is comprised of a limiting delay of 6 seconds between LOCA initiation and SI signal generation per FSARU Table 15.4.1-1B and a limiting delay of 100 seconds between the SI signal generation time and start of containment spray into containment. (4) The proposed revision increases the initial Control Room Ventilation System (CRVS) outside air intake flow rate for normal (Mode 1 operation) from 2100 scfm to 4200 scfm. The subject AOR assumes that the initial outside air intake flow rate is increased from 2100 scfm total to 2100 scfm per unit, or 4200 scfm total. This intake flow rate is reduced to 2100 scfm total when the non LOCA unit inlet dampers are assumed to close. (5) The proposed revision increases the delay time of the normal CRVS inlet damper closure from 10 seconds to 18 seconds on the unit not experiencing the LOCA, and from 10 seconds to 44.2 seconds on the unit experiencing the LOCA. 25

Enclosure PG&E Letter DCL-1 1-072 The current damper closure delay time for both units is ten seconds from receipt of the SI actuation signal, which is assumed to occur at time zero. In addition the following damper closure delays to both units' dampers are made: 1) a limiting delay of six seconds between LOCA initiatibn and SI signal generation per FSARU Table 15.4.1-1 B, and 2) a limiting delay of two seconds between the SI signal generation time and SI. Additionally, the closure of the LOCA unit's intake dampers will be delayed until DG start and loading due to postulated degraded 230 kV voltage. The DGs are assumed to load onto the 4 kV buses at 26.2 seconds after SI actuation. (6) The proposed revision increases the assumed control room unfiltered infiltration rate from 10 scfm to 70 scfm. Previously, 10 scfm was assumed for unfiltered infiltration. The current FSARU Post LOCA doses are below: CONTROL ROOM OPERATOR DOSES (REM) Gamma Beta Pathway Thyroid Whole Body Skin Containment leakage 5.96 0.0394 0.480 RHR pump seal leakage 0.022 0.0 0.0 Expected recirculation loop leakage 0.85 0.00002 0.0014 Recirculation loop leakage: 1.85 gpm, with charcoal filtration, or 0.186 gpm, with no filtration 18.45 0.0006 0.0083 Plume radiation (egress-ingress) 4.72 0.0066 0.0243 Other direct radiation pathways 0.00 0.0760 0.00 TOTAL CONTROL ROOM OPERATOR DOSES 30.00 10 CFR 50 APPENDIX A, GDC 19 LIMITS 30 5 30 OFFSITE DOSES (REM) SITE BOUNDARY Gamma Pathway Thyroid Whole Body Containment leakage 107.06 3.24 RHR pump seal leakage 0.0 0.0 Expected recirculation loop leakage 8.22 0.03 Recirculation loop leakage: 1.88 gpm, with charcoal filtration, or 0.189 gpm, with no filtration 184.72 0.52 TOTAL SITE BOUNDARY DOSES 300.00 - LPZ Gamma Pathway Thyroid Whole Body Containment leakage 19.01 0.293 RHR pump seal leakage 0.09 0.0 Expected recirculation loop leakage 2.12 0.003 Recirculation loop leakage: 11.07 gpm, with charcoal filtration, or 26

Enclosure PG&E Letter DCL-1 1-072 1.11 gpm, with no filtration 278.78 0.44 TOTAL LPZ DOSES 300.00 - 10 CFR 100 DOSE LIMITS 300 25 The proposed change revises the Post LOCA doses as seen below: CONTROL ROOM OPERATOR DOSES (REM) Gamma Beta Pathway Thyroid Whole Body Skin Containment leakage 14.05 0.042 0.51 RHR pump seal leakage 0.048 0.0 0.0 Expected recirculation loop leakage 1.878 0.00005 0.00038 Recirculation loop leakage: 0.42 gpm, with charcoal filtration, or 0.042 gpm, with no filtration 9.30 0.00027 0.0019 Plume radiation (egress-ingress) 4.72 0.0066 0.0243 Other direct radiation pathways 0.00 0.0760 0.00 TOTAL CONTROL ROOM OPERATOR DOSES 30.00 10 CFR 50 APPENDIX A, GDC 19 LIMITS 30 5 30 OFFSITE DOSES (REM) SITE BOUNDARY Gamma Pathway Thyroid Whole Body Containment leakage 110.0 3.26 RHR pump seal leakage 0.0 0.0 Expected recirculation loop leakage 8.22 0.03 Recirculation loop leakage: 0.42 gpm, with charcoal filtration, or 0.042 gpm, with no filtration 41.35 0.128 TOTAL SITE BOUNDARY DOSES 159.6 - LPZ Gamma Pathway Thyroid Whole Body Containment leakage 20.43 0.32 RHR pump seal leakage 0.09 0.0 Expected recirculation loop leakage 2.24 0.003 Recirculation loop leakage: 0.42gpm, with charcoal filtration, or 0.042 gpm, with no filtration 11.21 0.017 TOTAL LPZ DOSES 33.97 - 10 CFR 100 DOSE LIMITS 300 25 The proposed amendment would provide a new process for revising input parameters in the LOCA control room operator and offsite dose analysis without requesting prior NRC approval. Plant procedures provide administrative controls for maintaining the recirculation loop leakage below the values assumed in the 27

Enclosure PG&E Letter DCL-1 1-072 dose analysis in accordance with TS 5.5.2. Measured recirculation loop leakage values are lower than the flow rate limits provided in the FSARU. The proposed change would allow for the administratively controlled recirculation loop leakage to be revised to offset changes to other inputs of the control room operator and offsite dose analysis, as long as the total control room operator and offsite dose values are within the 10 CFR 50 Appendix A, GDC 19-1971 and 10 CFR 100 limits. The TS 5.5.19 Control Room Envelope Habitability Program and the TS 5.5.2 Primary Coolant Sources Outside Containment program are Technical Specification Controlled programs. Any revisions to inputs to the LOCA control room operator and offsite doses will be made in accordance with these programs. The requested process to revise inputs in the LOCA dose analysis is considered acceptable since the limiting thyroid dose does not exceed the applicable GDC 19-1971 and 10 CFR 100 limits. NEI 96-07 Section 4.3.3 states "For some licensees the current calculated dose consequences may already be in excess of the SRP guidelines for some events. In such cases, minimal increase is defined as less than or equal to 0.1 rem." Thus, NEI 96-07 allows a minimal increase in calculated dose consequences to be performed without prior NRC review and approval when dose consequences are in excess of SRP guidelines. Summary In summary, the proposed revisions to the TS 3.3.5 SRs ensure the FLUR setpoint values used in SR 3.3.5.3 will protect class 1 E equipment. For the new 230 kV degraded voltage scenario and increased ESF delays to bound the SLUR actuation time, the safety analysis results continue to meet the applicable acceptance criteria. Inputs to the control room operator and site boundary doses are revised, but the total control room operator and offsite doses remain within the applicable 10 CFR 50 Appendix A, GDC 19-1971 and 10 CFR 100 limits.

4. REGULATORY EVALUATION 4.1 Applicable Regulatory Requirements/Criteria 10 CFR 50, Appendix A, "General Design Criteria for Nuclear Power Plants," states:

                 "Criterion 17--Electric power systems. An onsite electric power system and an offsite electric power system shall be provided to permit functioning of structures, systems, and components important to safety. The safety function for each system (assuming the other system is not functioning) shall be to provide sufficient capacity and capability to assure that (1) specified acceptable fuel design limits and design conditions of the reactor coolant pressure boundary are not exceeded as a result of anticipated operational 28

Enclosure PG&E Letter DCL-1 1-072 occurrences and (2) the core is cooled and containment integrity and other vital functions are maintained in the event of postulated accidents. "The onsite electric power supplies, including the batteries, and the onsite electric distribution system, shall have sufficient independence, redundancy, and testability to perform their safety functions assuming a single failure. "Electric power from the transmission network to the onsite electric distribution system shall be supplied by two physically independent circuits (not necessarily on separate rights of way) designed and located so as to minimize to the extent practical the likelihood of their simultaneous failure under operating and postulated accident and environmental conditions. A switchyard common to both circuits is acceptable. Each of these circuits shall be designed to be available in sufficient time following a loss of all onsite alternating current power supplies and the other offsite electric power circuit, to assure that specified acceptable fuel design limits and design conditions of the reactor coolant pressure boundary are not exceeded. One of these circuits shall be designed to be available within a few seconds following a loss-of-coolant accident to assure that core cooling, containment integrity, and other vital safety functions are maintained. "Provisions shall, be included to minimize the probability of losing electric power from any of the remaining supplies as a result of, or coincident with, the loss of power generated by the nuclear power unit, the loss of power from the transmission network, or the loss of power from the onsite electric power supplies. "Criterion 18--Inspection and testing of electric power systems. Electric power systems important to safety shall be designed to permit appropriate periodic inspection and testing of important areas and features, such as wiring, insulation, connections, and switchboards, to assess the continuity of the systems and the condition of their components. The systems shall be designed with a capability to test periodically (1) the operability and functional performance of the components of the systems, such as onsite power sources, relays, switches, and buses, and (2) the operability of the systems as a whole and, under conditions as close to design as practical, the full operation sequence that brings the systems into operation, including operation of applicable portions of the protection system, and the transfer of power among the nuclear power unit, the offsite power system, and the onsite power system." 29

Enclosure PG&E Letter DCL-1 1-072 "Criterion 19--Control room. A control room shall be provided from which actions can be taken to operate the nuclear power unit safely under normal conditions and to maintain it in a safe condition under accident conditions, including loss-of-coolant accidents. Adequate radiation protection shall be provided to permit access and occupancy of the control room under accident conditions without personnel receiving radiation exposures in excess of 5 rem whole body, or its equivalent to any part of the body, for the duration of the accident. Equipment at appropriate locations outside the control room shall be provided (1) with a design capability for prompt hot shutdown of the reactor, including necessary instrumentation and controls to maintain the unit in a safe condition during hot shutdown, and (2) with a potential capability for subsequent cold shutdown of the reactor through the use of suitable procedures." 10 CFR 100.11, "Determination of exclusion area, low population zone, and population center distance," states in part: An exclusion area of such size that an individual located at any point on its boundary for two hours immediately following onset of the postulated fission product release would not receive a total radiation dose to the whole body in excess of 25 rem or a total radiation dose in excess of 300 rem to the thyroid from iodine exposure. FSARU Section 3.1.8.3, states that DCPP conforms to 10 CFR Part 50, Appendix A, General Design Criteria 17-1971, "Electric Power Systems." FSARU Section 8.3.1.1.8.2 states that.the emergency electric power system including each vital bus and its control, protection, and instrumentation is designed in accordance with IEEE Standards 308-1971 and 279-1971. NRC Letter "Request for Additional Information - Diablo Canyon Nuclear Power Plants, Unit 1 and 2," dated November 22, 1977 (Reference 1), defines the design and licensing requirements for sustained degraded voltage conditions at the offsite source, and for the interaction of the offsite and onsite emergency power systems. It also details first and second level undervoltage system requirements and states that:

      "The selection of voltage and time set points shall be determined from an analysis of the voltage requirements of the safety-related loads at all onsite system distribution levels, the voltage protection shall include coincidence logic to preclude spurious trips of the 30

Enclosure PG&E Letter DCL-1 1-072 offsite power source, the allowable time delay, including margin, shall not exceed the maximum time delay that is assumed in the FSAR accident analyses, the time delay shall minimize the effect of short duration disturbances from reducing the availability of the offsite power source(s), the allowable time duration of a degraded voltage condition at all distribution system levels shall not result in failure of safety systems or components, the voltage levels at the safety-related buses should be optimized for the full load and minimum load conditions that are expected throughout the anticipated range of voltage variations of the offsite power source by appropriate adjustment of the voltage tap settings of the intervening transformers." PG&E responded to this letter, with a description of how the DCPP design meets these requirements in PG&E Letter "Emergency Power System Designs for Sustained Degraded Grid Voltage Conditions," dated January 24, 1978. The 2010 NRC CDBI report (Reference 7) contained subsequent violations pertaining to this design. As stated in the purpose statement for this proposed license amendment, this LAR addresses the violations received during a CDBI. The changes proposed in this LAR meet the requirements of GDC 17-1971, GDC 18-1971, GDC 19-1971, 10 CFR 100, IEEE 279-1971, and IEEE 308-1971. 4.2 Precedent None 4.3 Significant Hazards Consideration PG&E has evaluated whether or not 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 change involve a significant increase in the probability or consequences of an accident previously evaluated? Response: No. The diesel generators (DGs) provide a source of emergency power when offsite power is either unavailable, or is degraded below a point that would allow safe unit operation. Undervoltage protection will generate a loss of power (LOP) DG start if a loss of voltage or degraded voltage condition 31

Enclosure PG&E Letter DCL-1 1-072 occurs on the 4.16 kV vital bus. The proposed technical specification (TS) change affects the voltage at which an emergency bus that is experiencing sustained degraded voltage will disconnect from offsite power and transfer to the DGs. While the TS limits are revised, the function remains the same and will continue to be performed. The first level undervoltage relays (FLUR) and second level undervoltage relays (SLUR) will continue to meet their required function to transfer 4.16 kV buses to the DGs in the event of insufficient offsite power voltage. This transfer will ensure that the class 1E equipment is capable of performing its function to meet the requirements of the accident analysis. The revised TS surveillance r6quirement (SR) 3.3.5.3 setpoints will not cause unnecessary separation of engineered safety function (ESF) loads from the 230 kV System. The proposed change does not affect any accident initiators or precursors. The ESF function delay times are bounding input parameters that represent actual plant performance for when these ESF functions can be credited to begin operating after an accident has already occurred. The increased ESF delay times are not physically related to the cause of any accident. Therefore, the increase in ESF delay times do not introduce the possibility of a change in the frequency of an accident previously evaluated. The revised LOCA control room operator and offsite dose analysis results remain within the applicable GDC 19-1971 and 10 CFR 100 limits.Therefore, the proposed activity does not result in an increase in the consequence of an accident previously evaluated in the FSARU. Therefore, the probability or consequences of any accident previously evaluated will not be significantly increased as a result of the proposed change. (2) Does the proposed change create the possibility of a new or different accident from any accident previously evaluated? Response: No. No new accident scenarios, transient precursors, failure mechanisms, or limiting single failures are introduced as a result of the proposed change. The revised surveillance requirements will continue to assure equipment. reliability such that plant safety is maintained or will be enhanced. An increased ESF delay time is not an initiator of any accident and does not create any new system interactions or failure modes of any structures, systems or components (SSC). Equipment important to safety will continue to operate as designed. The changes do not result in adverse conditions or result in any increase in the challenges to safety systems. Therefore, operation of the Diablo Canyon 32

Enclosure PG&E Letter DCL-1 1-072 Power Plant in accordance with the proposed amendment will not create the possibility of a new or different type of accident from any accident previously evaluated. Therefore, the proposed change does not create the possibility of a new or different accident from any accident previously evaluated. (3) Does the proposed change involve a significant reduction in a margin of safety? Response: No. The DGs provide emergency electrical power to the safeguard buses in support of equipment required to mitigate the consequences of design basis accidents and anticipated operational occurrences, including an assumed loss of all offsite power. SR 3.3.5.3 verifies that the LOP DG start instrumentation channels respond to measured parameters within the necessary range and accuracy. The proposed amendment corrects nonconservative values in the TS limits for the degraded voltage protection function. The proposed change to this SR assures that design requirements of the emergency electrical power system continue to be met. There are no new or significant changes to the initial conditions contributing to accident severity or consequences. The proposed increase in ESF delay times is considered an analysis input change. However, the safety analyses continue to meet all applicable acceptance criteria. The proposed amendment will not otherwise affect the plant protective boundaries, will not cause a release of fission products to the public, nor will it degrade the performance of any other SSCs important to safety. Therefore, the proposed change does not involve a significant reduction in a margin of safety. Based on the above evaluation, PG&E concludes that the proposed change 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. 4.4 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 Commission's regulations, and (3) 33

Enclosure PG&E Letter DCL-1 1-072 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 CONSIDERATION PG&E has evaluated the proposed amendment and has determined that 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 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 needs to be prepared in connection with the proposed amendment.

6. REFERENCES

1. NRC Letter "Request for Additional Information - Diablo Canyon Nuclear Power Plants, Unit 1 and 2," dated November 22, 1977

2. PG&E Letter "Emergency Power System Designs for Sustained Degraded Grid Voltage Conditions," dated January 24, 1978

3. PG&E Licensee Event Report 1-2010-002-02, "Potential Loss of Safety-Related Pumps due to Degraded Voltage During Postulated Accidents," dated September 24, 2010

4. NUREG-1 102, Revision 0, "Technical Specifications Diablo Canyon Power Plant, Unit No. 1," dated November 1984

5. NUREG-1 132, Revision 0, "Technical Specifications Diablo Canyon Power Plant, Unit No. 2," dated April 1985

6. PG&E Calculation No. 9000041128 (357S-DC), Revision 2, "4.16 kV Bus FLUR & SLUR Setpoint Calculation," dated July 18, 2011

7. NRC Letter "Diablo Canyon Power Plant - NRC Component Design Bases Inspection Report 05000275/2010007 and 05000323/2010007,"

dated July 23, 2010

8. PG&E Calculation No.9000008518 (170-DC), Revision 16A, "4kV Class 1E Motor Overcurrent Relay Setpoints-Basler Electric," dated May 5, 2011

9. PG&E Calculation No. 9000033535 (359-DC), Revision 9A, "Determination of 230 kV Grid Capability Limits As DCPP Offsite Power Source," dated May 6, 2011

10. Westinghouse Electric LLC Letter PGE-1 0-54, Revision 1, "Pacific Gas

             & Electric Company, Diablo Canyon Units 1 & 2, 230 kV Degraded 34

Enclosure PG&E Letter DCL-1 1-072 Voltage Evaluation - Engineering Report," dated October 15, 2010 (proprietary)

11. License Amendment No. 37 to Facility Operating License No. DPR-80 and Amendment No. 36 to Facility Operating License No. DPR-82, "Issuance of Amendments (TAC NOS. 71387 and 71388)," dated May 10, 1989

12. License Amendment No. 191 to Facility Operating License No. DPR-80, "Diablo Canyon Power Plant, Unit No. 1 - Issuance of Amendment RE: Technical Specification 5.6.5, 'Core Operating Limits Report (COLR)'(TAC NO. MC9299)," dated November 21, 2006

13. License Amendment No. 192 to Facility Operating License No. DPR-82, "Diablo Canyon Power Plant, Unit No. 2 - Issuance of Amendment RE: TS 5.6.5, 'Core Operating Limits Report (COLR)," (TAC NO.

MC9567),' dated December 20, 2006

14. Safety Evaluation by the Directorate of Licensing U.S. Atomic Energy Commission in the Matter of Pacific Gas and Electric Company Diablo Canyon Nuclear Power Station, Units 1 and 2 San Luis Obispo County, California Docket Nos. 50-275 and 50-323, dated October 16, 1974

15. License Amendment No. 80 to Facility Operating License No. DPR-80 and Amendment No. 79 to Facility Operating License No. DPR-82, "Issuance of Amendments, for Diablo Canyon Nuclear Power Plant, Unit No. 1 (TAC No. M79425) and Unit No. (TAC No. M79426)," dated April 1, 1993.

16. PG&E Letter DCL-02-049, "10 CFR 50.59 Report of Changes, Tests, and Experiments for the Period January 1, 2000, through December 31, 2001," dated April 6, 2002.

35

Enclosure Attachment 1 PG&E Letter DCL-1 1-072 Proposed Technical Specification Changes (marked-up)

LOP DG Start Instrumentation 3.3.5 SURVEILLANCE REQUIREMENTS (continued) SURVEILLANCE FREQUENCY SR 3.3.5.3 Perform CHANNEL CALIBRATION with Allowable In accordance with Value setpoints as follows: the Surveillance

a. Loss of voltage Diesel Start Allowable Value

                      > 0 V with a time delay of :s 0.8 seconds and Frequency Control Program              jxý a 2583 V with a 5 10 second time delay.

Loss of voltage initiation ofIAd-hw~- relay Allowable lale 2 0 V Wit 6 4seQnsd- ad 2582 V NWith Atdmelday 525 seconds sand A"ith 0ee!ay-Ao.a,4eAL-ue S2870-Vhnstarteous*

b. Degraded voltage Diesel Start Allowable Value a 3785 Vwith a time delay of 5 10 seconds.

Degraded voltage initiation of Load Shed Allowable Value > 3785 V with a time delay of

                      /5 20 seconds.
                                                                          .1
          /.

Loss of voltage initiation of load shed with relay Allowable Valu as of:

              ;3328

V for 5 10 sec

              >3120
                !        V for 5 6 sec
              ;: 2704 V for 5 4 sec
   *"   And one relay Allowable Value of:
             >! 3411 V, instantaneous DIABLO CANYON - UNITS 1 & 2                  3.3-42      Unit 1 - Amendment No. 4--,44-,4-166A, Unit 2 - Amendment No. 436,442.Q4,

Enclosure Attachment 2 PG&E Letter DCL-1 1-072 Proposed Technical Specification Changes (retyped) Remove Page Insert Page 3.3-42 3.3-42

LOP DG Start Instrumentation 3.3.5 SURVEILLANCE REQUIREMENTS (continued) SURVEILLANCE FREQUENCY SR 3.3.5.3 Perform CHANNEL CALIBRATION with Allowable In accordance with Value setpoints as follows: the Surveillance Frequency Control

a. Loss of voltage Diesel Start Allowable Value Program

                > 0 V with a time delay of _<0.8 seconds and
                > 2583 V with a _<10 second time delay.

Loss of voltage initiation of load shed with relay Allowable Values of:

                     >_3328 V for <1l0 sec

_>3120 V for _<6 sec _Ž2704 V for _<4 sec And one relay Allowable Value of: _Ž3411 V, instantaneous

b. Degraded voltage Diesel Start Allowable Value

                 > 3785 V with a time delay of < 10 seconds.

Degraded voltage initiation of Load Shed Allowable Value _>3785 V with a time delay of _<20 seconds. DIABLO CANYON - UNITS 1 & 2 3.3-42 Unit 1 - Amendment No. 4-3*,-142,-t65,200, Unit 2 - Amendment No. 4-15,442,2-4,

Enclosure Attachment 3 PG&E Letter DCL-1 1-072 Changes to Technical Specification Bases Pages (For information only)

LOP DG Start Instrumentation B 3.3.5 B 3.3 INSTRUMENTATION B 3.3.5 Loss of Power (LOP) Diesel Generator (DG) Start Instrumentation BASES BACKGROUND The DGs provide a source of emergency power when offsite power is either unavailable or is degraded below a point that would allow safe unit operation. Undervoltage protection will generate an LOP start if a loss of voltage or degraded voltage condition occurs on the 4.16kV vital bus. There are three LOP start signals, one for each 4.16 kV vital bus. Three-uUndervoltage relays are provided on each 4.16 kV4460 Class 1E vital bus for detecting sustained degraded voltage condition or a loss of bus voltage. A-relay-Relays will generate an LOP signal (first level undervoltage type relay setpoint) ifthe voltage is below 7-5-/equipment protection thresholds for a short time. The DG start relays (one per bus) have an inverse time characteristic and will generate an LOP signal with aAllowable Values of> 0 volts with a time delay of < 0.8 seconds time delay at Ž, 0 volts and > 2583 volts with at a _<10 seconds time delayfor-Ž_ 2583 -volts. In addition, the circuit breakers for all loads, except the 4160-480 V load center transformers, are opened automatically by Load Shedding Relays for first level undervoltage. Each of the vital 4.16 kV 4-160-kW-buses has a separate pair-two channel set of these relays. The relay channels have a two-out-of-two logic arrangement for each bus to prevent inadvertent tripping of operating loads during a loss of voltage either from a single failure in the potential circuits or from human error. One relay tripschannel contains one relay with an Allowable Value of instantaneously at > 2870-3411 volts, instantaneous. The second of the two channels consists of 3 discrete voltage and time delay relays, with Allowable Values of> 3328 volts for < 10 seconds, > 3120 volts for <6 seconds, and > 2704 for < 4 seconds, respectively, has an inverse time characteristic and delay of !94 seco~nds at no voltage and a 9 25 second delay wt;h -?2683 volts to prevent loss of operating loads during transient voltage dips, and to permit the offsite power sources to pick up the load. The LOP start actuation is described in FSAR, Section 8.3 (Ref. 1). Should there be a degraded voltage condition (second level undervoltage), where the voltage of the vital 4160-4.16 kV buses remains at approximately 3785 kV-volts or below, but above the setpoints of the first level undervoltage relays, the following second level undervoltage actions occur automatically: (1) After a < 10 second time delay, the respective diesel generators will start. (2) After a < 20 second time delay, ifthe undervoltage condition persists, the circuit breakers for all loads to the respective vital 4160 kV buses, except the 4160-480 V load center transformer, are opened and sequentially loaded on the DG. (continued) DIABLO CANYON - UNITS 1 & 2 Rev TBD Page 1 of 5

LOP DG Start Instrumentation B 3.3.5 BASES BACKGROUND Each vital 4160 -4.16 kV bus has two second level undervoltage relays (continued) operating with a two-out-of-two logic. Each vital 4160kV Bus also has two second level undervoltage timers. One timer provides the Diesel Generator start and the other will initiate load shedding. Allowable Value Setpoints The Setpoints used in the relays are based on the analytical limits pre.e.ted in FSAR, Chapter 15 (Ref. 2). The voltage and time delay setpoints protect ESF equipment. The allowable time delay, including margin, shall not exceed the maximum time delay assumed in the FSARU accident analysis (Chapters6 and 15) The selection of these Setpoints is such that adequate protection is provided when all sensor and processing time delays are taken into account. The actual nominal Setpoint entered into the relays is normally still more conservative than that required by the Allowable Value. If the measured setpoint does not exceed the Allowable Value, the undervoltage relay is considered OPERABLE. If the measured time delay does not exceed the Allowable Value, the timer is considered OPERABLE. Setpoints adjusted in accordance with the Allowable Value ensure that the consequences of accidents will be acceptable, providing the unit is operated from within the LCOs at the onset of the accident and that the equipment functions as designed. Allowable Values are specified for each Function in the LCO. The nominal setpoints are selected to ensure that the setpoint measured by the surveillance procedure does not exceed the Allowable Value if the undervoltage relay is performing as required. If the measured setpoint does not exceed the Allowable Value, the undervoltage relay is considered OPERABLE. Operation with a Setpoint less conservative than the nominal Setpoint, but within the Allowable Value, is acceptable provided that operation and testing is consistent with the assumptions of the unit specific setpoint calculation. Each Allowable Value specified is more conservative than the analytical limit assumed in the transient and accident analyses in order to account for instrument uncertainties appropriate to the trip function. These uncertainties are defined in calculations 174A DC Rev. 0 (Ref. 4) and 357-P357S-DC-Rev. (Ref. 54). APPLICABLE The LOP DG start instrumentation is required for the Engineered Safety SAFETY Features (ESF) Systems to function in any accident with a loss of ANALYSES offsite power. Its design basis is that of the ESF Actuation System (ESFAS). (continued) DIABLO CANYON - UNITS 1 & 2 Rev TBD Page 2 of 5

LOP DG Start Instrumentation B 3.3.5 BASES APPLICABLE Accident analyses credit the loading of the DG based on the loss of SAFETY offsite power during a loss of coolant accident (LOCA). The actual DG ANALYSES start has historically been associated with the ESFAS actuation. The (continued) DG loading has been included in the delay time associated with each safety system component requiring DG supplied power following a loss of offsite power. The analyses assume a non-mechanistic DG loading, which does not explicitly account for each individual component of loss of power detection and subsequent actions. The required channels of LOP DG start instrumentation, in conjunction with the ESF systems powered from the DGs, provide unit protection in the event of any of the analyzed accidents discussed in Reference 2, in which a loss of offsite power is assumed. The delay times assumed in the safety analysis for the ESF equipment include the 10 second DG start delay, and the appropriate sequencing delay, if applicable. The response times for ESFAS actuated equipment in LCO 3.3.2, "Engineered Safety Feature Actuation System (ESFAS) Instrumentation," include the appropriate DG loading and sequencing delay. The LOP DG start instrumentation channels satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii). LCO The LCO for LOP DG start instrumentation requires that one channel per bus for loss of voltage DG start with, two channels per bus for initiation ofload shed and their two corresponding timers and two channels per bus of degraded voltage function with one timer per bus for DG start and one timer per bus for initiation of load shed Functions shall be OPERABLE in MODES 1, 2, 3, and 4 when the LOP DG start instrumentation supports safety systems associated with the ESFAS. In MODES 5 and 6, the channels must be OPERABLE whenever the associated DG is required to be OPERABLE to ensure that the automatic start of the DG is available when needed. Loss of the LOP DG Start Instrumentation Function could result in the delay of safety systems initiation when required. This could lead to unacceptable consequences during accidents. During the loss of offsite power the DG powers the motor driven auxiliary feedwater pumps. Failure of these pumps to start would leave only one turbine driven pump, as well as an increased potential for a loss of decay heat removal through the secondary system. (continued) DIABLO CANYON - UNITS 1 & 2 Rev TBD Page 3 of 5

LOP DG Start Instrumentation B 3.3.5 BASES (continued) APPLICABILITY The LOP DG Start Instrumentation Functions are required in MODES 1, 2, 3, and 4 because ESF Functions are designed to provide protection in these MODES. Actuation in MODE 5 or 6 is required whenever the required DG must be OPERABLE so that it can perform its function on an LOP or degraded power to the vital bus. ACTIONS In the event a channel's Setpoint is found nonconservative with respect to the Allowable Value, or the channel is found inoperable, then the function that channel provides must be declared inoperable and the LCO Condition entered for the particular protection function affected. Because the required channels are specified on a per bus basis, the Condition may be entered separately for each bus as appropriate. A Note has been added in the ACTIONS to clarify the application of Completion Time rules. The Conditions of this Specification may be entered independently for each Function listed in the LCO. The Completion Time(s) of the inoperable channel(s) of a Function will be tracked separately for each Function starting from the time the Condition was entered for that Function. A.1 Condition A applies when one or more of the loss of voltage or the degraded voltage channel functions (this includes both relays and timers) on a single bus are inoperable. In these circumstances the Conditions specified in LCO 3.8.1, "AC Sources-Operating," or LCO 3.8.2, "AC Sources-Shutdown," for the DG made inoperable by failure of the LOP instrumentation are required to be entered immediately. The actions of those LCOs provide for adequate compensatory actions to assure unit safety. A Note is added to allow bypassing one channel for up to 2 hours for surveillance testing. This allowance is made where bypassing the channel does not cause an actuation and where at least one other channel is monitoring that parameter. SURVEILLANCE SR 3.3.5.1 not used REQUIREMENTS SR 3.3.5.2 SR 3.3.5.2 is the performance of a TADOT. The test checks trip devices that provide actuation signals directly, bypassing the analog process control equipment. For these tests, the relay Setpoints are verified and adjusted as necessary. Plant procedures verify that the instrument channel functions as requiredby verifying the as-left and as-found settings are consistent with those establishedby the setpoint methodology. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program. (continued) DIABLO CANYON - UNITS 1 & 2 Rev TBD Page 4 of 5

LOP DG Start Instrumentation B 3.3.5 BASES SURVEILLANCE SR 3.3.5.3 REQUIREMENTS SR 3.3.5.3 is the performance of a CHANNEL CALIBRATION. (continued) The setpoints, as well as the response to a loss of voltage and a degraded voltage test, shall include a single point verification that the trip occurs within the required time delay. CHANNEL CALIBRATION is a complete check of the instrument loop, including the sensor. The test verifies that the channel responds to a measured parameter within the necessary range and accuracy. Plant procedures verify that the instrument channel functions as requiredby verifying the as-left and as-found settings are consistent with those established by the setpoint methodology. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program. REFERENCES 1. FSAR, Section 8.3.

2. FSAR, Chapter 15.

3. BlankFSAR, Chapter 6.

4. Calculation 359S-DC, "4.16 kV Bus FLUR & SLUR Setpoint Calculation.! Dr, n74A",ndeR..ltagc Relay Settings for.4K System (27HFB32 & 27HFTI)."

5. CalculationR 357P DG, "SLUR and SLUR Timer SetpointS-."

DIABLO CANYON - UNITS 1 & 2 Rev TBD Page 5 of 5

Enclosure Attachment 4 PG&E Letter DCL-1 1-072 FSARU Markups

DCPP UNITS 1 & 2 FSAR UPDATE (2) If the component is shared with other systems, it is aligned during normal plant operation to perform its accident function, or, if not aligned to its accident function, two valves in parallel are provided to align the system for injection, and two valves in series are provided to isolate portions of the system not utilized for injection. These valves are automatically actuated by the safety injection signal. Table 6.3-8 indicates the alignment of components during normal operation, and the realignment required to perform the accident function. 6.3.3.6.1 Dependence on Other Systems Other systems that operate in conjunction with the ECCS are as follows: (1) The CCW system (Section 9.2.2) cools the RHR heat exchangers during the recirculation mode of operation. It also supplies cooling water to CCP1 and CCP2, the safety injection pumps, and the RHR pumps during the injection and recirculation modes of operation. (2) The ASW system (Section 9.2.1) provides cooling water to the CCW heat exchangers. (3) The electrical systems (Section 8.3) provide normal and emergency power sources for the ECCSs. (4) The ESF actuation system (ESFAS) (Section 7.3) generates the initiation signal for emergency core cooling. (5) The AFW system (Section 6.5) supplies feedwater to the steam generators. (6) The auxiliary building ventilation system (Section 9.4) removes heat from the pump compartments and provides for radioactivity contamination control should some leakage occur in a compartment. 6.3.3.7 Lag Times The sequence and time-delays for actuation of ECCS components for the injection and recirculation phases of emergency core cooling are given in Table 6.3-7. The ECCS delay times assumed in the accident analyses bound these values. Alignment of the major ECCS components during the injection and recirculation phases is shown in Figures 6.3-4 and 6.3-5, respectively. The sequence of events tables in Chapter 15 Tables 15.3 2 aRnd 15.3 3 summarize the calculated times at which the major components perform the safety-related functions for those various accident conditions (tabulated in Table 15.1-24) that require the ECCS. 6.3-26 Revision 19 May 2010

DCPP UNITS 1 & 2 FSAR UPDATE The minimum active components will be capable of delivering full rated flow within a specified time interval after process parameters reach the setpoints for the safety injection signal. Response of the system is automatic with appropriate allowances for delays in actuation of circuitry and active components. The active portions of the system are actuated by the safety injection signal. In analyses of system performance, delays in reaching the programmed trip points and in actuation of components are established on the basis that only emergency onsite power is available. The starting sequence following a loss of offsite power is discussed in detail in Chapter 8. Foraccidents that assume a LOOP, Tthe ECCS is operational after an elapsed time not greater than 25 seconds after the SI signal is actuated, including the time to bring the RHR pumps up to full speed. The ECCS operation has also been evaluated in PGE 54 (Reference 16) for an increaseddelay time of 42 seconds in order to bound potential scenariosin which the maximum SLUR actuation time occurs. The starting times for components of the ECCS are consistent with the delay times used in the LOCA analyses for large and small breaks. In the LOCA analysis presented in Sections 15.3 and 15.4, no credit is assumed for partial flow prior to the establishment of full flow based on all ECCS pumps achieving rated speed and no credit is assumed for the availability of normal 230-kV and 500-kV offsite power sources. The PGE-10-54 (Reference 16) evaluation which bounds the maximum SLUR actuation time, also assumes no credit for partialECCS flow until all ECCS pumps have obtained rated speed and achieved full flow capability. For smaller LOCAs, there can be -is-some-additional delay before the process variables reach their respective programmed trip setpoints since this is a function of the severity of the transient imposed by the accident. This is allowed for in the analyses of the range of LOCAs. Accumulator injection occurs immediately when RCS pressure has decreased below the operating pressure of the accumulator. 6.3.3.8 Limits on System Parameters The specification of individual parameters as indicated in Table 6.3-1 includes due consideration of allowances for margin over and above the required performance value (e.g., pump flow and NPSH), and the most severe conditions to which the component could be subjected (e.g., pressure, temperature, and flow). This consideration ensures that the ECCS is capable of meeting its minimum required level of functional performance. 6.3.3.8.1 Coolant Storage Reserves A minimum RWST volume is provided to ensure that, after an RCS break, sufficient water is injected and available within containment to permit recirculation cooling flow to 6.3-27 Revision 19 May 2010

DCPP UNITS 1 & 2 FSAR UPDATE

2. Westinghouse ECCS - Plant Sensitivity Studies, WCAP-8340 (Proprietary) and WCAP-8356, July 1974.

3. Westinghouse ECCS Evaluation Model-Summary, WCAP-8339, July 1974.

4. Westin-ghouse ECCS Evaluation Model - Supplementary Information, WCAP-8471 (Proprietary) and WCAP-8472, January 1975.

5. Westinghouse ECCS Evaluation Model - October 1975 Version, WCAP-8622 (Proprietary) and WCAP-8623, November 1975.

6. Environmental Testing of Engineered Safety Features Related Equipment (NSSS-Standard Scope), WCAP-7744, Volume I, August 1971.

7. Westinghouse ECCS Evaluation Model - February 1978 Version, WCAP-9220 (Proprietary) and WCAP-9221, February 1978.

8. "Reliability, Stress and Failure Rate Data for Electronic Equipment," Military Standardization Handbook, MIL-HDBK-217A, December 1965, Department of Defense, Washington, D.C.

9. Diablo Canyon Power Plant - Inservice Inspection Program Plan - The Third 10 Year Inspection Interval.

10. Technical Specifications, Diablo Canyon Power Plant Units 1 and 2, Appendix A to License Nos. DPR-80 and DPR-82, as amended.

11. Regulatory Guide 1.79, Preoperational Testing of Emergency Core Cooling System for Pressurized Water Reactors, USNRC, June 1974.

12. IEEE-Std-279, Criteria for Protection Systems for Nuclear Power Generating Stations, 1971.

13. Westinghouse ECCS Evaluation Model, 1981 Version, WCAP-9220-P-A, Rev. 7 (proprietary), WCPA-9221-A, Rev. 1 (nonproprietary), February 1982.

14. Young, M. Y., et al., BART-Al: A Computer Code for the Best Estimate Analysis of REFLOOD Transients, WCAP-9561-P, Addendum 3, June 1986.

15. Chiou, J. S., et al., Models for PWR Reflood Calculations Using the BART Code, WCAP-10062.

16. Westinghouse letter PGE-10-54, Diablo Canyon 230 kV Degraded Voltage Evaluation- Engineering Report Revision 1, October 15, 2010.

6.3-36 Revision 19 May 2010

DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.3-7 Sheet 1 of 4 SEQUENCE AND DELAY TIMES FOR STARTUP OF ECCS Delay, sec References Action Sequence Actuation (Subsystem or Minimum ECCS Performance Section Accident Signal(s) Component)

• Design Performance Assumed in Analysis FSAR Figures Tables

1. Major Reactor 15.4.1 Coolant System Rupture (LOCA)

a. Injection phase (g) Accumulator tank (g) (g) (g) 4 tanks, each with 850 ft3 of Three tanks injecting into RCS; 6.3 8.3-4 borated water @ 600 psig one injecting into broken loop (a) Containment I 1 10 Double barrier; fast automatic A single active failure is 8.3-4 6.2.4 6.2-12, isolation valves valve closure upon receipt of CIS allowable 6.2-13 &

6.2-14 (b) (d) ECCS required (k) (k) See Rapid reliable system alignment or A single active failure is 6.3.2 7.3-22, 8.3-4 valves Table isolation allowable 7.3-33 6.3-1 (b) (d) Centrifugal -5 15 4-1/2 Two centrifugal charging pumps One pump required at 6.3.2, 7.3-4 8.3-4 charging pumps supply borated water into a single design flow 9.3.4 injection flowpath splitting into 4 cold leg injection lines (b) (d) Safety injection Two pumps inject via a single path One pump delivering at 6.3.2 3.2-9 pumps splitting into 4 cold leg injection design flow lines (b) (d) Residual heat Two pumps inject into 4 cold legs, One pump delivering at 6.3.2, 3.2-9 removal pumps via 2 lines that each split into 2 design flow 5.5.6 cold leg injection lines (b) (d) Component cooling 25/25 35/35/ 4-1/2 Two flowpaths; each 11,500 gpm One flowpath required at 9.2.2 7.3-7 8.3-4 water pumps /30 40 @ 130 ft design flow (e) Auxiliary feed- 30/35 40/45 5 Two flowpaths; each 800 gpm One flowpath required at 6.5.2 7.3-8 8.3-4 water pumps @ 2350 ft design flow (b) (d) Auxiliary salt- 30/35 40/45 5 Two flowpaths; each 11,000 gpm One flowpath required at 9.2.7 7.3-5 8.3-4 water pumps @ 115 ft design flow Revision 12 September 1998

DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.3-7 Sheet 2 of 4 Delay, sec References Action Sequence Actuation (Subsystem or Minimum ECCS Performance Section Accident Signal(s) Component) 2 Ell M Design Performance Assumed in Analysis FSAR Figures Tables (c) Containment Two flowpaths; each 2600 gpm One flowpath required at 7.3-11 8.3-4 spray pumps @ 450 ft design flow Pump 1 26 26 1.7 Pump 2 22 22 1.7

b. Recirculation (f) Operating (Total switchover time is (Design performance for ECCSA A single failure is allowable 6.3.2 phase personnel shift approximately 10 min. and related equipment as described system alignment See 6.3.2) in la above) from injection phase

2. Major (b) Action sequence Same as la above Same as ia above Same as la above with these 15.4.2 Seccondary similar to 1a further notes: Accumulator and System Rupture above. Operation low head injection required only of ESF required. in the severe cases. Since no Valves isolate RCS rupture has occurred, all feedwater & steam four accumu-ators are functional Revision 12 September 1998

DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.3-7 Sheet 3 of 4 Action Sequence Actuation (Subsystem or Minimum ECCS Performance Section Accident Signal(s) Component) LhJ M il Design Performance Assumed in Analysis FSAR Figures Tables

3. Steam Generator Low Same as la Same as la above with Same as la above Same as la above (but all four 15.4.3 Tube Rupture pressurizer above although no additional isolation done accumulators assumed pressure containment within 30 minutes functional). Conservative spray. estimate of 125,000 lb of Additionally, reactor coolant transferred to automatic isolation the secondary side of the of individual steam affected steam generator generator blowdown valve occurs due to SGBD liquid radiation monitor.

Injection and charging flow regulated to maintain visible pressurizer water level. Auxiliary feedwater to affected SG manually isolated. Pressurizer reliefs operated to reduce RCS pressure under 1000 psia

4. Minor RCS Low 15.3.1 Rupture which pressurizer Actuates ECCS pressure, or level, or high containmen t pressure

a. Injection phase Same as Same as la Same as la above Same as ia above Same as la above la above above

b. Recirculation Same as Same as la Same as la above Same as 1a above Same as ia above la above above Revision 12 September 1998

DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.3-7 Sheet 4 of 4 (a) Initiated by means of containment isolation signal, which occurs on containment high pressure (2 of 3) or on safety injection signal (SIS). (b) Safety injection signal actuates on any of the following: Low pressurizer pressure, high containment pressure, low steamline pressure, or manual actuation. (c) Containment spray actuation signal, which occurs on containment high-high pressure (2 of 4), or manual actuation. (d) Emergency diesel loading sequencer loads the diesel in accordance with the sequence shown in Tables 8.3-2 and 8.3-4. Also see Figures 8.3-9, 8.3-10, 8.3-11, and 8.3-16. (e) Auxiliary feedwater autostart signal, which occurs with a SIS. SG low-low level or tripping of both main feedwater pumps. (I) Water level indication and alarms on the refueling water storage tank and in the containment sump provide ample warning to terminate the injection mode and begin the recirculation mode while the operating pumps still have adequate net positive suction head. Manual switchover by operating personnel changes the ECCS from injection to recirculation mode. (g) All valves between the accumulators and the RCS are required to be open in Modes 1, 2, and 3; consequently, the accumulators inject as soon as the RCS pressure i rops below the pressure (6 00 psia) of the accumulators. (h) Electrical and instrumentation delay time after "S" signal with main generator power or offsite power available. For containment spray pumps, delay time is after "P" si Inal. (i) Electrical and instrumentation delay time after "S"signal using diesel generator for a LOOP. For containment spray pumps, delay time is after "P" signal. Additionala l/ay times to bound the maximum 4 kV SLUR actuation time are documented in PGE-10-54 (Reference 16). (j) Equipment startup time after receipt of signal. (k) These delay times vary. Revisiob 12 September 1998

DCPP UNITS 1 & 2 FSAR UPDATE A minimum of two CFCUs are available and a maximum of three CFCUs are assumed to be available based on the single failure assumptions. Three long term cases are analyzed to assess the effects of single failures. The first case assumes minimum safeguards based on the postulated single failure of an SSPS train. This assumption results in the loss-of-one train of safeguards equipment. The operating equipment is conservatively modeled as: two CFCUs, one containment spray pump, one train of RHR, and one CCW heat exchanger. The other two cases assume maximum safeguards, in which both trains of SSPS are available. With the maximum safeguards cases, the single failure assumptions are the failure of one containment spray pump or the failure of one CFCU. The analysis of these three cases provides confidence that the effect of credible single failures is bounded. The fan coolers in the containment evaluation model are modeled to actuate on the containment high pressure setpoint with uncertainty biased high, (5 psig), and begin removing heat from containment after a 48-second delay with a LOOP. PGE-10-54 (Reference 20) evaluated an increased CFCULOOP delay time of 52 seconds to bound the maximum 4 kV SLUR actuation time. This evaluation was performed only for the limiting Unit 2 cases to assess the impact on the peak containment pressure and temperature. The CFCUs are cooled by CCW. The heat removal rate per containment fan cooler is calculated as a function of containment steam saturation temperature, the CCW inlet temperature and flow rate, and input to the GOTHIC cooler model. The heat removal rate is multiplied by the number of CFCUs available. The heat removed from the containment control volume is transferred to the CCW control volume receiving the flow through the CFCUs using a coupled heater model. Containment Spray System The containment spray is modeled with a boundary condition. DCPP has two trains of containment safeguards available, with one spray pump per train. An inherent assumption in the LOCA containment analysis is that offsite power is lost with the pipe rupture. This results in the actuation of the three EDGs powering the two trains of safeguards equipment. Startup of the EDGs delays the operation of the safeguards equipment that is required to mitigate the transient. Relative to the single failure criterion with respect to a LOCA event, one spray pump is considered inoperable due to the SSPS failure (minimum safeguards case) or as a single failure in a maximum safeguards case. In the maximum safeguards case, in which the single failure is assumed to be one CFCU, two spray pumps are available. The containment spray actuation is modeled on the containment high-high pressure setpoint with uncertainty biased high (24.7 psig). The sprays begin injecting 90°F water after a specified 80 second delay. The spray flow rate is a function of containment pressure and is presented in Table 6.2D-18. The containment spray is credited only 6.2D-29 Revision 18 October 2008

DCPP UNITS 1 & 2 FSAR UPDATE during the injection phase of the transient and is terminated on a refueling water storage tank empty alarm after switchover to cold leg recirculation at a time based on the number of SI and spray pumps operating. The timing of recirculation and spray termination assumed in the LOCA containment analysis are presented in Table 6.2D-17. PGE-10-54 (Reference 20) evaluated an increased containmentspray LOOP delay time of 100 seconds to bound the maximum 4 kV SLUR actuation time. This evaluation was performed only for the limiting Unit 2 cases to assess the impact on the peak containment pressureand temperature. Accumulator Nitrogen Gas Modelinq The accumulator nitrogen gas release is modeled with a flow boundary condition in the LOCA containment model. The nitrogen release rate was conservatively calculated by maximizing the mass available to be injected. The nitrogen gas release rate was used as input for the GOTHIC function, as a specified rate over a fixed time period. Nitrogen gas was released to the containment at a rate of 327.4 Ibm/s. The release begins at 51.9 seconds, the minimum accumulator tank water depletion time. 6.2D.4.1.5 LOCA Containment Integrity Results Plant input assumptions (identified in Section 6.2D.4.1.2) are the same as, or slightly more restrictive, than in the licensing-basis analyses performed with the COCO code (Reference 18). Benchmarking between the Diablo Canyon COCO and GOTHIC models was performed to confirm consistency in the implementation of the plant input values. The containment pressure, steam temperature, and water (sump) temperature profiles of the DEHL peak pressure case are shown in Figures 6.2D-3 through 6.2D-5. Table 6.2D-13 provides the transient sequence of events for the DEHL transient. The containment pressure, steam temperature, and water (sump) temperature profiles of the DEPS long-term EQ temperature transient are shown in Figures 6.2D-6 through 6.2D-81. Tables 6.2D-14 and 6.2-15 presents the sequence of events for the Unit 1 and Unit 2 DEPS transients, respectively. The peak pressure (Figure 6.2D-6) for the DEPS case occurs at 24.1 seconds after the end of the blowdown. The fans begin to cool the containment at 48.7 seconds. Containment sprays begin injecting at 88.01 seconds. The pressure comes down as the steam generators reach equilibrium with the containment environment, but spikes up again at recirculation when the CCW temperature increases and the CCW flow rate to the CFCUs decreases. The sensible heat release from the steam generator secondary system and RCS metal is completed at 3600 seconds, but at 3798 seconds, the RWST reaches a low level alarm and spray flow is terminated. The containment pressure increases for a time and then begins to 1The peak DEPS values are from Unit 2. 6.2D-30 Revision 18 October 2008

DCPP UNITS 1 & 2 FSAR UPDATE decrease over the long term as the RHR heat exchangers and CFCUs remove the heat from the containment. Table 6.2D-21 summarizes the containment peak pressure and temperature results and pressure and temperature at 24 hours for EQ support and the acceptance limits for these parameters. A review of the results presented in Table 6.2D-21 shows that the analysis margin (analysis margin is the difference between the calculated peak pressure and temperature and the acceptance limits) is maintained for Diablo Canyon with replacement steam generators. From the GOTHIC analysis performed in support of the Diablo Canyon replacement steam generator program the containment peak pressure is 41.4 psig. PGE-10-54 (Reference 20) evaluated the increasedESF LOOP delay times that bound the maximum 4 kV SLUR actuation time which resulted in a slight increase in the peak pressure to 41.7 psig. This evaluation was performed only for the limiting Unit 2 DEHL and DEPS minimum ECCS cases, The Unit 1 cases and other Unit 2 cases are bounded and remain based on the delay times associatedwith a LOOP. The long term containment results were not impacted and Aat 24 hours, the maximum containment pressure is 8.9 psig and the maximum temperature is 167.54°F. 6.2D.4.1.6 Conclusion The DCPP containment can adequately account for the mass and energy releases that would result from the replacement steam generator program. The DCPP containment systems will continue to provide sufficient pressure and temperature mitigation capability to ensure that containment integrity is maintained. The containment systems and instrumentation will continue to be adequate for monitoring containment parameters and release of radioactivity during normal and accident conditions and will continue to meet the DCPP licensing basis requirements with respect to GDC -13, -16, -38, -50, and -64 following installation of the replacement steam generators 6.2D.4.2 Steamline Break Containment Response 6.2D.4.2.1 Introduction and Background Containment integrity analyses are performed to ensure that pressure inside containment will remain below the containment building design pressure for a postulated secondary system pipe rupture. The mass and energy release analysis discussed in Section 6.2D.3 is input to this analysis. 6.2D.4.2.2 Input Parameters and Assumptions This section identifies the major input values that are used in the steamline break containment response analysis. The assumed initial conditions and the input assumptions associated with the fan coolers and containment sprays are listed in 6.2D-31 Revision 18 October 2008

DCPP UNITS 1 & 2 FSAR UPDATE Description", and "WCAP-8822(P)/8860(NP), "Mass and Energy Release Following a Steam Line Rupture," August 1983.

9. R. E. Land, Mass and Energy Releases Followinq a Steam Line Rupture, WCAP-8822 (Proprietary), WCAP-8860 (Non-Proprietary), September 1976.

10. T. W. T. Burnett, et al. LOFTRAN Code Description, WCAP-7907-P-A (Proprietary) and WCAP-7907-A (Non-Proprietary), April 1984.

11. M. P. Osborne and D. S. Love, Mass and Energy Releases Following a Steam Line Rupture, Supplement 1 - Calculations of Steam Superheat in Mass/Energy Releases Following a Steamline Rupture, WCAP-8822-S1-P-A (Proprietary),

September 1986.

12. D. S. Huegel, et al. RETRAN-02 Modeling and Qualification for Westinghouse Pressurized Water Reactor Non-LOCA Safety Analyses, WCAP-14882-P-A (Proprietary), April 1999.

13. GOTHIC Containment Analysis Package Technical Manual, Version 7.2, NAI-8907-06, Rev. 15, September 2004.

14. GOTHIC Containment Analysis Package Qualification Report, Version 7.2, NAI-8907-09, Rev. 8, September 2004.

15. License Amendment No. 169 for Kewaunee Nuclear Power Plant, Operating License No. DPR-43 (TAC No. MB6408), September 29, 2003.

16. GOTHIC Containment Analysis Package User Manual, Version 7.2, NAI-8907-02, Rev. 16, September 2004.

17. Brown and York, "Sprays formed by Flashing Liquid Jets", AICHE Journal, Volume 8, #2, May 1962.

18. F. M. Bordelon and E. T. Murphy, Containment Pressure Analysis Code (COCO), WCAP-8327 (Proprietary), WCAP-8326 (Non-Proprietary), July 1974.

19. Letter from Anthony C. McMurtray (NRC) to Thomas Coutu (NMC), "Enclosure 2, Safety Evaluation," September 29, 2003.

20. Westinghouse letter PGE-10-54, Diablo Canyon 230 kV Degraded Voltage Evaluation - EngineeringReport Revision 1, October 15, 2010.

6.2D-34 Revision 18 October 2008

DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.2D-1 SYSTEM PARAMETERS INITIAL CONDITIONS Unit 1 Unit 2 Parameters Value Value Core Thermal Power (MWt) 3479.0 Same RCS Total Flow Rate (Ibm/sec) 36888.88 37222.22 Vessel Outlet Temperature ('F) 615.1 Same Core Inlet Temperature (OF) 549.5 550.1 Vessel Barrel-Baffle Configuration Downflow Upflow Initial Steam Generator Steam Pressure (psia) 881.0 885.0 Steam Generator Design A54 Same Steam Generator Tube Plugging (%) 0 0 Initial Steam Generator Secondary Side Mass (Ibm) 132953.7 Same Assumed Maximum Containment Backpressure (psia) 61.7 Same Accumulator Water volume (ft3) per accumulator 850.0 Same N2 cover gas pressure (psia) 577.2 Same Temperature ('F) 120.0 Same SI Start Time, (sec) [total time from beginning of event which 31.1 31.3 includes the maximum delay from reaching the setpoint] (1) Note: Core thermal power, RCS total flow rate, RCS coolant temperatures, and steam generator secondary side mass include appropriate uncertainty and/or allowance. (1) PGE-10-54 (Reference 20) evaluated an increased SI start time that bounds the maximum 4 kV SLUR actuation time. This evaluation was performed only for the limiting Unit 2 DEHL and DEPS minimum ECCS cases. The Unit 1 cases are bounded by the Unit 2 cases and other Unit 2 cases remain based on the listed delay time associatedwith a LOOP Revision 18 October 2008

DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.2D-13 DOUBLE-ENDED HOT-LEG BREAK SEQUENCE OF EVENTS Time (sec) Event Description 0.0 Break Occurs 1.1 Reactor Trip Occurs on Compensated Pressurizer Pressure Setpoint of 1859.7 psia and SG Throttle Valves Closed 4.0 Low Pressurizer Pressure SI Setpoint = 1694.7 psia Reached (Safety Injection begins w ,**..ut-ayafter a 27 second delay and feedwater control valve starts to close) 4470 Main Feedwater Control Valve Fully Closed 15,54.9 Broken Loop Accumulator Begins Injecting Water 1569.0 Intact Loop Accumulator Begins Injecting Water 23.0 Peak Gas Temperature 23.5 Peak Pressure 24,43.8 End of Blowdown Phase - Transient Mode!ing Termiatcd 30.0 Transient Modeling Terminated Revision 18 October 2008

DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.2D-15 DIABLO CANYON UNIT 2 DOUBLE-ENDED PUMP SUCTION BREAK SEQUENCE OF EVENTS (MINIMUM SAFEGUARDS) Time (sec) Event Description 0.0 Break Occurs and Loss-of-offsite Power is assumed O74 Hi-1 Containment Setpoint (SI Actuation) Reached 1.23 Reactor Trip Occurs on Compensated Pressurizer Pressure Setpoint of 1859.7 psia and SG Throttle Valves Closed 4.20 Low Pressurizer Pressure SI Setpoint = 1694.7 psia Reached (Safety Injection begins after a 27 second delay and feedwater control valve starts to close) 13.2 Main Feedwater Control Valve Closed 1847.5 Broken Loop Accumulator Begins Injecting Water 1"67. 7 Intact Loop Accumulator Begins Injecting Water 23.5 Peak Containment Gas Temperature and Pressure 26.2 End of Blowdown Phase 34-.342.74 Pumped Safety Injection Begins 44.-752.8 CFCUs On 52---1.3 Broken Loop Accumulator Water Injection Ends 53-.-72. 1 Intact Loop Accumulator Water Injection Ends 88 100. 74 Containment Sprays Begin Injecting 20a56. 7 End of Reflood for Minimum Safeguards Case 56"-6. 7 Mass and Energy Release Assumption: Broken Loop SG Equilibration to 61.7 psia 829.363.3 Mass and Energy Release Assumption: Broken Loop SG Equilibration to 40.7 psia 1,536-548.6 Mass and Energy Release Assumption: Intact Loop SG Equilibration to 61.7 psia 1,678.0 Cold-Leg Recirculation Begins 1,741-7830.6 Mass and Energy Release Assumption: Intact Loop SG Equilibration to 39.7 psia 3,600.0 End of Sensible Heat Release from Reactor Coolant System and Steam Generators 3,798.0 Containment Sprays Terminated Revision 18 October 2008

DCPP UNITS 1 & 2 FSAR UPDATE 25,200.021, Switchover to Hot-Leg Recirculation 600.00 Revision 18 October 2008

DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.2D-17 Sheet 1 of 2 DIABLO CANYON CONTAINMENT LOCA INTEGRITY ANALYSIS PARAMETERS Parameter Value Auxiliary Service Water Temperature (OF) 64 RWST Water Temperature (OF) 90 Initial Containment Temperature (OF) 120 Initial Containment Pressure (psia) 16.0 Initial Relative Humidity (%) 18 Net Free Volume (ft3) 2,550,000 Reactor Containment Fan Coolers Total CFCUs 5 Analysis Maximum 3 Analysis Minimum 2 Containment High Setpoint (psig) 5.0 Delay Time (sec) Without Offsite Power 48.0 With 4 kV SLUR actuation 52.0 CCW Flow to the CFCUs (gpm) During Injection 8,000 During Recirculation 7,450 Containment Spray Pumps Total CSPs 2 Analysis Maximum 2 Analysis Minimum 1 Flowrate (gpm) During Injection Table 6.2.D-18 During Recirculation 0 Containment High High Setpoint (psig) 24.7 Spray Delay Time (sec) Without Offsite Power after "P"signal 80 With 4 kV SLUR actuationafter SI signal 100 Containment Spray Termination Time, (sec) Minimum Safeguards 3,798 Maximum Safeguards (1 CSP) 3,018 Maximum Safeguards (2 CSPs) 1,824 Revision 18 October 2008

DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.2D-17 Sheet 2 of 2 Parameter Value ECCS Recirculation ECCS Cold-Leg Recirculation Switchover, sec Minimum Safeguards 1,678 Maximum Safeguards (1 CSP) 1,033 Maximum Safeguards (2 CSPs) 829 Containment ECCS Cold-Leg Recirculation Flow, (gpm) Minimum Safeguards (1 RHR train) 3,252.3 Maximum Safeguards (2 RHR trains) 8,082.4 ECCS Hot-Leg Recirculation Switchover, sec 25,200 Containment ECCS Hot-Leg Recirculation Flow, (gpm) Minimum Safeguards (1 RHR train) 3,071.7 Maximum Safeguards (2 RHR trains) 4,576.8 Component Cooling Water System Total CCW Heat Exchangers 2 Analysis Maximum 2 Analysis Minimum 1 CCW Flow Rate to RHR Heat Exchanger (gpm per available HX) 4,800 ASW Flow Rate to CCW Heat Exchanger (gpm per available HX) 10,300 CCW Misc. Heat Loads (MBTU/hr) During Injection 1.0 During Recirculation 2.0 CCW Flow Rate to Misc. Heat Loads (gpm) During Injection 2,500 During Recirculation 500 (1) PGE-10-54 (Reference 20) evaluated the increased ESF delay times that bound the maximum 4 kV SLUR actuation time. This evaluation was performed only for the limiting Unit 2 DEHL and DEPS minimum ECCS cases. The Unit I cases and other Unit 2 are bounded and remain based on the delay times associatedwith a LOOP. Revision 18 October 2008

DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.2D-21

SUMMARY

OF LOCA PEAK CONTAINMENT PRESSURE AND TEMPERATURES Peak Peak Press @ Temp@ Break Location Pressure Time Gas Temp Time 24 hours 24 hours (psig) (sec) (OF) (sec) (psig) (OF) DEHL 44-441.7 237923,5 264.262.3 24.4230 - - DEPS min SI 39.8 24423.5 259.3 24.423.5 8.9 167.5 Acceptance <47 - - - <50 - Criteria (1) These limiting Unit 2 results are based on the PGE-10-54 (Reference 20) evaluation of the increasedESF delay times that bound the maximum 4 kV SLUR actuation time. Revision 18 October 2008

DCPP UNITS 1 & 2 FSAR UPDATE into the reactor coolant loops. The reactor coolant pumps are assumed to be tripped at the beginning of the accident and the effects of pump coastdown are included in the blowdown analyses. 15.3.1.2 Analysis of Effects and Consequences For loss-of-coolant accidents due to small breaks less than 1 square foot, the NOTRUMP (Reference 12) computer code is used to calculate the transient depressurization of the RCS as well as to describe the mass and enthalpy of flow through the break. The NOTRUMP computer code is a one-dimensional general network code with a number of features. Among these features are the calculation of thermal nonequilibrium in all fluid volumes, flow regime-dependent drift flux calculations with counter-current flooding limitations, mixture level tracking logic in multiple-stacked fluid nodes, and regime-dependent heat transfer correlations. The NOTRUMP small break LOCA emergency core cooling system (ECCS) evaluation model was developed to determine the RCS response to design basis small break LOCAs and to address the NRC concerns expressed in NUREG-061 1, "Generic Evaluation of Feedwater Transients and Small Break Loss-of-Coolant Accidents in Westinghouse-Designed Operating Plants." In NOTRUMP, the RCS is nodalized into volumes interconnected by flowpaths. The broken loop is modeled explicitly, with the intact loops lumped into a second loop. The transient behavior of the system is determined from the governing conservation equations of mass, energy, and momentum applied throughout the system. A detailed description of the NOTRUMP code is provided in References 12 and 13. The use of NOTRUMP in the analysis involves, among other things, the representation of the reactor core as heated control volumes with the associated bubble rise model to permit a transient mixture height calculation. The multinode capability of the program enables an explicit and detailed spatial representation of various system components. In particular, it enables a proper calculation of the behavior of the loop seal during a loss-of-coolant transient. Safety injection flowrate to the RCS as a function of the system pressure is used as part of the input. The SIS was assumed to be delivering water to the RCS 27 seconds after the generation of a safety injection signal. For the analysis, the SIS delivery considers pumped injection flow that is depicted in Figure 15.3-1 as a function of RCS pressure. This figure represents injection flow from the SIS pumps based on performance curves degraded 5 percent from the design head. The 27-second delay includes time required for diesel startup and loading of the safety injection pumps onto the emergency buses. The effect of residual heat removal (RHR) pump flow is not considered here since their shutoff head is lower than RCS pressure during the time portion of the transient considered here. Also, minimum safeguards ECCS capability and operability have been assumed in these analyses. 15.3-3 Revision 19 May 2010 1

DCPP UNITS 1 & 2 FSAR UPDATE A total SI injection delay time of 42 seconds was evaluated in PGE-10-54 (Reference

29) in order to bound the maximum 4 kV SLUR actuation time.

Peak cladding temperature analyses are performed with the LOCTA IV (Reference 4) code that determines the RCS pressure, fuel rod power history, steam flow past the uncovered part to the core, and mixture height history. 15.3.1.3 Results 15.3.1.3.1 Reactor Coolant System Pipe Breaks This section presents the results of a spectrum of small break sizes analyzed. The small break analysis was performed at 102 percent of the Rated Core Power (3411 MWt), a Total Peaking Factor (FQT) of 2.70, a Thermal Design Flow of 87,700 / 88,500 gpm/loop (Unit 1 / Unit 2) and a steam generator tube plugging level of 10 percent. For Unit 2, the small break analysis was performed for the upflow core barrel/baffle configuration and upper head temperature reduction. The limiting small break size was shown to be a 3-inch diameter break in the cold leg. In the analysis of this limiting break, an RCS Tavg window of 577.3 / 577.6 0 F, +50 F, -40 F (Unit 1 / Unit 2) was considered. The high Tavg cases were shown to be more limiting than the Low Tavg cases and therefore are the subject of the remaining discussion. The time sequence of events and the fuel cladding results for the breaks analyzed are shown in Tables 15.3-1 and 15.3-2. During the earlier part of the small break transient, the effect of the break flow is not strong enough to overcome the flow maintained by the reactor coolant pumps through the core as they are coasting down following reactor trip. Therefore, upward flow through the core is maintained. The resultant heat transfer cools the fuel rods and cladding to very near the coolant temperature as long as the core remains covered by a two-phase mixture. This effect is evident in the accompanying figures. The depressurization transients for the limiting 3-inch breaks are shown in Figure 15.3-9. The extent to which the core is uncovered for these breaks is presented in Figure 15.3-11. The maximum hot spot cladding temperature reached during the transient, including the effects of fuel densification as described in Reference 3, is 1391 / 1288 0 F (Unit 1 / Unit 2). The peak cladding temperature transients for the 3-inch breaks are shown in Figure 15.3-13. The top core node vapor temperatures for the 3-inch breaks are shown in Figure 15.3-33. When the mixture level drops below the top of the core, the top core node vapor temperature increases as the steam superheats along the exposed portion of the fuel. The rod film coefficients for this phase of the transients are given in Figure 15.3-34. The hot spot fluid temperatures are shown in Figure 15.3-35 and the break mass flows are shown in Figure 15.3-36. The core power (dimensionless) transient following the accident (relative to reactor scram time) is shown in Figure 15.3-8. The reactor shutdown time (4.7 sec) is equal to 15.3-4 Revision 19 May 2010

DCPP UNITS 1 & 2 FSAR UPDATE the reactor trip signal processing time (2.0 seconds) plus 2.7 seconds for complete rod insertion. During this rod insertion period, the reactor is conservatively assumed to operate at 102 percent rated power. The small break analyses considered 17x1 7 Vantage 5 fuel with IFM's, ZIRLO cladding, and an axial blanket. Fully enriched annular pellets, as part of an axial blanket core design, were modeled explicitly in this analysis. The results when modeling the enriched annular pellets were not significantly different than the results from solid pellet modeling. Several figures are also presented for the additional break sizes analyzed. Figures 15.3-37, 15.3-2, and 15.3-40 present the RCS pressure transient for the 2-, 4-, and 6-inch breaks, respectively. Figures 15.3-38 and 15.3-3 present the core mixture height plots for both breaks. The peak cladding temperature transients for the 2-inch breaks are shown in Figure 15.3-39. The peak cladding temperature transients for the 4-inch breaks are shown in Figure 15.3-4. These results are not available for the 6-inch break because the core did not uncover for this transient. The small break analysis was performed with the Westinghouse ECCS Small Break Evaluation Model (References 12 and 4) approved for this use by the Nuclear Regulatory Commission in May 1985. An approved cold leg SI condensation model, COSI (Reference 26), was utilized as part of the Evaluation Model. The PGE-10-54 (Reference 29) evaluation determined that the additionalECCS delay due to a 4 kV SLUR actuation would have an insignificanteffect on the SBLOCA thermal hydraulic results presented in this section. Therefore, the SBLOCA cases analyzed in this section with an ECCS delay of 27 seconds did not require revision and remain bounding for the 42 second delay associatedwith the maximum 4 kV SLUR actuation time. 15.3.1.4 Conclusions Analyses presented in this section show that the high-head portion of the ECCS, together with the accumulators, provides sufficient core flooding to keep the calculated peak cladding temperatures below required limits of 10 CFR 50.46. Hence adequate protection is afforded by the ECCS in the event of a small break LOCA. 15.3.2 MINOR SECONDARY SYSTEM PIPE BREAKS 15.3.2.1 Identification of Causes and Accident Description Included in this grouping are ruptures of secondary system lines which would result in steam release rates equivalent to a 6-inch diameter break or smaller. 15.3.2.2 Analysis of Effects and Consequences Minor secondary system pipe breaks must be accommodated with the failure of only a small fraction of the fuel elements in the reactor. Since the results of analysis presented 15.3-5 Revision 19 May 2010

DCPP UNITS 1 & 2 FSAR UPDATE

22. Deleted in Revision 12.

23. Deleted in Revision 13.

24. Deleted in Revision 13.

25. Deleted in Revision 13.

54-.26. Thompson, C. M., et al., Addendum to the Westinghouse Small Break LOCA Evaluation Model Usincq the NOTRUMP Code: Safety Injection Into the Broken Loop and the COSI Condensation Model, WCAP-10054-P-A, Addendum 2, Rev. 1, (proprietary), October 1995.

27. T. Q. Nguyen, et. al., Qualification of the PHOENIX-P/ANC Nuclear Design System for Pressurized Water Reactor Cores, WCAP-1 1596-P-A, June 1988.

28. S. L. Davidson, (Ed), et. al., ANC: Westinghouse Advanced Nodal Computer Code, WCAP-10965-P-A, September 1986.

29. Westinghouse letterPGE-10-54, Diablo Canyon 230 k V Degraded Voltage Evaluation- EngineeringReport Revision 1, October 15, 2010.

15.3-13 Revision 19 May 2010

DCPP UNITS 1 & 2 FSAR UPDATE for the DECLG break. These predictions are compared to the predictions based on Equation 15.4.1-1, and additional biases and uncertainties are applied where appropriate. The superposition assumption verification step was performed for the Unit 1 reanalysis (Reference 67). These calculations resulted in an adjustment of the bias and uncertainty that is required for the reanalysis methodology. The estimate of the PCT at 95 percent probability is determined by finding that PCT below which 95 percent of the calculated PCTs reside. This estimate is the licensing basis PCT, under the revised ECCS rule. The results of the Best Estimate LBLOCA analysis are presented in Table 15.4.1-2A. The difference between the 95 percentile PCT and the average PCT increases with each subsequent PCT period, due to propagation of uncertainties. 15.4.1.7A Additional Evaluations Zircaloy Clad Fuel: An evaluation of Zircaloy clad fuel has shown that the Zircaloy clad fuel is bounded by the results of ZIRLO clad fuel analysis. IFBA Fuel: An evaluation of IFBA fuel has shown that the IFBA fuel is bounded by the results of the non-IFBA fuel analysis. TAVG Coastdown: An end-of-cycle, full power TAVG coastdown at 5650 F evaluation was performed and concluded that there would be no adverse effect on the Best Estimate LBLOCA analysis as a TAVG window between 565 and 577.30 F was explicitly modeled in the Best Estimate LBLOCA analysis. These evaluations have been shown to continue to apply for the Unit 1 reanalysis (Reference 67). 15.4.1.8A Unit 1 10 CFR 50.46 Results It must be demonstrated that there is a high level of probability that the limits set forth in 10 CFR 50.46 are met. A total ECCS injection delay time of 42 seconds was evaluated in PGE-10-54 (Reference 73) in orderto bound the maximum 4 kV SLUR actuation time. The evaluation was performed for the limiting case and a minor PCTpenalty was assessed per 10 CFR 50.46 due to the estimated additionalcore heatup that could occurdue to the increased ECCS delay. Since minor PCT assessments per 10 CFR 50.46 do not require a complete re-analysis, the spectrum of cases for the Best Estimate LBLOCA results presentedin this section remain based on the 27 second ECCS delay time associatedwith a LOOP. These Best Estimate LBLOCA results with the PCTpenalty assessedand tracked per 10 CFR 50.46 bound the maximum 4 kV SLUR action time. The demonstration that these limits are met is as follows: 15.4-18 Revision 19 May 2010

DCPP UNITS 1 & 2 FSAR UPDATE As discussed in Section 15.4.1.2.6, the large break LOCA transient can be divided into convenient time periods in which specific phenomena occur, such as various hot assembly heatup and cooldown transients. For a typical large break, the blowdown period can be divided into the critical heat flux (CHF) phase, the upward core flow phase, and the downward core flow phase. These are followed by the refill, reflood, and long-term cooling periods. Specific important transient phenomena and heat transfer regimes are discussed below, with the transient results shown in Figures 15.4.1-1B to 15.4.1-12B. 15.4.1.8B 10 CFR 50.46 Requirements It must be demonstrated that there is a high level of probability that the limits set forth in 10 CFR 50.46 are met. A total ECCS injection delay time of 42 seconds was evaluated in PGE-10-54 (Reference 73) in order to bound the maximum 4 kV SLUR actuation time. The evaluation was performed for the limiting case and a minor PCT penalty was assessedper 10 CFR 50.46 due to the estimated additionalcore heatup that could occur due to the increased ECCS delay. Since minor PCT assessmentsper 10 CFR 50.46 do not require a complete re-analysis, the spectrum of cases for the Best Estimate LBLOCA results presentedin this section remain based on the 27 second ECCS delay time associatedwith a LOOP. These Best Estimate LBLOCA results with the PCT penalty assessedand tracked per 10 CFR 50.46 bound the maximum 4 kV SLUR action time. The demonstration that these limits are met is as follows: (1) Since the resulting PCT for the limiting case is 1872 °F, the analysis confirms that 10 CFR 50.46 acceptance criterion (b)(1), i.e., "Peak Cladding Temperature less than 2200 OF", is met. The results are shown in Table 15.4.1-2B. (2) Since the resulting local maximum oxidation (LMO) for the limiting case is 1.64 percent, the analysis confirms that 10 CFR 50.46 acceptance criterion (b)(2), i.e., "Local Maximum Oxidation of the cladding less than 17 percent," is met. The results are shown in Table 15.4.1-2B. (3) The limiting hot fuel assembly rod has a calculated maximum oxidation of 0.17 percent. Since this is the hottest fuel rod within the core, the calculated maximum oxidation for any other fuel rod would be less than this value. For the low power peripheral fuel assemblies, the calculated oxidation would be significantly less than this maximum value. The core wide oxidation (CWO) is essentially the sum of all calculated maximum oxidation values for all of the fuel rods within the core. Therefore, a detailed CWO calculation is not needed because the calculated sum will always be less than 0.17 percent. Since the resulting CWO is conservatively assumed to be 0.17 percent, the analysis confirms that 10 CFR 50.46 acceptance criterion (b)(3), i.e., "Core-Wide Oxidation less than 1 percent," is met. The results are shown in Table 15.4.1-2B. 15.4-23 Revision 19 May 2010

DCPP UNITS 1 & 2 FSAR UPDATE

72. PGE-10-56, "PG&E Diablo Canyon Units 1 and 2, Steam Generator Tube Rupture Margin to Overfill Analysis (CN-CRA-10-45 Rev. 0)," October 18, 2010

73. Westinghouse letter PGE-10-54, Diablo Canyon 230 kV Degraded Voltage Evaluation - EngineeringReport Revision 1, October 15, 2010.

15.4-72 Revision 19 May 2010

DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.3-1 TIME SEQUENCE OF EVENTS - SMALL BREAK LOCA Unit 1 2-inch 3-inch 4-inch 6-inch Transient Initiated, sec 0 0 0 0 Reactor Trip Signal, sec 43.58 18.32 10.55 5.9 Safety Injection Signal, sec 58 26.8 16.57 8.58 Safety Injection Begins"1 ', sec 85 53.8 43.57 35.58 Loop Seal Clearing Occursp 2 ), sec 1197 514 300 110 Top of Core Uncovered"'), sec 1796 941 635 N/A Accumulator Injection Begins, sec N/A 1984 885 385 Top of Core Recovered, sec 6500 3170 2545 N/A RWST Low Level, sec 1700 1689 1664 1640 Unit 2 2-inch 3-inch 4-inch 6-inch Transient Initiated, sec 0 0 0 0 Reactor Trip Signal, sec 44.72 18.78 10.82 6.11 Safety Injection Signal, sec 59.45 27.41 16.68 9 Safety Injection Begins"1 ', sec 86.45 54.41 43.68 36 Loop Seal Clearing Occurs(2 ), sec 1360 575 290 120 Top of Core Uncovered"'), sec 3200 722 770 N/A Accumulator Injection Begins, sec N/A 3050 985 400 Top of Core Recovered, sec N/A 3215 1630 N/A RWST Low Level, sec 1708 1690 1666 1641 (1) These SBLOCA cases assume Safety Injection flow begins 27.0 seconds (SI delay time) after the safety injection signal is reached based on a LOOP. The evaluation in PGE-1O-54 (Reference 29) determined that an increasedSI injection delay time of 42 seconds had an insignificanteffect on these SBLOCA thermal hydraulic results such that they remain conservatively bounding for the maximum SLUR actuation time. (2) Loop seal clearing is considered to occur when the broken loop seal vapor flow rate is sustained above 1 Ibm/s. (3) Top of core uncovery time is taken as the time when the core mixture level is sustained below the top of the core elevation. Revision 19 May 2010

DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.3-2 FUEL CLADDING RESULTS - SMALL BREAK LOCA Unit 1 2-inch 3-inch 4-inch PCT (-F) 907 1391 1241 PCT Time (s) 2173.3 1891.7 975.8 PCT Elevation (ft) 10.75 11.25 11.00 Burst Time (s) () N/A N/A N/A Burst Elevation (ft) (1) N/A N/A N/A Maximum Hot Rod Transient ZrO2 (%) 0.01 0.38 0.07 Maximum Hot Rod Transient ZrO2 Elev. (ft) 10.75 11.25 10.75 Hot Rod Average Transient ZrO2 (%) 0.01 0.06 0.01 Unit 2 2-inch 3-inch 4-inch PCT (OF) 814 1288 1004 PCT Time (s) 4838.3 1961.8 1079.2 PCT Elevation (ft) 11.00 11.25 10.75 Burst Time (s) (1) N/A N/A N/A Burst Elevation (ft) (1) N/A N/A N/A Maximum Hot Rod Transient ZrO2 (%) 0.01 0.18 0.01 Maximum Hot Rod Transient ZrO2 Elev. (ft) 11.00 11.25 10.75 Hot Rod Average Transient ZrO2 (%) 0 0.03 0.01 (1) Burst was not predicted to occur for any break size. (2) The evaluation in PGE-10-54 (Reference 29) determined that an increased SI injection delay time of 42 seconds had an insignificant effect on these SBLOCA thermal hydraulicresults such that they remain conservatively bounding for the maximum SLUR actuation time. Revision 19 May 2010

DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.4.1-1A UNIT 1 BEST ESTIMATE LARGE BREAK LOCA TIME SEQUENCE OF EVENTS B 0 sec. Break occurs L Reactor trip (pressurizer pressure or high containment pressure) 0 Pumped SI signal (pressurizer pressure or high containment pressure) W Accumulator injection begins D Pumped ECCS iniection begins (offsite power available) 0 Containment heat removal system starts (offsite power available) W 20-25 sec. End of bypass N End of blowdown R E Pumped ECCS injection begins (loss of offsite power) (1) F I Containment heat removal system starts (loss of offsite power) L L 35-40 sec. Bottom of core recovery R E F Accumulators empty L 0 0 D 5 min. Core quenched L 0 N G Switch to cold leg recirculation on RWST low level alarm T E R M Switch to hot leg/cold leg recirculation C 0 0 L I N G (1) A total SI injection delay time of 42 seconds that bounds the maximum 4 kV SLUR actuation time was evaluated in PGE-10-54 (Reference 73). However, these reportedsequence times still remain characteristicfor the limiting Best Estimate LBLOCA case. Revision 18 October 2008

DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.4.1-1B UNIT 2 BEST ESTIMATE LARGE BREAK SEQUENCE OF EVENTS FOR LIMITING PCT CASE Event Time (sec) Start of Transient 0.0 Safety Injection Signal 6.0 Accumulator Injection Begins 13.0 End of Blowdown 29.0 Safety Injection Begins (1) 33.0 Bottom of Core Recovery 37.0 Accumulator Empty 48.0 PCT Occurs 110.0 Hot Rod Quench 285.0 End of Transient 500.0 (1) A total ECCS injection delay time of 42 seconds was evaluated in PGE-10-54 (Reference 73) in order to bound the maximum 4 kV SLUR actuationtime. However, these reportedsequence times still remain characteristicfor the limiting Best Estimate LOCA case. Revision 18 October 2008

DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.4.1-2A UNIT 1 BEST ESTIMATE LARGE BREAK LOCA ANALYSIS RESULTS Component Blowdown Peak First Reflood Peak Second Reflood Peak PCTaverage <1508oF <1681'F <13840 F 9 5% PCT <1760OF <1976°F <1964 0 F Maximum Oxidation <11% Total Oxidation <0.89% (1) A total SI injection delay time of 42 seconds that bounds the maximum 4 kV SLUR actuationtime was evaluated in PGE-10-54 (Reference 73) and a PCTpenalty was assessed per 10 CFR 50.46 with respect to these limiting Unit 1 Best Estimate LBLOCA results. However, these reportedoxidation results remain conservatively bounding, Revision 18 October 2008

DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.4.1-2B UNIT 2 BEST ESTIMATE LARGE BREAK LOCA ANALYSIS RESULTS Result Criterion 95/95 PCT 1,872°F < 2,200°F 95/95 LMO 1.64% < 17% 95/95 CWO 0.17% <1% PCT - Peak Cladding Temperature LMO - Local Maximum Oxidation CWO - Core Wide Oxidation (1) A total SI injection delay time of 42 seconds that bounds the maximum 4 kV SLUR actuation time was evaluated in PGE-10-54 (Reference 73) and a PCTpenalty was assessedper 10 CFR 50.46 with respect to these limiting Unit 2 Best Estimate LBLOCA results. However, these reported oxidation results remain conservatively bounding, Revision 18 October 2008

DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.4.1-3A Sheet 1 of 4 UNIT 1 KEY BEST ESTIMATE LARGE BREAK LOCA PARAMETERS AND REFERENCE TRANSIENT ASSUMPTIONS Parameter Reference Transient Uncertainty or Bias 1.0 Plant Physical Description

a. . Dimensions Nominal APCTMOD

b. Flow resistance Nominal APCTMOD C. Pressurizer location Opposite broken loop Bounded

d. Hot assembly location Under limiting location Bounded

e. Hot assembly type 17x17 V5+ w/ZIRLO clad Bounded

f. SG tube plugging level High (15%) Bounded(a) 2.0 Plant Initial Operating Conditions 2.1 Reactor Power

a. Core average linear heat rate Nominal - 100% of uprated power (3411 APCTpD MWt)

b. Peak linear heat rate (PLHR) Derived from desired Technical APCTPD Specifications (TS) limit and maximum baseload

c. Hot rod average linear heat rate (HRFLUX) Derived from TS FAH APCTPD Revision 18 October 2008

DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.4.1-3A Sheet 2 of 4 Parameter Reference Transient Uncertainty or Bias

d. Hot assembly average heat rate HRFLUX/1.04 APCTPD

e. Hot assembly peak heat rate PLHR/1.04 APCTpD

f. Axial power distribution (PBOT, PMID) Figure 3-2-10 of Reference 9 APCTPD

g. Low power region relative power (PLOW) 0.3 Bounded(a)

h. Hot assembly burnup BOL Bounded

i. Prior operating history Equilibrium decay heat Bounded

j. Moderator Temperature Coefficient (MTC) TS Maximum (0) Bounded

k. HFP boron 800 ppm Generic 2.2 Fluid Conditions

a. Tavg Max. nominal Tavg = 577.3°F Nominal is bounded, uncertainty is in APCTic

b. Pressurizer pressure Nominal (2250.0 psia) APCTic

c. Loop flow 85000 gpm APCTMOD(b)

d. TUH Best Estimate 0

e. Pressurizer level Nominal (1080 ft3) 0

f. Accumulator temperature Nominal (102.5 0 F) APCTjc

g. Accumulator pressure Nominal (636.2 psia) ARCTIc Revision 18 October 2008

DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.4.1-3A Sheet 3 of 4 Parameter Reference Transient Uncertainty or Bias

h. Accumulator liquid volume 3 Nominal (850 ft ) APCTc

i. Accumulator line resistance Nominal APCTIc

j. Accumulator boron Minimum Bounded 3.0 Accident Boundary Conditions

a. Break location Cold leg Bounded

b. Break type Guillotine APCTMOD C. Break size Nominal (cold leg area) APCTMOD

d. Offsite power Off (RCS pumps tripped) Bounded(a)

e. Safety injection flow Minimum Bounded

f. Safety injection temperature Nominal (680 F) APCT~c

g. Safety injection delay Max delay <-{1 7.0 sec (with offsite power) Bounded

                                                                   < 27.0 sec (with LOOP)
                                                               <-42.0 sec (with 4 kV SLUR actuation)

h. Containment pressure Minimum based on WC/T M&E Bounded

i. Single failure ECCS: Loss of 1 SI train Bounded

j. Control rod drop time No control rods Bounded Revision 18 October 2008

DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.4.1-3A Sheet 4 of 4 Parameter Reference Transient Uncertainty or Bias 4.0 Model Parameters

a. Critical Flow Nominal (as coded) APCTMOD

b. Resistance uncertainties in broken loop Nominal (as coded) APCTMoD

c. Initial stored energy/fuel rod behavior Nominal (as coded) APCTMoD

d. Core heat transfer Nominal (as coded) APCTMoD

e. Delivery and bypassing of ECC Nominal (as coded) Conservative

f. Steam binding/entrainment Nominal (as coded) Conservative

g. Noncondensable gases/accumulator nitrogen Nominal (as coded) Conservative

h. Condensation Nominal (as coded) APCTMoD (a) Confirmed by plant-specific analysis.

(b) Assumed to be result of loop resistance uncertainity. Notes:

1. APCTMOD indicates this uncertainty is part of code and global model uncertainty.

2. APCTPD indicates this uncertainty is part of power distribution uncertainty.

3. APCTIC indicates this uncertainty is part of initial condition uncertainty.

Revision 18 October 2008

DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.4.1-38 Sheet 1 of 3 UNIT 2 KEY BEST ESTIMATE LARGE BREAK LOCA PARAMETERS AND INITIAL TRANSIENT ASSUMPTIONS Parameter Initial Transient Range/Uncertainty 1.0 Plant Physical Description

a. Dimensions Nominal Sampled

b. Flow resistance Nominal Sampled

c. Pressurizer location Opposite broken loop Bounded

d. Hot assembly location Under limiting location Bounded

e. Hot assembly type 17x17 V5 + with ZIRLOTM cladding, Bounded Non-IFBA

f. Steam generator tube plugging level High (15%) Bounded(a) 2.0 Plant Initial Operating Conditions 2.1 Reactor Power

a. Core average linear heat rate (AFLUX) Nominal - Based on 100% thermal power Sampled (3468 MWt)

b. Hot rod peak linear heat rate (PLHR) Derived from desired Technical Sampled Specification limit FQ = 2.7 and maximum baseload FQ = 2.1

c. Hot rod average linear heat rate (HRFLUX) Derived from Technical Specification Sampled FAH = 1.7

d. Hot assembly average heat rate (HAFLUX) HRFLUX/1.04 Sampled

e. Hot assembly peak heat rate (HAPHR) PLHR/1.04 Sampled

f. Axial power distribution (PBOT, PMID) Figure 15.4.1-15B Sampled

g. Low power region relative power (PLOW) 0.3 Bounded(a)

h. Cycle burnup -2000 MWD/MTU Sampled

i. Prior operating history Equilibrium decay heat Bounded Revision 19 May 2010

DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.4.1-3B Sheet 2 of 3 Parameter Initial Transient RangelUncertainty 2.0 Plant Initial Operating Conditions (continued)

j. Moderator temperature coefficient Technical Specification Maximum (0) Bounded

k. HFP boron 800 ppm Generic 2.2 Fluid Conditions

a. Tavg High Nominal Tavg = 577.6'F Bounded(a), Sampled

b. Pressurizer pressure Nominal (2250.0 psia) Sampled

c. Loop flow 85,000 gpm Bounded

d. Upper head fluid temperature Tcold 0

e. Pressurizer level Nominal 0

f. Accumulator temperature Nominal (102.5°F) Sampled

g. Accumulator pressure Nominal (636.2 psia) Sampled 3

h. Accumulator liquid volume Nominal (850 ft ) Sampled

i. Accumulator line resistance Nominal Sampled

j. Accumulator boron Minimum (2200 ppm) Bounded 3.0 Accident Boundary Conditions

a. Break location Cold leg Bounded

b. Break type Guillotine (DECLG) Sampled

c. Break size Nominal (cold leg area) Sampled

d. Offsite power Loss of offsite power Bounded(a)

e. Safety injection flow Minimum Bounded

f. Safety injection temperature Nominal (68°F) Sampled

g. Safety injection delay Maximum delay !517.0 sec (with offsite power) Bounded

                                                          !527.0 sec (with LOOP) 5 42.0 sec (with 4 kV SLUR actuation) (27.0-seG)

Revision 19 May 2010

DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.4.1-38 Sheet 3 of 3 Parameter Initial Transient RangelUncertainty 3.0 Accident Boundary Conditions (continued)

h. Containment pressure Bounded - Lower (conservative) Bounded than pressure curve shown in Figure 15.4.1-14B.

i. Single failure ECCS: Loss of one safety injection train; Bounded Containment pressure: all trains operational

j. Control rod drop time No control rods Bounded 4.0 Model Parameters

a. Critical flow Nominal (CD = 1.0) Sampled

b. Resistance uncertainties in broken loop Nominal (as coded) Sampled

c. Initial stored energy/fuel rod behavior Nominal (as coded) Sampled

d. Core heat transfer Nominal (as coded) Sampled

e. Delivery and bypassing of emergency core coolant Nominal (as coded) Conservative

f. Steam binding/entrainment Nominal (as coded) Conservative

g. Noncondensable gases/accumulator nitrogen Nominal (as coded) Conservative

h. Condensation Nominal (as coded) Sampled (a) Per Confirmatory Study results (Section 15.4.1.1.2.5)

Revision 19 May 2010

DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.4.1-7A Sheet 1 of 3 UNIT 1 PLANT OPERATING RANGE ALLOWED BY THE BEST-ESTIMATE LARGE BREAK LOCA ANALYSIS Parameter Operating Range 1.0 Plant Physical Description

a. Dimensions No in-board assembly grid deformation assumed due to LOCA + SSE

b. Flow resistance N/A

c. Pressurizer location N/A

d. Hot assembly location Anywhere in core

e. Hot assembly type Fresh 17X17 V5, ZIRLO, or Zircaloy cladding, 1.5X IFBA or non-IFBA

f. SG tube plugging level <15%

g. Fuel assembly type Vantage 5, ZIRLO, or Zircaloy cladding, 1.5X IFBA or non-IFBA 2.0 Plant Initial Operating Conditions 2.1 Reactor Power

a. Core average linear heat rate Core power < 102% of 3411 MWt

b. Peak linear heat rate FQ < 2.7

c. Hot rod average linear heat rate FAH < 1.7

d. Hot assembly average linear heat rate PHA -- 1.57

e. Hot assembly peak linear heat rate FQHA < 2.7/1.04 Revision 19 May 2010

DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.4.1-7A Sheet 2 of 3 Parameter Operating Range

f. Axial power distribution (PBOT, PMID) Figure 15.4.1-15A

g. Low power region relative power (PLOW) 0.3 < PLOW < 0.8

h. Hot assembly burnup <75,000 MWD/MTU, lead rod

i. Prior operating history All normal operating histories

j. MTC *0 at HFP

k. HFP boron Normal letdown 2.2 Fluid Conditions

a. Tavg 560.0 < Tave < 582.3-F

b. Pressurizer pressure 2190 < PRCS -<2310 psia

c. Loop flow > 85,000 gpm/loop

d. TUH Current upper internals

e. Pressurizer level Normal level, automatic control

f. Accumulator temperature 85 < accumulator temperature < 120OF

g. Accumulator pressure 579 < PACC < 664 psig

h. Accumulator volume 814 < Vacc < 886 ft 3

i. Accumulator fL/D Current line configuration Revision 19 May 2010

DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.4.1-7A Sheet 3 of 3 Parameter Operating Range

j. Minimum accumulator boron 2!2200 ppm 3.0 Accident Boundary Conditions

a. Break location N/A

b. Break type N/A

c. Break size N/A

d. Offsite power Available or LOOP

e. Safety injection flow Figure 15.4.1-13A

f. Safety injection temperature 46 < SI Temperature < 90°F

g. Safety injection delay *A17 seconds (with offsite power)

_<27 seconds (with LOOP)

                                                     < 42.0 sec (with 4 kV SLUR actuation)

h. Containment pressure Bounded - see Figure 15.4.1-14A

i. Single failure Loss of one train

j. Control rod drop time N/A Revision 19 May 2010

DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.4.1-7B Sheet 1 of 2 UNIT 2 PLANT OPERATING RANGE ALLOWED BY THE BEST-ESTIMATE LARGE BREAK LOCA ANALYSIS Parameter Operating Range 1.0 Plant Physical Description a) Dimensions No in-board assembly grid deformation during LOCA + SSE b) Flow resistance N/A c) Pressurizer location N/A d) Hot assembly location Anywhere in core interior (149 locations)(a) e) Hot assembly type Fresh 17x1 7 V5+ fuel with ZIRLOTM cladding f) Steam generator tube plugging level < 15% g) Fuel assembly type 17x17 V5+ fuel with ZIRLOTM cladding, non-IFBA or IFBA 2.0 Plant Initial Operating Conditions 2.1 Reactor Power a) Core average linear heat rate Core power_5 100.3% of 3,468 MWt b) Peak linear heat rate FQ - 2.7 c) Hot rod average linear heat rate FAH -51.7 d) Hot assembly average linear heat rate PHA < 1.7/1.04 e) Hot assembly peak linear heat rate FQHA < 2.7/1.04 f) Axial power distribution (PBOT, PMID) See Figure 15.4.1-15B. g) Low power region relative power (PLOW) 0.3 5 PLOWS< 0.8 h) Hot assembly burnup < 75,000 MWD/MTU, lead rod(a) i) Prior operating history All normal operating histories j) Moderator temperature coefficient 5 0 at HFP k) HFP boron (minimum) 800 ppm (at BOL) 2.2 Fluid Conditions a) TaV9 565 - 50 F S Tavg 5 577.6 + 50F b) Pressurizer pressure 2250 - 60 psia S PRCS -52250 + 60 psia Revision 18 October 2008

DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.4.1-7B Sheet 2 of 2 Parameter Operating Range c) Loop flow --85,000 gpm/loop d) TUH Converted upper internals, TCOLD UH e) Pressurizer level Nominal level, automatic control f) Accumulator temperature 85°F : TAcc - 120°F g) Accumulator pressure 579 psia < PACC < 664 psia h) Accumulator liquid volume 814 ft3 < VAcc 5 886 ft3 i) Accumulator fL/D Current line configuration j) Minimum accumulator boron > 2200 ppm 3.0 Accident Boundary Conditions a) Break location N/A b) Break type N/A c) Break size N/A d) Offsite power Available or LOOP e) Safety injection flow See Figure 15.4.1-13B. f) Safety injection temperature 46°F < SI Temp < 90°F g) Safety injection delay 5 17 seconds (with offsite power)

                                                                     < 27 seconds (with LOOP) 5 42.0 sec (with 4 kV SLUR actuation) h)  Containment pressure                                      See Figure 15.4.1-14B and raw data in Table 15.4.1-5B.

i) Single failure All trains operable(b) j) Control rod drop time N/A (a) 44 peripheral locations will not physically be lead power assembly. (b) Analysis considers loss of one train of pumped ECCS. Revision 18 October 2008

Enclosure Attachment 5 PG&E Letter DCL-1 1-072 Commitments Commitment 1 In order to ensure control of the setpoints for the proposed changes to TS SR 3.3.5.3 and the TS SR 3.3.5.3 Bases, the 10 CFR 50.59 controlled surveillance test procedures applicable to TS SR 3.3.5.3 will be updated as required as part of implementation of the amendment for each unit. Commitment 2 The "Equipment Control Guidelines" (ECGs) will be updated as part of implementation of the amendment for each unit to identify the methodologies used to determine the as-found and as-left tolerances. The ECGs are documents controlled under 10 CFR 50.59 and are incorporated into the FSAR by reference.}}