DCL-10-028, Diablo Canyon, Units 1 and 2, Emergency License Amendment Request 10-02, One Time Revision to Technical Specification 3.8.1, AC Sources - Operating.

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Diablo Canyon, Units 1 and 2, Emergency License Amendment Request 10-02, One Time Revision to Technical Specification 3.8.1, AC Sources - Operating.
ML100710749
Person / Time
Site: Diablo Canyon  Pacific Gas & Electric icon.png
Issue date: 03/11/2010
From: Becker J R
Pacific Gas & Electric Co
To:
Document Control Desk, Office of Nuclear Reactor Regulation
References
DCL-10-028
Download: ML100710749 (33)
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Text

Pacific Gas and Electric Company* March 11,2010 PG&E Letter DCL-10-028 U,S, Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D,C, 20555-0001 Docket No, 50-275 , OL-DPR-80 Docket No. 50-323 , OL-DPR-82 Diablo Canyon Units 1 and 2 Emergency License Amendment Request 10-02 James R. Becker Site Vice Pr es ident D i ablo Canyon Power Plant M.il Cod. 104/5/601 0, Box 56 Avil. Beach , CA 93424 805 , 545 ,3 462 Intarn.l: 691.3462 Fax: 805,545,6445 10 CFR 50.90 One Time Revision to Technical Specification 3.8.1, " AC Sources -Operating" Pursuant to 10 CFR 50.90, Pacific Gas and Electric (PG&E) hereby requests a License 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 a one-time change to Technical Specification (TS) 3.8.1, "AC Sources -Operating," Condition A Required Action A.2 completion time from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> to provide adequate time to implement compensatory actions, post-maintenance testing, return inoperable equipment to operable status, and review documentation necessary to assure proper completion of these actions. This amendment request represents a risk-informed licensing change. The proposed changes meet the criteria of Regulatory Guide 1.174, " An Approach for Using Probabilistic Risk Assessment i n Risk-I nformed Decisions on Plant-Specific Changes to the Licensing Basis," for risk-informed changes. The enclosure contains a description of the proposed changes, the supporting technical analyses , and the no significant hazards consideration determination. Attachments 1 and 2 contain marked-up and retyped (clean) TS pages, respectively.

Attachments 3, 4, 5, and 6 contain PRA documentation. PG&E has determined that this LAR does not involve a significant hazard consideration as determined per 10 CFR 50.92. Pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment needs to be prepared in connection with the issuance of this amendment.

This LAR i s submitted on an emergency basis to allow continued operation of DCPP Units 1 and 2 at the licensed core power level while in TS 3.8.1, Required Action A.2 for an additional 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. A mem b er of the STARS (S t rategic T eaming and R esource Sharing) Alliance Callaway. Comanche Peak. Diabl o Canyon. Palo Verde. San Onofre. South Texas P roject. Wolf Creek Document Control Desk March 11,2010 Page 2 PG&E Letter DCL-1 0-028 PG&E requests appro v al of this LAR no later than 1700 PST on March 1 2 , 2010. Also , PG&E requests the license amendment(s) be made effecti v e upon NRC issuance , to be implemented on the date of issuance. In accordance with site administrative pro c edures and the Quality Assurance Program, the proposed amendment has been reviewed by the Plant Staff Review Committee.

Pursuant to 10 CFR 50.91 , a copy of this proposed amendmen t is being sent to the California Department of Publ i c Health. PG&E makes no regulatory commitments (as defined by NEI 99-0 4) in th i s l e tt e r. T his letter includes no revisions to e xi sting regulatory commitments. If you have any quest i ons 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. ecker S it e V i ce Pr esi d e nt LMP1/3386/N50301167 Enclosure cc: Gary W. Butner, California Department of Public Health Diablo Distribution cc/enc: Elmo E. Collins , NRC Region IV Michael S. Peck , NRC , Senior Resident Inspector Alan B. Wang , NRC Project Manager , Office of NRR A mem b e r of t h e S T ARS (Strategic Teaming and R esource Sharing) A ll I ance Callaway

  • Comanc h e P e ak
  • Diab l o Canyon
  • PaLo Verde
  • S an Onofre
  • Wolf Creek Enclosure PG&E Letter DCL-10-028 Evaluation of the Proposed Change

Subject:

Emergency License Amendment Request 10-02 One Time Revision to Technical S pecification 3.8.1, "AC Sources -

Operating"

1.

SUMMARY

DESCRIPTION

2. DETAILED DESCRIPTION
3. TECHNICAL EVALUATION
4. REGULATORY EVALUATION 4.1 Applicable Regulatory Requirements/Criteria 4.2 Precedent 4.3 Significant Haza rds Consideration

4.4 Conclusions

5. ENVIRONMENTAL CONSIDERATIONS
6. REFERENCES

ATTACHMENTS:

1. Technical Specification Page Markups
2. Retyped Technical Specification Pages
3. PRA10-03 Revision 0
4. History DCPP PRA Model Development and Update
5. Summary Statement of Diablo Canyon Power Plant PRA Model Capability for Use in TS 3.8.1 Completion Time Extension submittal
6. Impacts of PRA Open Items/Gaps on Application

Enclosure PG&E Letter DCL-10-028

1.

SUMMARY

DESCRIPTION This letter is a request to amend Oper ating Licenses DPR-80 and DPR-82 for

Units 1 and 2 of the Di ablo Canyon Power Plant (DCPP), respectively.

This License Amendment Request (LAR) proposes a one-time change to

Technical Specification (TS) 3.8.1, "AC Sources - Operating," Condition A Required Action A.2 72-hour completion time (CT) to be extended to 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br />.

This LAR is submitted on an emergency basis to allow operation of DCPP Units 1 and 2 at the licensed core power level wh ile in TS 3.8.1, Required Action A.2, until corrective action can be taken to exit the required action.

On March 9, 2010, at 21:58 PDT, DCPP ope rators entered TS 3.8.1 Action A.2 "One required offsite circuit inoperable" for both units due to compensatory measures taken to address a nonconservative TS 3.3.5, "Loss of Power (LOP)

Diesel Generator (DG) Start Instrumentation." Accident scenarios involving loss of coolant accident (LOCA) and degraded offs ite power were postulated. While attempting to analyze the consequences of these scenarios, PG&E concluded both units were in an Unanalyzed Condition. To ensure class 1E loads do not fail to automatically transfer to emergen cy AC power during this new scenario, operators took compensatory measures. These compensatory measures placed both units in TS 3.8.1 Action A.2, which has a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> completion time.

An additional 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> would provide adeq uate time to implement corrective actions, post-maintenance testing, and return inoperable equipment to operable status.

The probabilistic risk assessment conduct ed for this request conservatively assumed a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> extension to the comple tion time for TS 3.8.1 to be bounding of the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> ext ension being requested.

2. DETAILED DESCRIPTION Proposed Amendment TS 3.8.1, "AC Sources - Operating," Condition A Required Action A.2 72-hour completion time to be extended on a one-time basis to 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> by adding the following footnote:

1 Enclosure PG&E Letter DCL-10-028

(1) For the DCPP Unit 1 and 2 Marc h 9, 2010 entry into Technical Specification 3.8.1, the required offsite circui t may be inoperable for a period not to exceed 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br />. U pon completion of modifications and restoration, this footnote is no longer applicable and will expire at 2158 PST on March 13, 2010.

The proposed TS changes are noted on the marked-up TS page provided in . The proposed retyped TS is provided in Attachment 2.

Description of Class 1E Alternating Current (AC) Electrical Sources Electric loads important to safety in a nuclear power plant are served by an electric power system pursuant to GDC 17. Electric power from the transmission network (i.e. the "preferred" source) to t he onsite electric distribution system is supplied by two physically independent circ uits designed and located so as to

minimize to the extent practical the lik elihood of their simultaneous failure under operating and postulated accident and envir onmental conditions. DCPP has two switchyards which are interconnected to PG&E' s electric grid via two 230 kilovolt (kV) and three 500 kV lines emanating from their respective switchyards; these switchyards are physically and electric ally separated and independent of each other. A combination of either of the 230 kV circuits and one of the 500 kV circuits provides independent sources of offsite power. The other 230 kV and 500 kV circuits provide capability beyond that required to meet minimum NRC regulatory requirements to ensure reliability of the offsite power system

s. The 230 kV System is a shared offsite s ource that provides startup and standby power to both units, and is immediatel y available following a loss-of-coolant accident (LOCA) to assure that core cooling, containment integrity, and other

vital safety functions are maintained.

The 500 kV System, in addition to providing for transmission of the plant's power output, also provides a delayed access source of offsite power after the main generator is disconnected. The 500 kV backfeed also assures that specified acceptable fuel design limits and

design conditions of the reactor coolant pressure boundary are not exceeded as a result of anticipated operational occurrences.

DCPP TS 3.8.1, "AC Sources

- Operating," specifies c ontrol requirements for the Class 1E AC electrical power distributi on system. The Class 1E AC distribution system for each unit is normally fed by power generated by that unit through the auxiliary transformers. However, as ba ckup, the Class 1E AC distribution system can be fed from the two offsite power sources (from the 500 kV system through the auxiliary transformers and from the 230 kV system th rough the startup transformers) and from onsite vital standby power sources (three DGs for each 2

Enclosure PG&E Letter DCL-10-028 unit). As required by 10 CFR 50, Appen dix A, GDC 17, the design of the AC electrical power system provides independence and redundancy to ensure an available s ource of power to the Engi neered Safety Features (ESF) systems.

The Class 1E AC distribution system fo r each unit is divided into three independent load groups (designated 4.16 kV buses F, G and H) so that the loss of any one group or bus does not prevent the minimum safety functions from being performed. Each of these load groups or safety related vital buses has connections to two offsite power sources and a single dedicated DG.

Each unit has a start-up transformer (SUT) (1-1, 2-1) which converts the shared

offsite 230 kV source to 12 kV for the unit 12 kV startup bus. The unit 12 kV startup bus supplies another SUT (1-2, 2-

2) that coverts t he 12 kV startup bus voltage to 4.16 kV.

A detailed description of the offsite power network and the circuits to the Class 1E buses is found in the DCPP Final Safety Analysis Report (FSAR), Chapter 8.

A single line diagram of the AC distribution system is shown in Figure 1 of this enclosure.

Figure 1 DCPP Electrical Distribution Overview The onsite standby power source for each Class 1E AC bus is a dedicated emergency diesel generator (DG). Each DG automatically starts on a safety injection (SI) signal, undervoltage at the 4 kV standby startup source (transformer 500kV Switchyard 230kV Switchyard(X)(Y)(Y)(X)LTC LTC 642 542 632 532Midway 2 Bus 2 Bus 1 Bus 1 Mesa 742 282 MorroMidway 3 732 262 Ba y U1 Main Gates 1 722 622 Bus 2 Bank Xfm r 1-12-1 212500kV / 25kVU2 Main Bank Xfmr 500kV/25kVSU Xfmrs Aux Xfm r Aux Xfm r Aux Xfm r Auxfm X r 230kV 25kV Bus EBus D U1 Main Generato r 1-1 1-2 DG 1-1 DG 1-2 DG 1-312kV SU Bus(Y) (X)Bus E Bus D Bus H Bus G Bus F DG 2-3 DG 2-1 DG 2-2 Bus FBus GBus H Bus E Bus D U2 Main Generato r 2-1 2-2 Bus E Bus D 12kV 4kV 12kV(Y) 25kV4kV 12kV(X)SU Xfmrs1-22-2 12kV 4kV 3 Enclosure PG&E Letter DCL-10-028 1-2, 2-2) connection to each safety-relat ed vital bus, or on a safety-related vital bus degraded voltage or undervoltage signal

. After the DG starts, it automatically connects to its respective bus after offsite power is isolated. The DGs also start and operate in the standby mode without connecting to the vital bus on an SI signal alone.

During plant operation with all DGs operable, in the event of a loss of both sources of offsite power (LOOP), the DGs start, loads shed, and ESF electrical loads are automatically sequentially loaded to the DGs in sufficient time to provide for safe reactor shutdown or to mitigate the consequences of a Design Basis Accident (DBA), such as a LOCA. On a LOOP, an undervoltage signal trips all vital loads and non-permanently connected loads from the vital bus.

After the associated DG is connected to the vital bus, the vital loads are sequentially loaded to the vital bus by load sequencing timers. The sequencing

logic controls the permissive and starti ng signals to motor breakers to prevent overloading the associated DG during the loading process.

Justification and Basis for the Emergency Circumstances

DCPP entered TS 3.8.1, Required Action A.2, at 21:58 on March 9, 2010, for

"One required offsite circuit inoperable."

for both units due to compensatory measures taken to address a nonconservative TS 3.3.5, "Loss of Power (LOP)

Diesel Generator (DG) Start Instrumentation." Accident scenarios involving loss of coolant accident (LOCA) and degraded offs ite power were postulated. While attempting to analyze the consequences of these scenarios, PG&E concluded both units were in an Unanalyzed Condition. To ensure class 1E loads do not fail

to transfer to emergency power duri ng this postulated new scenario, the aforementioned action was taken. Thes e compensatory measures placed both units in TS 3.8.1 Action A.2, which has a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> completion time.

These compensatory measures force the 4kV bus to align directly to the associated DG upon a receipt of a SIS, t hereby protecting the running 4kV loads on that bus from the postulat ed degraded offsite power supply.

This LAR is submitted on an emergency basis to allow for continued operation of DCPP Units 1 and 2 in order to prov ide adequate time to implement new compensatory actions, post-maintenance testing, return inoperable equipment to operable status, and review documentation necessary to assure proper

completion of these actions.

The new compensatory actions consis t of a design change to implement conservative LOOP DG start instrum entation first level under-voltage relay (FLUR) setpoints.

Risk-Informed Licensing Change 4

Enclosure PG&E Letter DCL-10-028 This LAR represents a risk-informed licensing change. The proposed change meets the criteria of Regulatory Guide (RG) 1.174, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific

Changes to the Licensing Basis," and RG 1.177, "An Approach for Plant-Specific, Risk-Informed Decision making: Technical Specifications," for risk-informed changes. RG 1.177 discusses the acceptable reasons for requesting TS changes. The following categories apply to this LAR:

Improvement to operational safety:

A change to the TS can be made due to reductions in the plant risk or a reduction in the occupational exposure of plant personnel in complying with the TS requirements.

Reduce unnecessary burdens:

The change may be requested to reduce unnecessary burdens in complying with current TS requirements, based on

operating history of the plant or the industry in general. This includes extending completion times

1) that are too short to complete repairs when components fail with the plant at-pow er, 2) to complete additional

maintenance activities at-power to reduce plant down time, and 3) provide

increased flexibility to plant operators.

3. TECHNICAL EVALUATION

3.1 Impact on Defense-In-Depth and Safety Margins In addition to discussing the impact of the changes on plant risk, the traditional engineering considerations need to be addressed. These include defense-in-depth and safety margins. The fundamental safety

principles on which the plant design is based cannot be compromised.

Design basis accidents are used to dev elop the plant design. These are a combination of postulated challenges and failure events that are used in

the plant design to demonstrate safe plant response. Defense-in-depth, the single failure criterion, and adequate safety margins may be impacted by the proposed change and considerat ion needs to be given to these elements.

Impact on Defense-in Depth

The proposed change needs to meet the def ense-in-depth principle, which consists of a number of elements. These elements and the impact of the proposed change on each follow:

5 Enclosure PG&E Letter DCL-10-028 A reasonable balance among pr evention of core damage, prevention of containment failure and consequence mitigation is preserved.

The 230 kV system is the sole offsit e power source capable of supplying immediate offsite AC power in the event of an accident or unit trip. The

loss of this source would mean that the offsite power system would not be immediately available to mitigate the e ffects of an event. It is noted that the 500 kV backfeed (i.e. delayed offsite source) would still be available to affect a safe shutdown for anticipated operational occurrences. This level of degradation is similar to the loss of offsite power coincident with an event, which is part of the DCPP design basis. For this worst case

condition, the onsite AC power sources are fully available (i.e. no

degradation or single failure vulnerabilities).

On March 9, 2010, at 21:58 PDT, DCPP operators entered TS 3.8.1 Action A.2 "One required offsite circuit inoperable" and defeated the auto

transfer of at least one 4kV bus to startup power for both units as compensatory measures taken to address a non-conservative TS 3.3.5, "Loss of Power (LOP) Diesel Generator (DG) Start Instrumentation."

Transfer of these buses to DGs remains operable.

Accident scenarios were postulated involving design basis accidents (DBA) resulting in safety inject sig nals (SIS) with a concurrent, sustained, degraded offsite power. While attempti ng to analyze the consequences of these scenarios, PG&E concluded both units were in an Unanalyzed

Condition. To ensure class 1E loads do not fail to transfer to emergency power during this new scenario, operators took the aforementioned

actions. These compensatory measur es placed both units in TS 3.8.1

Action A.2, which has a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> completion time.

In the postulated scenario, the norma lly running 4kV class 1E loads [two component cooling water pumps (CCW P) and one auxiliary saltwater pump (ASWP)] upon transferring to offsit e power as a result of an SIS, could trip on over-current protection due to the degraded (low) offsite

voltage.

The compensatory measure disables at least one of the three vital 4kV buses' auto-transfer to offsite power function. This compensatory measure forces the 4kV bus to align directly to the associated DG upon a receipt of a SIS, thereby protecting the running 4kV loads on that bus from the postulated degraded offsite power supp ly. Non-running class 1E loads on other buses would be unaffected.

6 Enclosure PG&E Letter DCL-10-028 This risk assessment will support a lic ense amendment request to extend the allowable completion time for TS 3.8.1 up to an additional 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> total).

This extens ion will allow enough time to perform modificati ons to the 4kV first level of undervoltage relay (FL UR) protection setpoint, such that normally running CCWPs and ASWPs will not experience degraded offsite

power upon transfer to offsite power sufficient to cause a trip on over-current during the postulated scenario.

In the first configuration, auto-transfer to offsite pow er is disabled (cutout) to a bus in each unit. In this conf iguration, the running pumps on the cutout bus (1 ASWP and 1 CCWP) may be protected from over-current trip since the cutout bus will transfer di rectly to the EDG on the SIS. This risk assessment assumes the other running CCWP will fail to transfer (due

to over-current) because the associate bus's auto-transfer to offsite power is enabled.

The third CCWP is assumed to be in standby. This pump will not start on the SIS due to the degraded voltage c ondition. Rather, the third CCWP will remain in standby until the asso ciated DG is running and the CCWP is sequenced on.

In the second configuration, while modifying the FLUR setpoint, a 4kV bus in each unit will be cutout from startup power as well as EDG power. A second bus on each unit may be cutout fr om offsite power, to protect the normally running pumps from degraded offsite power voltage.

The proposed one time change does not degrade the ability of one barrier

to fission product release and com pensate with an improvement of another. There is no physical design change or operational change

associated with this request; therefore the balance between prevention of core damage and prevention of containment failure and consequence mitigation is maintained. Furthermore , no new accidents or transients are introduced with the propos ed change and the likelihood of an accident or transient is not impacted.

Over-reliance on programmatic ac tivities to compensate for weaknesses in plant design.

The calculated risk increase for the CT c hanges is very small. Additional control processes are in place to compensate for any risk increase, including disabling auto transfer to offsite power for one bus per unit.

7 Enclosure PG&E Letter DCL-10-028 System redundancy, independence, and diversity are maintained commensurate with the expected frequency and consequences of challenges to the system.

The onsite AC power source (i.e. di esel generators) is the redundant counterpart to the offsite power system.

All of the diesel generators will be operable while in the proposed ext ended TS Condition, except for individual periods of inoperability controlled by existing TS while

implementing the new co mpensatory measures.

Current TS 3.8.1 Condition E limits the time with one required offsit e circuit inoperable and one diesel generator inoperable to 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />

s. Additionally, the onsite AC power sources, as a system, are independent and redundant; thereby satisfying the single failure criterion.

In the event of a loss of all AC power (i.e. station blackout), DCPP is an

"Alternate AC" plant and AC power c an be restored within 10 minutes. Operation with the 230 kV system in a degraded condition does not impact

the availability of the "Alternate AC" source.

There is no impact on the redundancy, i ndependence, or diversity of the offsite power systems. The redundant and diverse offsite power design will not be changed. The SUTs are reliable components.

Defenses against potential comm on cause failures are maintained and the potential for introduction of new common cause failure mechanisms is assessed.

Defenses against common cause fa ilures are maintained. Although separation of the ESF l oads from the grid woul d be an expected outcome should concurrent dual unit SI events o ccur, the grid would remain stable and the voltage would recover to wit hin the prescribed range. The postulated simultaneous loss of generat ion from both DCPP units is an existing requirement imposed on the DCPP Transmission Service Provider (TSP) by both PG&E and t he Western Electricity Coordinating Council (WECC). Therefore, the postulated simultaneous loss of generation from both DCPP units and the concurrent loading of the 230 kV System will not result in a LOOP event.

The CT extension requested is not so significant that any new common cause failure mechanisms would occu

r. In addition, the operating environment for these components re mains the same; therefore, new common cause failure modes are not expected. The number, design, and types of SUTs used for offsite power remain the same with these changes so the startup power system mainta ins the potential against common cause failures.

8 Enclosure PG&E Letter DCL-10-028 Independence of barriers is not degraded.

The barriers protecting the public and the independence of these barriers are maintained. Assessment of main tenance activities per 10 CFR 50.65 ensures that multiple systems will not be out of service simultaneously

during the extended CT that could l ead to degradation of these barriers, and an increase in risk to the public. In addition, the extended CT does not provide a mechanism that degrades the independence of the fuel

cladding, RCS, and containment barriers.

Defenses against human errors are maintained.

No new operator actions related to the CT extension are required to

maintain plant safety. No changes to current operating or maintenance procedures are required due to these changes because these procedures already include compensatory actions to limit risk when the 230 kV system is in a degraded condition. The increase in CT provides additional time

and flexibility to allow new compensa tory measures to be completed safely without undue pressure and without requiring an unplanned shutdown and cooldown.

Impact on Safety Margins

The proposed change does not impact th e current design or licensing basis. The change would only ap ply while implementing new compensatory measures for a non-conser vative technical specification.

The time in this configuration is limited.

Therefore, the proposed change results in no impact on safety margins.

3.2 Assessment of Impact on Risk A probabilistic risk assessment (P RA) has been performed using the NRC's three-tier approach described in RG 1.177. The three tiers consist

of:

Tier 1 - PRA Capability and Insights -

an evaluation of th e impact on plant risk of the proposed TS change as expr essed by the change in the risk matrix such as the CDF, the LERF, the incremental conditional core

damage probability (ICCDP), and the incr emental conditional large early

release probability (ICLERP),

Tier 2 - Avoidance of Risk-Signifi cant Plant Configurations - an identification of potentially high-risk configurations that could exist if 9

Enclosure PG&E Letter DCL-10-028 additional equipment were to be tak en out of service simultaneously, or other risk-significant operational fact ors such as concurrent system or equipment testing, and

Tier 3 - Risk-Informed Configurati on Risk Management - establishment of an overall configuration risk management program to ensure that other potentially lower probability, but nonetheless risk-significant, configurations resulting from maint enance and other operational activities

are identified and compensated for.

RG 1.177 requires the evaluation of t he proposed change on the total risk (i.e., on-line and shutdown risk). This evaluation only quantifies the risk associated with being in Mode 1 wit h the inoperable startup power inoperable for a time period greater than that allowed by the current TS (72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />). This is conservative si nce the risk of the TS-driven shutdown is not used to balance the risk of the proposed extended CT.

3.2.1 Tier 1: PRA Capability and Insights Tier 1 provides, in addition to evaluating the impact on plant risk to the

proposed one time TS change (Attachm ent 3), a summary of the DCPP

PRA histor y and the technical adequa cy of the PRA in support of the proposed application and its conclusi on. A summary of the DCPP PRA history and a description of the technical adequacy of the PRA is contained in Attachment 4 of this letter.

PRA Quality

The DCPRA is a living PRA, which is maintained through a periodic review

and update process. Attachment 5 of this letter discusses the review processes that the DCPRA has under gone, the st atus of the disposition/resolution of the findings from the reviews and the impact of those outstanding/open issues from the reviews on the results and conclusions of this study. Based on the qualitative discussion and/or the use of sensitivity analyses contained in Enclosure 6 of this letter, it is concluded that there are no open issues associated with the PRA

standards supporting requirements that would impact the results of this risk evaluation.

3.2.2 Tier 2: Avoidance of Risk-Signi ficant Plant Configurations In general, risk from performing main tenance on-line is minimized by:

10 Enclosure PG&E Letter DCL-10-028

  • Performing only those preventativ e and corrective maintenance items on-line required to maintain the relia bility of Structures, Systems or Components (SSC).
  • Minimizing cumulative unavaila bility of safety-related and risk significant SSCs by limiting the number of at-power maintenance outage windows per cycle per train/component.
  • Minimizing the total number of SSCs out-of-service (OOS) at the same time.
  • Minimizing the risk of initiating plant transients (trips) that could challenge safety systems by implementing compensatory measures.
  • Avoiding higher risk combinations of OOS SSCs using PRA insights.
  • Maintaining defense-in-depth by av oiding combinations of OOS SSCs that are related to similar safety functions or that affect multiple safety functions.
  • Scheduling in Train/Bus windows to avoid removing equipment from different trains simultaneously.

In general, risk is managed by:

  • Evaluating plant trip risk activities or conditions and mitigating them by taking appropriate compensatory m easures and/or ensuring defense-in-depth of safety systems that are challenged by a plant trip.
  • Evaluating and controlling risk based on probabilistic and key safety function defense-in-depth evaluations.
  • Implementing compensatory measures and requirements for management authorization or notification for certain "high-risk"

configurations.

Actions are taken and appropriate attenti on is given to configurations and situations commensurate with the level of risk as evaluated using

AD7.DC6. This occurs both during planning and real time (execution) phases.

For planned maintenance activities, an assessment of the overall risk of the activity on plant safety, including benefits to system reliability and performance, is currently performed and documented per AD7.DC6 prior to scheduled work. Consideration is given to plant and external conditions, the number of activities being performed concurrently, the

potential for plant trips, and the av ailability and "health" of redundant trains.

Risk is evaluated, managed and documented for all activities or conditions based on the current plant state:

  • Before any planned or emergent maintenance is to be performed.

11 Enclosure PG&E Letter DCL-10-028

  • As soon as possible when an emergent plant condition is discovered.
  • As soon as possible when an external or internal event or condition is recognized.

Compensatory measures are implem ented as necessary and if the risk assessment reveals unacceptable risk, a course of action is determined to restore degraded or failed safety functions and reduce the probabilistic

risk.

3.2.3 Tier 3: Risk-Informed C onfiguration Risk Management The objective of the third tier is to ensure that the ri sk impact of out of service equipment is evaluated prio r to performing any maintenance activity. As stated in RG 1.177, "a viable program would be one that is able to uncover risk-significant plant equipment outage configurations as they evolve during real-time, normal plant oper ation." The third-tier requirement is an extension of the se cond-tier requirement, but addresses the limitation of not being able to ident ify all possible risk-significant plant configurations in the second-tier evaluation.

DCPP has developed a process fo r online risk assessment and management. Following the process and procedures ensures that the risk impact of equipment unavailability is appropriately evaluated prior to performing any maintenance activity or following an equipment failure or other internal or external event that impacts risk. DCPP Administrative Procedure AD7.DC6, "On-Line Maintenance Risk Management," provides guidance for managing safety function, probabilistic, and plant trip risks as required by 10 CFR 50.65(a)(4) of the Maintenance Rule. The procedure

addresses risk management practices in the maintenance planning phase and maintenance execution (real time) phase for Modes 1 through 4. Appropriate consideration is given to equipment unavailability, operational

activities such as testing, and weather conditions.

In general, risk from performing main tenance on-line is minimized by:

Performing only those preventive and corrective maintenance items on-line required to maintain the relia bility of Structures, Systems or Components (SSCs). Minimizing cumulative unavailability of safety-re lated and risk-significant SSCs by limiting the number of at-power maintenance outage windows per cycle per train/component. Minimizing the total number of SSCs out of service at the same time. Minimizing the risk of initiating plant transients (trips) that could challenge safety systems by implementing compensatory measures.

12 Enclosure PG&E Letter DCL-10-028 Avoiding higher risk combinations of out of service SSCs using PRA insights. Maintaining defense-in-depth by avoidi ng combinations of out of service SSCs that are related to similar safety functions or that affect multiple safety functions. Scheduling in train/bus windows to avoid removing equipment from different trains simultaneously.

In general, risk is managed by:

Evaluating plant trip risk activities or conditions and mitigating them by taking appropriate compensator y measures and/or ensuring defense-in-depth of safety systems t hat are challenged by a plant trip. Quantitatively pre-evaluate risk signifi cant equipment OOS configurations affecting CDF by PRA methods. Qualitatively evaluate the ability of SSCs to support key safety functions that protect the fission product barrier s such as fuel cladding, reactor coolant system boundary and containment. Implementing compensatory measures and requirements for management authorization or notification for certain "high-risk" configurations resulting

from planned maintenance.

Actions are taken and appropriate attenti on is given to configurations and situations commensurate with the level of risk as evaluated using

AD7.DC6. This occurs both during planning and real time (execution) phases.

For planned maintenance activities, an assessment of the overall risk of the activity on plant safety, including benefits to system reliability and performance, is currently performed and documented per AD7.DC6 prior to scheduled work. Consideration is given to plant and external conditions, the number of activities being performed concurrently, the

potential for plant trips, and the av ailability and "health" of redundant trains.

Risk is evaluated, managed and documented for all activities or conditions based on the current plant state:

Before any planned or emergent maintenance is to be performed. As soon as possible when an emergent plant condition is discovered. As soon as possible when an external or internal event or condition is recognized.

13 Enclosure PG&E Letter DCL-10-028 Compensat ory measures are implement ed as necessary and if the risk assessment reveals unacceptable risk, a course of action is determined to restore degraded or failed safety functions and reduce the probabilistic risk.

3.2.4 Integrated Risk-Informed Assessment

The proposed change to extending the TS 3.8.1 allowable Completion Time for one required offsite circui t inoperable has been evaluated with a risk-informed approach. This approach dem onstrates that t he principles of risk-informed regulation are met for these proposed change:

The applicable regulatory requi rements will continue to be met Adequate defense-in-dept h will be maintained Sufficient safety margins will be maintained, and Any increases in CDF and LERF ar e small and consistent with the NRC Safety Goal Policy Statement and Regulatory Guides 1.174 and 1.177, And appropriate compensatory measures and contingency actions will be in place to avoid unnecessary risk and to reduce the likelihood of a loss of 230 KV system due to a concurrent unit SI event.

4. REGULATORY EVALUATION 4.1 Applicable Regulatory Requirements/Criteria General Design Criteria (GDC) 17

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 capaci ty and capability to assure that (1) specified acceptable fuel design limits and design conditions of the reactor

coolant pressure boundary are not ex ceeded as a result of anticipated operational 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, s hall have sufficient independence, redundancy, and testability to perform their safety functions assuming a single failure.

14 Enclosure PG&E Letter DCL-10-028 Electric power from the transmissi on 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 su fficient time following a loss of all onsite alternating current power suppl ies and the other offsite electric power circuit, to assure that specif ied 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 minimi ze the probability of losing electric power from any of the remaining supplies as a result of, or coincident with, the loss of power generat ed by the nuclear power unit, the loss of power from the transmission network, or the loss of power from the onsite electric power supplies.

4.2 Precedent None.

4.3 No Significant Hazards Consideration PG&E has evaluated whether or not a significant hazards consideration is involved with the proposed amen dment by focusing on the three standards set forth in 10 CFR 50.92, "Issuance of amendment," as discussed below:

1. Does the change involve a signifi cant increase in the probability or consequences of an accident previously evaluated?

This License Amendment Request (LAR) proposes a one-time change to

Technical Specification (TS) 3.8.1, "AC Sources - Operating," to extend, on a one-time basis, the allowable Completion Time for required action

A.2, from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br />.

The requested change does not physically alter any plant structures, systems, or components, and does not affect or create new accident initiators or precursors. The comp letion time (CT) to perform a required 15 Enclosure PG&E Letter DCL-10-028 action is not an accident initiator; t herefore, there is no effect on the probability of accidents previously evaluated.

An AC sour ce is required to mi tigate the consequences of accidents previously evaluated in the Final Sa fety Analysis Report Update. The requested change to allow one required offsite circuit to be inoperable for

up to 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> does not increase the consequences of those accidents

since the onsite AC sources would be av ailable, independent of the offsite sources.

Additionally, the redundant offsite circuit remains operable and capable of performing its required function for ant icipated operational occurrences. The requested change does not affe ct the types or amounts of radionuclides released following an accident, or the initiation and duration of their release.

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

2. Does the change create the possibili ty of a new or different kind of accident from any accident previously evaluated?

The proposed change does not introduce new failure modes or mechanisms associated with plant operat ion. Furthermore, the 96 hour0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> CT associated with the restoration of the offsite circuit would not create a new accident type.

Therefore, the proposed c hange does not create the po ssibility of a new or different kind of accident from any accident previously evaluated.

3. Does the change involve a significant reduction in a margin of safety? PG&E has determined that no significant risk is associated with allowing 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> when one offsite circuit is inoperable. Although the proposed change revises the completion time when the offsite circuit is inoperable, it does not affect any limiting conditions for operation, safety limits, other

operational parameters, or setpoints in the TS, nor does it affect any margins assumed in the accident analyses. The increase in the CT

increases the period when the plant may be operating with one offsite power source, but the redundant offsit e circuit is operable and therefore able to perform its required design functi on to safely shut the plant down and remove residual heat.

16 Enclosure PG&E Letter DCL-10-028 17 Therefore, the proposed c hange does not involve a significant reduction in a margin of safety.

Based on the above safety evaluati on, PG&E concludes that the change proposed by this LAR satisfies the no significant hazards consideration standards of 10 CFR 50.92(c), and accordingly a no significant hazards

finding is justified.

4.4 Conclusions

In conclusion, based on the considerat ions 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) 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 am endment and has determined that the proposed amendment does not involve: (1) a significant hazards consideration, (2) a significant change in the types or si gnificant increase in the amounts of any effluents that may be released offsite, or (3) a significant increase in individual or cumulative occupational radiation ex posure. Accordingly, the proposed amendment meets the eligibilit y criterion for categorical exclusion set forth in 10 CFR 51.22(c)(9). Therefore, pursuant to 10 CFR 51.22(b), no environmental

impact statement or environmental assessment need be prepared in connection with the proposed amendment.

6 REFERENCES

1. License Amendment 132 (OL-DPR-80) and 130 (OL-DPR-82) 230 kV Offsite Power System Upgrades.

Enclosure PG&E Letter DCL-10-028

Proposed Technical Specification Changes (marked-up)

Page: 3.8-1

AC Sourc es -Operating 3.8.1 3.8 ELECTRICAL POWER SYSTEMS 3.8.1 AC Sources -Operating LCO 3.8.1 APPLICABILITY:

ACTIONS The following AC electrical sources shall be OPERABLE:

a. Two qualified circuits between the offsite transmission network and the onsite Cla ss 1 E AC Electrical Pow e r Di s tribution Sy s tem; and b. Three diesel generators (DGs) capab l e of supplying the onsite Class 1 E power distribution s ubsystem(s)
and c. Two supply trains of the diesel fuel oil (DFO) transfer sys tem. MODES 1, 2, 3, and 4. -------------------------------------NOTE-------------------------

LCO 3.0.4b is not applicable to DG s. CONDITION REQUIRED ACTION COMPLETION TIME A. One required offsite circuit A.1 inoperable. AND A.2 P e rf o rm SR 3.8.1.1 for re qui red OPERABLE offsite circuit. Restor e r e quired offsite circuit to OPERABLE s tatu s. 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> AND On ce per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> thereafter. 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> s(1) AND 14 days f ro m di scovery of failure to meet L CO. (continued)

(1) For the DCPP Unit 1 a nd 2 March 9 , 2 010 e ntry i n t o T ec hn ica l Specification 3.8.1. th e r eq uir e d offsite circuit may be inoperable as speci f ied by R equ ir ed Action A.2 for a period not to exceed 96 hou r s. Up on co mp letio n of modifications a n d r esto r a ti on , th is footno te i s no l onge r app licable a nd wi ll expire a t 2158 PST on M a rch 13, 2010. DIABLO CANYON -UNITS 1 & 2 3.8-1 Unit 1 -Amendm e nt No.

Unit 2 -Amendment No.

En cl o s ur e Att ac hm e nt 2 PG&E L ette r DCL-10-0 28 Proposed Technical Specification Changes (retyped)

Remove Page Insert Page 3.8-1 3.8-1 AC Sources -Operating 3.8.1 3.8 ELECTRICAL POWER SYSTEMS 3.8.1 AC Sources -Operaling LCO 3.8.1 APPLICABILITY

ACTIONS The following AC electrical sources shall be OPERABLE: a. Two qualified circuits between the offsite transmission network and the onsite Class 1 E AC Electrical Power Distribution System; and b. Thre e diesel generators (DGs) capable of supplying the onsite Class 1 E power distribution s ubsystem(s);

and c. Two supply tra ins of the diesel fuel oil (DFO) transfer system. MODES 1, 2, 3, and 4. -------------------------------------NOTE---------------------------------------------------

LCO 3.0.4b i s not applicable to DGs. CONDITION REQUIRED ACTION COMPLETION TIME A. On e r equ ired offsite circuit A.1 inoperable. AND A.2 Perform SR 3.8.1.1 for required OPERABLE offsite circuit. Re store required offsite circuit to OPERABLE status. 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> AND On ce per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> thereafter.

72 hou rs(1) AND 14 days from discovery o f failure t o m eet LCO. ( continued)

(1) For th e DCPP Unit 1 and 2 March 9,2010 en try int o T echnica t Specification 3.8.1, th e r e quired offsite ci r cuit may be inoperable as specif i ed by Required Action A.2 for a period not to exceed 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br />. Upon completion of modifications and r es toration, th is footnote is n o long e r app l icab le and will expire at 2158 PST on March 13, 2010. DIABLO CANYON -UNITS 1 & 2 3.8-1 Unit 1 -Amendment No.

Unit 2 -Amendm e nt No.

PRA10-03 Revision 0 Enclosure Attachment 3 PG&E Letter DCL-1 0-028 PACIFIC GAS & ELECTRIC COMPANY PROBABILISTIC RISK ASSESSMENT CALCULATION FILE NO. PRA10-03 Revision 0

SUBJECT:

230 KV Offsite Power Completion Time Extension PREPARED BY: __

____ _ JohnPyo VERIFIED BY:

___ _ Nathan Barber DATE: __

__ VERI FlED I N ACCORDANCE WITH:_--"C,,-F.::.3

.,,-,1 D"-,1,,,5_

APPROVED BY: __

____ _ Mark Sharp This file contains: 8 pages CALCULATION FILE PRA10-03 REV. 0 RECORD OF REVISIONS REV. 0 Original calculation. PURPOSE/BACKGROUND PG&E Letter DCL-10-028 SHEET 2 On March 9, 2010, at 21 :58 PDT, DCPP operators entered TS 3.8.1 Action A.2 "One required offsite circuit inoperable" for both units due to compe nsatory measures taken to address a non-conservative TS 3.3.5, "Lo ss of Power (LOP) Diesel Generator (DG) Start Instrumentation

." Accident scenarios involving design ba sis accidents (DBA) resulting in safety inject signals (SIS) with a concurrent, sustained, degraded offsite power were postulated.

While attempting to analy ze th e consequences of these scenarios, PG&E concluded both units were in an Unanalyz ed Condition.

To ensure class 1 E loads do not fail to transfer to emergency power during this new scenario, operators took compensatory measures. These compensatory measur es placed both units in TS 3.8.1 A c tion A.2 , which has a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> completion time. In the postulated scenario, the norm a lly running 4160 V c lass 1 E loads; [Two component cooling water pumps (CCWP) and one auxiliary saltwater pump (ASWP)] upon transferring to offsite power as a result of an SIS, could trip on over-current protection due to the degraded (low) offsite voltage. The compensatory measure forces the 4160 V bus to align directly to the associated emergency diesel generator upon a receipt of a SIS, thereby protecting the running 4160 V loads from the postulated degraded offsite pow e r supply. This risk assessment will support a li cense amendment request to ex tend the allowabl e completion tim e for TS 3.8.1 up to an additional 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> total). This extension will allow enough tim e to perform modifi ca tions to th e 4160 V first level of undervoltage relay (FLUR) protection setpoint , such that normally running CCWPs and ASWPs will not experience degraded offsite power upon transfer to offsite power and therefore , will not trip on over-current during the postulated scenario.

This risk assessment will determine the combined change in risk associated with the sequential configurations described below: In the first configuration, 4160 V bus a uto-t ran s fer to offsite power is disabl ed (cutout). In this configuration , the running pumps on the cutout bus (1 ASWP and 2 CCWPs) will be protected from over-current trip since th e cutout bus will transfer directly to the EDG on the SIS. This risk assessment assumes the other CALCULATION FILE PRA10-03 REV. 0 SHEET 3 running CCWP will fail to transfer to emergency power (due to over-current) because the associated bus's auto-transfer to offsite power is enabled. In the second configuration, while modifying the FLUR setpoint, the affected 4160 V bus will be cutout from startup power as well as EDG power. The other bus may be cutout from offsite power, to protect the normally running pumps from degraded offsite power voltage. The offsite power failure probability of the baseline PRA model is assumed to include the postulated degraded voltage scenario. An additional case will be prepared, doubling the offsite power failure probability, to demonstrate the sensitivity to the postulated degraded voltage scenario.

METHODOLOGY The applicable methodology/criteria for assessing the risk associated with extending the Completion Time for Tech. Spec. systems/components is provided in Reg. Guide 1.177 [2]. Reg. Guide 1.177 [2] suggests assessing the effect on risk of the proposed increas e in Completion Time (CT) based on the following three tiers: Tier 1 -PRA Capability and Insights.

Tier 2 -Avoidance of Risk-Significant Plant Configurations, and Tier 3 -Risk-Informed Configuration Risk Management ASSUMPTIONS/ASSERTIONS

  • The proposed activity consists of two different configurations. In the first configuration, 4160 V bus G (in Unit 1) and bus F (in Unit 2) auto-transfer to offsile power is disabled (cutout). In this configuration, the runnin g pumps on the cutout bus (1 ASWP and 1 CCWP) will be protected from over-current trip , since the cutoul bus will transfer directly to the EDG on the SIS. The second running CCW pump is however not protected and therefore assumed to be failed. In the second configuration while modifying and testing of FLUR setpoint of 4 KV bus G (for Unit 1) and Bus F (for Unit 2), the corresponding 4 KV bus will be locked out from both startup power and asso c iated emergency diesel.
  • 4 KV bus under-voltage condition occurs regardless of type of a transient/accident.
  • 230 KV power supply is available. This is considered as the key uncertainty and a sensitivity analysis is performed.
  • This is one-time extension of the Completion Time. INPUT
  • The proposed duration for the first configuration is 138 hours0.0016 days <br />0.0383 hours <br />2.281746e-4 weeks <br />5.2509e-5 months <br /> and for the second configuration, 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> are proposed.

CALCULATION FILE PRA10-03 REV. 0 SHEET 4

  • For the average unavailability of a vital 4 KV bus, the current TS 3.B.1.d Completion Time of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is u sed. As the proposed change is only one time app l ication, the average unavailability is not expected to b e changed. ACCEPTANCE CRITERIA The acceptance guidelines for TS changes are provided in Sections 2.2.4 and 2.2.5 of RG 1.174 [1) and for AOT changes in Section 2.4 of RG 1.177 [2). The impact of the proposed change is consid e red low risk if the estimated ri sk metric values are l ess than those li ste d be l ow. Risk Metric Acceptance Criteria ACDF AVE 1.0 E-06 /yr A LERF AVE 1.0 E-07 /yr ICCDP 1.0 E-06 ICLERP 1.0 E-07 CALCULATIONS No maintenance model (DC01 NM) modified for SR 3.0.3 condition of potentially degraded load sequencing function of ESF l oads on to vita l 4 KV buses, DC01 NMDG, is used as th e base model. It is then further modified to reflect two different 4 KV bus configurations as de scr ibed in A ssu mption/Ass e rtion sec tion as the application mod e ls. For the first configuration, DC01 NMDG is modified with one of two CCW pumps fail s given the offsite power fails and given a name of WC01 B5 (Unit 1) and WC01 B6 (Unit 2). For the second configuration, a loss of one 4 KV bus for each unit is modeled and named as DCNMDGG (Unit 1) and DCNMDGF (Unit 2). The proposed change in the Completion Time is only for one time a nd not expected to change the current ave rage mainten a n ce practices.

Therefore th e current average unavailabilit y (MT AVE) of the offsite power is u se d in calcu l ation of the A CDF AVE and A LERF AVE. The ACDF AVE , A LERF AVE , ICCDP, lCLERP are calculated as follows: ACDF AVE = (CDF AVE -CDF base) * (MT AvE) A LERF AVE = (LERFAVE -LERF b ase) * (MT AVEl , where CDF AVE (LERFAV E ) is estimated based on the average unavailability of 230 KV offsite power supply (i.e., 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />), while CDF base (LERFba se) is estimated ba se d on zero unavailability (no-maintenance model). ICCDP'o'a' = ICCDP config 1 + ICCDP config 2 ICLERP'o'al = ICLERP config 1 + ICLERP config 2 CALCULATION FILE PRA10-03 REV. 0 ICCDP ro,,,,g' = (t;CDF eD'if'g') * (CT e",v',') = ({',.CDF e"'Y'g2) * (CT eD'if.,2) t;CDF eo,,,,g' = CDF e"if'g'-CDF brue t;CDF eD , ,,,g2 = C DF e.,,,,g2 -C DF bru e ICLERP cD'Y'g' = (t;LERF c",,,,g') * (CT eD ,,,,g l) ICLERP e.'Y'g2 = (MERF eD , ,,,g2) * (CT ro'Y'g2) MERF e., ,,,g' = LERF eoo,ftg' -LERF brue MERF ro'Y'g' = LERF eD , q'g' -LERF bruc The table below summarizes the results of the above equations: Configura ti on 1 I Configuration 2 Completion Time (CT). Hr 136 I B Ave. Un availabi lity (MT), Hr 12 Unit 1 Configuration 1 Configuration 2 CDF Av e 4.99E-05 4.25E-04 LERF AVe 3.33E-06 1.30E-05 CDF con l i. 4.99E-05 4.25 E-04 LERF co n fi Q 3.33E-06 1.30E-05 CDF ba,e 4.41E-05 4.41 E-05 LERF b as e 3.25E-06 3.25E-06 Unit 2 Confiquration 1 Confiquration 2 CDF A v e 4.91 E-05 5.04E-04 LERF A Ve 3.2BE-06 1.3BE-05 CDF con fiQ 4.91E-05 5.04E-04 LERF co nfio 3.2BE-06 1.3BE-05 CDF b a se 4.41 E-05 4.41 E-05 LERF b ase 3.25E-06 3.25E-06 Risk Matrix Unit 1 Unit 2 Acceptance Criteria {',.CDF A v E 5.21E-07 6.30 E-07 1 E-06/yr {',.LERF AV E 1.33 E-OB 1.45E-OB 1 E-07/yr ICCDP 4.3BE-07 4.9BE-07 1E-06 ICLERP 1.01E-OB 1.01 E-OB 1E-07 SHEET 5 CALCULATION FILE PRA10-03 REV. 0 SHEET6 Uncertainty and Sensitivity Analysis HEP sensitivity Description ICCDP I CLERP WC01B11 Config. 1 with HEP se ns. 4.15E-07 2.95E-09 DCNMDGFH Config 2 with HEP sens 2.30E-06 2.89E-08 2.71E-06 3.19E-08 Offsite Power Reliability sensitivity Des c ription ICCDP I CLERP WC01B9S Config 1 wHh offsite power 9.73E-08 1.55 E-09 sensitivity DCNMDGF S Config 2 with offsite power 7.33E-07 1.5 8E-08 sensitivity 8.31E-07 1.74E-08 Two sensitivities were performed as part of thi s analysis.

In one sensitivity, the plant centered offsite power failure probability was increa se d by a fa cto r of 2 to bound potential uncertainty associated with degraded reliability of the offsite pow er. The re s ult of this case is that ICCDP and ICLERP are within the RG 1.177 acceptance criteria.

The second se nsitivity case examines HEPs that are important to degrad e d offsite power conditions. The re s ults of this second sensitivity are that the ICCDP is above the RG 1.177 criteria.

The increase in ICCDP reflects upper bound to uncertainty r egarding HEP values. CCLERP r e mains below the criteria.

Conclusions As show in tables above, a risk increase resulting from a one-time extension of the Comp l etion Time is within the acceptance guideline provided in RG 1.1 74 and 1.177. The re s ults of sensitivity runs shown above also demonstrate that the co nclusion of this eva luation i s valid considering the key un ce rtainties related to this app l ication (e,g., offsite power reliability, HRA). The PRA models used to quantitatively demonstrate that a risk increase associated with th e proposed one-time extension of the Completion Tim e considers hazard groups such as internal events, seismic, and internal flooding.

Fire events are considered in the base model; however, the current state of fire modeling and fire impacts does not meet the ASME Combined PRA standard.

None the le ss, a qualitative fire impact on the cu rrent application i s provided here. The proposed plant configuration in vo lv es locking out automatic tran s fer of some of 4 kV vital bu s power s upplie s from the Startup power and/or emergency diesels. As s u c h a fire in areas that can impact remaining power supplies or vital buses could result in a much more severe transient than what postulated in the analysis. Therefore it is prudent that those co mponent s and systems important to this risk assessment be protected and activities that may initiate fires in the following areas s hould be precluded for the duration of the AOT. EDG rooms for bu sses that have the auto-transfer to offsite power cut out. Vital 4 kV bus rooms 12 KV SWGR rooms 125VDC Battery Charger Room s Vita l 480V room s CALCULATION FILE PRA10-03 REV. 0 SHEET7 Other significant fire scenarios generally cause a lo ss of offsite power , which causes equipment to load directly to EDG. In this application, th e total los s of offsite power has a beneficial impa c t when compared to the postulated , sustained degraded offsite power supply voltage scenario. The contributions to seismic CDF are dominated by the seismic-induced failure of major structures systems and components (SSCs). These seismic failures result in, among othe r scenarios, station black out, excessive LOCA or a loss of component cooling water (CCW). Seismic-induced relay chatter results in a los s of all vital AC and also contributes strongly to CDF. The contribution to seismic LERF is dominated by seismic-induced steam generator s tructural failure which directly results in a containment bypass and by core melt sequence with induced steam generator tube rupture. None of these contributors to CDF or LERF are sensitive to the availabil ity of the offsite power system. Separate attachments for DCPP PRA development history and its technical adequacy including evaluation of impacts of PRA open items and gaps on this application are provided as part of the LAR submittal.

Review of Dominant Sequences

  • Th e bulk of the in crease in CDF is due to general transient initiators such as reactor trip , loss of main feedwater, loss of condenser vacuum etc. These increases are a re s ult of the higher likelihood of a loss of power to one vital bus following a plant trip. This increased likelihood is due to the fact that the startup power s upply to one bus i s lo cked out and a complete los s of power to that bus occurs if the associated Diesel Generator does not start and load.
  • Loss of a running CCW pump upon los s of offsite power result s in an increase in the contribution from scenarios involving a loss of CCW.
  • The Loss of DC bu s G initiator results in a high e r CDF contribution than the baseline case since a DC failure disables the EDG associated with the bus for which sta rtup power i s locked out. A Diesel Generator failure on this bus results in a total loss of bus power. Plant modifications not incorporated into the PRA model New normally operating centrifugal charging pumps were added to both units. The se pumps have the capability to provide RCP seal injection following a loss of CCW since they do not depend on CCW for cooling. Crediting these pumps would significantly reduce the contribution to CDF from loss of CCW scenarios.

A l oss of CCW curren tl y causes a loss of th ermal barrier cooling to the RCPs and results in a failure of RCP seal injection after the CCW cooled E CCS charging pumps fail. Truncation In the Diablo Canyon PRA model, different truncation levels a r e set for each initiator to balance quantification time with adequacy of results. Initiator truncation values r ange from 1 E-12 to 1 E-15 with the majority of initiators possessing trun ca tion levels in th e 1 E-13 to 1 E-14 range.

CALCULATION FILE PRA10-03 REV. 0 SHEET 8 Using Riskman, the "unaccounted" sequence frequencies (success and core damage frequencies of unquantified sequence s) can be determined.

Note that, these are the frequencies of accident sequences that are not quantified until they reach the CDF endstate.

The quantification of each of these sequences is terminated when it s frequency along the event tree nodes falls below the truncation limit set for the quantification.

Generally, the CDF portion of the unaccounted frequency of a sequence r epresents a small fraction of the total unaccounted frequency of that sequence since the sequence(s) leading to Core Damage would involve at least one additional SSC and/or operator action failure. The total CDF unaccounted frequency for the application cases are l ess than 5% of the total calculated CDF. REFERENCES

1. RG 1.174," Regulatory Guide 1.174 -An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis", November 2002 2. RG 1.177, " Regulatory Guide 1.177 -An Approach for Plant-Specific , Risk-Informed Decisionmaking:

Technical Specifications, August 1998

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