ML052560269

Response to Request for Additional Information Regarding License Amendment Request for Extension of Diesel Generator Completion Time

ML052560269
Person / Time
Site:	Columbia
Issue date:	09/01/2005
From:	Oxenford W Energy Northwest
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
G02-05-147
Download: ML052560269 (72)

Text

ENERGY

'9NORTHWEST People -Vision-Solutions P.O. Box 968

• Richland, WA

• 99352-0968 September 1, 2005 G02-05-147 U.S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, D.C. 20555

Subject:

COLUMBIA GENERATING STATION, DOCKET NO. 50-397 RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME

References:

1) Letter dated May 19, 2004, DK Atkinson (Energy Northwest) to NRC, "Application for Amendment of Facility Operating License No. NPF-21 for Extension of Diesel Generator Completion Time"

2) Letter dated November 4, 2004, WA Macon (NRC) to JV Parrish (Energy Northwest), "Columbia Generating Station - Request for Additional Information (TAC No. MC3203)"

Dear Sir or Madam:

By Reference 1 Energy Northwest requested a change to Technical Specification (TS) 3.8.1, "AC Sources Operating," to permit a longer Completion Time for the Division 1 and Division 2 diesel generators (DG). By Reference 2 the NRC issued a Request for Additional Information (RAI) regarding the basis for the proposed change. This letter provides the responses to items 1 through 19 of the RAI. These responses are provided in Attachment 1 of this letter.

The responses include revisions to commitments provided in Reference 1 and additional commitments in response to the RAls. Attachment 2 contains the combined list of the commitments.

In response to NRC concerns expressed during initial telephone discussions after receiving the RAls and a meeting with the NRC on March 11, 2005 on these RAls, Energy Northwest has provided a cross-connection from our DG-3 as an alternate AC source to power selected safe shutdown equipment. The effort to design additional call

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 2 hardware, perform engineering and PRA calculations, and perform the regulatory evaluation, has resulted in an extended response period. In addition, this change required a minor change to the Action Statement. The revised TS page and Bases inserts are enclosed as Attachment 3 and replace those in Attachment 3 and 4 of Reference 1. Energy Northwest has included a revised no significant hazards consideration to address these changes. This is provided in Attachment 4.

If you have any questions regarding this matter, please contact GV Cullen, Licensing Supervisor at (509) 377-6105.

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

Executed on 2L.

, 2005.

Respectfully, WS Oxe,d Vice President, Technical Services Mail Drop PE04 Attachments:

1.

Response to Request for Additional Information, Items 1 through 19

2.

Revised Commitment list

3.

Revised Proposed TS and Bases Pages

4.

Revised No Significant Hazard Consideration cc:

BS Mallett - NRC RIV BJ Benney - NRC NRR NRC Sr. Resident Inspector - 988C RN Sherman - BPA/1399 WA Horin - Winston & Strawn

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 1 of 56

1. The 2004 peer review summary results performed per RG 1.200, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-informed Activities," provide only peer review A and B Facts and Observations (F&O) results. Based on the staff's review of the Columbia Generating Station (CGS) probabilistic risk assessment (PRA), provide the disposition of C F&Os found to be applicable to the proposed diesel generator (DG) completion time (CT) extension to 14 days.

Response

The summary of "C" Level Facts and Observations, their potential increase or decrease of the baseline CDF, baseline LERF, and a qualitative assessment on the delta risk metric associated with the Diesel Generator (DG) Completion Time (CT) application was reviewed by the Regulatory Guide (RG) 1.200 PRA Peer Review Team in February, 2004.

Based on the review results (focused on DG AOT application), there are 15 "C" level F&Os that may have impacts on the DG CT application. These F&O were reviewed and found to minimally impact the results in both positive and negative manners.

The following table lists the 15 "C" level F&Os and their disposition.

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 2 of 56 Response to RAI Question # 1 Level "C" F&Os Identified by the Peer Review Team To Potentially Impact the Risk Metric of the DG Completion Time Extension Level ACT F&O Fact and Observation Level C Disposition IE-C3-2 The initiating event frequencies appear to be inconsistent.

Convert IE frequency from Critical years to calendar years next Initiating event frequencies should be in reactor-calendar update. A sensitivity evaluation was completed with the initiating years (annual frequency) so that the calculated plant risk is in events normalized to reactor calendar year. The results were a units comparable to other societal risks.

small decrease in the core damage frequency (CDF) & large early release frequency (LERF) baseline results. This will not significantly impact the delta risk metrics results.

2 AS-A3-1 A conservative modeling assumption made in the PRA is that For loss of offsite power (LOOP) anticipated transient without a LOOP with failure to scram leads to core damage.

scram (ATWS) accident sequences, this conservative modeling Numerically, this is judged to not significantly alter the risk will minimally decrease the CDF and have a small decreasing spectrum. For most applications this is not considered effect on base line LERF. The conservative assumption is an important. This impact would be desirable to address in some optional change for the next update of the PRA. This will not applications such as extending the DIG CT. The conservative significantly impact the delta risk metrics results.

baseline assumption could mask the impact (ICCDP or ICLERP) due to these sequences.

3 AS-A4-5 The crew action to align offsite AC power is judged to be Add manual actuation of breakers HEP next upgrade. The HEP included in the empirical data for AC recovery as long as DC for manual recovery operations is expected to only minimally power is available on-site. If DC batteries are unavailable, it is increase the base CDF. This will not significantly impact the delta judged that offsite AC power recovery is no longer risk metrics results. However, during the DG Extended represented by the empirical data and a human error Completion Time, this small impact is offset by DG-4 being probability (HEP) for those manual breaker actions required to available to power the battery chargers so battery capability is restore AC power is needed.

preserved. During the extended CT when DG-4 is staged, DC control power for breakers for offsite AC power restoration can be For the case where batteries deplete under SBO conditions, assured.

what is the HEP associated with reconnecting to the offsite With the additional capability of cross connecting DG-3 to provide grid. if AC power is restored later than this time?

AC power to Division 1, 2 or the preferred offsite power switchgear's battery chargers, DC control power for breaker operation is assured well beyond the 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> credited in the baseline model. When credited in the PRA, the probability of having to perform manual breaker alignment to offsite power will be further reduced. This will be a permanent feature available continuously to respond to an SBO.

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 3 of 56 Response to RAI Question # 1 Level "C" F&Os Identified by the Peer Review Team To Potentially Impact the Risk Metric of the DG Completion Time Extension Level C Fact and Observation Level C Disposition F&O 4

SC-A6-4 Many of the thermal hydraulic runs In the Rev 5 PRA, the MAAP calculations were updated primarily for the DG AOT for success criteria are based on the application. The remainder of the thermal hydraulic runs will be revised and results pre-uprate power level of 3233 MWt incorporated in the next upgrade of the PRA.

using MAAP 3.0B. The MAAP runs T

b c

that impact the DG AOT extension Two bounding cases In terms of timing were also performed:

have been updated using the uprate (1) Case for Very Short Term: In a Turbine Trip without Makeup Injection, the core will power level of 3486 MWt and using be uncovered in 41 min for the pre-uprate case and in 32 min for the post uprate case.

MpwP 4u0i This difference would not impact the currently used 30-min recovery HEP as the existing P.0.

model has typically been developed with margin.

(2) Case for Very Long Term: In a Loss of Long Term Cooling (Loss of RHR) leading to containment failure before the core failure case, the pre uprate calculation predicted 31 hrs for containment breach while the post uprate predicted 27.7 hrs. The 3.3 hrs difference in timing is still beyond the currently used mission time of 24 hrs for long term cooling in the event tree sequence assumption.

All the post-accident HEPs that were based on MAAP results for timing have also been qualitatively reviewed. About 6 HEPs may be slightly impacted. Therefore, the overall impact to the modeling results (CDF and LERF) is not expected to be significant. This will not significantly impact the delta risk metrics results.

5 SY-B3-2 The high pressure core spray Because of the significant differences that exist between the HPCS Service Water Pump (HPCS) Service Water (SW) pump (HPCS-P-2) and the Service Water Pumps Train-A and -B (SW-P-1All B), it is (1C) is not included in the common considered not warranted to include HPCS SW Pump into the CCF. A few major cause factor (CCF) group for differences are listed in the following:

Standby Service Water Pumps IA and 1 B. Unless there is a compelling SW-P-I 1B HPCS-P-2 reason to maintain the HPCS Manufacturer Byron Jackson Pacific Service Water separately, these Design Flow 10,500 gpm 1200 gpm three pumps should be included in a Horse Power 1750 Hp 60 Hp group of three.

Head 500 Ft 123 Ft Power 4160 AC 480 AC Buses SM-7/8 (Div 1/2)

MC-4A (Div 3)

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 4 of 56 Response to RAI Question # 1 Level 'C" F&Os Identified by the Peer Review Team To Potentially Impact the Risk Metric of the DG Completion Time Extension Level 'C' Fact and Observation Level C Disposition F&O 6

SY-B5-2 There is no discussion of There are two 480 volt AC MCCs located in the Rx Bldg 522'. The Div-1 MCC contains MC-7B and the dependency of Rx MC-7BA, and Div-2 MCC contains MC-8B and MC-8BA. The current PRA model has the MCC Bldg MCCs on Rx Bldg room cooling supported by either one of the two means:

HVAC and in turn those systems that depend on

1. Normal RB HVAC, or the Rx Bldg MCCs. This

2.

Emergency Fan Cooling (using SW).

room cooling dependency could cause these MCCs to fail their function The PRA credits the normal HVAC and the Emergency Cooling Fans for all non-LOCA sequences, o fand credits the Emergency Cooling Fans, and normal HVAC with an operator action for LOCA. The operator action was for a reset of the FAZ signal. Based on an additional review, this modeling should be revised to only credit the Emergency Cooling Fan during a LOCA.

The function of the Normal RB HVAC is based on the plant Design Spec 318A (Burns & Roe). The dependency of RB MCCs (Div-I, 2) on RB HVAC has been described in the PSA-2-SY-REA notebook. Those systems modeled to be dependent on Div-I MCC are REC, GR4, LPCS, NS4, and RHR. Those systems modeled to be dependent on Div-2 MCC are RHR, Venting, and CAS.

The most likely accident class to challenge the operability of the RB HVAC is LOCA. But since the total LOCA class initiators only contribute about 2% of total plant CDF, the impact from the current RB HVAC modeling is not considered very significant. A revision to the PRA model will be made during the next update to properly credit the RB HVAC and more clearly document the

_dependencies.

This will not significantly impact the delta risk metrics results.

I4

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 5 of 56 Response to RAI Question # 1 Level UC" F&Os Identified by the Peer Review Team To Potentially Impact the Risk Metric of the DG Completion Time Extension Level uCf Fact and Observation Level C Disposition F&O 7

HR-Al, Section 3.1.1 indicates that the test and Table 2 of PSA-2-HR-0001 is a listing of the pre-accident initiators that include maintenance procedures listed in Table 2 were Volume 2, System Operating Procedures (SOP), and Volume 7, Surveillance C2-1 reviewed to identify misalignment actions; Procedures. The system misalignment errors could potentially occur from however, no misalignment actions are performing the SOP procedures. Surveillance procedures and SOP identified. The procedures provided in Table 2 procedures have been reviewed and verified that they have provided specific are all linked to existing basic events (mainly steps of restoring systems to operability following test and maintenance.

mis-calibration actions) and it is not clear that Therefore, the realignment is actually included in the procedures. The HEPs those procedures would be appropriate listed in Table 2 are the conservative HRA screening values and are sources to identify a misalignment action. No considered adequate for representing both misalignment errors and calibration indication is given that other procedures were errors.

included in the review. The HRA is missing classic examples of system mis-alignments, CGS does not perform all SOP Procedures on a fixed schedule. Many such as failure to restore SLC after systems would be performing SOP procedure only after a repair for Post maintenance.

Maintenance Testing (PMT). The misalignment error if not specifically treated in the pre-accident HEPs, such as SLC system, would still be reflected in the system functional failure (resulting in out of service) or pump fail-to-start data.

The Table 2, 3rd column text will be revised at the next update to include misalignment error. This will not significantly impact the delta risk metrics results.

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 6 of 56 Response to RAI Question # I Level 'C" F&Os Identified by the Peer Review Team To Potentially Impact the Risk Metric of the DG Completion Time Extension Level 'C" Fact and Observation Level C Disposition F&O 8

DA-C11_1 The unavailability analysis in PSA Based on a review of the calculation of Test and Maintenance data documented in the DA-0003 provides some general PSA-2-DA-0003, the referenced Table 3.17 has actually not been used for the general guidelines in Table 3.17 as to what criteria for selecting Out-of-Service time (OOS). This Table will be removed in the next activities are generally counted document update.

towards the unavailability estimates.

This is judged consistent with SR DA-The OOS time is determined by using the Maintenance Rule (MR) database, which C11.

includes both planned and unplanned OOS time. This database is controlled by the MR Administrator (e.g., Pg 2 of PSA-2-DA-0003).

However, one of the guidelines (#3) appears to be non-conservative. This guideline says that surveillance and INOP times were not counted because There is no impact to the delta risk metrics results.

they are planned activities. This is judged non-conservative because, planned or not, if such activities render the train unavailable then it should be counted.

4i A

1 I

I

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 7 of 56 Response to RAI Question # I Level "C" F&Os Identified by the Peer Review Team To Potentially Impact the Risk Metric of the DG Completion Time Extension Level '0" Fact and Observation Level C Disposition F&O 9

DA-D6-2 Common cause failure of the 2n" DC The CGS PRA has modeled the CCF for DC batteries and DC battery chargers. To bus is not included in the model.

address the CCF for the 2nd DC bus, an assessment has been performed based on NUREG-0666.

There is a potential for common

1) The conditional 2nd DC Bus failure for a minimum DC system may be estimated to be cause failure of a DC bus given an 3E-2 (Section 5, Pg. 37).

initial failure. This may be induced by

2) The unreliability would be reduced by a factor of 0.02 from a) Elimination of bus-tie-maintenance on the wrong bus or breaker, b) Surveillance improvement, and c) Maintenance and testing improvement.

equipment aging issues.

(Table 6, Pg 42)

3) The unreliability could further be reduced by the recent design provision for redundant battery chargers (E-C1-1A1N B and E-CI-2A/2B), and adding a 480 V AC emergency diesel generator (DG-4) for the Division I or Division 2 battery chargers. This is assumed to reduce the unreliability by a factor of 0.1.

4)

Based on the industrial LER data, a recovery probability of 0.5 may be assumed. (Pg.

E-1 0)

The resultant conditional 2nd DC Bus failure is estimated to be: 3E-2

• 0.02

• 0.1

• 0.5 = 3E-5.

If "A Loss Of Both DC Buses" is modeled to go directly to core damage, this conditional 2nd DC bus failure would increase the CDF by 1.05E-8/yr [=3.5E-4 (Initiation Event (IE) frequency for losing one division DC)

• 3E-5]. This is a -0.14% increase from the baseline CDF (7.33E-6/yr). Based on the small magnitude, and that the earlier work NUREG-0666 (4/1981) has not been updated by the more recent NUREG/CR-5497 (10/1998), the impact to the model is insignificant. Based on this, the CCF for the DC bus will be included in the next PRA upgrade. This will not significantly impact the delta risk metrics results.

10 DA-D6-4 SW-FL-ST3ACC3 is CCF of SW Based on a review of the CCF calculations, the 3-component SW suction strainer (filters) filters for Div. 1 & 2 SW. It is then CCF was actually correctly developed based on the standard MGL methodology (INEL-applied to Div. 3. The derivation and 94(0064). It was determined that the 3-component CCF is coincidently equivalent to the 2-name should reflect this effect.

component CCF for the SW suction strainer. Hence, there is no impact to the calculation The data for CCF of more than 2 model. Documentation will be revised to reflect this condition at the next PRA update..

pumps could be reconsidered given the basis for the CCF is not representative of CGS (i.e., it involves The CCF of more than 2 pumps has been evaluated to be not applicable (see #5 above,

_grassing" events at Hope Creek).

F&O SY-B3-2)

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-
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-

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 8 of 56 Response to RAI Question # I Level "C* F&Os Identified by the Peer Review Team To Potentially Impact the Risk Metric of the DG Completion Time Extension Level C Fact and Observation Level C Disposition F&O 11 DA-D6-5 Is there an assessment of the Yes, design differences include tandem drive engines versus single engine drive, generator common cause among EDG 1, 2, 3 manufacture and size, and others. These differences will be evaluated and the Div. 3 CCF that would indicate the gamma for the revised addressing these design differences in the next upgrade of the PRA. This will not Group of 3 is less than that in significantly impact the delta risk metrics results.

NUREG/CR-5497 because of design differences?

Unusually high gamma values could mask the ICCDP calculated for a DG CT extension.

12 DA-D6-7 The CGS CCF data analysis, as The CCF values used from INEEL-94-0064 are generally conservative. When updated to documented in PSA-2-DA-0004, uses the newer data source, the overall effect is estimated to be a lowering of the CDF and accepted industry techniques and LERF. An Update of the CCF data to latest version of NUREG/CR-5497 will be performed data sources. However, although the during the next update of PRA. This will not significantly impact the delta risk metrics latest revision of the INEEL CCF results.

generic database (NUREG/CR-5497) is used in some cases, the majority of the CCF calculations are performed using the old version of the INEEL database (INEEL-94-0064).

13 QU-D4-2 SBO S03 sequence is considered The overall effect of this comment is estimated to be a lowering of the baseline CDF. The conservative (see AS F&O on this crediting of HPCS operation for long term SBO conditions will be reviewed and the PRA sequence). HPCS will run and appropriately revised consistent with the use of using DG-3 in a cross connect configuration maintain adequate core cooling for to supply safe shutdown loads. This will not significantly impact the delta risk metrics

>24 hours, beyond containment results.

failure for some cases.

14 QU-E1-1 Include uncertainty factors for pre-The uncertainty factors for pre-initiators and post initiator HEPs do not impact the baseline initiator and post initiator HEPs.

CDF or LERF results. Future upgrades of the PRA will include uncertainty factors for HEPs.

This will not significantly impact the delta risk metrics results.

-~tt ~

- 3

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 9 of 56 Response to RAI Question # 1 Level "C" F&Os Identified by the Peer Review Team To Potentially Impact the Risk Metric of the DG Completion Time Extension Level C' Fact and Observation Level C Disposition F&O 15 LE-C2-3 Credit for AC non-recovery time does Some non-recovery calculations, using deviated timing from MMP 3.0B, were recognized not appear to be consistent with the as an approximation. Page 84 of PSA-2-L2-0001 documents the basis of these MAAP run results in PSA-2-L2-0001, approximations: This assumption is consistent with the CGS philosophy, to minimize Table 4.3.1-2. For example, accident complexity in areas of the analysis in which there is relatively little effect on the overall class 6B2B shows vessel failure at 12 results and insights from the analysis. The acceptability of the assumption waspredicated hours, but AC non-recovery is on consideration of the following facts:

credited for 15 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br />.

the time between core plate failure and vessel failure predicted by MAAP 3.0B is relatively short.

the current estimates for the time to vessel failure has been "discretized" into intervals for sequence groups. Six intervals are considered: 0 - 30 min, 30 min - 2 hrs, 2 - 3 hrs, 3 - 6 hrs, 6 -15 hrs, 15 - 24 hrs, and > 24 hrs.

there is a great deal of uncertainty in knowing whether the core debris is in an uncoolable configuration.

Therefore, the precision in the timing of events in the existing analysis does not support further resolution since the contribution to an increased probability of successful restoration of injection during the additional time which injection may be available is unlikely.to have much effect. This will not significantly impact the delta risk metrics results.

.1

-I r

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 10 of 56

2. Clarify or justify the reactor core isolation cooling (RCIC) system logic used. If the logic is in error, please revise the model and provide updated results for this application (base CDF, LERF, and CDF, LERF, ICCDP, and ICLERP). (Gate GHPS212 identified during the staff review of the CGS PRA).

Response

A review of the High Pressure Core Spray (HPCS) and RCIC system fault trees associated with the suction sources (Gate GHPS212 and GRCI712, respectively) was performed. The current AND logic used for both gates was determined to be reasonable for nearly all situations, based on system design features as well as the operational flexibilities provided by the suction source transfer capabilities. However, during the review of the logic, it was identified that the human reliability analysis should be augmented with a more detailed modeling of operator actions, and the gate logic should be altered for special situations.

As a result of the review, three Human Error Probabilities (HEPs) for the RCIC fault tree, and two HEPs for the HPCS fault tree were identified for incorporation into the model. These refinements provide a much more realistic modeling of special operating situations, such as the need to manually transfer HPCS to the suppression pool if CST suction pressure is low, or operator failure to refill the CST to the PRA credited level.

Additionally, the need to transfer HPCS to the suppression pool was conservatively assumed to be required for loss of coolant accidents (i.e., CST alone is not credited as a success during LOCA).

A sensitivity analysis was performed to examine the refinements discussed above, and the baseline CDF was found to increase by less than 1%. A change to the baseline CDF of this small magnitude is expected to have insignificant impacts to the risk metrics (LERF, ICCDP and ICLERP) for the DG CT extension. The modeling improvements to the fault trees of HPCS and RCIC will be incorporated into the next PRA upgrade.

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page I1 of 56

3. (a) Provide the installation schedule for the permanent alternate AC (AAC) power source and (b) the associated time frame requested for crediting the temporary AAC power source. (c) Will the temporary AC power source remain an option after the permanent AC power source is installed? (d) Clarify if the analysis credits the permanent AACSBC [alternate AC source to the Division 1 and Division 2 battery chargers] and for what time frame the temporary AC power source will be credited for the proposed 14 day CT. (e) The staff considers the schedule for the permanent installation should be identified as a commitment by the licensee.

Response

(a) The permanent Alternate AC Source (AACS) to the Battery Chargers design has been finalized and is comprised of a mobile, 480 volt, diesel generator herein after called Diesel Generator Number-4 (DG-4) and its associated connection configuration to the Class 1 E bus that supplies a division's battery chargers. Additionally, as provided in the response to RAI question number 16, the ability to cross-connect the Division 3 diesel generator, DG-3, to Division 1 or Division 2 has been developed. The acronym AACSBC will be shorted to AACS in the TS action statement to reflect that the risk management action is comprised of both sources being established. See electrical diagram in response to RAI question 16. We have completed all portions of the installation and post modification testing of DG-4 connection and DG-3 cross connection that required the plant to be in a shutdown condition.

(b) With sufficient completion of the installation during the last refueling outage, there is no need for crediting a temporary electrical distribution plant configuration of the AACS for the battery chargers for an interim period. This requested temporary configuration is no longer needed and is hereby withdrawn.

(c) We have decided to withdraw the use of a temporary DG for DG-4. This is no longer needed with the ability to complete the permanent DG-4 installation.

(d) The PRA analysis was performed for both the planned maintenance case, where DG-4 is available prior to taking an Emergency DG out of service, and for the case where DG-4 is unavailable for the full 14 days. This was presented in Attachment 5 of the submittal, in accordance with Regulatory Guide 1.177 section 2.3.6, to show the risk results with and without the proposed risk management measures. As indicated above, we have withdrawn the request associated with use of a temporary DG for DG-4.

Therefore, there will be no time during the extended Completion Time that a temporary DG will be used to meet the LCO Action.

If an emergent'DG maintenance was required, there may be an initial delay in staging DG-4, however, the Technical Specifications proposed would not allow this period to be greater than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. In response to RAI question #5 below, additional analysis was performed and the results are provided for an emergent DG maintenance condition where a delay in establishing DG-4 availability is addressed.

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Attachment I Page 12 of 56 (e) As reported above, the permanent plant wiring and hardware installation that required plant shut down is completed. This includes DG-4 installation on its mobile trailer and the associated internal plant wiring for DG-3 cross connect and DG-4. Post modification testing for DG-3 cross connect wiring and DG-4 wiring have been completed. The remaining refurbishment of breakers and their testing and staging of DG-4 can be completed on line. The operating, surveillance, and maintenance procedures and associated training are under development and will be completed prior to entering into the extended DG Completion Time.

4. Attachment 1 to the submittal states that procedures for verifying the AACSBC DG is capable of performing its risk management function, including starting and loading, will be performed prior to declaring the AACSBC available. (a) How is verification of temporary/permanent AACSBC availability accomplished? (b) Is this an additional risk management action commitment? (c) Is the temporary/permanent DG only considered available at 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />?

Response

The portion of the submittal proposing a temporary DG in place of DG-4 is withdrawn.

The following addresses Request for Additional Information (RAI) number 4 with respect to the permanent DG-4.

(a) Verification of DG-4's availability to perform its risk management function will be by periodic testing and inspections. This will include verification that, 1) a minimum of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of fuel is available, 2) the DG starts normally and obtains proper speed and voltage regulation, and 3) while running the diesel at rated full load for a period of one hour, the generator maintains proper voltage and frequency. This load testing will be performed using a load bank that is part of the DG-4 mobile unit and completely independent of the plant's electrical distribution system. The periodicity will be determined by the maintenance program.

If this testing is not current, DG-4 is not verified to be available and Required Action B.4.1 of Technical Specification 3.8.1, which is running concurrently, would expire and result in entering Condition 3.8.1.F, which requires the reactor to be shut down. If the above testing and inspections have been performed within the periodicity determined by the maintenance program (plus 25% of the interval), it is considered current and need not be repeated to demonstrate availability. There will be no requirement to re-perform the above testing if the interval between testing exceeds the interval plus 25% after entry into the extended DG CT. This is to assure that once staged and verified available, DG-4 becomes a protected feature similar to other risk important equipment during the DG CT period.

(b) Yes, this is a risk management action commitment. See response to RAI # 13.

RESFONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 13 of 56 (c) DG-4 is considered available once it is staged and verification testing is completed or verified current. For planned maintenance, this will be verified to be current prior to taking the DG out of service. For emergent conditions (repair), DG-4 will be verified to be available as soon as practicable, but prior to exceeding 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.

5. Maintenance and repair appear to be treated the same; the proposed CT extension does not appear to distinguish between corrective maintenance and preventive maintenance. (a) Are the estimates for CDF, LERF, ICCDP and ICLERP calculated for both preventive maintenance and repair (corrective maintenance)?

(b) Is the 72-hour LCO assumed to remain intact? (c) Does the evaluation assume only the extension from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 14 days? (d) Is the 24-hour TS common cause evaluation included in the results?

Response

(a) Partially. Two bounding sets of results were provided in the submittal. In the Table below, Case 1 and 3 results were provided in the submittal in Attachment 5 and are repeated for comparison.

For planned preventative maintenance, at the start of each OOS period it was assumed that DG-4 was available. Case 3 provides the results assuming a 14-day preventive maintenance with DG-4 pre-staged and available prior to removing a DG from service for the maintenance activity.

Case 1 assumes a very conservative condition for a 14-day corrective maintenance (without DG-4 for the full OOS time). Note: This case would not be allowed by the proposed TS change, but is provided in accordance with Regulatory Guide 1.177 Section 2.3.6.

For an emergent repair condition, the proposed TS change allows up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> into the DG's OOS period before DG-4 is required to be verified available. A specific calculation, assuming that the DG-4 would not be available for 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, has been performed and the results are provided in Case 2 below. Case 2 provides the risk calculation results for a 3-day repair (without DG-4) followed by an additional 11 days (with DG-4 available). This is the longest time allowed for an inoperable DG without completing the required risk management actions in the proposed TS change. This is a worst case evaluation, as DG-4 will be normally pre-staged and its surveillance testing current, requiring a very short verification of DG-4's status.

This combined case shows the impact to risk of a delay in the availability of the DG-4 for the first three days remains in the very small region per the acceptance guidelines of RG 1.174 (ACDF<1.OE-6/yr and ALERF< 1.OE-7/yr for risk being 'very small") and is well within the criteria of RG 1.177 (ICCDP<5.OE-7 and ICLERP<5.0E-8).

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 14 of 56 Case Scenarios for DG ACDF ICCDP ALERF ICLERP 1 &2 DG-1 DG-2 DG-1 DG-2 1

14-day corrective 5.43E-7 4.82E-7 5.14E-7 2.28E-9 2.22E-9 1.96E-9 maintenance

_ (repair W/O DG-4) 2 3-day repair W/O 3.58E-7 3.19E-7 3.38E-7 1.44E-9 1.62E-9 1.02E-9 DG-4 followed by 11-day with DG-4 3

14-day preventive 3.09E-7 2.76-E-7 2.92E-7 1.21 E-9 1.46E-9 7.67E-10 maintenance (with DG-4)

(b) Yes. The current 72-hour Action for one DG inoperable remains in the TS to provide an Action and associated Completion Time if the risk management Action B.4.2.1 is not accomplished within its Completion Time Limit (also 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />). This prevents a condition of not having an associated action provided when the LCO is not met.

(c) No. The evaluation assumed a full 14 days per cycle (2 years) out of service time for each DG.

(d) No, however, the common cause potential during the extended CT was considered.

The common cause factors for the DGs are provided in Attachment 5 of the submittal and are part of the results of determining the baseline risk metric values. However, the 24-hour LCO 3.8.1, Action B.3.1 to determine Operable DGs are not inoperable due to common cause failure remains a TS Action and no additional common cause potential or HEP for incorrectly determining if a common cause was present was added for the extended DG CT.

The DG extended Completion Time risk evaluation assumes that a common cause does not exist due to the Technical Specification requirement to perform this common cause evaluation or perform an operability test on the Operable DGs. If the common cause determination method is by evaluation and is not sufficiently determinate of whether a common cause failure exists, the TS Action allows testing to verify that the potential common cause is not impacting the Operable DG. If the common cause evaluation determines that the cause is likely to impact the operability of an Operable DG, LCO actions would allow a much shorter period to rectify this common cause or a plant shutdown would be required, irregardless of the risk evaluation results that include an increased common cause potential. Specifically, LCO Condition 3.8.1.E would require restoration of one DG to Operable status within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> for a Division 1 and Division 2 DG common cause and within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> if Division 3 DG is made inoperable by the common cause. Failure to restore a DG to operable status within these much shorter Completion Times would result in a required plant shutdown. Thus, for an actual common cause condition, TS would preclude using the extended DG Completion Time, unless the common cause condition is rectified.

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 15 of 56

6. For the equations on Attachment 5 page 5, please provide a reference for the derivation.

Response

The equations on Page 5 were used to calculate ACDFAVG and ALERFAVG, which are the changes in the annual average CDF and LERF due to the 14-day on-line maintenance unavailability of DGs.

The average CDF (average LERF) is calculated by adding the CDF (LERF) for the period during which the DG is out of service during this extended Completion Time to the CDF (LERF) for the remainder of the cycle.

These equations are used in accordance with the existing industry methods and are consistent with the equations/calculations provided in the following submittals.

1. Exelon Nuclear, LaSalle County Station, Units 1 and 2, NRC Docket Nos. 50-373 and 50-374, "Request for Amendment to Technical Specifications Extension of Allowable Completion Times for Division 1 and 2 Emergency Diesel Generators",

February 20, 2001, Attachment A, Pages 10 through 12.

2. Constellation Nuclear, Nine Mile Point Unit 1, Docket No. 50-220, "Application for Amendment to the Technical Specifications - Extension of Allowed Outage Time for an Inoperable Diesel Generatoe', March 27, 2002, Attachment H, Pages 1 through 4.

3. AmerGen, Clinton Power Station, Docket No. 50461, "Clinton Power Station Application for Amendment of Facility Operating License No. NPF-62 for Extension of Diesel GeneratorAllowed Outage Time (LA-99-016)", December 29, 2000,, Pages 2 through 4.

4. Entergy, River Bend Station, Docket No. 50-458, 'License Amendment Request (LAR) 2001-027, Emergency Diesel Generator Extended Allowed Outage Time",

September 24, 2001, Attachment 5, Pages 1 through 6.

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 16 of 56

7. Battery mission times assume battery testing completelsuccessful with elimination of margin for the proposed 14-day CT extension (i.e., battery capacity equal to or greater than 100% capacity hour basis for batteries). a) Is this a risk management action commitment? b) In addition, is a load shed required for 125 V dc or 250 V dc loads to support the 6-hour battery assumption?

Response

(a) Yes. In establishing the risk management actions for entering the extended CT period, we agree that it would be appropriate to assure the battery is charged and adequate battery capacity was available prior to entry.

We propose an additional commitment to assure sufficient battery capacity by verifying the results of the last battery capacity surveillance was greater than or equal to 100%

and that surveillance testing is current. Short time excursions in battery surveillance parameters outside limits will not invalidate this risk management compensatory measure commitment as specific TS Actions exist to restore the conditions within a reasonable time.

(b) Based on the realistic calculation approach and the results described below, the 125 volt Division 1 and Division 2 batteries are capable of meeting the 6-hour mission time with minimal load shedding. Although not required for the SBO per 10 CFR 50.63 the 250 V Division 1 battery may be needed if RCIC is required to be realigned and restarted during the 6-hour mission time. The associated load shedding for the 250 V battery and the actions are currently included in the SBO procedure.

During the PRA upgrade process for the DG CT Extension, the bases for an existing PRA assumption of a 6-hour mission time capability for the batteries was raised by our internal self assessment and later by the Peer Review Team. To determine a resolution of this F&O and provide a basis for a realistic battery mission time for PRA modeling, a set of sensitivity calculations was performed to determine the Division 1 and Division 2 batteries capability using realistic assumptions during an SBO. These calculations included additional loads due to design changes and voltage drop considerations for required equipment. The results were that for a 6-hour mission time with adequate margin, load shedding was required for both Division 125 volt batteries. This consists of stopping the DC supplied DG lubrication oil pumps and some emergency stairwell lighting that is not needed. The lube oil pumps for the DG under maintenance would most likely not have its lube oil pumps running. Stopping the DC lubrication pumps is reasonable for the DG's that did not start. Re-energizing these pumps would be part of a restart attempt and can be performed in the DG rooms. Included in the stairwell emergency lighting system was a set of lighting supplied from each of the Division 1 and Division 2 DC batteries. This emergency lighting was initially part of the design but was not credited in the 10 CFR 50.63 SBO coping analysis as other lighting is available.

The calculated mission time, with this minimal load shedding as described above, was 6Y hours, which includes a Y hour margin beyond the 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> used in the PRA.

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 17 of 56 Based on these sensitivity evaluations, it was judged that with the additional load shedding on the 125 volt batteries using a 6-hour battery mission time capability was a realistic and appropriate assumption in the PRA. To assure this 6-hour mission time remains valid, a constraint has been placed in the battery loads calculation to limit any future load addition to the batteries to remain within the 6-hour PRA bases to assure the battery's capability remains able to achieve the 6-hour mission time credited in the PRA.

Although not required to meet the 10 CFR 50.63 coping analysis, the above additional load shedding for Division 1 and Division 2 batteries will be added to the SBO procedure to provide adequate margin for the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> mission time. This procedure change will be completed prior to entry into the extended risk informed Completion Time.

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 18 of 56

8. Provide a discussion on the cumulative risk for the proposed CT extension with respect to previous CGS license amendment requests submitted to the staff for review and approval?

Response

A review of the bases for the following previously submitted license amendments was performed. We determined that these applications are not impacted by this request.

(a) Risk informed In Service Inspection (ISI) for code 1 piping:

To evaluate the potential impact associated with DG Completion Time Extension of 14 days on the ISI program, the Conditional Core Damage Frequencies (CCDFs) used in the ISI consequence analysis were recalculated using the PRA Revision 5 model and a sensitivity model. The sensitivity model increased the PRA Revision 5 unavailabilities due to maintenance of DG1, DG2, and DG3. The Revision 5 CCDFs were calculated to be lower than the values used in the current ISI program (PRA Rev. 4.0), which would result in the lower consequence categories. The sensitivity CCDFs were calculated to be similar or slightly higher than the Revision 5.0 CCDFs. This indicates that increasing the DG unavailability due to CT extension would have a very small impact on the ISI program.

(b) On Line Maintenance:

The impact of the DG CT Extension to ORAM-SENTINEL (or plant risk assessment) has been evaluated using a ZERO-Maintenance Revision 5 PRA model with the same truncation limit as was used in the ORAM-SENTINEL model for comparison. Since the submittal is for the DG CT, the results for DG-1 and DG-2 comparison are listed in the following table (included cases with DG-4):

Revised Model (Rev 5) with Zero-Current Risk Model - ORAM-maintenance SENTINEL CDF/yr RAW ICCDP CDF/yr RAW ICCDP l (Baseline =3.5E-6)

(7-DAY)*

(Baseline =1.39E-5)

(7-DAY)*

DG-1 Out-of-1.68E-5 4.8 2.55E-7 5.33E-5 3.83 7.56E-7 Service DG-1 Out-of-1.29E-5 3.69 1.81E-7 N/A N/A N/A Service (w/DG-4)

DG-2 Out-of-1.74E-5 4.96 2.66E-7 5.51 E-5 3.96 7.90E-7 Service DG-2 Out-of-1.31 E-5 3.74 1.84E-7 N/A N/A N/A Service (w/DG-4)

• The PRA component of the current plant risk analysis (PPM 1.5.14) is based on the weekly ICCDP.

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 19 of 56 Based on the calculations listed in the table, the Relative Achievement Worth (RAW) values from the updated model are slightly higher than the ones from the current model.

However, with DG-4 implemented, the RAW values are very close (slightly reduced).

In the category of ICCDP, the calculated values from the updated model are significantly decreased from those currently evaluated from the ORAM-SENTINEL model. In comparison, without DG-4 the ICCDP is reduced to about 1/3, while with DG-4 the ICCDP is reduced further to about 1/4.

Therefore, the impact of the change to a 14-day Completion Time does not adversely impact the Application of the Maintenance Rule in accordance with 10 CFR 50.65.

(c) Maintenance Rule (MR)

The relationships between the CGS PRA and MR program are addressed in two perspectives:

1. The importance ranking of systems, structures, and components to plant safety by the CGS PRA and modified by the MR Expert Panel.

2. The relationships of MR Maintenance Preventable Functional Failures (MPFFs) and unavailability criteria to PRA system reliability and unavailability.

In the CGS MR program, the system specific criteria included both MPFFs (reliability) and out-of-service hours (unavailability). In the quantification tasks for the MPFF performance criteria, the PRA was modified to eliminate out-of-service time due to maintenance. The links to external systems were broken and human errors were also removed. This was done in order to compare the calculated PRA hardware failure probability to the comparable estimated hardware functional failure probability.

Because of these PRA modifications, the DG CT Extension would have no effects on the MR reliability criteria.

For the unavailability, the analysis used to establish the MR criterion includes both PRA and plant experiences. Three methods used in determining the performance criteria include:

• Converting the PRA mean unavailability value into allowable OOS hours,

• Converting the PRA RAW importance measure into allowable OOS hours, and

• Examining and evaluating actual plant specific data for the OOS hours.

Based on these three different methods results, the recommended unavailability performance criteria were developed and presented to the Expert Panel. The final unavailability performance criteria were decided and assigned by the Expert Panel. The existing MR unavailability performance criteria for DG1, DG2, and DG3 are tracked at 250 hours0.00289 days <br />0.0694 hours <br />4.133598e-4 weeks <br />9.5125e-5 months <br /> per two-year cycle for each DG. When the TS Amendment request is approved, the DG unavailability performance criteria would be reevaluated and adjusted by the Expert Panel to include the additional 14-day DG outages.

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 20 of 56 (d) Risk Informed LCO 3.0.4 flexible Mode restraints and SR 3.0.3, missed surveillances:

Risk Informed LCO 3.0.4 prohibited a mode change for certain high-risk systems. The PRA change upgrade and the 14-day Completion Time extension did not alter the listed systems. Since the RAW values of the Revision 5 PRA model are not substantially changed with DG-4 in place, the CCDF values for most components are below or near the values previously used. Therefore, there would be no additions to the restricted list for LCO 3.0.4 and the results of risk evaluation results for a Mode change or a missed surveillance would not be greatly changed. The small impact on RAW would also cause no appreciable effect on any calculation associated with a missed surveillance.

Currently, we have no Surveillance that is under an extended performance delay time associated with SR 3.0.3.

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 21 of 56 9a. The 2004 Peer Review was not a 100% review, but a selective sampling. What systems applicable to the proposed CT extension were reviewed and what systems were not reviewed? Additionally, if the review resulted in a graded capability I for the supporting requirement with specific aspects to be upgraded, how are the required upgrades identified?

Response

(1) With the exception of Nuclear Steam Supply Shutoff System (NS4), Compressed Air System (CAS), and Reactor Building HVAC System (REA), the Peer Review Team reviewed all the PRA system notebooks. The system notebooks applicable to the DG CT extension were reviewed.

(2) The recommended changes to the PRA modeling, bases, or its documentation identified by the Peer Review Team are documented in the F&Os. The F&Os are tracked and prioritized for resolution in the future PRA update in accordance with Technical Instruction TI 4.34, "PRA Configuration Control".

(3) There were no F&Os from the Peer Review Team associated with the internal events PRA that required a PRA modification for the TS Application request. However, all application related Level "B" F&Os were identified and a plant tracking log entry implemented to track their disposition. All supporting requirements that were graded to be "not met" or "Capability 1" were reviewed for their impact on the TS application results. This was presented in Attachment 6 of the submittal and the resolution provided. Of the 20 related internal events F&Os, 8 have been implemented, 2 are not applicable, 5 are planned for the next revision and 5 have been resolved as not required through sensitivity analyses.

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 22 of 56 9b As stated in RG 1.200, the team qualifications determine the credibility and adequacy of the peer reviewers. To avoid any perception of a technical conflict of interest, the peer reviewers will not have performed any actual work on the PRA.

Discuss the independence of the Peer Review team members with respect to the guidelines given in RG 1.200.

Response

RG 1.200, Section 2.2, Table 5 includes the following characteristics and attributes of a PRA Peer Review Team and its members:

• Independent with no conflict of interest (not have preformed any actual work on the PRA)

• Collectively represent expertise in all the technical elements of the PRA including integration

• Expertise in the technical element assigned to review

• Knowledge of the plant design and operation

• Knowledge of the peer review process An additional consideration in selecting this team was the individuals familiarity with the ASME standard the NRC's in-process development of RG 1.200. Erin Engineering had supported this industry development. This peer review activity was part of the pilot program for the NRC RG 1.200 pilot program, which necessitated an understanding of the ASME standard and RG 1.200.

Table 9-1 shows a summary of these qualifications for each team member along with the specific PRA elements that they were directly responsible for reviewing.

As noted in Table 9-1, none of the PRA Peer Review Team members participated in the PRA upgrade for the CGS model reviewed. The upgrade was performed by Energy Northwest personnel working with another contractor (Scientech).

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 23 of 56 Table 9-1 PRA PEER REVIEW - TEAM MEMBER QUALIFICATIONS AND RESPONSIBILITIES Checklist, Qualitative Summary, and RG 1.200 Qualification Requirements l

Fact/Observation Forms Expertise in Knowledge of J

Knowledge of Accident l

Technical Plant Design and Peer Review Initiating Sequence Success Systems Peer Reviewer Independence Elements Operation Process Events Evaluation Criteria Analysis Reviewer No. I No involvement See Extensive BWR Author of NEI 00-02

• (1), (2)

• (1), (2) in the 2003 PRA Table 9-2 experience with design and participant in 23 reviewed and BWR EOPs PRA Peer Reviews Reviewer No 2 No involvement See Extensive BWR Trained in the PRA l

• (1), (2) in the 2003 PRA Table 9-2 experience with design Peer Review reviewed and BWR EOPs process prior to the l__

CGS Review Reviewer No 3 No involvement See Extensive BWR Participant in 3 in the 2003 PRA Table 9-2 experience with design BWR PRA Peer reviewed and BWR EOPs Reviews Reviewer No 4 No involvement See Extensive BWR Participant in 5

• (1), (2),

• (Fire) in the 2003 PRA Table9-2 experience with design BWR PRA Peer (4) (Fire) reviewed and BWR EOPs Reviews Reviewer No 5 No involvement See Extensive experience Trained in the PRA

• (Fire)

• (Fire)

• (Fire) in the 2003 PRA Table 9-2 with fire assessments Peer Review reviewed in BWRs process prior to the l_

_CGS Review l

Forms to be Submitted:

(1) Checklist Form (to be submitted by person who presented results at exit meeting)

(2) Qualitative Summary Form (to be submitted by person who presented results)

(3) Fact/Observation Form (to be submitted by each reviewer for area reviewed)

(4) Includes checklists and facts & observations for both fire and internal events Reviewers; The name of the reviewers have been withheld from the docketed response, but are documented in the Peer Review report on file at Energy Northwest

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 24 of 56 Table 9-1 (cont'd)

PRA PEER REVIEW - TEAM MEMBER QUALIFICATIONS AND RESPONSIBILITIES Checklist, Qualitative Summary, and Fact Observation Forms(3) l Data Human Reliability Quantification and Containment Reviewer Analysis Analysis Internal Flood Results Interpretation Performance Analysis Fire Analysis Reviewer No 1 Reviewer No 2

• (1), (2), (4)

Reviewer No 3

• (1), (2), (4)

Reviewer No 4

• (1), (2),

• (1), (2)

• (1), (2), (4)

(4) (Fire)

Reviewer No 5

• (Fire)

• (Fire)

• (Fire)

I Forms to be Submitted:

(1) Checklist Form (to be submitted by person who presented results at exit meeting)

(2) Qualitative Summary Form (to be submitted by person who presented results)

(3) Fact/Observation Form (to be submitted by each reviewer for area reviewed)

(4)

Includes checklists and facts & observations for both fire and internal events Reviewers An.

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 25 of 56 Table 9-2 PRA PEER REVIEW CERTIFICATION TEAM EXPERIENCE l

EXPERIENCE

SUMMARY

TEAM l

Years l Yearsof PRA MEMBER Degree l Experience Experience j Selected PRA Projects Reviewer No 1 BS, Engineering Science 32 28

• Author of NEI 00-02 and its

- RPI predecessor the BWROG MS, Nuclear Engineering Certification Guidelines

- RPI Lead Reviewer on 17 BWR Ph.D., Nuclear PRA Peer Reviews Engineering - RPI Chief Analyst on 5 BWR Level I PRAs Chief Analyst on 10 BWR Level 2 PRAs Developed review template and performed four PRA Self-Assessments of PRAs versus the ASME PRA Standard and DG-1122

• BWR PRA Specialist Reviewer No 2 BS, Nuclear Engineering 10 10 Extensive experience with

-RPI WINNUPRA.

Expert in HRA application to BWRs.

Provided Pre-certification review input for Oyster Creek.

Contributed in the application of certification guidelines to a CANDU reactor PRA.

On-line and shutdown HRA analyst for many U.S.

BWRs.

Supported many PRA updates to address certification comments.

RESPONSE TO REQUEST FORADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF` DIESEL GENERATOR COMPLETION TIME Page 26 of 56 Table 9-2 PRA PEER REVIEW CERTIFICATION TEAM EXPERIENCE EXPERIENCE

SUMMARY

TEAM l

Years Years ofPRA MEMBER Degree l Experience l Experience l

Selected PRA Projects Reviewer No 3 BS, Mechanical 12 12 12 years of BWR PRA Engineering -

experience.

UC Berkeley Technical reviewer or modeler for over 10 Level 1 and Level 2 IPEs.

Lead engineer on over 10 Probabilistic Shutdown Safety Assessments.

Member of two PSA peer review certification teams using the NEI guidelines.

Technical engineer for applying risk informed evaluations to support plant maintenance rule, MOV, l__ _ AOV, and ISI programs.

Reviewer No 4 BS, Mechanical 16 16 Over 15 years experience in Engineering - SJSU PRA.

MBA-SJSU Participated in risk assessments for government and commercial facilities both domestic and international.

Supported most U.S. BWR PRA Programs.

Provided risk assessment support to the Space Shuttle PRA.

Experienced in Level 1 and Level 2 PRA internal and external events, and shutdown risk assessment.

Team member on the following PSA Certifications:

CGS, Fitzpatrick, BFN, Hope Creek, Hatch, and Pilgrim.

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OFRDIESEL GENERATOR COMPLETION TIME Page 27 of 56 Table 9-2 PRA PEER REVIEW CERTIFICATION TEAM EXPERIENCE EXPERIENCE

SUMMARY

TEAM l

Years l Years of PRA l MEMBER Degree I Experience I Experience I

Selected PRA Projects Reviewer No 5 BS, Electrical 23 13 Nationally known expert in Engineering - SJSU the development of Fire PRAs for the nuclear industry.

Provided technical support services related to at-power and shutdown fire risk studies for a number of nuclear facilities.

Provided fire risk related services for Braidwood, Brunswick, Clinton, Cooper Nuclear Station, Duane Arnold Energy Center, Dresden, Farley, Fermi-2, Fort Calhoun Station, LaSalle, Limerick, Peach Bottom, Prairie Island, Quad Cities, Shearon Harris, and St. Lucie.

Fluent with the application of both the EPRI FIVE and Fire PRA Implementation Guide approaches and has performed numerous fire modeling analyses to refine specific fire compartment evaluations.

Developed detailed fire risk assessments in support of the Significance Determination Process (SDP).

Extensive background in deterministic Appendix R Safe Shutdown analyses and electrical engineering Key member of team developing the implementation guide for NFPA 805.

Member of team developing ANS Fire PRA Standard.

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Attachment I Page 28 of 56 As part of full disclosure, it is noted that prior to the 2004 PRA Peer Review, ERIN had provided general consulting services to CGS for a number of years. These services include: engineering services related to Motor Operated Valve (MOV) deterministic evaluations, fire analyses, Significant Determination Process (SDP) Source Book Development and Training, Severe Accident Management training, Reliability Centered Maintenance, outage planning risk assessment models, on-line maintenance risk analysis, and PRA modeling. However, the members of the CGS PRA Peer Review Team have not participated in the development of the 2003 PRA Revision 5 upgrade that was reviewed in January 2004.

The members of the CGS PRA Peer Review Team have performed work for Energy Northwest in the above-mentioned areas as follows:

Reviewer No 1:

1. Reviewer No 1 supported CGS SDP evaluations related to RCIC failures and MOC Switch Breaker failures in the "Significance Determination Process (SDP) 2002 and 2003 issue resolution." This also included minor identification of the model changes that were later incorporated into the 2003 PRA model that was reviewed.

2. The SDP evaluations were performed to support interactions with the NRC in significance determination of operational events. As part of those interactions, minor model changes were developed that incorporated lessons learned from the event assessments into older PRA models. Some of these models were later adopted by Energy Northwest in the 2003 PRA CGS model that was reviewed.

3. Provided specific recommendations regarding the modeling of loss of offsite AC power and its recovery in a time phased event tree. This effort was performed for a previous PRA model and was not used by Energy Northwest in the reviewed model.

4. Participated in the BWROG PRA Certification Peer Review of the WNP-2 PRA in 1997. This 1997 PRA model was a predecessor to the current PRA model. This experience provided additional familiarity with the NUPRA modeling of CGS. This review was an independent review sponsored by the BWROG.

These consulting services are not viewed as compromising the independence of Reviewer No 1, nor did they result in Reviewer No 1 reviewing models or documentation that he had been involved in developing.

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 29 of 56 Reviewer No 3:

1. Converted an earlier version of the NUPRA CGS PRA fault tree/event tree based PRA models for CGS into large fault tree models to facilitate rapid solution times for supporting On-line Maintenance safety evaluations. This effort was a computer model developed from an older CGS PRA model and was used in on-line maintenance evaluations. The on-line maintenance computer model is not part of the 2003 PRA update that was reviewed in January 2004.

2. Provided specific recommendations regarding the modeling of loss of offsite AC power and its recovery in a time phased event tree. This effort was performed for a previous PRA model and was not used by Energy Northwest in the reviewed model.

These consulting services are not viewed as compromising the independence of Reviewer No 3, nor did they result in Reviewer No 3 reviewing models or documentation that he had been involved in developing.

Reviewer No 4:

1. Participated in shutdown risk studies for CGS (WNP-2). The effort involved development of time-to-boil curves, shutdown human error probabilities, shutdown initiating event frequencies, and shutdown event trees. The effort included the development of Risk Management Guidelines and Safety Function Assessment Trees.

2. Prior to joining ERIN in 1990 and as an engineer at Tenera, L.P. (formerly Delian Corporation), Reviewer No 4 participated in system modeling in support of the CGS (WNP-2) IPE.

3. Participated in the Boiling Water Reactor Owners Group (BWROG) PRA Certification Peer Review of the WNP-2 PRA in 1997. This 1997 PRA model was a predecessor to the current PRA model. This experience provided additional familiarity with the NUPRA modeling of CGS. This review was an independent review sponsored by the BWROG.

These consulting services are not viewed as compromising the independence of Reviewer No 4, nor did they result in Reviewer No 4 reviewing models or documentation that he had been involved in developing.

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10. In Attachment 6, is the switchgear room cooling confirmed to be met for the proposed 6-hour mission time?

Response

The proposed 6-hour mission time is associated with the expected battery capacity to supply coping equipment during an SBO. The batteries are capable of supplying power to critical coping equipment for 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> without the support of DG-4 or the cross connect from DG-3. The 6-hour mission time is associated with crediting RCIC and other coping equipment in the PRA for the length of time that the batteries can reasonably be expected to supply power. Additionally, 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> is credited in the PRA for DG-1 or DG-2 recovery without DG-4 during an SBO. The Peer Review Team identified a related concern that completion of the switchgear room heat up calculations was necessary to provide adequate engineering documentation for the assumption that sufficient mission time is available without HVAC (reference Attachment 6, pg 43 of 98, Engineering basis). The term "switchgear" was used to encompass all of the critical electrical coping equipment located in an area of CGS known as the "vital Island." The vital island houses the Class 1 E 4.16 kV electrical distribution switchgear, the Class 1 E 4.16kV/480 unit substations, certain 480 volt Class 1 E Motor Control Centers, battery rooms, battery charger and inverter rooms and reactor protection system motor-generator rooms for Division 1 and Division 2.

Vital Island Room Cooling During an SBO (Batteries Only)

A calculation has been completed to demonstrate that the vital island equipment rooms for critical coping equipment will not reach the equipment's temperature limits within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> during an SBO with batteries providing the only source of electrical power to Division 1 and 2. The calculation demonstrates that the temperatures will remain below the temperature limits for the coping equipment and electrical distribution switchgear and panels located within the vital Island for up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. No compensatory measures are required to achieve this.

Two additional cases were evaluated to address the compensatory measures that supply alternate AC power to equipment located in or supplied by switchgear located in the vital island rooms. These compensatory measures provide alternate AC power in the event of an SBO while in an extended DG CT LCO Action.

DG4 Alternate AC power for the battery chargers The proposed DG-4 will re-energize the battery chargers and will provide a much longer time for certain coping equipment operation, no longer restrained by battery capacity limits. This would result in higher vital island equipment room temperatures and thus, required an evaluation to assure that equipment limits are not exceeded for these increased heat loads and longer durations. A calculation was completed for this case based on the final design of the DG-4 distribution equipment, cabling, and loading. This

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 31 of 56 calculation demonstrates that the temperature increase within the vital island was within the equipment's temperature limits for at least a period of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> with simple compensatory actions of opening certain equipment room doors and the placement of 4 floor fans at the entrance of certain equipment rooms. The SBO procedure will be revised to include these initial compensatory measures to assure room temperature limits are not exceeded for the longer mission time (beyond 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />) made possible by DG-4. Energy Northwest will complete the revision of the implementing procedure prior to entry into the extended Completion Time proposed. Because the actions are simple and driven by procedure and are part of aligning the plant to receive power to the battery chargers from DG-4, these actions are part of the considerations for DG-4's availability probability in the PRA evaluation during the extended CT period and there is no impact to the risk analysis.

DG-3 Cross Connect. Alternate AC Power for Selected Safe Shutdown Equipment The response to RAI #16 provides a commitment to install a cross connection capability from DG-3 to power a division's selected safe shutdown loads. Whenever this cross connection alignment is being used to energize these loads, the HVAC will be placed in operation for the associated division's electrical equipment rooms. The additional heat loads being powered by DG-3 should not challenge any temperature limits in those rooms as the equipment's HVAC will provide cooling. However, DG-4 is assumed to be powering the other division's battery chargers without direct HVAC cooling. A calculation has been completed that demonstrates that the room temperature response to the thermal addition of both the safe shutdown loads (non-accident), powered from the DG-3 cross connection, and the loads powered from DG-4 remain within limits for at least 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The configuration of fans and doors assumed in the calculation for supplying the division without direct HVAC cooling when aligning for only DG-4 will be specified in the SBO procedure to assure the increased heat loads from DG-4 remain below the room limits. Likewise, the configuration of doors and fans used in the calculation when DG-3 is powering one division of the vital island safe shutdown equipment will be specified in the SBO procedure. This will be completed prior to entering into an extended DG CT.

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 32 of 56

11. On page 22 of Attachment 5 it is stated that the AACSBC will be pre-staged with required cabling and distribution boards in place for rapid connection. Does this refer to either the temporary or permanent AACSBC?

Response

This referred to the portion of the distribution system from DG-4 to the 250 V Division 1 battery charger. The final connection to the battery charger was not recommended to be performed at power as it would require the Reactor Water Clean Up System (RWCU) to be removed from service. This is no longer necessary as the necessary in plant installation was completed in the R-17 refueling outage. The need for approval of a temporary wiring installation no longer exists and this portion of the submittal's request is withdrawn.

12. For the permanent installation of the AACSBC, the submittal states that the installation will comply with CGS's separation criteria. Provide an evaluation of the conformance of this installation to the requirements of IEEE 279 (10 CFR 50.55a(h)) and IEEE 308 with respect to channel independence, separation, interaction and single failure.

Response

In response to question 16, CGS has developed a means to use the Division 3 DG to power another Division's selected safe shutdown loads. In addition, the DG-4 can provide power to the batteries during long term SBO conditions. This response evaluates both additional sources for conformance to IEEE 308 and IEEE-279.

DG-3 Cross Connect - Evaluation During Normal Plant Operations The cross tie feature to connect DG-3 to either, but not both, the Division 1 or Division 2 safety buses to power selected safe shutdown loads, is in manual "standby" and not electrically connected during normal plant operations which maintains normal medium voltage bus configurations and therefore, conformance to channel independence, separation, interaction and single failure requirements is maintained. This cross connection can only be made manually in the non-safety related portion of the 4.16 kV AC distribution system (SM-1, SM-2, and SM-3). See Figure 16-1 under RAI #16 response. The normal supply to these non-safety related switchgear is from the unit auxiliary transformers whose supply is the main turbine. In the event of a turbine trip, unit shutdown, or accident, the preferred offsite power source, TRS, supplies this portion of the AC distribution system. The switchgear then, in turn, supplies power to a separate ESF bus. The cross connect design uses spare breaker compartments and breakers that currently exist within this non-safety related switchgear and the non-safety related switchgear that feeds the Division 1 (SM-1 to SM-7) or Division 2 (SM-3 to SM-

8) safety busses. The design provides dual breaker isolation between the non-safety related switchgear (SM-1, SM-3) and the cross connection at SM-2. When the breakers

.1

'Wi s

-A RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 33 of 56 are racked in (as would be the case during the extended DG CT period), there is no automatic action that would cause a connection from SM-2 to the other non-safety related switchgear. Thus no automatic action would preclude the preferred offsite power source from performing as designed. Normally, the breakers would be racked out providing even greater separation between non-safety related switchgear and the preferred power source. Additionally, this portion of the AC distribution system and the DG-3 cross connection through SM-2 is independent from the backup offsite power source (TRB).

During normal operation these breakers will be stored in the racked out position with control fuses removed to ensure required isolation, separation, and no interaction occurs between the non-safety switchgear cabinets.

Prior to entering into the extended DG CT the breakers will be racked in and opened with their breaker control fuses pulled. Because the breakers are deactivated in their open position, no single failure within this cross connection would result in the inability for the preferred power system to support the performance of all safety functions required for a design basis event.

Therefore, during normal operation and during the extended DG CT period, the DG-3 cross connect feature does not change CGS's compliance to IEEE 308 and IEEE 279 as provided in the FSAR, thus channel independence, separation, interaction and single failure are not affected.

DG-3 Cross Connect - Evaluation During an Actual SBO The loss of power to Division 1 or 2 or a full SBO (loss of power to both Division 1 and Division 2 emergency buses) would present the conditions for potential use of this cross connect feature to align DG-3 to either SM-7 or SM-8. The use of the alternate AC power alignment from DG-3 provides an additional power source to low pressure systems.

In this alignment, the function of DG-3 is to supply selected safe shutdown systems in one division and the HPCS pump will be secured. There are no automatic connections from DG-3 to either Division 1 or 2 by this design. This design does provide a non-automatic connection from DG-3 to Division 1 or Division 2.

In performing this cross connection, administrative and design features are used to assure that adequate independence and separation is maintained and any deleterious interaction is avoided. In the unlikely event an SBO occurs requiring this cross connect to be placed in service, the selected division's loads will be initially stripped including deactivating the Division's DG output breaker. The HPCS system will be secured, its pump breaker will be opened and the breaker control fuses removed. The control power for a set of breakers at SM-2 and either SM-1 or SM-3 to power a single division will then be energized. The cross connect breakers will be manually closed under

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION 0F. DIESEL GENERATOR COMPLETION TIME-Page 34 of 56 administrative controls. This allows DG-3 to be cross connected to either Division 1 or Division 2, but not both. The alignment of the cross connect to one division will include verifying that the breaker that would cross connect the other division remains deactivated. This will be the primary means to assure that DG-3 does not supply multiple redundant divisions at one time. This will ensure independence is maintained and divisional interaction between Division 1 and Division 2 does not occur. Upon restoration of an onsite DG the independence between DG-3 and the restored DG is maintained by the deactivated DG output breaker. The AC restoration procedure will require a dead bus transfer back to the normal emergency divisional DG.

Essentially, deploying the cross connect feature to SM-1 or SM-3 allows DG-3 to provide an alternate source of AC power through the existing preferred offsite power source circuit pathway to either SM-7 or SM-8, but not both. In this way, use of DG-3 during an SBO to power another division's selected safe shutdown loads takes advantage of existing electrical distribution equipment to maintain independence, separation, and avoidance of deleterious interaction between safe shutdown load groups (Division 1 and Division 2). Independence between Division 3 and the selected Division I or 2 is preserved as much as practicable. Although the HPCS pump breaker is isolated and deactivated, there remains a need to maintain HPCS valve position indication for Operators to verify containment integrity. These small loads are also powered from DG-3 in the cross connect alignment. This is considered appropriate while in an SBO condition. This is consistent with the normal configuration for the preferred offsite power source (where all three safety divisions are supplied by one offsite power circuit through the startup transformer TR-S). This line up of the preferred power source supports the design function to supply sufficient electrical power for safe shutdown and for operation of emergency systems and engineered safety features when responding to accident conditions with appropriate coordination of the breakers and access to alternate power sources to assure multiple divisions are not lost due to a fault.

Should high pressure injection be required beyond the RCIC capabilities, shutting down the low pressure cooling system, isolating the Division I or Division 2 switchgear from the cross connect, and realigning the distribution of DG-3 to the HPCS pump can be accomplished quickly.

For reference, the NRC has approved the use of the HPCS Diesel Generator in this manner as a compensatory measure during extended DG CT at River Bend and Grand Gulf.

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 35 of 56 DG Evaluation During Normal Operations During normal operations, DG-4 will not be connected to the onsite AC distribution system. DG-4 will be located outside of the diesel generator building sufficiently removed to maintain separation requirements. There is no physical connection structurally or mechanically with the DG building. The only electrical connection to the plant during normal operations is a small electrical circuit to support DG standby loads from a non safety related power source.

The design provides for DG-4 to be connected to quick disconnect plugs located in the exterior wall of the DG-building sufficiently separated from DG-1 and DG-2.

Additionally, a Class 1 E isolation breaker is provided from this disconnect plug to the DG's support MCC. All raceway and cabling from the Class 1 E isolation breaker to the DG's MCC is Class I E. Whenever that portion of the AC Distribution System is being relied upon to meet the Technical Specification requirements (at power or shutdown),

the manual isolation breaker(s) are locked open and the DG-4 feeder cables are disconnected from the quick disconnect plugs. The isolation breaker is located immediately inboard from the exteriorly mounted quick disconnect plugs, and is appropriately coordinated. This provides dual means to assure isolation between the non-safety DG-4 and the divisional bus. Neither an inadvertent connection of DG-4 to the quick disconnects nor does an inadvertent closure of the isolation breaker affect the Divisional bus. The Isolation breaker positions are administratively controlled.

The DG-4 is designed with a load bank for testing. All surveillance testing, maintenance and repair of DG-4 can be accomplished without any interaction with the Class 1 E distribution system.

Therefore, during normal operation and during the extended DG CT period, the DG-4 power supply to the batteries does not change CGS's compliance to IEEE 308 and IEEE 279 as provided in the FSAR, thus channel independence, separation, interaction and single failure are not affected.

DG Evaluation During an Actual SBO During an SBO, operations will attach the feeder cable to the quick disconnect plugs, deactivate the associated Divisional DG's output breaker, open the feeder breaker from the unit substation to the battery chargers MCC to isolate from the upstream 4.16 kV portion of the distribution system, and close the DG-4 feeder isolation breaker to re-energize the DG's MCC and backfeed to the battery charger's MCC.

On Division 2, a connection path is also being provided to power the non-safety related battery charger (Cl-7) from the Division 2 AC distribution network. Charger C1-7 supplies control power to the non-safety-related switchgear SM-1, SM-2, and SM-3.

This will ensure power is available to operate the DG-3 cross connect breakers. This

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT-REQUEST FOR EXTENSION OFbDIESEL GENERATOR COMPLETION TIME Page 36 of 56 connection to the non-safety related battery charger is through the isolation circuit breaker that normally supplies a backup 125 volt DC charger for Division 2. Two transfer switches are provided that can be aligned to supply either the normal 125 Volt back up Division charger or Charger C1-7. These transfer switches are locked in their normal alignment position. The first transfer switch connects either the Backup Division 2 125 volt battery charger or provides a connection to a second transfer switch. The second transfer switch allows power to be fed to the C1-7 charger from either the Division 2 bus or the normal non-safety bus. The design does not allow the Division 2 bus to be electrically connected to the non-safety bus. This non-safety related load is isolated from the safety bus through the Class 1 E bus breaker, isolation fuses, and the series transfer switches. No single inadvertent operator action would result in a loss of separation between the Division 2 bus and the non-safety related supply. Further, if a single failure of the second transfer switch occurred, the Division 2 bus breaker and isolation fuses would isolate the fault. Additionally, there is no interaction between the safety bus and the normal non-safety related supplies to the non-safety battery charger.

DG-4 and DG Evaluation Durinq an Actual SBO During a long term SBO condition, both the DG-3 cross connect and the DG-4 charger supply will be separately aligned to supply different divisions. Although DG-3 and DG-4 connect to the AC distribution system at different voltage levels, it is necessary to avoid multiple sources from supplying the same Division and cause a potential deleterious interaction. Administrative controls will be used to prevent this by requiring only one division to be aligned to an alternate source.

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13. a) Is the temporaryipermaanent AACSBC to be included in the 10 CFR 50.65(a)(2) Maintenance Rule? b) Will the AACSBC have established performance criteria? If so please identify the performance criteria for the AACSBC.

Response

The submittal proposed if DG-4 should not be available, a temporary diesel may be obtained of sufficient capacity and staged until DG-4 becomes available. This proposed request is withdrawn.

The following address the permanent DG-4.

a) Yes, DG-4, the alternate source to the battery chargers, will be a permanent plant feature. An advanced maintenance program review has been performed by the Maintenance Rule Expert Panel and they have determined that it is in scope.

Accordingly, DG-4 will be included in the Maintenance Rule program per 10 CFR 50.65(a)(2). DG-4 is a permanent, mobile, 480 volt diesel generator that will have performance criteria established through the Maintenance Rule Expert Panel.

b) Yes, The performance criteria will include reliability and availability based on the risk significance to be determined by the expert panel. The development of these performance criteria will be based on assumptions used in the PRA and updated in accordance with the PRA update program. This is a new commitment.

14. Provide the DG unavailability goals and reliability criterion (functional failures) and comparatives to the estimates used in the CGS PRA.

Response

To ensure the proposed extension of the DG Completion Time does not degrade operational safety over time, should equipment not meet its performance criteria, an evaluation is required as part of the Maintenance Rule of 10 CFR 50.65. The reliability and availability of the affected DG's (DG-1, DG-2, and DG-3) at CGS are monitored under the Maintenance Rule Program. If the pre-established unreliability or unavailability performance criteria are exceeded for the DGs, consideration must be given to 10 CFR 50.65(a)(1) actions, including increased management attention and goal setting in order to restore DG performance (i.e., reliability and availability) to an acceptable level. The performance criteria are risk informed and are a means to manage the overall risk profile of the plant. An accumulation of large core damage probabilities over time is precluded by the performance criteria.

The DGs are all currently in the 10 CFR 50.65(a)(2) Maintenance Rule category (i.e.,

the DGs are meeting established performance goals). Performance of the DG on-line maintenance is not anticipated to result in exceeding the current established

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 38 of 56 Maintenance Rule criteria for DGs. Pursuant to 10 CFR 50.65(a)(3), DG unreliability and unavailability are monitored and periodically evaluated in relationship to the Maintenance Rule goals. Each CGS DG has a base unavailability goal of 250 hours0.00289 days <br />0.0694 hours <br />4.133598e-4 weeks <br />9.5125e-5 months <br /> per 24-month period. The current running 24-month, unavailability values for the DGs are:

DG 129 hours0.00149 days <br />0.0358 hours <br />2.132936e-4 weeks <br />4.90845e-5 months <br />; DG 139 hours0.00161 days <br />0.0386 hours <br />2.29828e-4 weeks <br />5.28895e-5 months <br />; and DG 53 hours6.134259e-4 days <br />0.0147 hours <br />8.763227e-5 weeks <br />2.01665e-5 months <br />. The Maintenance Rule performance goal for reliability is no more than one MPFF per division in a rolling 24-month period. A 10 CFR 50.65(a)(1) evaluation will be performed when one MPFF occurs. Since May 1, 2002, the DGs have not failed to start in any of the more than 110 starting demands. Within the past 24 months, DG-2 had no MPFF and DG-1 had one MPFF in November of 2003 when the DG tripped (failed to load) while paralleling it to the grid.

The CGS PRA unavailability values were conservatively derived directly from the highest total annual out-of-service hours. The values used in the calculation are:

Diesel Generator Unavailability Unreliability*

DG-1 3.72E-3 DG-2 1.35E-2 DG-3 5.20E-3 Failure to Start 1.55E-3/d**

Failure to Load 1.04E-2/d**

Failure to Run 2.67E-3Ihr

• The CGS DG unreliability values used in the PRA for all three DGs

• • A failure to start value of 1.1 9E-2/d (provided in Attachment 5 of Reference 1) combined both the failure to start and failure to load mode.

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15. For the sensitivity studies performed, a) were collective effects evaluated (instead of separate) for individual componentslevents? Integrated impact?

b) What are the effects resulting from the worst case considerations of all the sensitivity studies.

Response

The sensitivity studies that had been performed for the DG CT Extension Submittal were discussed in Attachment 5, Section 6 of the Submittal. Among the items being discussed, there are four evaluations performed for PRA Level 1 and two evaluations for Level 2. It is recaptured in the following table with impacts to CDFbaseline and LERFbaseiine included:

Sensitivity Items Level 1 Impact Level 2 Impact (ACDFbaseline)

(ALERFbaselIne) 1 HPCS Mission Time. 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> versus 22 hour2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br />s: The CGS

[6.3]*

PRA model uses 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> based on assumptions regarding containment interface. The Peer-Review Team had E

considered this assumption to be overly conservative. A

-6.88E-7 (negligible) mission time of 22-hr was used for HPCS mission time as a sensitivity analysis.

2 Recirc Pump Seal Leakage, no leakage versus 36 qpm

[6.4]*

leakage: The amount of seal leakage would affect the containment condition for determining the RCIC operability. An E

E HEP was developed to bypass the RCIC back pressure trip as a sensitivity analysis.

3 Level 2 human error probability using generic values 0.1 or 0.9

[6.5]*

versus 0.9 for all: The L2 HEP values 0.1 or 0.9 were based on logical assumptions in lieu of specific development from N/A

+7.89E-7 linking. A sensitivity was performed for setting all HEPs to be 0.9.

4 Level 2 phenomenological failure probabilities using 1 E-2: The

[6.6]*

CGS PRA model uses 7E-1 for Ex-Vessel Steam Explosion N/A

-1.11E-7 based on conservative reference. The Peer Review Team had considered this assumption to be overly conservative.

5 A re-development of all DG CT impacted vost-accident HEPs:

[6.7]*

Based on an extensive HRA analysis performed recently, failure probabilities of 24 operator actions were modified.

+6.95E-7

+9.96E-8 Human-error dependency was re-examined, and minimum I HEP values were added.

6 Re-grouping pump failure probability data: Subdivided the 16.8]*

failure probabilities in the pump database between standby

+3.47E-7

+1.9E-9 and running pumps per Peer Review Team comments.

CDF LERF Total effects based on numerical combination of all sensitivity 7.68E-6 1.46E-6 items(Separate Effects)

Total effects based on integrated calculation of all sensitivity 7.57E-6 1.19E-6 items (Collective Effects)

• [x.x] Section reported in Attachment 5, Reference 1

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 40 of 56 a) The collective effects of the sensitivity analysis performed have been calculated and listed in the bottom two rows of the table. The integrated impact can be examined by comparing the integrated results (carrying the synergistic or collective effects) with numerical summations. It is evident from the table that the collective effect are limited, and the combinations of uncertainties actually resulted in some canceling of the uncertainty effects. This indicates that there is no significant bias in the model for the sensitivity analysis performed. For ACDF, the integrated calculation is decreased by 1.4%, which is insignificant. For ALERF, the integrated calculation is decreased by 18.5%, which may be reasonable based on the multiplication nature in the calculation from level one cascaded to level two.

b) As an evaluation for a calculated worst case, Cases 3, 5, and 6 of the sensitivity analysis were selected for a combined worst case calculation. The resultant CDF is 8.28E-6 and LERF is 2.11E-6. Since, from uncertainty analysis viewpoint, a worst case consideration is judged to be outside of the uncertainty band, no trended conclusions are attempted.

The collective effects discussed above were evaluated for baseline CDF and LERF only. It is judged that the collective effects of sensitivity analysis to the ICDF (discussed in NUREG 1.174) and ICCDP (discussed in NUREG 1.177) are enveloped by the baseline CDF and LERF analysis. This is judged based on how a similar amount of impact would affect the conditional CDF and conditional LERF during the extended DG CT conditions.

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16. The AAC source described in your submittal is not a qualified AAC source to support your request because it does not have enough capacity to power safe shutdown loads. In the past, the staff has granted extension in allowed outage time for DGs to those licensees who have installed a qualified AAC credited for station blackout (SBO) events which can be substituted for an inoperable DG in the event of a loss of offsite power (LOOP). Also, some BWR licensees have taken credit for the Division IlIl DG which can be cross-connected to either Division I or Division II AC buses to provide an alternate source of power for an SBO or in the event of a LOOP when one DG is in the extended outage and the other DG becomes unavailable. This cross-connection can be accomplished within two hours. These licensees have demonstrated that when the Division IlIl DG is cross-connected to the Division I or 11 bus, it can carry all of the Division I or 11 automatically connected loads with the exception of certain loads. Some licensees have installed a temporary commercial-grade diesel generator capable of supplying power to, at a minimum, the required safe-shutdown loads on the DG train removed from service for the maintenance outage.

In view of the above, should you elect to utilize the Division IlIl DG as an alternate power source, please provide the following additional information:

a. Is this going to be a permanent cross-connection? How long would it take to accomplish this connection?

b. Demonstrate that Division III DG has enough capacity to power loads that are needed for a station blackout and a loss of offsite power.

Response

a. Yes, the Division 3 DG will be used as an alternate power source. Less than two hours. The DG-3 cross connect will be verified to be available prior to entering into the extended DG CT. This requirement has been added to the proposed TS Action.

Engineering Evaluation of Change to RG 1.177 Proposed Change:

In addition to the proposed DG-4 for an alternate AC source to the battery chargers and in response to this question, to support defense-in-depth for the requested diesel generator Completion Time extension, Energy Northwest has designed and is completing the installation of a cross-connection feature to allow DG-3 to power the Division 1 or Division 2 Engineered Safety Features (ESF) bus. The remaining tasks are refurbishment of the 4160 V breakers and completing the procedures for use. This cross-connection is a permanent plant feature using electrical breakers that are part of the original plant design. These spare breakers were available to accomplish the cross

Rr?2ONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT-REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 42 of 56 connection in the three non-safety related switchgear cabinets that supply Division 1, 2 and 3 ESF buses. Energy Northwest has completed the installation of the cabling for this connection. SBO response and alignment procedure will be revised and implemented prior to entering the extended Completion Time period requested by the technical specification change. The buses and cross-connection are illustrated in figure 16-1.

The SBO procedure will detail the cross-connection actions that selectively strip one of the de-energized buses, (Division 1 or Division 2) of its loads, defeats the HPCS LOCA automatic initiation signals, and performs breaker line-ups from DG-3 to power the selected ESF emergency switchgear. Prior to starting the pumps, the ECCS or decay heat removal systems may be filled and vented, if required.

Compliance with Existing Regulations The AC power system is specifically designed to assure sufficient power to safely shut down the plant and mitigate postulated accidents. Full and redundant capability is maintained with either all onsite power sources '(DG-1, DG-2, and DG-3) or Offsite power (230 kV-TRS and 115 kV-TRB). With only DG-1 or DG-2 and the HPCS function available, full capability to safely shutdown the plant and to mitigate postulated accidents is maintained. However, single failure capability is not maintained.

Therefore, a limitation is placed on the length of time that this condition can exist without requiring a change in plant operating modes to exit the Applicability of the TS LCO (i.e.,

in this case, the change in operating modes is to shutdown the plant). This time limit has been based on a past conservative risk evaluation. This change to the DG CT allows an increase in the length of time the plant can be in this condition based on more realistic and quantitative risk evaluations. The increase in length of time for a DG to be inoperable in the proposed TS change does not change the currently allowed plant configuration. It only changes the length of time this condition is allowed. Therefore, this change fully meets the current regulatory requirements related to minimum capability to safely shutdown the plant or to mitigate postulated accidents.

The two proposed AC power sources provide additional ability to cope with an SBO without impacting the station's evaluation to the requirements of 10 CFR 50.63. The design changes to CGS for these additional features do not change the analysis that demonstrates a minimum of four hours ability to cope with a SBO event. These additional AC power sources provide the ability to cope for much longer and/or to proceed to bring the plant to safe shutdown using DG-3 when the need for the HPCS function is not required. The current SBO analysis states:

The RCIC system is considered the backup to HPCS during SBO. Columbia Generating Station's coping analysis includes battery voltage profiles for both the 125 V dc and 250 V dc batteries that provide power to RCIC system equipment.

These battery profiles assume that RCIC is providing sole mitigation for the SBO

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENTREQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 43 of 56 event. Although the RCIC system is not credited for SBO event mitigation, it is the preferred SBO mitigation system and will be maintained available to respond to an SBO event. (FSAR Page 8A-3/4)

The DG-4 design change provides the ability to maintain RCIC as the preferred SBO mitigation system for a period that exceeds the current SBO coping time requirement of 4-hours.

Upon establishing RCIC as the SBO mitigation system, the need to maintain DG-3 solely for HPCS is no longer required. Yet, it is prudent to maintain the ability to quickly reestablish the HPCS function in the unlikely event that RCIC and the low pressure injection/cooling system subsequently fail. The design provides the capability to quickly isolate the low pressure system and transfer power back to the HPCS pump should this become necessary (within approximately 25-30 minutes). The SBO procedure that provides the cross connecting actions will contain a section for isolating the Division 1 or 2 bus and re-energizing the HPCS system.

Following a loss of offsite power or a station blackout, the normal priority for restoration of power to a Division 1 or Division 2 emergency bus is:

1) The recovery of the operable onsite diesel (either Division 1 or 2). Division 3 is not assumed to be lost in a SBO per the CGS licensing and design basis. Recovery of a Division 1 or Division 2 DG provides sufficient capability to perform all required accident safety functions and safe shutdown functions.

2) The recovery of one of the offsite power sources. Recovery of TRS restores preferred offsite power to Divisions 1, 2, and 3; recovery of TRB restores power to Division 1 and 2 (DG-3 is not lost). Recovery of either of these provides full capability to perform all accident safety functions and safe shutdown functions.

The current licensing basis for an SBO event for CGS is to be able to cope during an SBO for 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The SBO analysis does not assume that either DG-1 or DG-2 is operable. Therefore, the proposed TS change to allow a DG to be taken out of service for maintenance for 14 days does not change the ability of CGS to cope with an SBO, because DG-1 and DG-2 are not considered to be operable during the event. However, the proposed additional AC sources provide additional defense-in-depth. The additional AC sources clearly provide significant ability to avoid core damage for an extended duration SBO event.

The decision to energize the cross-connect will be a Shift Manager action within the SBO procedure. This will assure that these additional features are properly coordinated within the NRC approved 10 CFR 50.63 Safety Evaluation and our SBO coping strategy for CGS. Should prompt recovery of an onsite or offsite power source be delayed, the Shift Manager will direct station personnel to start the cross-connect configuration

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OFODIESEL GENERATOR COMPLETION TIME Page 44 of 56 alignment based on the anticipated recovery delay and a stabilized reactor inventory control state. Initial alignment can commence immediately once reactor level inventory control is stabilized and initial SBO coping actions are completed. This initial configuration can be completed, as on shift resources become available, within the first 90 minutes without impacting the HPCS function. Once the decision is made to replace the HPCS injection function with the low pressure safe shutdown function, energizing the safe shutdown load bus can be accomplished in approximately 20-30 minutes.

In summary, during the extended DG CT period, Energy Northwest commits to being able to accomplish the energizing of the cross connection from DG-3 to the Division 1 or Division 2 ESF switchgear bus (SM-7 or SM-8 respectively) within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> in accordance with our Station Blackout Procedure. When the cross-connection procedure is finalized, this ability will be verified through training and simulation to assure adequate on-shift resources and that response ability is within the 2-hours.

Defense-in-Depth With proper administrative controls, these added features improve operational safety defense-in-depth and reduce plant risk for conditions arising out of loss of AC power events.

If at any time after the onset of the SBO, prompt recovery of an offsite power source or recovery of the required diesel is not anticipated, the DG-3 cross-connect will be initiated to facilitate a transition to low pressure injection or cooling in accordance with CGS's EOPs. The alignment of the distribution system to cross connect DG-3 to power a Division 1 or Division 2 emergency bus is possible with on-shift personnel with the permanently installed hardware. The configuration alignment of the distribution system may proceed after initial operator actions have been completed. The time to configure one division of the distribution system to be able to receive DG-3 power is approximately 90 minutes from the SBO's initiation. The energizing of the Divisional bus by DG-3, once the distribution system has been configured for the cross connection, can be accomplished in approximately 20-30 minutes and simply requires the HPCS system to be secured, its pump breaker opened and deactivated (its breaker control fuses pulled), the under voltage logic for the Division 3 to SM-2 breaker defeated, and then manually closing two non-safety related switchgear breakers (SM-2 breaker and the SM-1 or SM-3 breaker).

DG-4 will also be pre-staged and able to energize the Division I or Division 2 battery chargers in 2-4 hours from the SBO's initiation. With DG-4 providing power to the battery chargers, the coping ability is extended well beyond the 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> required by 10 CFR 50.63. Thus, significant additional time and margin is available for an informed decision to be made by the Shift Manager on transferring DG-3 power to support Division 1 or Division 2 low pressure injection systems.

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF;DIESEL GENERATOR COMPLETION TIME Page 45 of 56 Once reactor level is stabilized using RCIC, the preferred SBO mitigation system, and HPCS is no longer needed, an additional power supply capability for low pressure systems can be established. Reactor vessel pressure can be reduced below the low pressure injection set point and a transition of the AC power source (DG-3) to supply a low pressure injection or low pressure cooling system will provide additional safety benefit to bring the plant to safe shutdown. This design also provides for additional features should conditions occur where the high pressure core spray system is not available during a loss of AC power event. The alignment of DG-3 to power the low pressure system and use of the automatic depressurization system (ADS) valves to reduce reactor pressure provides an additional feature. These capabilities improve the defense-in-depth during the requested TS Completion Time.

The addition of DG-4 prolongs the availability of critical batteries from 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> to beyond 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, greatly extending the time the plant can cope until AC power is recovered.

The addition of DG-3 cross-connect provides a means to power sufficient equipment to safely shutdown the plant during an SBO. The DG-3 cross connect goes beyond just coping with the SBO conditions until normal AC power is recovered; it provides a means to mitigate the effects of an SBO. Cross-connecting DG-3 to power Division 1 or Division 2 transfers power from high pressure core spray to a low pressure system with adequate injection/cooling to bring the plant to safe shutdown (non DBA) and mitigate core damage. Additionally, the alternate shutdown cooling mode of RHR cools both the reactor and the suppression pool.

Additionally, the DG-3 cross connect is also capable of providing sufficient AC power for operation of important systems to protect containment integrity. There are several modes of RHR that directly mitigate the temperature and pressure conditions in containment. These include the suppression pool cooling mode and the containment spray mode. Additionally, the Alternate Shutdown Cooling Mode (Ref. RG 1.139) provides the ability to cool the suppression pool and reach a cold shutdown condition of the reactor providing both reactor and containment cooling at the same time. The DG-3 cross connect to the division's ESF bus will allow sufficient power to align RHR to the mode of operation needed during the progression of the postulated SBO. The RHR system is described in FSAR Section 5.4.7 and Section 6.2.2.

If both an offsite power source and the Operable onsite DG can not be promptly recovered, initiating the DG-3 cross-connect alignment would be an immediate action appropriately prioritized with the other existing immediate actions (e.g., reactor vessel level control, reactor vessel pressure control, battery load shedding, etc.). The Shift Manager would make the decision to energize the selected ESF bus from DG-3 based on the actual likelihood of recovering an onsite or offsite AC power source and the stabilization of reactor level on RCIC.

System channel independence, separation, interaction and single failure are maintained as described in the response to RAI 12. The additional AC sources are designed and

R7-E3PONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF<DIESEL GENERATOR COMPLETION TIME Page 46 of 56 will be deployed via administrative controls to not compromise these characteristics of design separation protection.

Neither the proposed additional AC sources, when applied as described above, nor the extension in the Completion Time significantly impact the current defense-in-depth. A reasonably balanced approach has been achieved of improving core damage mitigation, preventing containment failure, and minimizing the consequences of the mitigation improvements. The proposed TS change and the additional AC sources have not significantly changed the balance among these principles of prevention and mitigation. The proposed AC sources provided increase capability for mitigation of core damage and prevention of containment failure at all stages of an SBO.

Safety Margins The NRC has reviewed and approved the ability of CGS to cope with the SBO condition for 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The ability of CGS to cope with a 4-hour SBO has been evaluated without reliance on this cross-connection capability (See Appendix 8A of the CGS FSAR). The DG-3 cross-connect, although not credited for meeting the 10 CFR 50.63 provisions of the regulations, is capable of powering safe shutdown equipment and is also capable of significantly increasing the actual coping time by powering critical batteries on the division energized. It can be placed in service within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. The coping evaluation of Appendix 8A is not altered by the proposed addition of a DG-3 cross connect feature.

Additionally, Energy Northwest has proposed a DG-4, 480 V diesel generator as a backup source to the battery chargers. This extra source will assure that battery power is available to support RCIC, ADS, and other features. This allows CGS to be able to cope with an SBO well beyond 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The DG-4 adds a defense-in-depth measure that is not credited in the current Station Blackout coping analysis. The ability of CGS to cope with a 4-hour SBO has been evaluated without reliance on this additional battery charger supply capability (See Appendix 8A of the CGS FSAR). The coping evaluation of Appendix 8A is not altered by the proposed addition of DG-4.

The other major safety margin benefit of the proposed AC sources is the additional time provided for recovery of an offsite or onsite AC source. With these additional AC power features, the probability of recovery of an AC source is significantly improved.

The Emergency Action Levels to activate the emergency response organization upon a loss of offsite power (a precondition to an SBO event) are not changed by this request.

Compensatory risk measures have been proposed that provide appropriate restrictions to preclude simultaneous equipment outages during the extended DG completion Time period. These compensatory actions include not performing surveillance and maintenance activities on other divisional risk significant equipment that would impact their operability. The planning restrictions include scheduling DG maintenance to avoid

REF-6,NSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 47 of 56 adverse weather or other abnormal conditions. Compensatory actions are proposed that assure the offsite power sources are not impacted by maintenance that would impact grid reliability and that conditions that create the potential of developing grid instabilities do not exist.

Sufficient design and administrative controls are proposed to assure there are no new potential common cause failures and that existing potential for common cause failure is not worsened. The design features of DG-4 and the cross connect distribution circuits do not degrade any existing barriers. The penetrations of the DG-4 cabling through the diesel room outside wall is through approved fire rated devices that preserve the fire rating of the DG outside walls.

Due to the change in performing the DG maintenance online, significant maintenance and operator training and planning are proposed for the change. The training includes, the operation and maintenance of DG-4, the compensatory measures required to be in place prior to a planned entry into the DG extended Completion Time, and the alignment and energizing of DG-3 to either Division 1 or 2 ESF bus. This training, along with management overview for first time evolutions, will assure defenses against human errors are maintained and, where appropriate, enhanced.

Finally, the compliance with General Design Criteria 17 is not impacted. The proposed compensatory actions, including the proposed additional AC sources during the extended Completion Time enhance CGS conformance with the Appendix A General Design Criteria of 10 CFR Part 50.

Evaluation of Risk Impact (associated with DG-3 and DG-4)

A risk evaluation shows that there is an optimum time for energizing the DG-3 cross connection. The risk was evaluated for performing the cross connect at 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and at 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> (assuming DG-4 is maintaining Div 1 batteries). There is a measurable improvement in risk for the latter. The principal factors that cause this difference in risk are the decrease in human error probability and the decrease in RCIC failure probability due to additional time to make the transition from a high pressure to the low pressure state where low pressure injection/cooling system can be placed in service. Ensuring that the transition can be completed while maintaining reactor pressure below the low pressure set point permissive for low pressure system injection and maintaining reactor level, are critical steps in this transition sequence. Allowing a controlled but slower reactor pressure decrease to below the low pressure injection permissive set point (approximately 6-7 hours) while using RCIC (with HPCS remaining available) provides the lowest risk transition sequence. With DG-4 maintaining batteries functional, this extended time is available, if needed.

However, if DG-4 is not available or fails, then an early transition with DG-3 would be the better choice (assuming an offsite or onsite AC source would not be recovered).

R'ESPOQSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICEN-SE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 48 of 56 Although not a limiting parameter for coping, the next parameter of concern in the emergency operating procedures becomes the high containment temperature limit (HCTL). An analysis performed to support the PRA shows that the HCTL is predicted to occur in approximately 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br />. By the addition of the DG-4 source to the battery chargers, there is a significant time margin for performing the DG-3 cross connect or restoring an onsite or offsite AC supply.

As shown in Attachment 5 of Reference 1, the proposed TS change to increase the Completion Time is in the "very small risk" region of Figure 3 and Figure 4 of RG 1.174 without crediting DG-4 or DG-3. Therefore, the proposed increase does not overly rely on these features. Further, the change does not overly rely on programmatic features or over optimistic reliability assumptions.

With these additions, DG-4 and DG-3 cross connect capability, the Shift Manager has significantly increased means to not only cope with an SBO but to mitigate its effects and safely shut down the plant.

a t

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 49 of 56

b. The capacity of DG-3 has been evaluated and is capable of providing one train of selected safe shutdown equipment. This would include one division's emergency service water system, the associated RHR pump, which can be aligned in suppression pool cooling, containment cooling, or an injection mode, and necessary associated support systems. Table 16-1 below provides the loads that could be powered. DG-3 has a continuous rating of 2600 kW and a 2,000-hour rating of 2850 kW. A station procedure will establish the loads that can be connected to prevent overloading DG-3.

The approximate loads allowed by the procedure are provided in Table 16-1 below:

Table 16-1 Selected Safe Shutdown Loading On DG-3 LOAD DESCRIPTION Div 1 Loads kW Div 2 Loads kW SSW Pump 1280 1261 SW HVAC 9

9 DG-3 and Support System Auxiliaries 166 166 RHR Pump 625 644 RHR Pump Room HVAC 3

3 MOVs, Transformer Losses, Misc.

42 39 Control Room HVAC 25 25 Vital Island HVAC & Battery Room Exhaust 75 51 Miscellaneous Power Panels, Lighting, etc.

170 164 Chargers (250 and 125 Vdc) & associated Inverter 229 84 Total DG-3 Loading 2624 2446 DG-3 Capacity 2000 hr @ 90 F 2850 2850 Margin 226 404 Selected additional loads that can be energized as DG-3 permits.

Fuel Pool Cooling 38 38 CAS compressor 82 82 SGT / Containment venting 25 25

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 50 of 56 Figure 16-1 DG-3 Cross Connect and DG-4 II X -

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Shown in bold is new wiring and breakers to the CGS electrical distribution system

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 51 of 56

17. (a) What type of communication has been established between the control room operator of CGS and the system load dispatcher? b) Did Energy Northwest obtain current grid conditions information from the dispatcher prior to maintenance on the DG? c) Is the dispatcher notified in advance that the DG is going to be out for extended period of time?

Response

(a) Telephone communication on both grid and onsite power source conditions with the Bonneville Power Administration (BPA) grid dispatcher is a normal activity by the CGS control room staff and the unit coordinator. This is detailed in an existing Letter Agreement with BPA and plant procedures to assure sensitive conditions are communicated to each other.

The following are means of communication with the grid dispatcher.

• A direct ring-down circuit on the control room supervisor's station (single push button connect),

• A control room telephone from control room to the BPA Dial Automatic Telephone System (DATS),

• A direct DATS phone located in the Rad Waste building communications room, and

• Two separate commercial telephone numbers.

This communication involves the status of grid conditions including the early warning from BPA transmission system dispatchers of potential or developing instabilities.

A formal agreement with BPA assures that any emergent grid condition potentially affecting the reliability of the offsite source of power to CGS's two credited offsite power sources is immediately communicated to CGS. Upon notification to the BPA dispatcher from the Pacific Northwest Security Coordinator of issues concerning reliability of the offsite sources of power to the CGS plant or notification that the automatic grid monitoring equipment (State Estimator) used to establish state of the network against contingencies that affect CGS is out of service, BPA dispatch will immediately notify CGS Operations.

Prior to entering the extended DG CT and performing planned maintenance on a DG, Energy Northwest will verify through BPA that there are no PNSC notifications concerning reliability of the offsite sources of power to the CGS plant. Prior to the planned maintenance activity, Energy Northwest will verify with BPA that there is no current report of failure regarding the automatic grid monitoring equipment used to assess the state of the network.

BPA is required, in cooperation with CGS, to implement a Dispatcher's Standing Order (DSO) necessary to meet the standards for nuclear plant operations as required to meet

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 52 of 56 nuclear industry regulatory requirements. This DSO remains on file at BPA's Munro and Dittmer dispatch centers. BPA is required to inform Energy Northwest in advance of any necessary or proposed changes to the DSO and provide an opportunity for Energy Northwest to review and comment prior to implementing any material changes.

This standing order establishes further communication actions by the grid dispatcher to mobilize BPA assets to respond to emergencies at CGS. A loss of power condition where power capability to critical AC buses are reduced to a single power source for greater than 15 minutes such that any additional single failure would result in a Station Blackout is classified at the Emergency Action Level (EAL) of Alert which would activate the DSO communication.

In addition, BPA is required to notify Energy Northwest in the event BPA requires outages of the Federal Columbia River Transmission System (FCRTS) equipment or facilities that are materially relevant to reliable deliveries to Energy Northwest.

For planned grid maintenance activities, certain BPA grid parameters and planned maintenance activity schedules are available to Energy Northwest on the BPA OASIS website.

CGS communicates any changes to our output, including main generator output, paralleling of DGs to the grid for testing, notification of DG inoperability, and power needs to BPA.

These communication agreements are controlled by procedures and standing orders within CGS and BPA.

Backing up these procedurally driven communications, CGS has an onsite monitoring system (oscillograph recorder) with alarms that sense a grid condition change that may be important to CGS. This provides back up information to the Control room staff for rapidly changing grid voltage conditions. Procedures require control room communication to the BPA Dispatch Center for information related to the alarms.

(b) Yes. Prior to removing a DG from service, current procedures require contacting BPA for verifying stable grid conditions exist. We will assure that we also obtain the projected grid conditions when planning an online elective DG maintenance. This will continue to assure that periods of stable grid conditions are chosen and that planning of maintenance activities by BPA on the grid can be coordinated to avoid conflict.

(c) Yes. CGS has a letter of agreement with BPA that requires the following advanced notification from CGS to BPA:

• Emergency Diesel Generator and support system outages or testing that require protection of the opposite divisions to ensure minimum safety system availability.

• Transformer, bus, or switchgear outages or testing that require protection of the opposite divisions to ensure minimum safety system availability.

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 53 of 56

• Telecommunications maintenance that may impact telemetry between CGS and BPA assets such as Ashe Substation.

• Reactor power changes (up or down).

• Station outages both planned and forced.

Station procedures implement this communication when the above conditions occur.

RESPON!SE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 54 of 56

18. Clarify if there are there any seasonally based or other restrictions on DG maintenance. Provide clarification as to what is meant by severe weather and the action to be taken.

Response

Although there are no seasons where'the extended CT is proposed to be restricted for this application request, an extended DG outage will not normally be scheduled during extremely hot or cold forecasted conditions when potentially high grid loading conditions could occur. Whenever planned or emergent DG maintenance is required during these times, BPA will be requested to confirm that a loss of CGS power would not cause grid instability during the time the DG will be inoperable based on forecasted loading. Due to the high level of hydro generation in the FCRTS, periods of grid loading sufficient to cause grid instability to CGS offsite circuits are very infrequent.

Although a date driven risk management restriction is not proposed, verifying the grid is in a stable condition is a proposed risk management restriction. See RAI 19a.

Severe weather is based on the weather condition and not the specific season that it normally occurs. The following definition of severe weather is based on the National Weather Service definition and associated restrictions are contained in CGS procedures.

Severe Weather - Severe weather is defined as any of the following:

• Actual 15-minute average wind speed at 33' tower elevation exceeding 61 mph.

• Hail greater than or equal to 3/4"' in diameter.

• Visual sighting of a funnel cloud or tornado.

• Lightning strikes in the local area (i.e., Benton/Franklin counties).

• Heavy snow or icing condition.

For present or imminent unusual external conditions, such as severe weather, brush fire, or offsite power instability, the Shift Manager qualitatively assesses the risk impact of on-going or planned maintenance activities on plant safety and implements appropriate contingency actions.

In the case of the elective maintenance and planned entry into the extended CT for an inoperable DG, the procedure will be modified to restrict a preplanned entry for elective maintenance when present or forecasted unusual external conditions occur or are forecasted to occur within the extended DG CT period.

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n RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 55 of 56 I

19. Attachment 7 lists risk management commitment actions for the extended CT.

The staff considers the following measures need to be added:

a. The condition of the offsite power supply, switchyard and the grid will be evaluated prior to entering the extended CT for elective maintenance. An extended CT will not be entered to perform elective maintenance when grid stress conditions are high such as during summer temperature and/or high demand.

b. No maintenance or testing that affects the reliability of the trains associated with the operable DGs will be scheduled during the extended CT. If any testing and maintenance activities must be performed while the extended CT is in effect, a 10 CFR 50.65 (a)(4) evaluation will be performed.

c. The system load dispatcher will be contacted once per day and informed of the DG status along with the power needs of the facility.

Response

a) The intent of the fourth Risk management action in Attachment 7 of Reference 1 is to assess the grid stability conditions and not enter the extended completion time to perform elective maintenance if grid stability conditions are not warranted regardless of the season that the grid instability condition occurred. However, to define a restriction based on season or date may not provide the appropriate risk management controls.

The risk management action in our submittal reads:

"The condition of the offsite power supply and transmission yard, including transmission lines and the stability of the FCRTS, will be evaluated through contact with the BPA dispatcher."

We further commit that if the grid stress conditions are high or forecasted to be high resulting in a significant potential for the grid to not be able to remain stable or supply sufficient post trip offsite power minimum voltages, the extended completion time will not be entered to perform elective maintenance.

b) The intent of the seventh risk management action in Attachment 7 of Reference 1 is not to perform elective maintenance on the remaining Operable DG(s) or support systems. The risk management action in our submittal reads:

While in the proposed extended DG CT, the following systems are risk significant during the extended DG CT period and will be protected so that elective maintenance and testing are not performed: Cross train DGs and their respective Service Water Systems, TR-S and TR-B and the associated breakers and relay logic (protective and control), the HPCS system, and the RCIC system.

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 56 of 56 Included in the term "cross train DG(s)" were their necessary support systems. Energy Northwest further confirms that under our program, which implements 10 CFR 50.65(a)(4), any testing and maintenance activities that must be performed while the extended CT is in effect, are required to have a 10 CFR 50.65(a)(4) evaluation performed. Attachment 2 of this response documents modification to the Attachment 7 of Reference 1 to confirm these aspects of the risk management action.

c) This measure is already in place at CGS. Energy Northwest currently contacts the system load dispatcher whenever a DG is out of service as part of our TS Action 3.8.1.b for one required DG inoperable. This action requires that, within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and then once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> thereafter, verification of correct breaker alignment and indicated power availability for each offsite circuit is performed. The surveillance procedure for meeting SR 3.8.1.1 specifies that the way power availability for each offsite circuit is verified is by contacting the BPA grid dispatch center to determine the offsite power availability for both the 230 kV and 115 kV offsite power supplies. This procedure verifies that a State Estimator's post trip voltage prediction of inadequate offsite power voltage levels does not exist. Please note the station's off-site power needs are already defined in a formal letter agreement with BPA. Further, as previously stated, the CGS agreement with BPA includes a provision that if the grid conditions change to a point where the grid operator is not able to meet our offsite power needs, CGS will be notified.

6RESPONtSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME - Revise Attachment 7 of Reference 1 Page 1 of 4 COMMITMENTS FOR THE EXTENDED DG CT

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME - Revise Attachment 7 of Reference 1 Page 2 of 4 Revised Energy Northwest Commitments to incorporate changes and additions contained in the Attachment A responses to the RAI:

Number Location of Commitment Commitments For Extended DG CT 1

Ref 1, Attachment 1, Page This commitment from Reference 1 is deleted. The final design of the AACS is described in RAI response No 9

16. The installation of the equipment required to be installed when plant is shut down was completed in RAI Response 3 refueling outage R-1 7. The remaining portions will be completed prior entering the extended DG CT Action.

2 Ref 1, Attachment 1, Page This commitment from Reference 1 is deleted. The temporary configuration request of the AACSBC is 10 withdrawn.

3 Ref 1, Attachment 1, Page The DG extended CT will not be entered for scheduled maintenance purposes if severe weather conditions are 18 expected.

RAI Response 16 & 18 Pages 46/47 & 53 4

Ref 1, Attachment 1, Page The condition of the offsite power supply and transmission yard, including transmission lines and the stability of 18 the Federal Columbia River Transmission System, will be evaluated through contact with the BPA dispatcher. If the grid stress conditions are high or forecasted to be high resulting in a significant potential for the grid to not be RAI Responses 16,17, able to remain stable condition or supply post trip offsite power minimum voltages, the extended completion 18, 19a, & 19c time will not be entered to perform elective maintenance. The BPA dispatcher will be contacted on at least a daily bases during the extended DG Completion Time to assure that conditions that create the potential for Pages 46, 47, 49, 51 & 52 developing grid instabilities do not exist 5

Ref 1, Attachment 1, Page No elective maintenance will be scheduled within the transformer yard that would challenge the TR-S or TR-B 18 connections or offsite power availability during the proposed extended DG CT.

6 Ref 1, Attachment 1, Page Operating crews will be briefed on the DG work plan, with consideration given to key procedural actions that 18 would be required in the Loss Of Offsite Power (LOOP) or SBO.

7 Ref 1, Attachment 1, Page While in the proposed extended DG CT, the following systems are risk significant during the extended DG CT 18 period and will be protected so that elective maintenance and testing are not performed:

RAI Responses 16, 19b Cross train DGs, their support systems, and their respective Service Water Systems TR-S and TR-B and the associated breakers and relay logic (protective and control)

Pages 46147& 51 HPCS system RCIC system e--Rae 1

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RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME - Revise Attachment 7 of Reference 1 Page 3 of 4 Number Location of Commitment Commitments For Extended DG CT 8

RAI Response 19b Any testing and maintenance activities that must be performed while the extended DG CT is in effect, are Page 51 required to have a 10 CFR 50.65(a)(4) evaluation performed 9

Ref 1, Attachment 1, Page While in the proposed extended DG CT, additional elective equipment maintenance or testing that requires any 18 other risk significant equipment to be removed from service will be evaluated and activities that yield unacceptable results will be avoided.

RAI Responses 16 & 19b Pages 46/47 & 54 10 Ref 1, Attachment 1, Page Emergent conditions that result in the protected systems being challenged will be managed to minimize the risk 18 impact.

11 RAI Responses 1 & 2 Incorporate modeling and PRA Documentation changes identified in Level C F&Os (Nos. 1-4 and 6-14) and the Pages 2-10 modeling improvements to the fault trees of HPCS and RCIC into the next PRA upgrade.

12 RAI Response 7 The battery capacity will be verified prior to entry into the extended Completion Time by the following:

Page 16 The results of the last battery capacity surveillance was greater than or equal to 100%,

The battery surveillances are current Short time excursions in battery parameters outside surveillance limits will not invalidate the risk managbment compensatory measure commitment as specific TS Actions exist to restore the conditions within a reasohable time.

A restraint in the battery load calculation, maintains the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> capability for the PRA basis.

13 RAI Responses 4 & 16 For planned maintenance, DG-4 and DG-3 cross connect will be verified to be available and any associated Page 12 & 41 surveillance procedures are current prior to taking the DG out of service. For emergent conditions (repair), DG-4 and DG-3 will be verified to be available as soon as practicable, but prior to exceeding 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.

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RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME - Revise Attachment 7 of Reference 1 Page 4 of 4 Number Location of Commitment Commitments For Extended DG CT 14 RAI Responses 3, 7, 10, Incorporate the administrative controls on the use of DG-3 and DG-4 into the SBO procedure, including the 12, 16 required load shedding of Division I and 2 125 volt batteries, the specific configuration of floor fans and door alignments used in the thermal calculation, and configuration of the buses to facilitate the energizing of their use.

Pages 12, 16, 17, 30-34, Also provide a section for isolating the Division 1 or 2 bus and re-energizing the HPCS system. Procedures will 41 be completed and training provided prior to entry into the extended DG CT.

15 RAI Responses 3 & 4 Perform the periodic Surveillance and maintenance procedures for verifying DG-4 is able to perform its risk Pages 12 & 13 management function. Procedures will be issued and training provided prior to entry into the extended DG CT.

16 RAI Response 17 Revise planning procedures to obtain the projected grid conditions when planning an online elective DG maintenance. Assure that periods of stable grid conditions are chosen and that planning of maintenance Page 50 activities by BPA on the grid are coordinated with DG outage planning to avoid conflict.

17 RAI Response 13 Page Establish performance criteria for DG-4 in accordance with the Maintenance Rule requirements. The 37 development of these performance criteria will be based on assumptions used in the PRA and updated in accordance with the PRA update program.

18 RAI Response 16 Verify through training and simulation the ability to accomplish the energizing of the cross connection from DG-3 Page 42 to the Division 1 or Division 2 ESF switchgear bus (SM-7 or SM-8 respectively) within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> in accordance with the SBO Procedure.

REiSPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME - Revise Attachment 7 of Reference 1 Page 1 of 4 COMMITMENTS FOR THE EXTENDED DG CT

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME - Revise Attachment 7 of Reference 1 Page 2 of 4 Revised Energy Northwest Commitments to incorporate changes and additions contained in the Attachment A responses to the RAI.

Number Location of Commitment Commitments For Extended DG CT I

Ref 1, Attachment 1, Page This commitment from Reference 1 is deleted. The final design of the AACS is described in RAI response No 9

16. The installation of the equipment required to be installed when plant is shut down was completed in RAI Response 3 refueling outage R-1 7. The remaining portions will be completed prior entering the extended DG CT Action.

2 Ref 1, Attachment 1, Page This commitment from Reference 1 is deleted. The temporary configuration request of the AACSBC is 10 withdrawn.

3 Ref 1, Attachment 1, Page The DG extended CT will not be entered for scheduled maintenance purposes if severe weather conditions are 18 expected.

RAI Response 16 & 18 Pages 46/47 & 53 4

Ref 1, Attachment 1, Page The condition of the offsite power supply and transmission yard, including transmission lines and the stability of 18 the Federal Columbia River Transmission System, will be evaluated through contact with the BPA dispatcher. If&

the grid stress conditions are high or forecasted to be high resulting in a significant potential for the grid to not be RAI Responses 16, 17, able to remain stable condition or supply post trip offsite power minimum voltages, the extended completion 18, 1 9a, & 1 9c time will not be entered to perform elective maintenance. The BPA dispatcher will be contacted on at least a daily bases during the extended DG Completion Time to assure that conditions that create the potential for Pages 46, 47, 49, 51 & 52 developing grid instabilities do not exist 5

Ref 1, Attachment 1, Page No elective maintenance will be scheduled within the transformer yard that would challenge the TR-S or TR-B c'.z 18 connections or offsite power availability during the proposed extended DG CT.

6 Ref 1, Attachment 1, Page Operating crews will be briefed on the DG work plan, with consideration given to key procedural actions that 18 would be required in the Loss Of Offsite Power (LOOP) or SBO.

7 Ref 1, Attachment 1, Page While in the proposed extended DG CT, the following systems are risk significant during the extended DG CT 18 period and will be protected so that elective maintenance and testing are not performed:

RAI Responses 16, 19b Cross train DGs, their support systems, and their respective Service Water Systems TR-S and TR-B and the associated breakers and relay logic (protective and control)

Pages 46/47& 51 HPCS system RCIC system

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME - Revise Attachment 7 of Reference 1 Page 3 of 4 Number Location of Commitment Commitments For Extended DG CT 8

RAI Response 1 9b Any testing and maintenance activities that must be performed while the extended DG CT is in effect, are Page 51 required to have a 10 CFR 50.65(a)(4) evaluation performed 9

Ref 1, Attachment 1, Page While in the proposed extended DG CT, additional elective equipment maintenance or testing that requires any 18 other risk significant equipment to be removed from service will be evaluated and activities that yield unacceptable results will be avoided.

RAI Responses 16 & 19b Pages 46/47 & 54 10 Ref 1, Attachment 1, Page Emergent conditions that result in the protected systems being challenged will be managed to minimize the risk 18 impact.

11 RAI Responses 1 & 2 Incorporate modeling and PRA Documentation changes identified in Level C F&Os (Nos. 1-4 and 6-14) and the Pages 2-10 modeling improvements to the fault trees of HPCS and RCIC into the next PRA upgrade.

12 RAI Response 7 The battery capacity will be verified prior to entry into the extended Completion Time by the following:

Page 16 The results of the last battery capacity surveillance was greater than or equal to 100%,

The battery surveillances are current Short time excursions in battery parameters outside surveillance limits will not invalidate the risk management -

compensatory measure commitment as specific TS Actions exist to restore the conditions within a reasonable time.

A restraint in the battery load calculation, maintains the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> capability for the PRA basis.

13 RAI Responses 4 & 16 For planned maintenance, DG-4 and DG-3 cross connect will be verified to be available and any associated Page 12 & 41 surveillance procedures are current prior to taking the DG out of service. For emergent conditions (repair), DG-4 and DG-3 will be verified to be available as soon as practicable, but prior to exceeding 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.

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RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME - Revise Attachment 7 of Reference I Page 4 of 4 Number Location of Commitment Commitments For Extended DG CT 14 RAI Responses 3, 7, 10, Incorporate the administrative controls on the use of DG-3 and DG-4 into the SBO procedure, including the 12, 16 required load shedding of Division I and 2 125 volt batteries, the specific configuration of floor fans and door alignments used in the thermal calculation, and configuration of the buses to facilitate the energizing of their use.

Pages 12, 16, 17, 30-34, Also provide a section for isolating the Division I or 2 bus and re-energizing the HPCS system. Procedures will 41 be completed and training provided prior to entry into the extended DG CT.

15 RAI Responses 3 & 4 Perform the periodic Surveillance and maintenance procedures for verifying DG-4 is able to perform its risk Pages 12 & 13 management function. Procedures will be issued and training provided prior to entry into the extendedODG CT.

16 RAI Response 17 Revise planning procedures to obtain the projected grid conditions when planning an online elective DG maintenance. Assure that periods of stable grid conditions are chosen and that planning of maintenance Page 50 activities by BPA on the grid are coordinated with DG outage planning to avoid conflict.

17 RAI Response 13 Page Establish performance criteria for DG-4 in accordance with the Maintenance Rule requirements. The 37 development of these performance criteria will be based on assumptions used in the PRA and updated in accordance with the PRA update program.

18 RAI Response 16 Verify through training and simulation the ability to accomplish the energizing of the cross connection from DG-3 Page 42 to the Division I or Division 2 ESF switchgear bus (SM-7 or SM-8 respectively) within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> in accordance with the SBO Procedure.

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RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 1 of 2 Insert I ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. (continued)

OR B.4.2.1 Establish risk 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> management actions for the alternate AC sources.

AND B.4.2.2 Restore required 14 days DG to OPERABLE status.

AND 17 days from discovery of failure to meet LCO

R.ESPON2'E TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 2 of 2 Insert 2 LCO 3.8.1 Action BA Bases A second optional set of Actions is provided, that if the risk management actions for establishing the alternate AC sources to division 1 or division 2 (AACS) occurs within the 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time limit, an extended Completion Time up to 14 days from the DG's initial inoperability is allowed. To establish the AACS, DG-4, a 480-volt diesel generator is staged and available and the DG-3 cross-connection to power selected safe shutdown loads is available. The AACS is considered available when DG-4 can be aligned and supplying the battery chargers within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> and the DG-3 cross-connection can be implemented in accordance with the emergency procedures for a loss of offsite power or a station blackout event within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. Additional risk management actions in accordance with the configuration risk management program required by 10 CFR 50.65a(4) are to be put in place to assure that significant risk configurations are avoided during the extended DG inoperability.

Similar to Action A.3 Completion Time, when the 14-day extended Completion Time is applicable, the 17 day Completion Time provides a limit on the time allowed in a specified condition after discovery of failure to meet the LCO.

RESPO'QN!E TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 1 of 4 NO SIGNIFICANT HAZARDS CONSIDERATION

RESPON!ISE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 2 of 4+.,.

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NO SIGNIFICANT HAZARDS CONSIDERATION In accordance with 10 CFR 50.92, a proposed change to the operating license involves a no significant hazards consideration if operation of the facility in accordance with the proposed change would not: 1) involve a significant increase in the probability or consequences of any accident previously evaluated; 2) create the possibility of a new or different kind of accident from any accident previously evaluated; or 3) involve a significant reduction in a margin of safety. The proposed changes have been evaluated against each of the three criteria set forth in 10 CFR 50.92 in support of this determination, and are provided below.

The proposed Technical Specification (TS) changes the Limiting Conditions for Operation (LCO) 3.8.1 Required Actions A.3, B.3.2, and B.4 and their respective Completion Times. The proposed changes, include a Required Action to establish risk management actions for the alternate AC sources (AACSs). These AACSs provide significant risk mitigation for a Station Blackout event. The crediting of performing Surveillance Requirement (SR) 3.8.1.2 to allow meeting the SR if performed within the previous 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> enhances the risk management of the required testing.

Does the operation of Columbia Generating Station in accordance with the proposed amendment involve a significant increase in the probability or consequences of an accident previously evaluated?

Response: No.

The proposed changes do not adversely affect the design of the DGs, the operational characteristics or function of the DGs, the interfaces between the DGs and other plant systems, or the reliability of the DGs. Required Actions, including the risk management action to establish the AACSs, and the associated Completion Times are not initiating conditions for any accident previously evaluated, and the DGs are not initiators of any previously evaluated accidents.

The DGs support the mitigation of the consequences of previously evaluated accidents that involve a loss of offsite power. The consequences of a previously analyzed accident will not be significantly affected by the extended DG Completion Time since the remaining DGs will continue to be capable of performing their accident mitigation function as assumed in the accident analysis.

Thus, the consequences of accidents previously analyzed are unchanged between the existing TS requirements and the proposed changes. The consequences of an accident are independent of the time the DGs are out of service as long as there are adequate DGs available.

Based on the above, the proposed change to extend the DG allowed Completion Time during plant operation will not involve a significant increase in accident probabilities or consequences.

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R.ESPOQNSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 3 of4

.4.

Does the operation of Columbia Generating Station in accordance with the proposed amendment create the possibility of a new or different kind of accident from any accident previously evaluated?

Response: No.

No new accidents would be created since no changes are being made to the plant that would introduce any new accident causal mechanisms. This amendment request does not impact any plant systems that are accident initiators; neither does it adversely impact any accident mitigating systems. The addition of the AACSs will provide added time for responding to a loss of all AC power assumed in accident analyses. The design of the AACSs will contain features and administrative controls to maintain the separation and protection of emergency AC power sources and their distribution systems and does not create the possibility of a new or different kind of accident from any previously evaluated.

Based on the above, implementation of the proposed changes will not create the possibility of a new or different kind of accident from any accident previously evaluated.

Does the operation of Columbia Generating Station in accordance with the proposed amendment involve a significant reduction in the margin of safety?

Response: No.

Margin of safety is related to the confidence in the ability of the fission product barriers to perform their design functions during and following an accident.

These barriers include the fuel cladding, the reactor coolant system, and the containment system. Throughout the period of the current TS Completion Time, when one DG is out-of-service during power operation, the margin of safety is managed by limiting the allowed outage time and other concurrent power source outages within the TS. This time period is a temporary relaxation of the single failure criteria, which, consistent with overall system reliability considerations, provides a limited time to repair the equipment and conduct testing. The extension of the current TS Completion Time to 14 days has been determined not to be a significant reduction in the margin of safety. The proposed changes will not result in a significant decrease in DG availability so that the assumptions regarding DG availability are not impacted. Probabilistic Risk Assessment (PRA) methods and a deterministic analysis were utilized to fully evaluate the effect of the proposed DG Completion Time extension. The results of the analysis show no significant increase in Core Damage Frequency (CDF) and Large Early Release Frequency (LERF).

REnPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT REQUEST FOR EXTENSION OF DIESEL GENERATOR COMPLETION TIME Page 4 of 4 The proposed risk management action to provide the AACSs enhances the ability to cope with a Station Blackout (SBO) event by providing alternate power

-sources to power selected safe shutdown equipment. These additional sources enhance safety margin in the event that AC recovery is delayed beyond the current analysis. The proposed Completion Time change and risk management actions do not adversely affect the assumptions or inputs to the safety analyses of the FSAR including the plant's ability to cope with a SBO as defined in 10 CFR 50.63, "Loss of All Alternating Current Power."

Energy Northwest has also proposed a number of risk rmanagement actions to reduce the possibility of a plant transient, a loss of high-pressure or low pressure injection and cooling systems, a loss of other on-site power sources, or a loss of offsite power during the period the DG is out-of-service.

Based on the above, implementation of the TS Change does not result in a significant reduction in the margin of safety. This is based on the management of plant risk, the reliability of the other diesel generators, and the inclusion of risk management actions.

Therefore, the proposed changes will not significantly increase the probability or.

consequences of any accident previously evaluated, create the possibility of a new or different kind of accident from any accident previously evaluated, or involve a significant reduction in the margin of safety. Therefore, the proposed assessment meets the requirements of 10 CFR 50.92, in that it involves no significant hazards consideration.