NLS2009048, Response to Request for Additional Information for License Renewal Application Severe Accident Mitigation Alternatives

Response to Request for Additional Information for License Renewal Application Severe Accident Mitigation Alternatives

ML091880319
Person / Time
Site:	Cooper
Issue date:	07/01/2009
From:	Minahan S Nebraska Public Power District (NPPD)
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
NLS2009048
Download: ML091880319 (49)

Text

N Nebraska Public Power District "Always there when you need us" 54.17 NLS2009048 July 1, 2009 U.S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, D.C. 20555-0001

Subject:

Response to Request for Additional Information for License Renewal Application

- Severe Accident Mitigation Alternatives Cooper Nuclear Station, Docket No. 50-298, DPR-46

References:

1. Letter from Tam Tran, U.S. Nuclear Regulatory Commission, to Stewart B. Minahan, Nebraska Public Power District, dated June 8, 2009, "Request for Additional Information for the Review of the Cooper Nuclear Station License Renewal Application.(TAC No. MD9763 and MD9737)."

2. Letter from Stewart B. Minahan, Nebraska Public Power District, to U.S.

Nuclear Regulatory Commission, dated September 24, 2008, "License Renewal Application."

Dear Sir or Madam:

The purpose of this letter is for the Nebraska Public Power District to respond to Section A of the Nuclear Regulatory Commission Request for Additional Information (RAI) (Reference 1) related to the Cooper Nuclear Station License Renewal Application (LRA) Environmental Report severe accident mitigation alternatives. These responses are provided in Attachment 1. Certain changes to the LRA (Reference 2) have been made to reflect these RAI responses. These changes are provided in Attachment 2.

Should you have any questions regarding this submittal, please contact David Bremer, License Renewal Project Manager, at (402) 825-5673.

COOPER NUCLEAR STATION P.O. Box 98 / Brownville, NE 68321-0098 Telephone: (402) 825-3811 / Fax: (402) 825-5211 ar)ý2 www nppd com

NLS2009048 Page 2 of 2 I declare under penalty of perjury that the foregoing is true and correct.

Executed on-- V1-o (Date)

Sincerely, Stewart B. Minahan Vice President - Nuclear and Chief Nuclear Officer

/wv Attachments cc: Regional Administrator w/ attachments USNRC - Region IV Cooper Project Manager w/ attachments USNRC - NRR Project Directorate IV- 1 Senior Resident Inspector w/ attachments USNRC - CNS Nebraska Health and Human Services w/ attachments Department of Regulation and Licensure NPG Distribution w/o attachments CNS Records w/ attachments

ATTACHMENT 3 LIST OF REGULATORY COMMITMENTS© 4 4

ATTACHMENT 3 LIST OF REGULATORY COMMITMENTS© Correspondence Number: NLS2009048 The following table identifies those actions committed to by Nebraska Public Power District (NPPD) in this document. Any other actions discussed in the submittal represent intended or planned actions by NPPD. They are described for information only and are not regulatory commitments. Please notify the Licensing Manager at Cooper Nuclear Station of any questions regarding this document or any associated regulatory commitments.

COMMITMENT COMMITTED DATE COMMITMENT NUMBER OR OUTAGE None

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I PROCEDURE 0.42 REVISION 23 PAGE 19 OF 26 ý

NLS2009048 Page 1 of 44 Attachment 1 Response to Request for Additional Information for License Renewal Application - Environmental Report Severe Accident Mitigation Alternatives Analysis Cooper Nuclear Station, Docket No. 50-298, DPR-46 The Nuclear Regulatory Commission (NRC) Request for Additional Information (RAI) regarding the License Renewal Application Environmental Report severe accident mitigation alternatives (SAMA) analysis are shown in italics. The Nebraska Public Power District's (NPPD) response to each RAI is shown in block font.

NRC Request: ENV-SAMA-1

1. Provide the following information regardingthe probabilisticsafety analysis (PSA) used for the severe accident mitigation alternatives (SAMA) analysis:

a. There are three core damagefrequency (CDF)-relatedestimates reported in Attachment E to the environmental report (ER); i.e., 9.2 7E-06per year in Table E. 1-1 (CDFby Major Initiators),9.23E-06peryear in Table E. 1-8 (CDFby PlantDamage State), and 1.16E-05 per year in Table E. 1-9 (ReleaseFrequency by Release Category). Explain the reasonsfor the differences in these values, and the rationalefor selecting the total releasefrequency as the baselinefrequency for evaluating SAMA benefits.

b. Section E. 1.4.6 describes the May 2008 Boiler Water Reactor Owners Group (B WROG) peer review of the 2007TM model, Revision 1. Cooper Nuclear Station's (CNS's) review of the preliminarypeer reviewfindings determined that resolution of the findings would not result in a significant impact on the probabilisticrisk analysis (PRA) results, and that the areas considered "not met" or capability category I have a negligible effect on the baseline CDF. For each peer review finding,provide a summary of the finding and an assessment of the impact of resolution of the finding on the SAMA identification and analysis results. The response should also address each of the supportingrequirements having a capability category considered "not met" or capability category I, and discuss its potential impact on the SAMA identificationand analysis results.

NPPD Response:

L.a. The difference between the CDF in Table E. I-1 (CDF by Major Initiators) and the CDF in Table E. 1-8 (CDF by Plant Damage State) is due to the method of quantification. The former utilized a "one top" quantification whereas the latter utilized a sequence

NLS2009048 Page 2 of 44 quantification. These quantification methods yield slightly different results due to variations similar to rounding differences in algebraic calculations.

The value of 1.1 6E-05/rx-yr in Table E. 1-9 (Release Frequency by Release Category) is higher than the Level 1 CDF due to the manner in which the Level 2 containment event tree (CET) model was constructed and quantified. The Level 2 CET model used to evaluate the SAMAs was a single top model linked with the Level 1 fault tree. The CET model included numerous split fractions with failure paths that did not meet the rare event approximation (i.e., greater than 5E-2). The associated success paths were modeled with complementary events that approximated the expected success path probabilities (i.e., 1.0 failure probability). Thus, the sum of the split fraction events was slightly larger than 1.0. The cumulative effect of these success path approximations on the end state frequencies caused the difference between the Level 1 CDF frequency and the total Level 2 end state frequency.

The total release frequency is appropriate for use as the baseline frequency for evaluating SAMAs because the SAMA evaluation requires Level 2 analysis. To evaluate the benefit of each SAMA, the Level 1 or Level 2 portion of the model was modified as appropriate and the change in the total release frequency was used to provide a bounding estimate of the change in risk that could be achieved by implementation of the SAMA. The model that was used to analyze the SAMAs is the same model that provided the baseline total release frequency value of 1.16E-05/rx-yr. Since the SAMA analysis is based on the difference between the baseline model frequency and the "SAMA model" frequency, it is appropriate to use the same fault tree and CET model to calculate both frequencies.

The success path approximations in the Level 2 CET model have negligible impact on the results of the SAMA analysis because the effects tend to be cancelled out by the delta-CDF calculation and are further mitigated by bounding analyses and by use of the factor of 3 to account for uncertainties in the analysis.

1.b. The May 2008 BWROG peer review identified 22 findings, each against a different supporting requirement (SR). The SRs with findings were classified as follows:

a) Ten (10) SRs classified as not met, b) Two (2) SRs classified as met (cat. I), and c) Ten (10) SRs classified either as met (cat. II), met (cat. I/II), met (cat III), met (cat. I/I1), or met (cat. I/II/II).

The following tables contain summaries of these SRs and the associated peer review finding. It also includes an assessment of the impact of resolving each finding on the SAMA identification and analysis results. Table 1 contains the findings for SRs classified as not met, Table 2 contains the findings for SRs classified as met (cat. I), and Table 3 contains the remaining findings.

NLS2009048 Page 12 of 44 NRC Request: ENV-SAMA-2

2. Provide the following information relative to the Level 2 analysis:

a. Table E.1-]O identifies the releasefractionsfor each release mode. The release fractionsfor iodine and cesium for the LL/I release mode are significantly lower than the correspondingreleasefractionsfor both the LL/E and LL/L release modes. Provide an explanationfor this apparentanomaly.

b. In the discussion of the Level 2 analysis (Section E. 1.2), the process used to develop and group the source terms into containment event tree (CET) end states is not clear.

i. Clarify whether a single CET was usedfor the grouping of source terms, or whether a single CET was usedfor each accident class orfor each plant damage state (PDS). Provide a typical CET showing release categoriesassigned to each end state.

ii. For each CETsequence, massfractions obtainedfrom the representative MAAP calculations were "weighed accordingto the contribution of that sequence to the sum of the sequences in the end state bin" (pageE. 1-68).

Identify and describe the number of MAAP calculations or runs made to obtain the massfractions.Provide an example of the weighting calculationfor a representative CET sequence.

c. Table E.1-5 shows three events (CNT-SMP-FF-MLTOF,RPV-DWV-FO-BARIS, and CNT-MDL-FF-WTRCV) having a risk reduction worth (RRW) value of 2.181.

Provide details on which portions of the large early releasefrequency (LERF) model are affected in the computation of the RR W.

NPPD Response:

2.a. As described in ER Section E.1.2.2.6, for each CET sequence, a value for each of the release-to-environment mass fractions was obtained from the representative MAAP calculation. These mass fractions were then weighted according to the contribution of that sequence to the sum of the sequences in the end state bin. The final mass fraction representing the end state bin was the sum of these individual weighted mass fractions for each species. An example of this calculation is provided in the response to Question 2b.

For the LL/I end state, the dominant sequences involve offsite release via containment venting through an intact suppression pool. This path results in very effective fission product scrubbing resulting in very low offsite releases. The MAAP run representing the

NLS2009048 Page 13 of 44 dominant sequences for the LL/I end state has a cesium iodide (CsI) release fraction of 1.79E-6.

For the LL/E and LL/L end states, the dominant sequences involve release paths from the primary containment that bypass the suppression pool with less effective fission product scrubbing. These sequences resulted in low-low offsite releases, but not as low as the LL/I sequences. The MAAP run representing the dominant sequences for the LL/L end state has a CsI release fraction of 8.48E-4. Also, the MAAP run representing the dominant sequences for the LL/E end state has a CsI release fraction of 1.7E-4.

Since the dominant sequences in the LL/I end state involve more effective fission product scrubbing through the suppression pool, the release fractions for iodine and cesium for the LL/I release mode are lower than the corresponding release fractions for both the LL/E and LL/L release modes. Although the difference appears significant, the impact is minimal because the LL end state grouping consists of those sequences expected to have a CsI offsite release magnitude of less than 0.1%.

2.b.i A single CET was developed for each PDS. A typical CET showing the release category assigned to each Level 2 end state in the CET is provided below.

NLS2009048 Page 14 of 44

NLS2009048 Page 15 of 44 2.b.ii The following table identifies the 46 representative MAAP calculations used to obtain the mass fractions.

Case Description Comments CN060500 Loss of Makeup at High None Pressure -'No Injection - No Drywell (DW) sprays CN060500A Loss of Makeup at High A large 24 inch diameter path to the environment Pressure - Failure to Isolate is opened at event initiation to simulate worst case Large Containment failure of containment isolation. Containment Penetration - No Injection - failure time is reported when DW liner melt may No DW sprays be expected following Reactor Pressure Vessel (RPV) breach.

CN060501 Loss of Makeup at High This run demonstrates the impact of RPV pressure Pressure - Open 1 Safety at time of vessel breach. The pressure in the RPV Relief Valve (SRV) at is reduced to approximately 65 psia at vessel incipient core damage - No breach, by opening one SRV at incipient core Injection - No DW sprays damage. DW pressure just prior to vessel breach is approximately 33 psia.

CN060502 Loss of Makeup at High DW sprays assumed to fail at containment failure Pressure - DW sprays - No for this run.

Injection CN060503 Loss of Makeup at High DW sprays assumed to fail at containment failure Pressure - DW sprays for this run.

operate - No Injection CN060504 Loss of Makeup at High DW sprays assumed to continue operating after Pressure - DW sprays containment failure for this run (required operate - No Injection adjustment of Low Pressure Coolant Injection (LPCI) Net Positive Suction Head (NPSH) curve).

CsI release is reduced to negligible fraction, however the case with DW spray failure at the time of containment failure is relatively small also

(<1%).

CN060505 Loss of Makeup - RPV at Without DW spray and no injection a large DW Low Pressure - Emergency liner melt results in worst case radionuclide release Depressurization (ED) at for RPV at low pressure.

Minimum Steam Cooling Reactor Pressure Vessel Water Level (MSCRWL) -

No DW sprays - No Injection

NLS2009048 Page 16 of 44 Case Description Comments CN060505A Loss of Makeup -RPV at Low A large 24 inch diameter path to the environment Pressure - Failure to Isolate is opened at event initiation to simulate worst case Large Containment failure of containment isolation. Containment Penetration - ED at failure time is reported when DW liner melt may MSCRWL - No DW sprays - be expected following RPV breach.

No Injection CN060506 Loss of Makeup - RPV at DW sprays assumed to fail at containment failure Low Pressure - ED at for this run., Liner melt through occurs for this run MSCRWL - DW sprays after DW sprays fail on containment failure and operate - No Injection water level in DW boils off to less than one foot.

CN060507 Loss of Makeup -RPV at Low Same as CN060506, except containment failure is Pressure - ED at MSCRWL - assumed to be small for this run. DW sprays DW sprays operate - No assumed to fail at containment failure for this run.

Injection Liner melt through occurs for this run after DW sprays fail on containment failure and water level in DW boils off to less than 1 foot. Liner melt is delayed slightly compared to CN060506 due to smaller containment breach.

CN060507A Loss of Makeup -RPV at Low Same as CN060506, except containment failure is Pressure - ED at MSCRWL - assumed to be small for this run and DW sprays DW sprays operate - No assumed to continue operating after containment Injection failure (required adjustment of LPCI NPSH curve). This run was specified to investigate the impacts of small vs. large containment failure, without a large DW liner melt.

CN060508 Loss of Makeup -RPV at Low DW sprays assumed to continue operating after Pressure - ED at MSCRWL - containment failure for this run (required DW sprays operate - No adjustment of LPCI NPSH curve).

Injection CN060509 Loss of Makeup -RPV at Low Turning on one loop of SPC at four hours avoids Pressure - ED at MSCRWL - exceeding Primary Containment Pressure Limit DW sprays operate - (PCPL) and containment failure curve.

Suppression Pool Cooling (SPC) at four hours - No Injection

__

NLS2009048 Page 17 of 44 Case Description Comments CN0605 10 Loss of containment heat CS pump fails as containment pressure rises above removal - ED at MSCRWL - pressure to maintain SRVs open and shutoff head Core Spray (CS) and Control conditions met. Core damage occurs after Rod Drive (CRD) (scram containment failure at the Wet Well (WW). DW flow) available initially liner melt through occurs after RPV breach.

CN0605 1OT Loss of containment heat CS pump fails as containment pressure rises above removal - ED at MSCRWL - pressure to maintain SRVs open and shutoff head CS available initially conditions met. Core damage occurs before containment failure at the WW. Core damage occurs before containment failure in this run because no high pressure injection exists (e.g.

CRD) at the time the SRVs go closed. DW liner melt through occurs after RPV breach.

CN060511 Loss of containment heat CS pump fails as containment pressure rises above removal - ED at MSCRWL - pressure to maintain SRVs open and shutoff head CS and CRD (scram flow) conditions met. Core damage occurs after available initially containment failure at the DW. DW liner melt through occurs after RPV breach. This run is the same as CN0605 10 except containment failure occurs at the DW head, which shortens the time 10% CsI release. CRD makes up for decay heat losses following CS pump shutoff, until containment failure.

CN06051 IT Loss of containment heat Same as case CN060510T except large removal - ED at MSCRWL - containment failure occurs at the DW head instead CS available initially of WW. Note that for this case 10% CsI is released to the environment prior to liner melt due to containment failure location being at the DW

_head prior to RPV breach.

CN060512 Loss of containment heat CS prevents core damage until containment failure removal - Large LOCA on failure curve.

(LLOCA)- CS available CN060513 Loss of containment heat Same as case CN060512 except containment removal - LLOCA - CS failure location is DW instead of WW. This run available shows the significant contribution of suppression pool scrubbing on Csi release. CS prevents core damage until containment failure on failure curve.

NLS2009048 Page 18 of 44 Case Description Comments CN060514 LLOCA with two vacuum Containment failure at DW assumed to occur one breakers failed open - No minute following LOCA due to vapor suppression Injection - No Sprays bypass.

CN060515 LLOCA with two vacuum Containment failure at DW assumed to occur one breakers failed open - No minute following LOCA due to vapor suppression Injection - DW Sprays bypass. DW sprays operate within five minutes of operate Emergency Operating Procedure (EOP) trigger and eventually fail at approximately 4.6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> due to assumed NPSH issues. This run is similar to CN060514 except DW sprays are used and it demonstrates their ability to keep CsI release relatively low.

CN060516 LLOCA with two vacuum Containment failure at WW assumed to occur one breakers failed open- No minute following LOCA due to vapor suppression Injection - No Sprays bypass. This run shows the extended time and reduction in CsI release for a WW airspace failure compared to run CN060514 (DW failure).

CN060517 LLOCA - No Injection - No Although DW liner melt may occur during this Sprays - DW venting at PCPL run, it was not allowed, in order to capture the impact of venting. Venting via a one inch path commenced at PCPL (12.15 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br />) and slowly reduces containment pressure, until a pressure spike requires opening two inch path at 21.23 hours2.662037e-4 days <br />0.00639 hours <br />3.80291e-5 weeks <br />8.7515e-6 months <br />. Vents were never closed once opened.

CN060517A LLOCA - No Injection - No Although DW liner melt may occur during this Sprays - WW venting at run, it was not allowed, in order to capture the PCPL impact of venting. Venting via a 20-inch WW path commenced at PCPL (12.15 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br />) and quickly reduces containment pressure. This is considered a bounding Hard Pipe Vent (HPV) continuous release from the WW to environment.

NLS2009048 Page 19 of 44 Case Description Comments CN060518 Anticipated Transient SPC fails following containment failure at 260'F Without Scram (ATWS) with pool temperature. LPCI NPSH required adjusted Standby Liquid Control to 60% of manufacturer.

(SLC) Failure, RPV depressurized, DW head failure location, High Pressure Coolant Injection (HPCI) and LPCI utilized with level control CN060519 ATWS with SLC Failure, Due to run not allowing depressurization, HPCI RPV not depressurized, DW assumed failure on high suppression pool head failure location, HPCI temperature results in loss of injection and early and LPCI utilized with level core damage. LPCI NPSH required adjusted to

_control 60% of manufacturer.

CN060520 ATWS with SLC Failure, SPC fails following containment failure at 260'F RPV depressurized, WW pool temperature. LPCI NPSH required adjusted failure location, HPCI and to 60% of manufacturer.

LPCI utilized with level control CN060521 ATWS with SLC Failure, Due to run not allowing depressurization, HPCI RPV not depressurized, WW assumed failure on high suppression pool failure location below water temperature results in loss of injection and early line, HPCI and LPCI utilized core damage. LPCI NPSH required adjusted to with level control 60% of manufacturer.

CN060522 ATWS with SLC Failure, SPC fails following containment failure at 260'F RPV depressurized, WW pool temperature. LPCI NPSH required adjusted failure location below water to 60% of manufacturer. Decontamination Factor line, HPCI and LPCI utilized for Reactor Building (DFRB) is higher for this run with level control due to suppression pool draining into torus room, resulting in code seeing increased CsI in the Reactor Building (RB) not making it to the environment.

CN060523 ATWS with SLC Failure, Due to run not allowing depressurization, HPCI RPV not depressurized, DW assumed failure on high suppression pool head failure location, HPCI temperature results in loss of injection and early and LPCI utilized with level core damage. LPCI NPSH required adjusted to control 60% of manufacturer.

CN060524 Break Outside Containment - None No Injection

NLS2009048 Page 20 of 44 Case Description Comments CN060525 Station Blackout (SBO) - ED No real Direct Current (DC) power limitations at MSCRWL - No DW sprays impact for this run, due to assumption of no

- No Injection injection. RPV failure occurs before DC power is challenged, resulting in failure at low RPV pressure.

CN060525A SBO - ED at MSCRWL - No RCIC trips on high exhaust back-pressure after DW sprays Reactor Core approximately six hours. ED on MSCRWL occurs Isolation Cooling (RCIC) within an hour of RCIC loss. Assumed battery Injection depletion at 11 hours1.273148e-4 days <br />0.00306 hours <br />1.818783e-5 weeks <br />4.1855e-6 months <br /> results in RPV repressurization and RPV fails at high pressure.

CN060525B SBO - ED at MSCRWL - No HPCI is assumed failed at five hours for this run DW sprays - HPCI Injection due to assumed battery depletion. RPV is depressurized by manually opening SRVs at MSCRWL. All batteries are assumed depleted at 11 hours1.273148e-4 days <br />0.00306 hours <br />1.818783e-5 weeks <br />4.1855e-6 months <br />, resulting in RPV pressure rising prior to vessel failure at high pressure due to potential battery impact on SRVs.

CN060525C SBO - ED at MSCRWL - No RCIC trips on high exhaust back-pressure after DW sprays - RCIC Injection approximately one hour. ED on MSCRWL occurs within an hour of RCIC loss. RPV breach occurs prior to 11-hour assumed battery depletion time, therefore, RPV pressure is low at breach.

CN060525D SBO - ED at MSCRWL - No HPCI is assumed failed at five hours for this run DW sprays - HPCI Injection due to assumed battery depletion. RPV is depressurized by manually opening SRVs at MSCRWL. All batteries are assumed depleted at 11 hours1.273148e-4 days <br />0.00306 hours <br />1.818783e-5 weeks <br />4.1855e-6 months <br />, resulting in RPV pressure rising prior to vessel failure. Vessel failure occurs with RPV pressure approximately 500 psia due to potential battery impact on SRVs.

CN060526 Loss of Makeup at High Press No containment melt or failure when sprays and

- DW sprays - SPC - No SPC are successful.

Injection CN060527 Loss of Makeup at Low Press No containment melt or failure when sprays and

- ED at MSCRWL - DW SPC are successful.

_sprays - SPC - No Injection

NLS2009048 Page 21 of 44 Case Description Comments CN060528 LLOCA with two vacuum No containment melt or failure when sprays and breakers failed open - DW SPC are successful. This run assumed two sprays - SPC - No Injection vacuum breakers were failed open, but did not fail containment automatically as was assumed in CN060516.

CN060529 Loss of Makeup at High Press Containment venting via WW until full, then

- No Injection - No DW switched to DW. Vent path size and duration used sprays - Flood containment to control containment pressure within PCPL and with service water (SW) cross 5 psi below PCPL. If largest vents were needed tie following RPV breach - the code opens and remains open. DW liner melt Venting Throttled was not allowed for SW cross tie runs.

Depressurization via the RPV breach allows injection rates in excess of Minimum Debris Retention Injection Rate (MDRIR) via SW cross tie.

CN060529A Loss of Makeup at High Press Containment venting via WW until full, then

- No Injection - No DW switched to DW. Vent path size determined by sprays - Flood containment ability to reduce/maintain pressure below PCPL.

with SW cross tie following Vents remain open once opened.

RPV breach - Venting Remains Open CN060530 Loss of Makeup -RPV at Low Containment venting does not occur until DW is Press - ED at MSCRWL - No flooded to an elevation near the bottom of fuel. At Injection - DW sprays (within which time the largest DW vent path is opened and five minutes of RPV breach) - remains open (arbitrarily assumed). PCPL is never Flood containment with SW exceeded.

cross tie following RPV breach - Venting Throttled CN060530A Loss of Makeup -RPV at Low This run result is the same as CN060530, since the Press - ED at MSCRWL - No only difference is vent remains open in this run.

Injection - DW sprays (within Since, PCPL was not exceeded until flood-up was five minutes of RPV breach) - near complete, the results are the same.

Flood containment with SW cross tie following RPV breach - Venting Remains

_Open

NLS2009048 Page 22 of 44 Case Description Comments CN060531 LLOCA - No Injection - DW No throttling of venting was required as PCPL not sprays (within five minutes of exceeded until flood-up was near completion.

RPV breach) - Flood Largest DW vent was opened and remained open containment with SW cross at this time.

tie following RPV breach -

Venting Throttled CN060532 Loss of Makeup at High Press None

- No Injection - No DW sprays Stuck Open Relief Valve (SORV) at time = 0 CN060533 Loss of Makeup at High Press None

- No Injection - No DW sprays - SORV at hot node temperature of 3000'F The following example of the weighing process is provided for the IBLI -40 Level 2 sequence:

Sequence: IBL1-40 Sequence Probability: 1.0651E-7 CET end state for sequence: M/I Total probability for all significant M/I sequences: 1.8327E-7 Fraction of sequence probability to total end state probability: 1.0651E-7/1.8327E-7 =

0.581 MAAP run representative of Sequence: CN060525C CsI mass fraction obtained from MAAP results for CN060525C: 8.75E-2 Sequence CsI mass fraction contribution to total M/I end state mass fraction: 0.581 x 8.75E-2 = 5.08E-2 The mass fraction contribution from all M/I sequences was summed resulting in an end state mass fraction of: 1E-1 2.c. The three basic events CNT-SMP-FF-MLTOF, RPV-DWV-FO-BARIS, and CNT-MDL-FF-WTRCV all involve failure of the drywell shell (melt-through).

Basic event CNT-SMP-FF-MLTOF models the probability that the amount of core melt debris is greater than the sump volumes. If the sumps do not overflow, no debris comes into contact with the drywell shell. The drywell pedestal sumps are able to hold approximately 22% of the core debris; however, eventually more than 80% of the debris may be released from the RPV causing the sumps to overflow leaving a large fraction of

NLS2009048 Page 23 of 44 the core that could migrate to the drywell shell. Therefore, the probability of this event is set to 1.0 in the CNS PRA model.

Basic event RPV-DWV-FO-BARIS models the probability that barriers fail to block the debris from reaching the steel shell. This event is a result of the proposed Mark I containment modification to install a curb to prevent debris from spreading across the floor and contacting the shell. Since such a curb does not exist at CNS, the probability of this event is set to 1.0 in the CNS PRA model.

Basic event CNT-MDL-FF-WTRCV models the probability that the operator fails to align alternate injection sources (i.e., SW crosstie or fire protection system crosstie) in the Level 2 analysis. Following failure to recover injection systems in the Level 1 analysis, if the RPV is successfully depressurized, an additional time window is available (approximately three hours) for system recovery before RPV breach and the potential for shell attack occurs. Given that the operator has failed to align alternate injection in Level 1, the HEP accounts for recovery of injection sources within the extended time before RPV breach and the attendant containment challenges that would occur at RPV breach.

The probability of this event is set to 0.9 in the CNS PRA model.

NRC Request: ENV-SAMA-3

3. For each of the dominantfire areas, explain what measures, if any, have already been taken (since the individualplant examination of external events (IPEEE)) to reducefire risk. Include in the response specific improvements to fire detection systems, enhancements to fire suppression capabilities,changes that would improve cable separationand drain separation,and improvements to processes/proceduresfor monitoring and controllingthe quantity of combustible materials in criticalareas.

NPPD Response:

3. The IPEEE listed compartments 3A (switchgear room IF), 3B (switchgear room IG),

lOB (control room and security access system corridor), and 20A (service water pump room) as the dominant fire areas.

Fire protection improvements to monitor and control the quantity of combustible materials in critical process areas, and to monitor and control pre-staging of outage materials have been implemented since the IPEEE was submitted on October 30 1996, which would reduce CDF values for all of the dominant zones.

The following discussion for each zone explains additional measures, if any, taken to reduce risk in that zone and explains why the fire CDF cannot be further reduced in a cost-effective manner.

NLS2009048 Page 24 of 44 Switchgear rooms 1F and 1G (Compartments 3A and 3B)

No design changes have been made in the switchgear rooms to reduce fire risk since the IPEEE. The switchgear rooms have a fire detection system which provides an alarm in the control room. Phase II SAMA 63 (not cost-beneficial) was evaluated to determine the benefit from adding automatic suppression systems to the switchgear rooms. Thus, no further cost-effective changes in this zone were identified to reduce CDF.

Main Control Room and Security Access System Corridor (Compartment 1OB)

No design changes have been made in the control room and security access system corridor to reduce fire risk since the IPEEE. For this compartment, the sensing devices used for fires include both fuse elements (that melt given high temperature) and smoke detectors. The main control room is also continuously manned. Therefore, a fire in this compartment will result in prompt fire brigade response and manual extinguishment. An automatic suppression system would not provide a significant safety benefit. An automatic suppression system based on Halon or CO 2 would asphyxiate any personnel remaining in this compartment, and thus require evacuation. A water-based automatic suppression system would damage the control equipment.

Phase II SAMA 65 (not cost-beneficial) was evaluated to determine the benefit from upgrading the alternate shutdown panel to reduce the fire CDF from scenarios that result in main control room evacuation. Since the main control room is always inhabited ensuring prompt fire detection and manual suppression, no further cost-effective changes in this zone were identified to reduce CDF.

Service water pump room (compartment 20A)

No changes have been made in the service water pump room to reduce fire risk since the IPEEE. Since the service water pump room is equipped with a detection system that alarms in the main control room and a total flooding halon suppression system, no further cost-effective changes in this zone were identified to reduce CDF.

NRC Request: ENV-SAMA-4

4. Provide the following information concerning the MACCS2 analyses:

a. Specify the fraction of the public that was assumed to participatein an evacuation at CNS. NUREG-1150 assumed a 99.5 percent evacuation within the emergency planningzone (EPZ);previous SAMA analyses have assumed a 95 percent evacuation. If a 95 percent evacuation was not assumed at CNS, address the

NLS2009048 Page 25 of 44 potential impact on the off-site exposure risk and avertedpublic exposure cost if5 percent of the populationfails to evacuate the EPZ.

b. In Section E. 1.5.2.8, it is stated that the core inventory is based on a bounding reloadcore immediatelyfollowing shutdown. Provide the core enrichment and burnup used in the MAACS2 analyses. Confirm that this core inventory reflects the expectedfuel management/burnup during the renewalperiod.

NPPD Response:

4.a. The fraction of the public that was assumed to participate in an evacuation at CNS is 1 (or 100 percent) in the SAMA analyses.

If only 95 percent of the population had been assumed to evacuate the EPZ, then the off-site exposure risk would have been 2.15 person-rem/yr for the baseline severe accident consequences. Similarly, the public exposure cost would have been $46,280. These numbers represent an increase of less than one percent of the values reported in Section 4.21.5.1.4 of the License Renewal Application Environmental Report (LRA-ER) assuming 100 percent evacuation. The fact that the site is in a low population area is the reason for the results. Consequently, the impact on the offsite exposure risk and averted public exposure cost would be insignificant if five percent of the population failed to evacuate the EPZ.

4.b. Core enrichment and burnup are not explicitly used in the MACCS2 analysis; rather the core inventory of key nuclides is used directly. The core enrichment and burnup assumed for determining the core inventory for the MACCS2 analysis are consistent with values used to determine the fission product inventory utilized in the current licensing basis dose calculations reflected in the CNS Updated Safety Analysis Report (USAR). The fission product activity inventory utilized a "bounding" core assumed to consist of an initial enrichment of 3.908 Wt % U-235 and high burnup GE14 fuel undergoing 1300 effective full power days (EFPD) of continuous irradiation to achieve an end of cycle core average exposure (CAVEX) of 35.8 Gwd/MT, which is more than six percent above the equilibrium core analyzed. Activity inventories were calculated with the Oak Ridge National Laboratory isotope generation and depletion code ORIGEN2, incorporating the BWR extended bumup library BWRUE. The core inventory utilized in the MACCS2 analysis assumed a thermal power level of 2429 MW(t), which encompasses the licensed maximum power level of 2419 MW (t), following the CNS Measurement Uncertainty Recapture (MUR) power uprate. This core inventory reflects the expected fuel management/bumup for the renewal period.

NLS2009048 Page 26 of 44 NRC Request: ENV-SAMA-5

5. Provide the following with regardto the SAMA identification and screeningprocess:

a. Table E.1-5 identifies the RR Wfor events that contribute to LERF. The table appears to contain success events and associatedSAMAs. For example, CGS-PHE-FF-INERTrepresentssuccessful containment inertingand has the highest RRWvalue in the table (3.417). Another example is RPV-MDL-SC-C1A1E, successful depressurization(Class IA, IE), which has an RRW value of 1.335.

Discuss the rationalefor identifying SAMAs for success events.

b. There appear to be events in Table E.1-5 that are complementary (e.g., as the probabilityof event A approacheszero, the probabilityof event B approaches1. 0.

Evaluation of RRW for these events would need to consider this relationship. To examine how this relationshipbetween events was addressed in Table E. 1-5, provide the value usedfor CGS-PHE-SC-INERT(containment not inerted; venting required)when calculating the RR Wfor CGS-PHE-FF-INERT (containment inerted; venting not required). If the value of this and other complementary events were not directly coupled in the computation of the RR Ws, provide a revised Table E. 1-5 with these events appropriatelyaddressed(i.e., the probabilityof event CGS-PHE-SC-INERT is set equal to 1.0 when the probability of event CGSPHE-FF-INERTis set equal to 0. 0). Provide an assessment of the results on the SAMA identificationand evaluation.

c. From Table E.1-3, event TDCA (loss of 125 VDC A) and event EDC-XHE-FO-RSTA (failureto restoreDCpower within 30 minutes) have RR W values of]. 19, which would imply a potential CDFreductionfor DCpower improvements of about 20 percent. These events are addressedby SAMAs 1, 2, 3, 13, 14, 15, 19, and 21, which in turn are covered by analysis cases 1 through 5 and 14.

However, these analysis cases show a CDF reduction (in Table E. 2-2) of about 3 percent or less (except for analysis case 14). Explain why there are not additionalDCpower-relatedSAMAs for these basic events that have potentially greaterCDFreduction impacts than 3 percent. For example, provide the rationalefor why a proceduralSAMA addressingevent EDC-XHE-FO-RSTA with a potential CDFreduction of about 20 percent was not considered.

d. Event PCI-CNT-FF-PREEX(pre-existingcontainmentfailure) has an RR W of 1.056. All of the SAMAs consideredfor this event involve major hardware modifications. Provide an assessment of the costs and benefits of lower cost SAMAs for this event (e.g., periodic monitoring of containment integrity during normal operation or procedures to isolate the containmentfollowing an event).

NLS2009048 Page 27 of 44

e. ER Section E.2.2, identified three criteriaused to screen PhaseI SAMAs, all of which are qualitative. However, informationprovided in the "ScreeningResults" column of Table E.2-1 suggests that other criteriawere used, including "Small CDFReduction" (SAMAs 209, 227, and 229), and "Outliers Were Resolved Analytically" (SAMAs 217, 220, 221, 224, 226, and 227). Clarify the criteria used to perform the PhaseI screening.

f Table E.2-2, describes SAMA 21 as being partof SAMA 13 and no separate evaluation is provided.Explain the rationalefor including SAMA 21 as a unique SAMA if it cannot be implemented as an independent SAMA.

g. In Table E.2-1, SAMA 232 (protectthe diesel exhaust from tornado generated missiles) is describedas being resolved by a modification completed in 1998.

However, in the NRC safety evaluation report (SER) on the CNS IPEEE dated April 2001, the issue is describedas yet to be addressedin the JPEEEIssue Resolution Plan. Clarify this apparentdiscrepancy.

NPPD Response:

5.a. As described in ER Section E. 1.2.1, Table E. 1-5 provides a correlation between the Level 2 RRW risk significant events (severe accident phenomenon, initiating events, component failures and operator actions) down to 1.005 identified from the CNS 2007TM Revision 1 PSA LERF model and the SAMAs evaluated in Section E.2.

Table E. 1-5 includes basic events that are not failure events. Rather, they are "success events" used to identify the conditions under which the failure events in a particular sequence occur. These events were included in Table E. 1-5 since they provide information about the model, but the SAMAs identified for these events do not have the same meaning as those identified for the component and human failure events. SAMAs identified for component and human failure events are intended to decrease the risk contribution from that failure event by decreasing the probability of the failure event itself. However, since decreasing the probability of a success event is not desirable, SAMAs identified for success events are intended to decrease the risk contribution from the cutsets or events related to the success event. The SAMAs identified for a success event in Table E. 1-5 are also listed in Table E. 1-5 for the specific component and human failure events in Table E. 1-5 that are related to the success event.

For example, RPV-MDL-SC-C1A1E represents successful RPV depressurization. If the probability of successful depressurization increases, then the LERF contribution is decreased. The primary benefits associated with the ability to depressurize the RPV include the following:

NLS2009048 Page 28 of 44

" Enables injection to the RPV from low pressure injection systems, such as, LPCI, CS, condensate, and fire water.

" The stresses on primary system components are reduced; thereby increasing the likelihood that the primary system will remain intact.

" The likelihood that high pressure blowdown coupled with inadequate vapor suppression would lead to immediate containment failure is reduced.

" The likelihood that molten material will be finely dispersed in the containment atmosphere leading to a direct containment heating failure mode is reduced.

Thus, Phase II SAMAs 26, 27, 43, and 44, to enhance depressurization (or decrease the risk contribution from failure of depressurization), were listed for event RPV-MDL-SC-ClAlE.

Also, CGS-PHE-FF-INERT and CGS-PHE-SC-INERT are split fractions which indicate whether the containment is inerted. The failures that result in release with containment inerted are different than those with containment not inerted.

CGS-PHE-FF-INERT represents the containment being inerted, so combustible gas venting is not required. Since containment failure must occur to have a release in the absence of containment gas venting, SAMAs that decrease the probability of containment failure due to severe accident phenomena will decrease the LERF impact of cutsets containing CGS-PHE-FF-INERT. Thus, Phase II SAMA 70, to install a curb to prevent debris from spreading across the floor and contacting the shell, was identified to decrease risk from cutsets containing CGS-PHE-FF-INERT.

CGS-PHE-SC-INERT represents the containment not inerted and venting is required.

Since release can occur without containment failure in cutsets with CGS-PHE-SC-INERT, Phase II SAMAs 48, 49, 50, and 52, to improve venting and fission product scrubbing and to provide passive overpressure relief, were identified to reduce risk from cutsets containing CGS-PHE-SC-INERT.

5.b. The value of CGS-PHE-SC-INERT and CGS-PHE-FF-INERT when calculating RRW were 0.01 and 0.99, respectively.

The split fraction events are utilized for sequence identification. As described in response to RAI 5.a., the LERF impact of cutsets containing CGS-PHE-FF-INERT or CGS-PHE-SC-INERT was reduced by decreasing the probability of individual events in the cutsets. The values of other split-fraction events were also directly coupled in the computation of RRW.

NLS2009048 Page 29 of 44 Since split fraction events were directly coupled in the computation of RRW, revision of table E. 1-5 is not necessary and there is no impact on SAMA identification and evaluation.

5.c. The list of 244 Phase I SAMA candidates includes SAMAs from a number of industry documents and from previous SAMA submittals. This list included several DC power enhancements which would improve events TDCA (loss of 125 VDC bus A) and EDC-XHE-FO-RSTA (failure to restore DC power within 30 minutes), but these had already been implemented at CNS. The remaining applicable enhancements were evaluated as Phase II SAMAs 1, 2, 3, 13, 14, 15, 19, and 21. While each of these Phase II SAMAs is capable of improving the DC power system, none is capable of mitigating a complete loss of 125 VDC bus A. Thus, all postulated DC power-related SAMAs for these basic events have been implemented or evaluated.

Since DC power is a support system, SAMAs that mitigate failure of the supported systems would also reduce the contribution from failure of TDCA. TDCA is a dominant CDF contributor for two primary reasons.

1. Loss of 125 VDC bus A power results in loss of division 1 remote breaker and logic controls for division 1 low pressure emergency core cooling systems (ECCS), diesel generator 1, and reactor core isolation cooling. Additionally, loss of 125 VDC bus A results in loss of the low pressure injection source provided by the main condensate pumps because all three condensate pumps are lost. Pumps A and C are lost due to the inability of DC logic to transfer the alternating current (AC) buses to the startup transformer. Pump B is lost due to inadequate cooling caused by DC logic failure of two of the three turbine equipment cooling (TEC) pumps.

2. Loss of 125 VDC bus A power results in the loss of instrument air and the inability to open air-operated valves to vent containment using the wetwell or drywell vent systems. This leaves only the hard pipe vent method of venting containment. Instrument air is lost because the A compressor fails due to DC logic failures, and air compressors B and C lose cooling due to DC logic failure of two of three TEC pumps and two of four reactor equipment cooling (REC) pumps.

Therefore, the SAMAs postulated to improve low pressure injection (Phase II SAMAs 28, 29, 32, 47, 64, and 78) and containment venting (Phase II SAMAs 20, 48, 49, 50, 52, and 53) would also lower the contribution due to loss of 125 VDC bus A.

Basic event EDC-XHE-FO-RSTRA (failure to restore DC power within 30 minutes) is a recovery event, similar to loss of offsite power recovery events, with a probability based

NLS2009048 Page 30 of 44 upon industry experience. It is not based upon plant-specific human reliability analyses.

CNS has detailed, symptom-based procedures which provide adequate guidance for loss of 125 VDC components.

5.d. Event PCI-CNT-FF-PREEX represents a pre-existing containment failure leading to loss of NPSH to the ECCS pumps. Lower cost SAMAs such as periodic monitoring of containment during normal operation and procedures to isolate containment following an event were not evaluated because they already exist at CNS. Containment is inerted during normal operation, so a leak large enough to lead to loss of NPSH to the ECCS pumps would result in the need for an unusual amount of nitrogen and would not go unnoticed.

Also, CNS procedures and programs monitor containment integrity. The containment leak rate program, in accordance with 10 CFR 50, Appendix J, includes local and integrated leak rate testing of primary containment pressure-retaining components. Also, the containment inservice inspection program, in accordance with ASME Section XI Subsection IWE and 10 CFR 50.55a, includes inspections of the primary containment and its integral attachments to ensure that degradation does not exist that would challenge the leak tight barrier.

5.e. Section E.2.2 has been revised to add statements that clarify the screening criteria (see Attachment 2).

5.f. SAMA 21, Modify plant procedures to allow use of a portable power supply for battery chargers, was included as a unique SAMA due to the belief that a suitable portable power supply was available to supply the battery chargers. Further investigation revealed that the available skid mounted portable power supply is not sufficient to supply the battery chargers. (The portable power supply is considered available in the cost estimates for SAMAs 14 and 20.) Since SAMA 13, purchase of a portable power supply, requires the plant procedure revisions, SAMA 21 is included as part of SAMA 13.

5.g. The modification to protect the diesel exhaust from tornado generated missiles was completed in 1998.

In response to the NRC Staff Evaluation Report on the Cooper IPEEE dated April 2001, clarification was provided in CNS letter (NLS2001057) to the NRC dated July 6, 2001, with the subject "IPEEEStaff Evaluation Report Clarificationand Commitment Status Update - CooperNuclear Station, NRC Docket 50-298, DPR-46." The clarification indicated that the modification, which involved elimination of the bypass valves for the diesel generator mufflers and eliminated the failure mode described in the CNS IPEEE submittal, was completed in 1998.

NLS2009048 Page 31 of 44 NRC Request: ENV-SAMA-6

6. Provide the following with regard to the Phase II cost-benefit evaluations:

a. Fora number of the PhaseII SAMAs listed in Table E.2-2, the information provided does not sufficiently describe the associatedmodifications and what is included in the cost estimate. Provide a more detaileddescription of both the modifications and the cost estimatesfor PhaseII SAMAs 20, 44, 45, 63, 70, 72, 73, 76, 77, and 80. Also, for SAMA 76 describe what is meant by "group 1 isolations" in the context of both the plant and the PRA model.

b. Analysis case 14 covers SAMA 14 (portablegeneratorfor DCpower to supply individualpanels), SAMA 22 (install independent high-pressure injection (HPI) system), and SAMA 23 (additionalHPIpump with independent diesel). For this case, high-pressurecoolant injection (HPCI) unavailabilitywas set to zero resulting in a 32 percent reduction in CDF. However, event HCI-SYS-TM-HPCI (HPCIunavailabledue to test and maintenance) has an RR W equal to 1.03.

i. Explain the rationalefor assigningSAMA 14 to analysis case 14, andfor estimating the benefit for this SAMA by setting HPCIunavailabilityto zero.

ii. Explain the large CDF reduction (32 percent) when the RR Wfor HPCI unavailabilitydue to test and maintenance would suggest only a 3 percent reduction. Clarify whether loss of DC panelpower is the dominant contributorto HPCIunavailability. Identify the other significant contributorsto HPCIunavailability.

c. In Table E.2-2, the modeling assumptionfor SAMA 6 (i.e., change the time available to recover offsite power to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />) is inconsistentwith the modeling assumption of analysis case 6 (i.e., set failure to transfer the reactorprotection system panels to their alternatepower source to zero). Clarify which description is correct. Provide a revised evaluation, if necessary.

d. Table E.2-2 describes the bounding analysisfor SAMA 78 as "reducing.operator actions that could be improved via trainingfor alternateinjection via the fire water system by a factor of 2." The descriptionprovidedfor the corresponding analysis case 23 (pageE. 2-8) is similar.Provide a clarification of how the evaluation of this SAMA was modeled in the PRA. Identify the associated operatoraction(s) and the initialand modified human errorprobabilityvalue(s).

NLS2009048 Page 32 of 44

e. SAMA 41 (modify procedure to provide ability to align diesel power to more air compressors) has an estimated cost of $1.2M. This cost appears highfor what appears to be a procedure and trainingissue. Justify the cost estimatefor this SAMA.

f SAMA 69 (upgrade the seismic capacity of the dieselfirepump fuel tank and water supply tank) is intended to increasethe reliability of the fire water system in seismic events. The benefit of this SAMA was determined by eliminatingfailure of the diesel-drivenfire pump. Discuss how eliminatingfailure of the diesel-driven fire pump in the internalevent model, in conjunction with the external event multiplier, captures the benefitfrom this SAMA in seismic events. Justify the benefit and cost estimatesfor this SAMA.

g. SAMA 14 (portablegeneratorfor DCpower to supply the individualpanels) and SAMA 13 (portablegeneratorfor DCpower to supply the battery chargers)both involve use of a portablegenerator.SAMA 14 is cost beneficial while SAMA 13 is not. Discuss whether it isfeasiblefor SAMA 13 to use the same portable generatoras SAMA 14, and ifso, provide a revised evaluation of SAMA 13.

h. SAMA 70 (installa curb to prevent debrisfrom spreading across the floor and contactingthe shell) has a CDFreduction of 11. 6percent. Explain how this SAMA reduces CDF,and identify the events in Table E. 1-3 that are impacted.

SAMA 75 (implement generation risk assessment into plant activities) has a large benefit owing to the many risk contributorsthat it impacts. Provide a detailed description of this SAMA, including: (1) a discussion of how it would be implemented at CNS, (2) a more comprehensive description of analysis assumptions, (3)justificationfor the assumedfactor of 2 reduction in initiating eventfrequency for affected events, and (4) a more detailed discussion of the estimated implementation cost.

Pages 4-83 and E.2-2 of the ER indicate that the SAMA cost estimates did not include the cost of replacementpower during extended outages requiredto implement the modifications, nor did they accountfor inflation. Clarify how other costfactors were treated in these estimates, specifically, contingency costs associatedwith unforeseen implementation obstacles, and maintenance and surveillance costs.

k. Explain why a factor of 3 is used to represent uncertainty,given that the ratio of the 95th percentile CDF to the mean CDFis said to be 1.86. Provide the S5 percentile, mean, and 95th percentile CDFvalues.

NLS2009048 Page 33 of 44

1. The CNS cost-benefit analysis showed that eleven of the SAMA candidates (SAMAs 14, 25, 30, 33, 40, 45, 64, 68, 75, 78, and 79) were potentially cost-beneficial.

i. The ER does not provide any indicationof CNS's plans regardingthe eleven Phase II SAMAs found to be potentially cost-beneficial. Describe CNS's plans regardingthese SAMAs, and any other potentially cost-beneficial SAMAs that may emergefrom further analyses in response to these RAIs.

ii. In view of the significant number ofpotentially cost-beneficial SAMAs, it is likely that several of these SAMAs address the same risk contributors.

As such, implementation of an optimal subset of these SAMAs could achieve a large portion of the total risk reduction at a fraction of the cost, and render the remainingSAMAs no longer cost-beneficial. In this regard: (1) identify those SAMAs that Nebraska PublicPower District (NPPD)considers highestpriorityfor implementation, (2) provide an assessment of the impact on the remainingSAMAs if these high-priority SAMAs are implemented, and (3) identify those SAMAs that would no longer be cost-beneficialgiven implementation of the high-priority SAMAs. Also, provide any specific plans/commitments regarding implementation of the high priority SAMAs.

NPPD Response:

6.a. ER Section E.2.3 provides a general description of the cost estimating process. It notes that detailed site-specific cost estimates were not required for all SAMA candidates, but that the cost of each candidate was conceptually estimated to the point where conclusions regarding the economic viability of the proposed modification could be adequately gauged.

SAMA 20 provides redundant power to the direct torus hard pipe vent valves to improve their reliability and enhance containment heat removal capability. CNS already has a skid mounted portable AC generator that was used for the old Technical Support Center.

The cost estimate for SAMA 20 assumes that this generator would be used to provide power to the valves; therefore a generator is not included in the cost estimate. The

$714,000 cost estimate includes costs to provide electrical wall penetrations in the control building to allow generator hook-ups to the appropriate buses. It also includes costs to provide new or revised operating procedures, and to provide operator training.

Since the CNS SRVs and main steam isolation valves (MSIV) have redundant power supplies and accumulators, SAMA 44 would enhance the reliability of these valves by

NLS2009048 Page 34 of 44 replacing them with an improved design. As stated in the ER, the cost estimated for SAMA 44 came from a cost estimate for a similar SAMA at Pilgrim. In an RAI response letter (ADAMS Accession Number ML061930418), Pilgrim indicated that since their SRVs have redundant DC power supplies and back up nitrogen supplies, the only way to enhance SRV reliability would be to replace the valves with an improved design. The estimated cost to replace four SRVs with more reliable SRVs at Pilgrim was $1,500,000.

Since CNS has eight SRVs and eight MSIVs, and the Pilgrim estimate to replace four valves is greater than the benefit (with uncertainty) of $574,974 for CNS SAMA 44, a detailed site-specific cost estimate was not needed to determine that SAMA 44 is not cost-beneficial.

The modification for SAMA 45 involves procurement of a portable compressor to be aligned to the supply header to reduce the risk associated with loss of instrument air.

CNS recently replaced the three positive-displacement instrument air compressors with screw type compressors. While that modification was being performed, a rented portable compressor was used to supply instrument air. Therefore, the hook-ups remain available to support the SAMA 45 modification and are not included in the cost estimate. The cost estimate of $100,000 includes the cost of a new screw type compressor (approximately

$85,000) as well as costs to mount the compressor on a trailer for mobility and necessary procedure changes. SAMA 45 has been retained on the list of SAMAs that is potentially cost-beneficial.

The modification for SAMA 63 is to add automatic gas suppression systems in the switchgear rooms. As stated in the ER, the cost estimate for SAMA 63 came from a cost estimate for a similar SAMA at Brunswick. NUREG-1437, Supplement 25, indicates that the estimated cost of installing an automatic gas suppression system in two reactor building areas was $750,000 at Brunswick. Since Brunswick is a two unit site, the estimate for CNS was reduced accordingly to $375,000. Since the Brunswick and CNS SAMAs both evaluate addition of two automatic gas suppression systems, use of the Brunswick estimate for CNS is appropriate. Since the estimated cost is greater than the benefit (with uncertainty) of $347,908, a detailed site-specific cost estimate was not needed to determine that SAMA 63 is not cost-beneficial.

SAMA 70 is to install a curb to prevent debris from spreading across the floor and contacting the drywell shell. The curb would be steel reinforced concrete with a diameter of approximately 50 feet, six inches high and three feet wide. The curb may not be a perfect circle to allow for routing around installed equipment and existing structures.

Drilling into the existing containment floor may be necessary to ensure compatibility between existing and new concrete. Analysis would have to be performed to ensure that new drywell structure is as good as, or better than, the existing design. Details of the cost estimate are as follows:

NLS2009048 Page 35 of 44

$50,000 civil modification and 10 CFR 50.59 review

$120,000 3-D analysis of new drywell structure

$160,000 miscellaneous material and labor

$100,000 adder for safety-related modification

$50,000 project management and support

$33,000 mobilization, tools and training

$165,000 contingency for lack of detailed estimate

$100,000 contingency for budget estimate

$66,000 construction management fee, insurance, and performance bond NUREG-1437, Supplement 26, indicates that the estimated cost of providing a means of automatically preventing drain down of the condensate storage tank to the hot well during an SBO was $230,000 at Monticello. Although the Monticello report does not indicate exactly what this modification would entail and the details of the modification for CNS have not been postulated, it would require a hardware modification. The benefit (with uncertainty) of CNS SAMA 72 is only $62,671. As described in ER Section E.2.3, based on a review of previous SAMA evaluations and an evaluation of the expected implementation costs at CNS, hardware modifications cost from $1 00K to > $1 000K.

Since the benefit is less than $1 00K, a detailed site-specific cost estimate was not needed to determine that SAMA 72 is not cost-beneficial.

Analysis Case 37 in ER Section E.2.3 describes the modification for SAMA 73. This modification entails installation of a chiller in the yard with the associated piping and valves and includes penetrations through the reactor building. A heat exchanger would be required in the reactor building to transfer heat from the torus water to the chiller water. Pipe penetrations would be needed on the torus to allow for water circulation to the heat exchanger. Procedure changes and training would also be required. Details of the cost estimate are as follows:

$70,000 multi-discipline modification and 10 CFR 50.59 review

$40,000 pipe sizing and seismic calculations

$25,000 one new and eight revised procedures

$100,000 commercial grade 150 ton chiller

$250,000 nuclear grade heat exchanger

$40,000 piping and supports

$30,000 valves

$40,000 two penetrations to allow chiller water circulation to and from the torus

$30,000 instrumentation and controls

$30,000 electrical cables and conduits

$100,000 adder for safety-related modification

$70,000 project management and support

NLS2009048 Page 36 of 44

$50,000 mobilization, tools and training

$200,000 contingency for lack of detailed estimate

$100,000 contingency for budget estimate

$100,000 construction management fee, insurance, and performance bond SAMAs 76, 77, and 80 were assumed to cost > $1 00K since they are hardware modifications. The details of the modifications have not been established. As described in ER Section E.2.3, based on a review of previous SAMA evaluations and an evaluation of the expected implementation costs at CNS, hardware modifications cost from $ 1OOK to > $1000K. Since the benefit (with uncertainty) for SAMAs 76, 77, and 80 is less that

$1 00K, the conclusion that these SAMAs are not cost beneficial was made without detailed modification descriptions or detailed cost estimates.

"Group 1 isolations" refers to the primary containment isolation system (PCIS) actions to close the MSIVs and main steam line drain valves. Groups 2 through 7 of PCIS actuate to close other valves such as residual heat removal (RHR), reactor water cleanup, HPCI and RCIC steam lines, and sample valves. Each isolation group is actuated by different isolation signals within PCIS. A Group 1 isolation occurs on low reactor water level, low main steamline pressure, high main steamline area leak detection temperature, low condenser vacuum, or high main steamline flow. The PRA models Group 1 isolation as an initiator which causes closure of the MSIVs, resulting in loss of the main condenser as a heat sink.

SAMA-76 is proposed to improve steam tunnel HVAC reliability. The main steamline leak detection system is composed of temperature switches, some of which are dispersed near the steam lines in the steam tunnel providing assurance that a significant break will be detected rapidly and accurately. However, since PCIS will cause a Group 1 isolation if the temperature in the steam tunnel is > 200'F, failure of steam tunnel HVAC can result in a Group 1 isolation, and closure of the MSIVs, although a main steamline break has not occurred.

6.b.i. Phase II SAMA 14 would provide alternate DC feeds (using a portable generator) to panels supplied by a DC bus. Upon loss of a DC bus, a portable generator could be used to provide power to an individual 125 VDC motor control center. Analysis case 14, which estimates the benefit of setting HPCI unavailability to zero, was selected to conservatively assess the benefit of SAMA 14 because the benefit of providing an alternate DC source to HPCI to support emergency core cooling was judged to be larger than the benefit of providing an alternate DC source to other panels. This is due to the importance of HPCI in intermediate LOCA sequences and because the turbine-driven HPCI pumpý can continue to run in SBO sequences as long as DC control power is available.

NLS2009048 Page 37 of 44 6.b.ii. Event HCI-SYS-TM-HPCI (HPCI unavailable due to test and maintenance) has an RRW equal to 1.03. However, in analysis case 14, HPCI was set to never fail (HPCI top gates were set to zero). Thus, analysis case 14 conservatively results in a 32% reduction in CDF.

Although importance measures for HPCI unavailability have not been quantified, loss of DC power is a significant contributor to HPCI unavailability. Table E. 1-3 shows that other significant HPCI failure contributors are failure of the turbine-driven pump to start (HCI-TDP-SS-TP), the test and maintenance event (HCI-SYS-TM-HPCI), failure of hydraulic valve HO 10 (HCI-HOV-CC-HO 10), failure of the turbine-driven pump to continue to run (HCI-TDP-SR-TP24) and failure to bypass the high temperature trip (HCI-XHE-FO-BYPTP).

Since the implementation cost is not much larger than the benefit (with uncertainty) for Phase II SAMA 14, this SAMA might not be cost-beneficial if the analysis was refined to only fail the DC power contributor to HPCI unavailability. However, the SAMA was conservatively retained on the list of SAMAs for further evaluation.

6.c. The Table E.2-2 description of the modeling assumption for SAMA 6 has been revised to state "Failure to transfer the RPS panels to their alternate power source was set to zero in the level 1 PSA model" (see Attachment 2). No revised evaluation is necessary.

6.d. For SAMA analysis case 23, failure probabilities for operator actions related to injection via the fire water system were reduced by a factor of 2. Specifically, failure probabilities for basic events FPS-XHE-FO-DFPAL, FPS-XHE-FO-DISEL, and FPS-XHE-FO-RPVIN were reduced as described below.

FPS-XHE-FO-DFPAL - CREW FAILS TO ALIGN DFP UNDER SBO CONDITION

(>2 HRS. AVAIL)

The failure probability for this operator action was reduced to 5.OOE-02 from its original value of 1.OOE-01. The manipulation time for this action could be reduced via training.

The response time may also be reduced slightly due to heightened awareness provided by training. A factor of two improvement bounds the expected decrease in failure probability attainable by decreasing the response and manipulation time by increasing training on this action.

FPS-XHE-FO-DISEL - NO FUEL OIL MAKEUP PROVIDED WITHIN 8 HOURS The failure probability for this operator action was reduced to 9.50E-03 from its original.

value of 1.90E-02. The manipulation time for this action could be reduced via training.

The response time may also be reduced slightly due to heightened awareness provided by training. A factor of two improvement bounds the expected decrease in failure

NLS2009048 Page 38 of 44 probability attainable by decreasing the response and manipulation time by increasing training on this action.

FPS-XHE-FO-RPVIN - OPERATOR FAILS TO ALIGN FIRE PROTECTION SYSTEM FOR RHR LOOP A INJECTION The failure probability for this operator action was reduced to 5.OOE-02 from its original value of 1.00E-01. The manipulation time for this operator action could be reduced via training. The response time may also be reduced slightly due to heightened awareness provided by training. A factor of two improvement bounds the expected decrease in failure probability attainable by decreasing the response and manipulation time by increasing training on this action.

Operator actions FPS-XHE-FO-DFPAL1, "CREW FAILS TO ALIGN DFP UNDER SBO CONDITION (<30 MIN. AVAIL)," and FPS-XHE-FO-RHR25A, "OPERATOR FAILS TO MANUALLY OPEN RHR-MO-25A LOCALLY," were originally assigned a failure probability of 1.0 because they cannot be performed within the available time.

The failure probability for these events was not reduced in the analysis for SAMA 78 because increased training is not expected to reduce manipulation or response times such that these actions can be performed within the available time. Since SAMA 78 is potentially cost-beneficial with the existing analysis, altering this assumption would not change the SAMA results.

6.e. SAMA 41 is intended to increase availability of instrument air after a loss of offsite power. Station air compressor (SAC) A is powered from critical 480V bus IF, SAC B is powered from critical 480V bus 1G, and SAC C is powered from a non-critical bus.

Thus, only SACs A and B will receive diesel power following a loss of offsite power.

Since current design does not allow for power connections between SAC C and either diesel generator (DG)1 or DG2, implementation of SAMA 41 would require electrical, mechanical, and structural hardware modifications to power SAC C from diesel power following a loss of offsite power. The cost estimate of $1,200,000 for this SAMA is based on an estimate for a similar SAMA for James A. FitzPatrick Nuclear Power Plant.

Although procedure changes would also be required to utilize this additional power connection, the description of SAMA 41 in the Tables E.2-2 and E.2-3 has been clarified (see Attachment 2).

6.f. Without a complete fire PRA, complete seismic PRA, and detailed evaluation of seismic-fire interactions, the exact benefit from SAMA 69 for external events cannot be characterized. However, in accordance with the guidelines in NEI 05-01, an external events multiplier has been used to ensure that SAMA benefits account for the benefits of both internal and external events. The external events multiplier for CNS is three,

NLS2009048 Page 39 of 44 because the external event CDF contribution was estimated to be twice that of the internal events.

In the internal events PRA, the diesel fire pump is credited as an alternate source of water for injection to prevent core damage. Following a fire or seismic event, the diesel fire pump might also be needed to combat a fire, but its contribution to core damage prevention would come from its use as an alternate source of water for injection.

Although this particular SAMA would not increase the availability of the diesel fire pump following an internal event initiator, the benefit of eliminating failure of the diesel-driven fire pump can be, and was, assessed using the internal events model. Since the external event CDF contribution is twice that of the internal events, and SAMA 69 only provides external event benefit, doubling the internal events benefit would provide an appropriate estimate of the benefit of SAMA 69. However, the external events multiplier of three was used for ease and consistency with the other SAMAs.

In summary, since it provides a conservative assessment, the benefit estimate for SAMA 69 is appropriate.

As described in ER Section E.2.3, based on a review of previous SAMA evaluations and an evaluation of expected implementation costs at CNS, hardware modifications were estimated to cost from $1 00K to > $1 000K. Since SAMA 69 would entail a hardware modification of the fuel and water tank structural supports, the implementation cost estimate of > $1 00k is appropriate.

6.g As indicated in the response to Question 5.f., the available skid mounted portable power supply considered in the cost estimates for SAMAs 14 and 20 is not sufficient to supply the battery chargers as proposed in SAMA 13. Since the SAMA submittal, NPPD has designed, installed and placed in service a new diesel generator that can supply the swing battery charger during an SBO at CNS. Therefore, SAMA 13 has been implemented at CNS.

6.h. The "CDF Reduction" value for each SAMA in Table E.2-2 is the reduction in release frequency obtained by implementation of the SAMA. SAMA 70 reduces the release frequency by providing a barrier between the reactor vessel and the drywell shell which will prevent core debris from contacting the drywell shell, but it does not reduce the Level 1 CDF. Therefore, events in Table E. 1-3 are not impacted by SAMA 70. Several events in Table E. 1-5 are impacted by SAMA 70.

6.i. (1) The insights gained from the CNS PRA model have identified important systems and components that, if maintained at a high level of reliability, provide assurance that core damage is avoided. NPPD identified those insights by identifying those components whose failure or unavailability would contribute the most to core

NLS2009048 Page 40 of 44 damage. Similarly, the Generation Risk Assessment (GRA) relies on a detailed logic model, but its objective is to determine which components are most likely to cause a plant trip or to result in a manual trip. Insights from the GRA model assist in identifying maintenance activities and operational practices that will avoid the most likely causes of plant trips. At CNS, the GRA model is part of an overall Equipment Reliability Excellence Plan. The initial phase, which is complete, was to perform single point vulnerability (SPV) studies on 19 systems to identify components that, if failed, would lead to plant trip. This information can be used to re-evaluate maintenance activities and design dependencies for these systems to reduce the likelihood of a failure that leads to a plant trip. By identifying these SPVs and addressing the insights gained in this manner, the likelihood of plant trips occurring from normally running support systems will be reduced.

(2) The GRA program was piloted by CNS for the Electric Power Research Institute (EPRI) and the results were presented to the industry on numerous occasions, including EPRI's Equipment Reliability Forum and the American Nuclear Society International PSA Conference. The overview of the methodology was made available publically through these venues. The technical details of CNS system-specific equipment performance and loss generation figures of merit are published in EPRI literature, but the material remains subject to copyright laws.

The analysis assumptions made for the GRA are too numerous to be presented here, but are well documented in several EPRI reports including the following:

Introduction to Simplified Generation Risk Assessment Modeling, TR1007386, Final Report, January 2004.

Generation Risk Assessment (GRA) at Cooper Nuclear Station, TRIO 11924, Final Report, December 2005 Pilot Application of Enterprise Project Prioritization Process at Nebraska Public Power District (NPPD) 1012954, Final Report, March 2006 Comparison of Qualitative (AP-913) and Quantitative (Generation Risk Assessment) Equipment Reliability Assessment technique, TR1013575, Technical Update, December 2006.

The GRA model is a decision-making tool that focuses resources on achieving safe and reliable plant operation while dealing specifically with uncertainties associated with projecting equipment performance. The method specifically accounts for statistical variability and is part of the decision-making process. The GRA uses state-of-the-art industry accepted risk assessment tools to improve plant performance by further reducing scrams while ensuring nuclear safety at the plant.

NLS2009048 Page 41 of 44 (3) A bounding analysis of the benefit of fully implementing GRA was performed for SAMA 75 by reducing initiating event frequencies since the objective of the GRA is to reduce the likelihood of failures that lead to plant trip. The conservative factor of 2 reduction in initiating event frequency is based on recent operating history and expert opinion given NPPD's expertise in the GRA process.

(4) The estimated implementation cost is a best-estimate of the costs associated with the GRA based on NPPD experience to date. A detailed implementation cost estimate has not been developed.

6.j. The cost estimates for SAMA implementation did not include maintenance and surveillance costs. However contingency costs for unforeseen implementation obstacles were included.

Cost estimates for SAMA consideration followed Entergy's standard process for development of project estimates. The process is applied to establish conceptual (+/-

25% to 50% accuracy), preliminary (+/- 15% to 30% accuracy), and definitive (+/- 10%

to 20% accuracy) estimates during the study, design, and implementation phases of a design project.

The SAMA cost estimates capture anticipated expenses by identifying the parts of the organization that must support the proposed SAMA modification from the conceptual perspective. Typical expenses associated with project cost estimating include calculations, drawing updates, specification updates, bid evaluations, contract issuance, design package preparation, walkdowns, planning and scheduling, estimating, procurement, configuration management, ALARA, QC/QA, training, simulator, IT, design basis update, construction, multi-discipline and independent review of design concepts and calculations, 10 CFR 50.59 review, USAR update, cost control, contingency, security, procedures, post work testing, and project management and close-out. In addition, the project cost estimates include corporate indirect charges.

In summary, the cost estimates for the subject SAMAs followed Entergy's standard process for development of project estimates. Therefore, these cost estimates are reasonable conceptual level estimates.

6.k. The summary report for the PRA model provides the following CDF values:

5 th percentile CDF = 4.41E-06 Mean CDF = 9.63E-06 9 5 th percentile CDF = 1.79E-05

NLS2009048 Page 42 of 44 Thus, as indicated in the ER, the ratio of the 9 5 th percentile CDF to the mean CDF is about 1.86. However, the previous revision of the summary report indicated that this ratio was approximately 2.9. When the revised values were published, the uncertainty factor of 3 was retained in the SAMA analysis to prevent the necessity for rework.

Since the potential impact of using of a larger uncertainty factor would be to retain more SAMAs as cost-beneficial, the factor of 3 is conservative.

6.1.i. The potentially cost-beneficial SAMAs do not relate to adequately managing the effects of aging during the period of extended operation; therefore, they need not be implemented as part of license renewal pursuant to 10 CFR Part 54. However, as indicated on page 4-85 of the ER, detailed engineering project cost-benefit analyses were initiated for the 11 potentially cost-beneficial SAMAs. Additional potentially cost-beneficial SAMAs that may emerge from further analyses in response to RAIs would be treated in the same manner.

6.1 .ii. (1) Of the 11 potentially cost-beneficial SAMAs, those that have the most cost-effective risk reduction potential are 30, 33, 68, and 79, based on their potential for significant risk reduction and relatively low implementation cost (cost estimate is less than 10% of the benefit with uncertainty).

SAMAs 14, 45, 75, and 78 would have second priority based on their potential for risk reduction and their mitigation of plant risk contributors not addressed by SAMAs 30, 33, 68, or 79.

(2) The benefit of the remaining potentially cost-beneficial SAMAs (25, 40, and 64) is expected to be reduced significantly if the higher priority SAMAs are implemented.

(3) As indicated in Item (2) above, the benefit of SAMAs 25, 40, and 64 is expected to be reduced significantly, although a reanalysis has not been performed that would establish that these SAMAs would be no longer cost-beneficial if the higher priority SAMAs were implemented. Regarding specific plans or commitments to implement the high priority SAMAs, refer to the response to 6.1.i.

above.

NRC Request: ENV-SAMA-7

7. For certain SAMAs considered in the ER, there may be lower-cost alternatives that could achieve much of the risk reduction at a lower cost. In this regard,discuss whether any lower-cost alternatives to those PhaseII SAMAs considered in the ER, would be viable andpotentially cost-beneficial. Evaluate the following SAMAs (previouslyfound to be

NLS2009048 Page 43 of 44 potentially cost-beneficial at otherplants), or indicate if the particularSAMA has already been considered. If the latter, indicate whether the SAMA has been implemented or has been determined to not be cost-beneficialat CNS:

a. Provide additionalspace cooling to the residualheat removal service water (RHRSW) boosterpump rooms, CS pump rooms, residualheat removalpump rooms, service water pump rooms, and HPCIpump room via the use ofportable equipment (in lieu of a redundant train of RHRSW boosterpump room ventilation consideredin SAMA 35).

b. Improve alternateshutdown trainingand equipment (in lieu of upgradingthe ASDS panel considered in SAMA 65). The intent of this alternative is to reduce the human errorprobabilityof requiredactions by improving trainingon operating the plantfrom outside the control room and improving communications equipment andplansfor coordinationamong local operators (see Brunswick Phase II SAMA 31).

c. Enhance dc power availability(providecablesfrom diesel generatorsor another source to directly power battery chargers).

d. Develop guidance/proceduresfor local, manual control of reactorcore isolation coolingfollowing loss of dc power.

e. Manual venting of containment using either a local hand wheel or gas bottle supplies (consideredfor Nine Mile Point Unit 1) as a possible alternativefor containmentpressurecontrol.

NPPD Response:

As described in ER Section E.2. 1, the Phase I list of SAMA candidates included those presented in NEI 05-01, those evaluated by other BWRs, those identified in the CNS Individual Plant Evaluation (IPE) and IPEEE, and those postulated to address risk-significant terms in the current CNS PSA model. Thus, a comprehensive effort was made to identify lower-cost alternatives to those Phase II SAMAs considered in the ER. However, many lower-cost alternatives have already been implemented at CNS and therefore, were not included in the Phase II cost-benefit analysis.

7.a. NPPD has implemented several lower-cost alternatives to provide additional space cooling to the CS pump rooms, RHR pump rooms, RHRSW booster pump room, SW pump room, and HPCI pump room, should the normal ventilation system fail. The specific actions vary depending on the particular room, but include managing heat loads, removing equipment hatches or plugs, opening doors, and using portable fans and ducting

NLS2009048 Page 44 of 44 as necessary to prevent damage to the equipment in the room. Therefore, the proposed SAMA has already been implemented at CNS.

7.b. Brunswick Phase II SAMA 31, to improve alternate shutdown training and communication equipment and plans for coordination among operators at local controls, was evaluated as Phase I SAMA 192. This SAMA has already been implemented at CNS because CNS has detailed procedures for alternate shutdown, which include use of communication equipment and coordination among operators. CNS operators are trained in these procedures.

7.c. Phase II SAMA 13 evaluated the use of a portable generator to supply DC power to the battery chargers. As indicated in the response to Question 6.g., NPPD has designed, installed and revised procedures to use a new diesel generator that can supply the swing battery charger during an SBO at CNS. Therefore, SAMA 13 has been implemented at CNS.

7.d. Phase I SAMA 79 was evaluated for developing guidance to allow local, manual control of RCIC operation. Since procedural guidance exists to allow local, manual control of RCIC operation, this SAMA has already been implemented at CNS.

7e. Phase I SAMAs 63 and 151 were evaluated to improve manual venting of containment.

Phase I SAMA 63 evaluated revising procedures to allow manual initiation of emergency depressurization. Phase I SAMA 151 evaluated enabling manual operation of containment vent valves via local controls. Both Phase I SAMAs 63 and 151 have already been implemented at CNS.

NLS2009048 Page 1 of 2 Attachment 2 Changes to the License Renewal Application Related to Environmental Report SAMA RAI Responses Cooper Nuclear Station, Docket No. 50-298, DPR-46 This attachment provides changes to the License Renewal Application based on the responses to the RAIs provided in Attachment 1. The changes are presented in underline/strikeout format.

I1. Section E.2.2 (Qualitative Screening of SAMA Candidates (Phase I) states:

"The purpose of the preliminary SAMA screening was to identify the subset of candidate SAMAs that would reduce severe accident risk at CNS and would therefore warrant a detailed cost-benefit evaluation. Potential SAMA candidates were screened out if they modified features not applicable to CNS, if they had already been implemented at CNS, or if they were similar in nature and could be combined with another SAMA candidate to develop a more comprehensive or plant-specific SAMA candidate. During this process, 49 of the Phase I SAMA candidates were screened out because they were not applicable to CNS, 24 of the Phase I SAMA candidates were screened out because they were similar in nature and could be combined with another SAMA candidate, and 91 of the Phase I SAMA candidates were screened out because they had already been implemented at CNS, leaving 80 SAMA candidates for further analysis. The final screening process involved identifying and eliminating those items whose implementation cost would exceed their benefit as described below. Table E.2-2 provides a description of each of the 80 Phase II SAMA candidates."

This paragraph is revised to read:

"The purpose of the preliminary SAMA screening was to identify the subset of candidate SAMAs that would reduce severe accident risk at CNS and would therefore warrant a detailed cost-benefit evaluation. Potential SAMA candidates were screened out if they modified features not applicable to CNS, if they had already been implemented at CNS, or if they were similar in nature and could be combined with another SAMA candidate to develop a more comprehensive or plant-specific SAMA candidate. During this process, 49 of the Phase I SAMA candidates were screened out because they were not applicable to CNS. Of these 49 SAMAs, three SAMAs (209, 227, and 229) had already been analyzed for CNS and were considered not applicable due to low benefit. Also, five SAMAs (217, 220, 221, 224, and 226) were seismic outliers that were resolved during the A-46 program. These SAMAs were included to show that IPEEE vintage improvements had been addressed. However, since the outliers have been resolved, the suggested improvements are no longer applicable to CNS. ,-24 Twenty-four of the Phase I SAMA candidates were screened out because they were similar in nature and could be combined

NLS2009048 Page 2 of 2 with another SAMA candidate, and 91 of the Phase I SAMA candidates were screened out because they had already been implemented at CNS, leaving 80 SAMA candidates for further analysis. The final screening process involved identifying and eliminating those items whose implementation cost would exceed their benefit as described below.

Table E.2-2 provides a description of each of the 80 Phase II SAMA candidates."

Reference:

Response to RAI ENV-SAMA-5.e.

2. Table E.2-2, Assumptions column for SAMA 6 on Page E.2-31 states:

"The time available to recover offsite power before HPCI and RCIC are lost was changed to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> during station blackout scenarios in the level IPSA model."

This is revised to read:

"The time available to reeover-offsite pawer befor-e HPCI and RCIC are lost was changed te 2* hurs dur.ing station blackouit scenarios in the level iPSA model. Failure to transfer the RPS panels to their alternate power source was set to zero in the level 1 PSA model."

Reference:

Response to RAI ENV-SAMA-6.c.

3. Tables E.2-2 and E.2-3, left most columns on Page E.2-49 and E.2-74, respectively, state:

"41- Modify procedure to provide ability to align diesel power to more air compressors."

This is revised to read:

"41-- Modify procedu-,,'re- to Provide ability to align diesel power to more air compressors."

Reference:

Response to RAI ENV-SAMA-6.e.