ML13039A200

Monticello, Enclosures 1 & 2 to L-MT-12-114 - Responses to the Gap Analysis and Marked Up Page Changes to EPU Documentation Based on the Gap Analysis Results, Part 1 of 3

ML13039A200
Person / Time
Site:	Monticello
Issue date:	01/21/2013
From:	Xcel Energy, Northern States Power Co
To:	Office of Nuclear Reactor Regulation
References
L-MT-12-114, TAC MD9990
Download: ML13039A200 (126)

Text

L-MT-12-114Enclosure 1ENCLOSURE 1RESPONSES TO THE GAP ANALYSISIntroductionOn November 20, 2012, Northern States Power -Minnesota (NSPM) presented to theNRC the results of a Gap Analysis performed to verify the adequacy of the extendedpower uprate (EPU) documentation. Due to the delay in review of the MonticelloNuclear Generating Plant (MNGP) EPU License Amendment Request (LAR), the NRCwas concerned that various aspects of the NRC review were no longer applicable.Through the Gap Analysis, NSPM demonstrated that various technical items requiredrevision and some design and licensing bases information had changed, but overall thebody of EPU documentation was correct with the exception of the issues identified forcorrection.As part of that discussion, NSPM provided the NRC with a table of items that hadchanged in the EPU documentation. This table was discussed and NRC provided theircomments on the documentation needed to close the items.This enclosure contains a brief synopsis of each item discussed in the Gap Analysis,the information the NRC needed to close the gap (from the November 20, 2012 meetingwith NRC), and the NSPM response to the identified gap.Page 1 of 80 L-MT-12-114Enclosure 1ContentsProvided below are responses to the following items from the Gap Analysis:Item 1 -Grid Stability AssessmentItem 2 -Battery Capacity ChangesItem 3 -Changes to Setpoint CalculationsItem 4 -Steam Dryer Noise Filtering and Noise ReductionItem 5 -Reactor Water Cleanup Impact on Reactor Water QualityItem 6 -Noble Metals ModificationItem 7 -Unnecessary Abnormal Operating Procedure (AOP) ChangeItem 8 -Emergency Core Cooling System (ECCS) Pump Flow RatesItem 9 -Residual Heat Removal and Core Spray Pump Rooms Post-Loss ofCoolant Accident (LOCA) HeatupItem 10 -Final Feedwater Temperature ChangeItem 11 -Piping Components Requiring Further AnalysisItem 12 -Technical Support Center (TSC) Dose CalculationItem 13 -Risk AssessmentItem 14 -Computer Code ChangesItem 15 -Turbine Bypass Valve CapacityItem 16 -Reactor Head Spray Nozzle Fatigue AssessmentItem 17 -Emergency Operating Procedure Flow Chart for ATWSItem 18 -Main Steam Line ThermowellsItem 19 -EPU Modifications List ChangesItem 20 -Annulus Pressure (AP) LoadsItem 21 -Emergency Core Cooling System (ECCS) Analysis ConfirmationItem 22 -Confirmation that Oscillation Power Range Monitor (OPRM) Testing isCompletedItem 23 -Fatigue Monitoring ProgramItem 24 -Motor Operated Valve (MOV) Program ChangesItem 25 -Shroud Screening Criteria Flaw Evaluation and Recirculation Line Break(RLB) LoadsItem 26 -High Energy Line Break (HELB) Analysis ReconstitutionItem 27 -Equipment Qualification Program ReconstitutionItem 28 -Effects of Loss of Stator Water Cooling AnalysisPage 2 of 80 L-MT-12-114Enclosure 1ITEM I -GRID STABILITY ASSESSMENTNRC REQUESTED INFORMATION: Change MNGP substation figure to show new gridconnections. Send the figure and identify that Midwest Independent System Operator(MISO) has reconfirmed their original study is satisfactory based on CAPX2020. NRCwould like to see the MISO letter. State the effect on grid stability. Include results oflatest stability review -just reference the consultant's review.NSPM RESPONSE:Since submittal of the original stability study in L-MT-08-052 (Reference 1-1), Enclosure14, an additional 345 KV line has been added to the MNGP substation which increasedthe number of transmission lines from 5 to 6 connecting to this substation. Thisincluded an upgrade of the 345 KV bus from a ring bus to a breaker-and-one-halfsystem (USAR Section 8.2.1).The power increase related to the EPU project was originally planned in two phases in2009 and 2011. EPU is currently planned to be implemented following the 2013 outage.Midwest Independent Transmission System Operator, Inc. (MISO) has approved the fullpower increase in a signed Interconnection Agreement (IA) as executed in MISOProjects (G725 13MWe and G929 60.8MWe) on October 6, 2009.The Large Generator Interconnection Agreement (LGIA) did not identify the need forany additional interconnection, or system protection facilities, or require any distribution,generator, or network upgrades.On February 22, 2011, Xcel notified MISO ISO that the Commercial Operation Date(COD) for Monticello Projects G725 and G929 has been extended from May, 2011 toAugust 2013. This change notification was not considered a material change inaccordance with Midwest ISO electric tariff and a LGIA restudy was not required.The evaluation, analysis, and IA in support of the MISO upgrades are documented inthe following approved engineering evaluations:By email dated September 24, 2012 from Vikram Godbole of MISO to variousindividuals, MISO reported the results of a restudy evaluation of projects with permanentGenerator Interconnection Agreements (GIAs). The study included:1. Stability Analysis2. Network Resource Interconnection Service (NRIS) analysis3. Project summary results.The MNGP EPU is covered by GIA G929. No adverse impacts were identified for thisstudy.See Enclosure 2 for a markup of L-MT-08-052, Enclosure 14 reflecting these changes.Page 3 of 80 L-MT-12-114Enclosure 1See Enclosure 3 for latest version of NH-1 78635 -USAR Section 15 figure and theemail from Vikram Godbole of MISO.References1-1 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "LicenseAmendment Request: Extended Power Uprate (TAC MD9990)," L-MT-08-052,dated November 5, 2008. (ADAMS Accession No. ML091410120)Page 4 of 80 L-MT-12-114Enclosure 1ITEM 2 -BATTERY CAPACITY CHANGESNRC REQUESTED INFORMATION: Ongoing plant changes to battery loadingincluding finalization of 13.8 KV design has changed the battery capacity values.Update battery load final margin results to NRC. Include a discussion about anychanges to safety related (SR) loads such as emergency diesel generator (EDG).Identify which loads have changed and why, confirm that aging margin and temperaturefactors are included.NSPM RESPONSE:NSPM letters L-MT-08-039 and L-MT-09-043 (References 2-1 and 2-2) providedpreliminary information regarding MNGP battery capacity and loading based on theplanned changes associated with EPU. NSPM is providing final MNGP battery capacityvalues and analyses based on operation at EPU conditions.Load changes within the Safety Related Direct Current (DC) Onsite Power Systemremain bounded by the capacity of the existing station batteries. Cell sizing evaluationsfor revised system configurations confirm positive capacity margin remains for theanalyzed scenarios following implementation of plant changes during the EPU outage.The final cell sizing margin for the safety related batteries is summarized in Table 2-1below.Table 2-1 Final Battery Cell Sizing MarginsEssential Battery CLTP EPUCapacity Margin Capacity Margin125 VDC Division I 15.83% 9.29%250 VDC Division I 23.63% 20.64%125 VDC Division II 26.58% 8.11%250 VDC Division II 2.04% 22.81%Cell sizing evaluations performed for post-EPU conditions do not modify Aging Factorsor Temperature Correction Factors used in the Current Licensed Thermal Power(CLTP) analyses. For Safety Related 125 VDC and 250 VDC station batteries, theminimum electrolyte temperature is taken as 60F and a corresponding 1.11Temperature Correction Factor is used following the guidance of IEEE Std. 485-1997,"IEEE Recommended Practice for Sizing Lead-Acid Batteries for StationaryApplications." A 1.11 Aging Factor is used corresponding to 90% manufacturer's ratedcapacity in agreement with the acceptance criterion of Monticello TechnicalSpecifications Surveillance Requirement SR 3.8.6.6.No Safety Related 250 VDC load changes were implemented under EPU, although theHigh Pressure Coolant Injection (HPCI) Station Blackout (SBO) operating sequencewas revised (Reference 2-3, Enclosure 5, Sections 2.3.4 and 2.3.5) for EPU conditions.Page 5 of 80 L-MT-12-114Enclosure 1Improvements in 250 VDC Division II battery margin are not due to EPU changes, butrather load timing changes implemented under a separate battery capacity marginmanagement modification. Minor load changes were incorporated in the Safety Related125 VDC calculations for new equipment associated with the replacement GeneratorStep Up transformer, replacement 1 R transformer, replacement 2R transformer, MainGenerator Rewind and the new 13.8 kV non-safety related switchgear.NRC REQUESTED INFORMATION: Staff requests a detailed discussion of thechanges to electrical equipment loading and capacities since the last submittal,including emergency diesel generators.NSPM RESPONSE:Modifications to the 1 R and 2R offsite power transformers were in the conceptual stagewhen Reference 2-1 was submitted to the NRC. These designs have been finalizedwith new equipment ratings listed below. As discussed in Reference 2-1, the existingnon-safety related #11 and #12 buses will be replaced with new buses rated foroperation at 13.8kV. Table 2-2 identifies the new AC electrical equipment provided forEPU. Table 2-2 also includes the new motor loads operating on the new buses.Table 2 -2 EPU Replaced Equipment Ratings ComparisonEquipment CLTP EPURating Rating1 R Transformer 22.400/29.867/37.333 MVA 40.5/54 MVAOA/FA/FA @ 65C Rise ONAN/ONAF @ 65C Rise115kV-4.16kV-4.16kV 115kV-13.8kV-4.16kV2R Transformer 56 MVA 40.5/54 MVAFOA @ 65C Rise ONAN/ONAF @ 65C Rise34.5kV-4.16kV-4.16kV 34.5kV-13.8kV-4.16kVNon-Safety Related 2000 A Continuous 2000 A ContinuousSwitchgear #11 4.76 kV 15 kVNon-Safety Related 2000 A Continuous 2000 A ContinuousSwitchgear #12 4.76 kV 15 kVFeedwater Pump 6000 HP 8000 HP#11 and #12 4000 V 13200 VCondensate Pump 1750 HP 2400 HP#11 and #12 4000 V 13200 VReactor Recirculation MG 4000 HP 4000 HPSet Drive Motor 4000 V 13200 V#11 and #12Page 6 of 80 L-MT-12-114Enclosure 1Table 2-3 provides a comparison of the full steady state and largest accident loading.Table 2-3 AC Electrical Loading for Steady State and Accident ConditionsLoading Condition Steady State Loading Percent of 1R or 2R EPUEPU Conditions Transformer ONAF* RatingFull Plant Load 36.9 MVA 68.3%LOCA Load 39.1 MVA 72.4%*ONAF is the ANSI/lEE Standard C57.12.00 defined 4 digit code describing the coolingattributes of a transformer.There are no EPU changes to the ratings for safety-related loads. No increase in flowor pressure is required for any AC-powered Emergency Core Cooling System (ECCS)equipment for EPU. The EDG design basis loading is not affected by EPU (Reference2-3, Enclosure 5, Section 2.3.3.)See Enclosure 2 for a markup of L-MT-08-039 and L-MT-08-043 reflecting thediscussed changes.References2-1 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "MonticelloExtended Power Uprate (USNRC TAC MD8398): Acceptance ReviewSupplemental Information," L-MT-08-039, dated May 28, 2008. (ADAMSAccession No. ML081490639)2-2 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "MonticelloExtended Power Uprate (USNRC TAC MD8398): Acceptance ReviewSupplemental Information Package 6," L-MT-08-043, dated June 12, 2008.(ADAMS Accession No. ML081640435)2-3 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "LicenseAmendment Request: Extended Power Uprate (TAC MD9990)," L-MT-08-052,dated November 5, 2008. (ADAMS Accession No. ML091410120)Page 7 of 80 L-MT-12-114Enclosure 1ITEM 3 -CHANGES TO SETPOINT CALCULATIONSNRC REQUESTED INFORMATION: Calculations provided to the NRC have changed.Briefly discuss previously provided calculations that have changed.. Describe thechanges and conclusion that there are no technical changes. Specifically state that thevalues computed in the calculations and reported to NRC did not change.NSPM RESPONSE:NSPM letter L-MT-09-026 (Reference 3-1), Enclosure 1, provided a response to NRCRAI EICB RAI No. 1. In this response NSPM provided the following calculations:CA-95-073 R4 -Reactor low water level Scram setpointCA-95-075 R1 -MSL High flow trip setpointCA-96-054 R5 -Turbine Stop Valve Closure/Generator Load Reject Scram BypassNSPM's response to EICB RAI No. 1 in L-MT-09-026 indicates that the calculationrevisions were performed to "support recent plant modifications and to improve thequality of the calculation by adding more detail... These revisions have not changed theEPU values shown in Table 2.4-1." Note: Table 2.4-1 is a reference to the original EPULAR analysis provided in L-MT-08-052 (Reference 3-2), Enclosure 5. Thesecalculations were provided as part of the process of documenting changes to MNGPoperating parameters resulting from changes from CLTP operation to EPU operations.These calculations were revised after Reference 3-1 was submitted to the NRC.However, there were no changes to the EPU values reported in Reference 3-1. Onlyadministrative changes to the calculations have occurred. These administrativechanges do not change or affect any setpoint values previously reported to the NRC.There are no proposed changes to EPU documentation resulting from this response.References3-1 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "MonticelloExtended Power Uprate: Response to NRC Instrumentation & Controls BranchRequest for Additional Information (RAI dated March 11, 2009, and April 6, 2009,and Fire Protection Branch RAIs dated March 12, 2009 (TAC No. MD9990)," L-MT-09-026, dated May 13, 2009. (ADAMS Accession No. ML0832301 11)3-2 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "LicenseAmendment Request: Extended Power Uprate (TAC MD9990)," L-MT-08-052,dated November 5, 2008. (ADAMS Accession No. ML091410120)Page 8 of 80 L-MT-12-114Enclosure 1ITEM 4 -STEAM DRYER NOISE FILTERING AND NOISE REDUCTIONNRC REQUESTED INFORMATION: Specific submittals contain information that hasbeen superseded by the Replacement Steam Dryer (RSD). Update to supersedeoutdated information.NSPM RESPONSE:In letter L-MT-09-043 (Reference 4-1) in response to NRC RAI EMCB-SD RAI No. 5,NSPM provided information to the NRC discussing the noise reduction techniques thatwere applied to the steam dryer data collected in support of qualification of the MNGPsteam dryer at EPU conditions. Subsequently, NSPM replaced the original MNGPsteam dryer with a replacement steam dryer. Therefore, the information provided inresponse to EMCB-SD RAI No. 5 is no longer applicable to the MNGP EPU LAR. Thisinformation has now been superseded by information provided in L-MT-12-056(Reference 4-2), Enclosure 2.In letter L-MT-09-043 (Reference 4-1) in response to NRC RAIs EMCB-SD RAI No. 6and No. 7, NSPM provided information to the NRC discussing the noise filteringtechniques that were applied to the steam dryer data collected in support of qualificationof the MNGP steam dryer at EPU conditions. Subsequently, NSPM replaced theoriginal MNGP steam dryer with a replacement steam dryer. Therefore, the informationprovided in response to EMCB-SD RAIs No. 6 and No. 7 is no longer applicable to theMNGP EPU LAR. This information has now been superseded by information providedin L-MT-12-056 (Reference 4-2), Enclosure 2.See Enclosure 2 for a markup of the RAI responses reflecting these changes.References4-1 Letter from T J O'Connor (NSPM) to Document Control Desk (NRC), "MonticelloExtended Power Uprate: Response to NRC Mechanical and Civil EngineeringReview Branch(EMCB) Requests for Additional Information (RAIs) dated March20, 2009, and June 26, 2009 (TAC No. MD9990)," L-MT-09-043, dated August12, 2009. (ADAMS Accession No. ML092260436)4-2 Letter from M A Schimmel (NSPM) to Document Control Desk (NRC), "MonticelloExtended Power Uprate: Replacement Steam Dryer -Second Set of Responsesto Requests for Additional Information (TAC MD9990)," L-MT-12-056, dated July19, 2012. (ADAMS Accession No. ML12207A541)Page 9 of 80 L-MT-12-114Enclosure 1ITEM 5 -REACTOR WATER CLEANUP IMPACT ON REACTOR WATER QUALITYNRC REQUESTED INFORMATION: MNGP did not take any credit for increasingReactor Water Cleanup (RWCU) capacity for assessment of impact on water quality. Amodification has been completed to maintain RWCU flow capacity as a constantpercent of feedwater (FW) flow. Summarize the changes in the analysis anddemonstrate that what was submitted is conservative or the change is negligible.NSPM RESPONSE:Current EPU DocumentationIn L-MT-08-052 (Reference 5-1), NSPM assessed impact on reactor water qualitybased on the installed RWCU pump capacity in 2008. This is demonstrated by thefollowing from L-MT-08-052, Enclosure 5, Section 2.1.7:"RWCU flow is usually selected to be in the range of 0. 8% to 1.0% of FW flow basedon operational history. The existing RWCU flow slightly exceeds this range (1.08%of FW flow). The RWCU flow analyzed for EPU is within this range... "The remaining portion of Section 2.1.7 demonstrated the adequacy of the proposedRWCU flow reduction impact on typical reactor water iron and conductivity changes.Previous operating experience had shown that the FW iron input to the reactorincreases for EPU as a result of the increased FW flow. It was anticipated to raise thetypical reactor water iron concentration from < 1.7 ppb to < 2.0 ppb. However, thischange was considered insignificant, and did not affect RWCU performance.The effects of EPU on the RWCU system functional capability was reviewed, and thesystem can perform adequately at EPU rated thermal power (RTP) with the originalreduced RWCU system flow. Using the original RWCU system flow at EPU RTP resultsin a slight increase in the calculated reactor water conductivity (from 0.1 pS/cm to 0.115pS/cm) because of the increase in FW flow. The current reactor water conductivitylimits are unchanged for EPU and the actual conductivity remains within these limits.Reference 5-1, Enclosure 5, also states,"Table 2.1-4 indicates that the changes in RWCU system operating conditions aresmall and are acceptable. The system flow rate is unchanged. ..Revision to EPU DocumentationA modification has been developed to maintain- RWCU flow capacity as a constantpercent of FW flow. The RWCU System parameters shown in the L-MT-08-052,Enclosure 5, Table 2.1-4 will change as a result of the modification that increasedRWCU flow rate from 160 gpm nominal to 180 gpm nominal. The increased flowthrough the RWCU system represents less than a 0.001% change in both the ReactorRecirculation System and FW systems. This flow rate increase is considered to have anegligible effect on each system for temperature, enthalpy, and flow rate considerationsPage 10 of 80 L-MT-12-114Enclosure 1for interfacing systems. The changes to Table 2.1-4 (provided in Enclosure 2) alsoinclude changes due to the as-built determination that feedwater temperature is about50F higher than shown on the original heat balance shown in L-MT-08-052, Enclosure 5,Figure 1-2. See item 10 for more details regarding final feedwater temperaturechanges.In addition, the values shown in the L-MT-08-052, Enclosure 5, Table 2.1-5 were alsobased on an assumed 15% reduction in RWCU capacity as compared to feedwater flowrate (the 2008 pump capacity). Since the RWCU system has been upgraded to allow aflow increase from 160 gpm to 180 gpm, (12.5% increase), the system capacity ascompared to FW flow returns to the original system specification requirement,equivalent to 1% of the feedwater flow rate.This capacity increase reduces the estimated EPU values shown for conductivity andiron for EPU in the L-MT-08-052, Enclosure 5, Table 2.1-5. The increase in system flowcapacity returns the Estimated EPU Value to values comparable to the CLTP values.Similarly, the Projected EPU Margin indicated on L-MT-08-052, Enclosure 5, Table 2.1-5 will increase.The L-MT-08-052, Enclosure 5, Table 2.1-5 values were not recalculated and remainconservative with respect to actual operating conditions and the OperatingGuideline/Limit provided in the table. No changes to L-MT-08-052, Enclosure 5, Table2.1-5 are provided.See Enclosure 2 for a markup of the L-MT-08-052, Enclosure 5, Section 2.1.7, includingTable 2.1-4, reflecting these changes.References5-1 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "LicenseAmendment Request: Extended Power Uprate (TAC MD9990)," L-MT-08-052,dated November 5, 2008. (ADAMS Accession No. ML091410120)Page 11 of 80 L-MT-12-114Enclosure 1ITEM 6 -NOBLE METALS MODIFICATIONNRC REQUESTED INFORMATION: Dose rates for steam areas discussed in the EPULAR are based on use of Hydrogen Water Chemistry (HWC). NRC noted that in thedraft Safety Evaluation (SE) no mention is made of HWC, but it needs to. NRC wouldlike to change the SE in this area and qualitatively update to include Noble chemistrychanges that NSPM discussed. Discuss changing solubility of hydrogen (H2) effect on40CFR190 at EPU conditions that results in increased dose. This should be discussedindependently of Noble chemistry.NSPM RESPONSE:NSPM is planning to install a NobleChem modification at the MNGP in mid-2013. Theuse of noble metal chemistry will allow a reduction in H2 use while maintaining the abilityto mitigate the potential for intergranular stress corrosion cracking (IGSCC) andirradiation assisted stress corrosion cracking (IASCC). The NobleChem modification isnot currently installed; therefore, the EPU dose analyses provided in the EPUdocumentation remain valid. The following evaluation supports the premise thatassessments performed in the EPU documentation are conservative and still boundingonce NobleChem is installed.Dose rates for steam areas discussed in the EPU LAR are based on use of HydrogenWater Chemistry (HWC). L-MT-08-052 (Reference 6-1), Enclosure 5, Section 2.1.4,Reactor Coolant Pressure Boundary Materials, states that "to mitigate the potential forIGSCC and IASCC, Monticello utilizes hydrogen water chemistry."For the assumed HWC regime, the gas injection rates for H2 and oxygen (02) wouldincrease proportionally with power level to maintain dissolved gas concentrationsconstant. System capacity would support the required flow increase with H2 flow rateincreasing from 36 scfm at 1775 MWt to 41 scfm at 2004 MWt.L-MT-08-052, Enclosure 5, Section 2.10.1, Normal Operational Radiation Levels,provides a discussion on dose impact for operation at EPU conditions assuming fullHWC injection (without NobleChem). This discussion was augmented by RAIresponses provided in NSPM letter L-MT-09-042 (Reference 6-2). Each of theresponses in Reference 6-2 had some relevance to EPU doses resulting from use ofHWC.H2 injection rates for use of HWC result in operation with a normal feedwater H2concentration of approximately 1.6 ppm. Under NobleChem the H2 concentration willbe reduced to a normal range of 0.25 ppm to 0.40 ppm. This equates to a H2 injectionrate of approximately 8 scfm. Reducing the H2 concentration will reduce the steam lineradiation levels due to a reduction in the amount of nitrogen-16 (N-16) being removedfrom the reactor. Typical radiation level changes are indicated by the Main Steam LineRadiation Monitor (MSLRM). MSLRM data correlated to H2 concentration is shown inTable 6-1 for various HWC injection rates.Page 12 of 80 L-MT-12-114Enclosure 1Table 6-1 Dose Rates vs HWC Injection RatesReactor HWC "A"Power Injection MSLRM FW H2(MWt) Rate (scfm) (mr/hr) (pp) Date/Time1763 0.0 499 0.00 3/29/12 0900 -11001774 8.0 517 0.34 8/8/12 1510- 16001774 18.9 1725 0.80 1/29/12 0700 -11001774 37.1 2584 1.58 11/28/12 0100 -0200The expected radiation level under NobleChem is approximately 517 mr/hr based on anestimated 8 cfm H2 injection rate yielding a 0.34 ppm hydrogen concentration (between0.25 and 0.40 ppm). This is 20% of the normal value of 2584 mr/hr with a feedwaterhydrogen concentration of 1.58 ppm typical of operation with HWC at CLTP conditions.This indicates that NobleChem will reduce radiation from N-16 by a factor ofapproximately 5.This factor of 5 reduction can be used to provide a rule of thumb impact on dose rates.Once NobleChem is implemented the dose reductions will impact the responsesprovided in L-MT-09-042 NRC RAI No. la, lb and 2a by reducing the dose rates by afactor of 5.Reference 6-1, Enclosure 5, Section 2.10.1, stated for off-site doses that the maximumdose rates at plant boundaries are expected to remain below the 10 CFR 20.1302maximum dose rate of 2 mrem/hr. Addition of NobleChem would not affect thisconclusion and, as demonstrated above, would reduce the off-site maximum dose rate.Since the NobleChem modification is not currently installed, the EPU analyses providedin L-MT-08-052, Enclosure 5, and L-MT-09-042 are still correct and provide boundingresults. The purpose of this evaluation is to indicate that these dose estimates will bevery conservative when NobleChem transition is completed for MNGP.40 CFR 190 AssessmentThe response to Reference 6-2, Enclosure 1, RAI No. 2(b) covers the impact on 40CFR 190. The expected dose related to sky shine was stated in Reference 6-1 as lessthan 6 mrem/yr for Monticello. These results were subsequently corrected by latercorrespondence provided in L-MT-09-042 (Reference 6-2), Enclosure 1, RAI No. 2(b) to10 mrem/yr. These results remain conservative as these values would also be reducedby the impact of NobleChem as discussed below.In Reference 6-2, Enclosure 1, RAI No. 2(b) the impact of sky shine was estimated bycomparing the maximum difference between inner and outer ring thermoluminescentdetector (TLD) locations provided in Table 1A and scaling this factor by an estimatedPage 13 of 80 L-MT-12-114Enclosure 1increase in worst case sky shine of 34.4%. The maximum contribution from sky shinewas predicted to be 9.1 mrem/yr.Reference 6-2, Enclosure 1, RAI No. 2(b) Table 1A has been updated to provide dataup to 2012. The new data does not change the previous results. Applying the impact ofNobleChem would reduce the 9.1 mrem/yr predicted sky shine dose by a factor of up to5 (i.e. reducing the resultant sky shine dose rate to approximately 1.9 mrem/yr).Other ChangesDuring this review NSPM identified that additional data could be added to update theNRC with the latest available data regarding dose rates recorded at MNGP and at theInner and Outer Ring locations. Enclosure 2 contains updates to Tables 1, 1A(discussed above) and 2 as presented in L-MT-09-042 (Reference 6-2) NRC RAI No.2(b) to include available data after 2006.Reference 6-2, Enclosure 1, RAI No. 2(b) Table 1, has been updated to provide data upto 2012. The average dose per year has not increased with the additional data,therefore, the conclusions made from this data has not changed.Reference 6-2, Enclosure 1, RAI No. 2(b) Table 2 was updated to provide available dataup to 2011. The average dose per year with the additional data is still well below the 10CFR 50 Appendix I and 10 CFR 20 limits, therefore, the conclusions made from thisdata has not changed.See Enclosure 2 for a markup of the L-MT-09-042, NRC RAI No. 2(b), reflecting all thechanges discussed in this section.References6-1 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "LicenseAmendment Request: Extended Power Uprate (TAC MD9990)," L-MT-08-052,dated November 5, 2008. (ADAMS Accession No. ML091410120)6-2 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC),"Monticello Extended Power Uprate: Response to NRC Reactor InspectionBranch Request for Additional Information (RAI) dated March 20, 2009 (TACNo. MD9990)," L-MT-09-042, dated June 16, 2009. (ADAMS Accession No.ML091671787)Page 14 of 80 L-MT-12-114Enclosure 1ITEM 7 -UNNECESSARY ABNORMAL OPERATING PROCEDURE (AOP) CHANGENRC REQUESTED INFORMATION: Turbine Backpressure limit in AOPs wasindicated as a planned change. Update to remove reference to changing AOP. Providea brief basis for change from L-MT-08-052, Enclosure 5.NSPM RESPONSE:L-MT-08-052 (Reference 7-1), Enclosure 5, Section 2.11.1, stated:"The following are the AOP procedural changes:* Turbine backpressure limits have changed as a result of modifications to thelow-pressure turbines. These requirements will be incorporated into theDecreasing Condenser Vacuum AOP. The new turbine backpressure limitsare slightly less restrictive at full EPU conditions, are slightly more restrictiveat intermediate power conditions and are unchanged at low powerconditions."After completion of the low-pressure turbine design, the turbine backpressure limitswere changed such that no significant change in required trip margins existed. It wastherefore determined that no change was warranted and this change will not be made.See Enclosure 2 for a markup of the L-MT-08-052, Enclosure 5, Section 2.11.1reflecting this change.References7-1 Letter from T J O'Connor (NSPM) to Document Control Desk (NRC), "MonticelloExtended Power Uprate: Updates to Docketed Information (TAC MD9990)," L-MT-10-072, dated December 21, 2010. (ADAMS Accession No. MLI103570026)Page 15 of 80 L-MT-12-114Enclosure 1ITEM 8 -EMERGENCY CORE COOLING SYSTEM (ECCS) PUMP FLOW RATESNRC REQUESTED INFORMATION: Pump flow rate assumptions used in the netpositive suction head required (NPSHr) analysis changed as a result of the resolution ofthe Containment Accident Pressure (CAP) issue. Update EPU documentation toindicate that RAI responses contain information that should be superseded.NSPM RESPONSE:In letters L-MT-09-048 and L-MT-09-073 (References 8-1 and 8-2) NSPM providedresponses to NRC RAIs concerning ECCS pump flow rates crediting the use of CAP.Subsequently in letters L-MT-12-082 and L-MT-1 2-107 (References 8-3 and 8-4),NSPM provided revised analyses for ECCS pump flow rates crediting the use of CAP,while applying the guidance of SECY 11-0014. These revised analyses supersedeportions of the responses provided in Reference 8-1 and 8-2.See Enclosure 2 for markups to L-MT-09-048, RAIs 12 and 29; and markups to L-MT-09-073 RAIs 5 and 6, based on the revised analyses provided in L-MT-12-082 and L-MT-12-107.References8-1 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "MonticelloExtended Power Uprate: Response to NRC Containment and VentilationReview Branch (SCVB) Request for Additional Information (RAI) dated March19, 2009, and March 26,2009 (TAC No. MD9990) ", L-MT-09-048, dated July13, 2009. (ADAMS Accession No. ML092170404)8-2 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "MonticelloExtended Power Uprate: Response to NRC Containment and Ventilation ReviewBranch (SCVB) Requests for Additional Information (RAIs) dated July 2, 2009and July 14, 2009(TAC MD9990)," L-MT-09-073, dated August 21, 2009.(ADAMS Accession No. ML092430088)8-3 Letter from M A Schimmel (NSPM) to Document Control Desk (NRC), "MonticelloExtended Power Uprate and Maximum Extended Load Line Limit Analysis PlusLicense Amendment Requests: Supplement to Address SECY 11-0014 Use ofContainment Accident Pressure (TAC Nos. MD9990 and ME3145) (TACMD9990)," L-MT-12-082, dated September 28, 2012. (ADAMS Accession No.ML12276A057)Page 16 of 80 L-MT-12-114Enclosure 18-4 Letter from M A Schimmel (NSPM) to Document Control Desk (NRC), "MonticelloExtended Power Uprate and Maximum Extended Load Line Limit Analysis PlusLicense Amendment Requests: Supplement to Address SECY 11-0014 Use ofContainment Accident Pressure, Sections 6.6.4 and 6.6.7 (TAC Nos. MD9990and ME3145) (TAC MD9990)," L-MT-12-107, dated November 30, 2012.(ADAMS Accession No. ML12276A057)Page 17 of 80 L-MT-12-114Enclosure 1ITEM 9 -RESIDUAL HEAT REMOVAL AND CORE SPRAY PUMP ROOMS POST-LOSS OF COOLANT ACCIDENT (LOCA) HEATUPNRC REQUESTED INFORMATION: Original responses were based on engineeringjudgment and said that building heatup would be -< 1.80F. Formal calculations exist nowthat have changed the value. Summarize changes in reactor building (RB) heatupcalculation and include why they were needed and why they are conservative. Confirmthat method is the same and indicate why change has occurred. Indicate whether pipesupport modifications will be necessary. Indicate that GOTHIC was used and whatversion. State that there is no change in methodology.NSPM RESPONSE:NSPM reported in letters L-MT-08-052 (Reference 9-1), Enclosure 5, Section 2.7.5 andL-MT-09-048 (Reference 9-2), NRC (SCVB) RAI No. 34 that the Residual HeatRemoval (RHR) and Core Spray (CS) pump room temperatures would change basedon EPU conditions. Specifically, NSPM reported that the RHR and CS pump roomtemperatures were determined to increase up to 1.80F following a LOCA at EPUconditions. This 1.80F increase was determined using engineering judgment based onheat load increases in the rooms.Subsequently, a formal calculation for the building heatup resulting from the LOCAscenario at EPU conditions has been finalized. This calculation concluded that anincrease of 2.9°F for RHR and CS pump room temperatures would occur following aLOCA at EPU conditions.GOTHIC 7.2a was used for the modeling software which in combination with enhancedReactor Building conductors, volumes, and surface areas updated for EPU, provides amore accurate analysis of the LOCA event than previous modeling versions. Nomethodology changes were made. The 2.90F temperature increase for the RHR andCS pump rooms has been evaluated and determined to be acceptable. Nomodifications in the RHR and CS pump rooms are required due to the higher LOCAtemperatures at EPU conditions.See Enclosure 2 for a markup of the EPU documentation reflecting these changes.References9-1 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "LicenseAmendment Request: Extended Power Uprate (TAC MD9990)," L-MT-08-052,dated November 5, 2008. (ADAMS Accession No. ML091410120)Page 18 of 80 L-MT-12-114Enclosure 19-2 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "MonticelloExtended Power Uprate: Response to NRC Containment and VentilationReview Branch (SCVB) Request for Additional Information (RAI) dated March19, 2009, and March 26,2009 (TAC No. MD9990)", L-MT-09-048, dated July13, 2009. (ADAMS Accession No. ML092170404)Page 19 of 80 L-MT-12-114Enclosure 1ITEM 10 -FINAL FEEDWATER TEMPERATURE CHANGENRC REQUESTED INFORMATION: Change in final as-built feedwater temperature.Temperature change for full EPU conditions is approximately 50F higher than originallyanalyzed. This affects the feedwater (FW) piping design limit. NSPM needs to describehow this change has been assessed. Provide more information from GE on how it wasevaluated. Indicate what events/transients have been looked at (including other non-limiting reload events such as Loss of FW heating). Indicate that the containmentresponse remains bounding. Need to demonstrate how we came to conclusion that it isnegligible.NSPM RESPONSE:Following the 2011 Refueling Outage, the newly installed feedwater (FW) heaterperformance exceeded expectations with a higher than predicted FW temperatureexiting the 15A and 15B heaters. The issue was entered into and evaluated in theMNGP corrective action program.NSPM evaluated the increased FW temperature impact on design bases accident -lossof coolant accident (DBA-LOCA) and the high energy line break (HELB) analysesperformed for the EPU project.A feedwater temperature of 400.80F was used to develop revised reactor heat balancesto account for EPU power level, MELLLA+ flow rate, and using an extrapolation fromCLTP power level. From this effort, revised EPU and MELLLA+ heat balances wereobtained. For piping analysis purposes, 402.80F was used for conservatism.Consideration for Transient AnalysisGEH performed a study and determined that the impact of the FW temperature changeon anticipated operational occurrences (AOOs) was negligible. GEH further concludedthat sufficient margin remains in the peak dome pressure safety limit and ASME upsetcondition limit when accounting for this small FW temperature change.Consideration of DBA-LOCA Containment Response:The incremental heat added to containment as a result of the FW temperature changewas determined to be less than 0.97 MBTU, which is conservative for both the short-term and long-term DBA-LOCA analyses. This was compared to the conservativelydetermined total FW input plus the metallic heat BTU of approximately 55.5 MBTU. TheFW enthalpy delta was determined to be insignificant. There was sufficientconservatism (approximately 8 MBTU) identified in the analysis to account for the smallchange in FW temperature.This evaluation demonstrates that the assumed heat added to containment (as a resultof the incremental change in FW temperature) is significantly bounded by the analysisof record. Therefore, the impact of having a slightly higher feedwater temperature isbounded by the assumptions and conservatisms used in the analysis.Page 20 of 80 L-MT-12-114Enclosure 1Considerations for HELB:The systems communicating with the feedwater piping were evaluated for potentialHELB impacts of this increased feedwater temperature. FW HELB breaks were notimpacted significantly since the temperature change is small when compared to thelarge volume of relatively cold water drawn from the condenser. The evaluationdetermined that three FW HELB cracks were impacted and one Reactor Water Cleanup(RWCU) break was impacted.The three cracks releasing FW are of sufficient duration (> 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />) that the increase intemperature/enthalpy does have some impact on volume temperatures. The RWCUbreak impacted the evaluation of a RWCU HELB in the Steam Chase. These changeshave been included in related calculations in order to provide configuration and designcontrol. Further discussion concerning final HELB analysis results are provided in Item26.ConclusionsAnalyses to account for change in FW temperature have been performed thatdemonstrate that changes do occur in certain HELB results. However, the revised FWtemperature had only minor impact on Reactor Building maximum temperatures,pressures, or flood levels. The changes to HELB profiles resulting from the finalfeedwater temperature changes are included in the response to Item 26.Some of the Environmental Qualification (EQ) temperature profiles durations arealtered, and this documentation is currently being revised to incorporate this change.See item 27 for further discussion concerning EQ changes.There are no proposed changes to EPU documentation resulting from this response.Page 21 of 80 L-MT-12-114Enclosure 1ITEM 11 -PIPING COMPONENTS REQUIRING FURTHER ANALYSISNRC REQUESTED INFORMATION: L-MT-08-052, Enclosure 5, Table 2.2-2d indicatedsix areas where further piping analysis was required. The analyses for these six areasare completed. Provide a complete summary of the feedwater (FW) piping evaluationcompleted. Demonstrate that results are within code allowables. Look at discussion inL-MT-09-044 and L-MT-1 1-044 and confirm these results. Provide pipe support stresstables similar to L-MT-09-044, Enclosure 1, pgs 27 and 28.NSPM RESPONSE:NSPM letter L-MT-08-052 (Reference 11-1), Enclosure 5, Section 2.2.2.1 includingTable 2.2-2d indicated that certain piping analyses remained to be completed. This wasaccurate as of the initial EPU LAR submittal. However, these analyses have now beencompleted and thus L-MT-08-052, Enclosure 5, Section 2.2.2.1 and Table 2.2-2d can berevised to reflect these changes.In addition, L-MT-09-044 (Reference 11-2), Enclosure 1, EMCB RAI No. 17a providedMain Steam System piping evaluation results. A portion of these results have changed.Specifically, the Main Steam line piping outside Containment results have changed andare updated below.Torus Attached Piping, RHR (BOP Condensate Service Water Lines), CrossAround Piping, CARV Discharge PipingReference 11-1, Table 2.2-2d indicated that these piping analyses along with MainSteam and Feedwater/Condensate remained to be completed. The Torus AttachedPiping, RHR (BOP Condensate Service Water Lines), Cross Around Piping, CARVDischarge Piping analyses are now completed and all the results are within the codeallowables.The Main Steam and Feedwater/Condensate lines are discussed separately below.Main Steam SystemNSPM confirmed the Main Steam line piping inside Containment analysis resultsprovided to the NRC in Reference 11-2, EMCB RAI No. 17a are correct and have notchanged. Therefore, no changes to this response are necessary.In this same response NSPM provided Main Steam line piping outside Containmentanalysis results to the NRC. NSPM has determined that these values have changed.The revised values are provided below.Page 22 of 80 L-MT-12-114Enclosure 1Table 11 Main Steam Loading ResultsMaximum Flued Head Anchor LoadsMaximum Pipe Stresses (Outside Containment)Load Combination Service Node Stress Allowable InteractionLevel (psi) (psi) RatioP+DW A TURD 7650 15000 0.51TH Range A TURB 16618 22500 0.74P+DW+TSV B TURC 12288 18000 0.68P + DW + OBE* B X7A 14289 18000 0.79DW+SRSS(TSV, D X7A 21026 26325 0.80SSE)*HELB TH N/A TURB 16618 18000 0.92HELB N/A TURD 3263 1 30000 1.09**DW+TH+OBE*Excluding seismic category II pipe between Stop Valves and Turbine**Indicates a HELB at this location, this load combination is used only to evaluate the need toassume a HELB and is not required to have an Interaction Ratio <1 to meet USAR requirements.Maximum Turbine LoadsLoad Service Mx Allowable Interaction Mz Allowable InteractionCombination I Level (ft-lb) (ft-lb) Ratio J (ft-lb) (ft-lb) RatioDW B 3714 413000 0.090 1848 722000 0.2563 86DW + TH B 2846 413000 0.689 1631 722000 0.2261 03 55Note: Loads from all turbine nodes were combinedPage 23 of 80 L-MT-12-114Enclosure 1Feedwater SystemPreviously NSPM reported that the FW/Condensate system piping evaluations were notcomplete. These evaluations are now complete. Below are the results of theFW/Condensate piping evaluations.Table 11 Feedwater/Condensate Loading ResultsFW/CondensateMaximum Pipe Stresses (Maximum Interaction Ratios):Node Load Combination Stress si Allowable (psi) Interaction RatioOlON P + DW 8,637 15,000 0.58Q12N I TH 18,119 22,500 0.81PN25 P + DW + SSE896 14,602 22.863 0.639Reactor Feed Pump Nozzles Stress Analysis*:Load Case Max Equivalent Stress Allowable SafetyStress (psi) (psi) FactorP-2A Suction (DW+TH) [ 8,118 20,855 2.6P-2A Discharge (DW+TH) ]9,014 20,855 2.3P-2B Suction (DW+TH) 8,203 20,855 2.5P-2B Discharge (DW+TH) 8,774 20,855 2.4[P-2A Suction (DW+TH+UBC) 18,136 20,855 2.6IP-2A Discharge (DW+TH+UBC) 9,376 1 20,855 2.2[P-2B Suction (DW+TH+UBC) 8,247 20,855 2.5P-2B Discharge (DW+TH+UBC) 8,844 20,855 2.4*The analysis presented here does not include the latest analysis of the stresses on the nozzles. Thelatest analysis of the stresses increased the stress by a maximum of <1.1%, which resulted in it beingdeemed unnecessary to re-analyze as the safety factors of>2.2 will bound these minor increases instresses, as a minimum safety factor of 1.5 is required for normal (static) operating conditions perASME BPVC See. II, Part D-C, Table lA values at 315'F.Maximum Support Load:I Support # I Node I Description I Force (lb) Allowable (lb) I Interaction Ratio IFWH-90 1401NI F (IRmax 946 953 0.993!!See Enclosure 2 for a markup of the EPU documentation reflecting the completedpiping analyses and the changes identified above for the Main Steam and FeedwaterSystems.Page 24 of 80 L-MT-12-114Enclosure 1Temperature Pressure ChangesAs part of the reanalysis of piping for EPU pressures and temperatures changed due toEPU conditions. The EPU Design Pressure and Temperature columns contain thevalues used in the EPU design analyses performed for the subject piping. Thesechanges are provided in the following table:Table 11 Design Pressure and Temperature Comparison of CLTP and EPUThe Crossaround PipingLine No. EPU DesignFrom -to PressurePsigEPU DesignTemperatureOFCLTPPress*/TempE6A from crossaround 269 4To E-15A heater (08-211)E6B from crossaround 269 4To E-15B heater (09-105)The Extraction Steam Lines to 13 and 14 heaters1010220/396220/396Line No.From -toEPU DesignPressurePsigEPU DesignTemperatureOFCLTPPress*/TempE8A-20"-HACondenser -E-13A heater(08-128)E8B-20"-HACondenser -E-13B heater(08-128)E7A-10"-HATurbine -E14A(08-128)E7B-10"-HATurbine -E14B(08-128)10010017017032932936336368/31568/315117/348117/348Page 25 of 80 L-MT-12-114Enclosure 1Condenser DrainsLine No.From -toEPU DesignPressurePsigEPU DesignTemperatureOFCLTPPress*/TempCD9-6" 269T-6A- CD5CD10-6" 269CD9-condenserCD5-6"-HCD 269CD5 -condenserCD5-6" 269T-6B -E-14ACD11-6" 269T-6D -CD6CD12-6" 269CD11- condenserCD6-6"-HCD 269CD6 -condenserCD6-6" 269T-6C -E-14BRelief Valve and Vent Piping410410410410410410410410212/392100/392212/392100/392212/392100/392100/392212/392RV2/12-6" (12 heaters)RV3/13-6" (13 heaters)RV4/14-6" (14 heaters)RV5/15-4" (15 heaters)V2A-8"/6" (1 2A vent)V2B-8"/6" (128 vent)VIA-8"/6" (11 A vent)V1 B-8"/6" (11 B vent)5092158269261333370410261261192192vacuum/243vacuum/310vacuum/344vacuum/3905050505015/24515/24515/24515/245Page 26 of 80 L-MT-12-114Enclosure 1Condensate PipingLine No. EPU Design EPU Design CLTPFrom-To Pressure Temperature Press*/TempPsig OFC1A/C1BCondenser-Pump Vacuum 145 Vacuum/135CIA/Cl B-16"Pump-Air Ejector 450 145 434/135C2A/C2BAir Ejector-Steam 450 145 434/135Packing ExhausterC2-12"-GB 450 145 434/135Air Ejector BypassSteam Packing Exhauster 434/135-11 Drain CoolersC4A/C4B11 Drain Cooler- 450 158 434/14411 FW HeaterC4A/C4B11 FW Heater-12 Drain Cooler 450 182 434/175C4A/C4B12 Drain Cooler -450 199 434/19312 FW HeaterC4A/C4B12 FW Heater-13 FW Heater 450 250 434/238C4A/C4B13 FW Heater-FW Pump 450 321 434/310Page 27 of 80 L-MT-12-114Enclosure 1Feedwater PipingLine No.From-ToFW3 and FW4FW Pump Recirc linesEPU DesignPressurePsig1550EPU DesignTemperatureOF323CLTPPress*/Temp1550/313FW2A/FW2BFW Pump-14 FW HeaterFW2A/FW2B14 FW Heater-15 FW HeaterFW2A/FW2B15 FW Heater-MO-1614 & MO-16151550155015503233571550/3131550/3451550/4001250/400410410FW2A/FW2BMO-1614 & MO-1615-2nd check valve from vessel 1250Heater Drains PipingLine No.From-ToEPU DesignPressurePsigEPU DesignTemperatureOFCLTPPress*/TempHD1, HD11.HP Heater- CV-1 019& CV-1 058HD1, HD11CV-1019 & 1058-14 HeatersHD1, HD11HD1 & HD11-CV-1020 & 1059HD1, HD11CV-1020 &CV1 059-Condenser #28 & #19269371269371215/349110/349215/349-/349269371269371Page 28 of 80 L-MT-12-114Enclosure 1Line No. EPU Design EPU Design CLTPFrom-To Pressure Temperature Press*/TempPsig OFHD2, HD12 149 337 110/31814 Heaters-CV-1017 & 1056HD2, HD12 149 337 63/318CV-1017 & 1056-13 HeatersHD2, HD12 149 337 110/318HD2 &12-CV-1018 & 1057HD2, HD12 149 337 -/318CV-1018 & 1057-Condenser #12 & 10HD3, HD13 87 263 64/24813 Heaters-CV-1015 & 1054HD3, HD13 87 263 12/248CV-1015 & 1054-12 HeatersHD3, HD13 87 263 64/248HD3 &13-CV-1016 & 1055HD3, HD13 87 263 -/248CV-1016 & 1055-Condenser #13 & 19HD4, HD14 19 258 12/24312 Heaters-T-52 A & BHD5, HD15 19 258 12/243T-52A & B-12 Drain CoolersPage 29 of 80 L-MT-12-114Enclosure 1Line No. EPU Design EPU Design CLTPFrom-To Pressure Temperature Press*/TempPsig OFHD6, HD16 19 193 12/185Drain Coolers-CV-1013 & 1052HD6, HD16 19 193 -/185CV-1013 & 1052-11 HeatersHD6, HD16 19 193 12/185HD6, HD16-CV-1014 &1053HD6, HD16 19 193 -/185CV-1014 &1053-Condenser #11 & #7HD7, HD17 -6.3 185 -7/18011 Heaters-11 Drain CoolersHD8, HD18 -6.3 185 -7/180HD7 & HD17-Condenser #7HD9, HD19 -6.3 155 -7/13811 Heaters-Condenser #5* Pressure values indicated with a "-" were determined to be less than 50 psig.The changes identified in Item 11 are included in the markups provided in Enclosure 2.Changes are identified under Items 11 and 26.References11-1 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "LicenseAmendment Request: Extended Power Uprate (TAC MD9990)," L-MT-08-052,dated November 5, 2008. (ADAMS Accession No. ML091410120)Page 30 of 80 L-MT-12-114Enclosure 111-2 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), " MonticelloExtended Power Uprate: Response to NRC Mechanical and Civil EngineeringReview Branch (EMCB) Requests for Additional Information (RAIs) dated March28, 2009 (TAC MD9990)," L-MT-09-044, dated August 21, 2009. (ADAMSAccession No. ML092390332)Page 31 of 80 L-MT-12-114Enclosure 1ITEM 12 -TECHNICAL SUPPORT CENTER (TSC) DOSE CALCULATIONNRC REQUESTED INFORMATION: L-MT-08-036, Enclosure 6 provided a vendorcalculation for TSC Internal Dose. This calculation was subsequently revised. Providea discussion of revised calculation, including a table of changes. Indicate which eventsare/are not affected and why that determination was made. Report the results andindicate calculation within acceptable limits.NSPM RESPONSE:Reference 12-2, Enclosure 6 contained calculation ALION-CAL-M NGP-4370-03,"MNGP EPU -TSC Internal Dose, Revision 0." This calculation was subsequentlyrevised to Revision 1. The results of the calculation revision change were reported tothe NRC in Reference 12-1. However, the update did not recognize that L-MT-08-036(Reference 12-2),, Enclosure 6 was impacted by this change.The change affects the TSC post-LOCA dose. A complete description of the reason forthe change is provided in Reference 12-1, Enclosure 4, including updated excerpts fromthe EPU documentation (including dose tables) that show the corrected TSC dose. Thedose tables also include the NRC acceptance criteria and demonstrate that the revisedTSC post-LOCA dose is well within the NRC acceptance criteria.See Enclosure 2 for a markup of Reference 12-2 indicating that the provided calculationis no longer applicable.References12-1 Letter from T J O'Connor (NSPM) to Document Control Desk (NRC), "MonticelloExtended Power Uprate: Updates to Docketed Information (TAC MD9990)," L-MT-10-072, dated December 21, 2010. (ADAMS Accession No. ML103570026)12-2 Letter from T J O'Connor (NSPM) to Document Control Desk (NRC), "MonticelloExtended Power Uprate (USNRC TAC MD8398): Acceptance ReviewSupplement Regarding Radiological Analysis," L-MT-08-036, dated May 20,2008. (ADAMS Accession No. ML081430494)Page 32 of 80 L-MT-12-114Enclosure 1ITEM 13 -RISK ASSESSMENTNRC REQUESTED INFORMATION: Ongoing changesto model, site design andoperation have impacted previously reported results. Describe any changes toOperations or Design that affect the PRA analysis. Indicate that enhancements havebeen identified that would have a small change on the baseline CDF. A description in aqualitative manner is acceptable since this is not a risk informed application. Discussany HEP/HRA changes. See SRP 19.2, Appendix D for criteria. Indicate thatenhancements and proposed changes would not significantly affect delta CDF/LERF.Conclude that ACDF and ALERF have not changed, or conclude that the change is stillvery small. Indicate that the model will be revised in the future to include allenhancements and EPU changes..NSPM RESPONSE:NSPM letter L-MT-08-052 (Reference 13-1), Enclosure 15 provided a risk evaluation ofoperation of the MNGP at EPU conditions. This assessment was performed in March2008. The following Gap assessment shows that while a number of changes haveoccurred at the MNGP that impact the PRA analysis, the results of these changes donot have a significant impact on the change in risk attributable to the EPU as comparedto the March 2008 assessment and related analysis. Therefore, no additional changesto L-MT-08-052, Enclosure 15 are proposed at this time.Although the current Probabilistic Risk Assessment (PRA) model of record is the samebase model used to perform the EPU Risk Assessment (Identification of RiskImplications Due to Extended Power Uprate at Monticello, March, 2008, Enclosure 15 toL-MT-08-052), two general areas are considered in the following Gap Assessment toaddress changes since the 2008 timeframe when the EPU Risk Assessment wasperformed. First, plant modifications that have been (or will be) implementedsubsequent to the EPU risk assessment (but prior to EPU implementation), includingEPU modifications that have been refined since 2008, are considered for their potentialimpact on the EPU Risk Assessment. No significant changes to the Human ErrorProbability/Human Reliability Analysis (HEP/HRA) insights from the March 2008submittal result from these plant modifications. Second, several adjustments have beenmade over the past several years to the current PRA model, that are intended to bringthe PRA into conformance with the ASME/ANS PRA standard endorsed by the NRC inRegulatory Guide 1.200. These adjustments are not associated with implementation ofEPU. This revised PRA model is scheduled to become the new model of record in thefirst half of 2013.Plant ModificationsPlant modifications on equipment that have potential to impact PRA model results thatwere not included in the original EPU Risk Assessment:Page 33 of 80 L-MT-12-114Enclosure 1" Condensate Pump Replacement- This modification replaces both CondensatePumps with higher capacity pumps and motors, generally leading to a risk reduction,but two features have potential for a small negative impact on risk. The pump motoroil will be cooled by Service Water (SW), and higher pump capacity can lead tohigher potential flood rates. The SW dependency impact is minimized by the factthat Feedwater pumps are already dependent on SW. The internal flooding impactis offset by the enhanced High Energy Line Break (HELB) flood barrier that protectsthe Division 1 4 KV equipment. This change impacts the base risk level, but thedifferential risk due to EPU would not be impacted.* Division 1 4KV Switchgear Room HELB Barrier Improvement -Enhancedflooding protection to the lower 4 KV switchgear is being installed to accommodateHELB concerns. A flooding barrier up to 7 feet high is being installed. As the lower4 KV equipment is one of the critical areas that drive base internal flooding risk atMonticello, this modification will significantly offset negative impacts from increaseddesign flow in systems accommodating EPU. This change reduces the base risklevel, but the differential risk due to EPU would be minimal." Feedwater Regulating Valve Replacement -New Feedwater Regulating valveswill have virtually the same dependencies and failure modes as the existing valves.New valve positioners for these valves will incorporate digital technology with somepossible additional failure modes, but will eliminate some existing failure modes.Overall impact on risk is neutral.* Service Water Pump Replacement -All three SW pumps have been replaced withhigher capacity pumps. Pump #11 power supply has been switched from loadcenter LC-103 to LC-107. Increased risk from higher potential flooding rates is offsetby improved flooding barrier for the lower 4 kV room, and enhanced systemcapability. The new power source to Pump #11 can be maintained under Loss ofOffsite Power (LOOP) conditions using the #13 Diesel Generator. Overall impact onrisk is neutral." Instrument Air System Upgrade -All three air compressors have been replacedby much higher capacity compressors. Two smaller air dryers have been replacedby three reliable and high capacity dryers. Power supplies to the compressors werechanged to provide back up from alternate power sources. Service water has beeneliminated as a potential failure mechanism to compressors. The compressors arerelocated to an area that is not susceptible to internal flooding. Higher reliability ofthe Instrument Air system has a positive impact on overall risk. Thus, the changereduces the base risk level, but the differential risk due to EPU would be minimal.* Condensate Demineralizer Replacement -Higher capacity demineralizers havebeen installed to accommodate EPU conditions. Demineralizer outlet valve failuremode has changed from fail-closed to fail-as-is. This change improves condensatesystem reliability under loss of instrument air events. Increase in potential floodrates due to larger pipe diameters and associated air operated valves (AOVs) in thedemineralizer system is offset by improved flood protection of the lower 4 KVPage 34 of 80 L-MT-12-114Enclosure 1switchgear equipment. This change reduces the base risk level, but the differentialrisk due to EPU would be minimal.0 CAPX2020 Subyard Improvements -Significant enhancements to the 345 KVoffsite power grid have been incorporated. One additional offsite power source isprovided from the new Quarry power line. The new 345 KV ring bus now remainsintact following a plant trip as opposed to breaking the ring bus upon tripping themain generator for the old configuration. This results in more reliable offsite powersources, particularly following a plant transient. The net impact on overall risk ispositive. This change reduces the base risk level, but the differential risk due to EPUwould be neutral.0 Feedwater Pump Replacement -New higher capacity feedwater pumps will beinstalled to provide the enhanced flow required for EPU conditions. The powersource to the pump motors will be shifted to the new 13.8 kV supplies. This systemupgrade will result in no significant change in base risk or differential risk due toEPU.* 13.8 KV Switchgear Installation -A new power supply for the FW pumps,Condensate pumps and Recirculation pump motor-generator (MG) set drive motorswill be placed in service. The new configuration is very similar to the existing powersupplies, except for the increased 13.8 KV voltage. Buses 11 and 12 will berelocated to the old hot machine shop building. Overall impact on base risk ordifferential risk from the EPU due to this modification is neutral.* Hotwell Level Increase -Main condenser hotwell level will be increased slightly toprovide additional net positive suction head (NPSH) for the new Condensate pumps.The slight addition in makeup water inventory will enhance the ability to cool thereactor, but also will increase flood source inventory. This potential additionalsource of floodwater will be offset by the enhanced flood barrier protecting the lower4 KV switchgear room. Risk impact is not significantly affected by this modification.* Maximum Extended Load Line Limit Analysis Plus (MELLLA+) -MELLLA+ willmodify the power-flow map to allow operation along a higher rod line. A post-EPU/MELLLA+ Reactor Recirculation pump trip or runback will not reduce power asmuch as the current condition. There will be a slight impact on reactor power levelfollowing Anticipated Transient Without Scram (ATWS). An evaluation ofAttachment 6 (Monticello MELLLA+ Risk Assessment) of L-MT-10-003 (MELLLA+License Amendment Request) was performed to determine if changes subsequentto the submittal could alter the fundamental conclusion of the assessment. Thisevaluation concluded that although the baseline CDF/LERF is expected to increasefrom upgrading the PRA model of record, the outcome will not result in a shiftoutside of Region III (Very Small Changes) acceptance guidelines from RegulatoryGuide 1.174 (An Approach for Using PRA in Risk-Informed Decisions on PlantSpecific Changes to the Licensing Basis).0 Main Turbine/Generator Upgrades -The Turbine/Generator upgrades have noeffect on structures, systems and components (SSCs) that have potential'toPage 35 of 80 L-MT-12-114Enclosure 1significantly impact critical safety functions modeled in the PRA. Therefore thebaseline or differential risk results are not impacted by these modifications.*1 R/2R Auxiliary Transformer Replacements -New transformers will be installedto accommodate the new 13.8 KV loads. In addition to the increase in designcapacity, these new transformers will be less dependent on AC power for coolingunder post transient conditions. This results in a net reduction in baseline risk.* Main Generator Output Transformer Replacement -The newly installed MainGenerator Output Transformer has no effect on SSCs that have potential tosignificantly impact critical safety functions modeled in the PRA. Therefore, thismodification has no impact on baseline risk or differential risk from the EPU.PRA Model EnhancementsFuture PRA model enhancements to conform to the ASME/ANS Standard have beenconsidered for their potential impact on PRA EPU assessment results as describedbelow:* Potential Condensate Demineralizer flooding due to spurious AOV operation -In the process of designing the new condensate demineralizer system, it wasdiscovered that single AOV failures in the system could result in overfilling theBackwash Receiving tank and subsequent flooding of the 911' elevation of theTurbine Building. The modification to protect the lower 4 KV room from flooding asdiscussed above, significantly reduces the risk associated with this floodingpotential. Although this vulnerability has always existed for MNGP, it will impact theinternal flooding baseline results of the PRA. This change impacts the base risklevel, but the differential risk due to EPU would not be impacted.* Control Rod Drive Hydraulic (CRDH) system success criteria changes -Success criteria crediting early injection success for the CRDH system will bemodified in the next revision of the PRA model. This change in CRDH successcriteria is a result of new insights obtained by detailed hydraulic modeling of theCRDH system that were performed as part of the Reg. Guide 1.200 model upgrade.Long term (late in the event) CRDH success criteria are not impacted by this newinsight. Importance of the CRDH system as an early injection source is limited dueto its limited flow capacity. This model improvement would be appropriateregardless of the impact from EPU, yet the timing where CRDH becomes a credibleearly injection source will change slightly following EPU implementation. Thischange impacts the base risk level, but the differential risk due to EPU would not besignificantly impacted." Diesel Fire Pump and CRDH ventilation dependencies -Recent insights haverevealed that long term use of the Diesel Fire Pump with room ventilation failurewould be challenged by the fact that personnel accessibility to the room to make upfuel oil to the day tank is complicated by high room temperatures. Similar insightshave shown that loss of room ventilation to the CRDH pump room may make flowPage 36 of 80 L-MT-12-114Enclosure 1enhancement valve manipulations in the room prohibitive if not performed soon afterthe ventilation system loss. Although these insights were not incorporated in themodel used for the EPU assessment, the issues are the same for both pre- andpost-EPU conditions. This small change impacts the base risk level, but thedifferential risk due to EPU would not be impacted." Modular Accident Analysis Program (MAAP) Parameter File correctionsrelated to Drywell Coolers -An error was identified in the parameters used todefine Drywell Cooler sizing and performance. A number of the thermal-hydrauliccalculations using the MAAP code had to be re-run for the future PRA. Since theEPU risk assessment was performed prior to discovery of this issue, the overallimpact of this issue on the EPU risk assessment has been evaluated anddocumented in a report. This report determined the following about the discrepantsuppression pool pressure and temperature calculations:"In addition, the SPIT and SPIP point in time values mentioned in the Commentcolumn of Table E-1 of the MNGP EPU risk assessment report for this case arenot reflective of the MNGP containment response; however, these particularparameter values are commentary and not specifically used directly in anycalculation."While a number of the MAAP simulations in this report are impacted by thismodeling issue, NSPM has determined that this issue has no impact on thenumerical risk results or conclusions of the MNGP EPU risk assessment.* Fire Water/Condensate Service Water (CSW) success criteria changes -Thepump and system flow characteristics for the Fire Water and CSW systems havebeen recently updated to more accurately reflect the expected injection flow ratesinto the reactor vessel following depressurization. These new data revealed thatflow from these alternate injection systems is less than that credited in the currentPRA model. These new insights have resulted in a lengthened period of timebetween the initiating event and the time when these systems should be credited ascapable of making up for decay heat losses. Although this refined information willresult in an increase in overall base CDF/LERF, the same increase would apply toboth pre- and post-EPU conditions, and therefore, would not result in a significantdifferential change to the risk of EPU.* Safety Relief Valve (SRV) Depressurization success criteria changes -TheEPU risk assessment was based on a model that credited early Fire Water andCSW system injection following depressurization with two SRVs. Future revisions ofthe PRA model will use a more restrictive definition of core damage (peak fueltemperature of 1800OF versus 22001F) based on the recommendations in the ASMEPRA standard. The more restrictive definition of core damage, combined withupdated pump flow characteristics for Fire and CSW systems mentioned above, willremove those systems from being credited as successful early injection systems.Although this success criteria change will result in an increase in overall baseCDF/LERF, the same increase would apply to both pre- and post-EPU conditions,Page 37 of 80 L-MT-12-114Enclosure 1and therefore, will not result in a significant change to the EPU assessment results interms of change in risk due to operating at a higher power level.Best estimate Battery Capacity Calculation -A thorough battery analysis hasbeen performed subsequent to the EPU risk assessment, which provides bestestimate battery duration following a Station Blackout (SBO) event. This analysisshows that High Pressure Coolant Injection (HPCI) and Reactor Core IsolationCooling (RCIC) can function well beyond the 4-hour design battery duration uponloss of all AC power. Incorporation of this insight into the PRA model results in areduction in SBO risk and the baseline values for CDF and LERF. The impact onthe EPU risk assessment would be minor since the battery analysis results wouldapply equally to the pre-EPU and post-EPU models.Conclusion:Plant changes that have been implemented subsequent to the EPU risk assessmentand plant modifications designed to support the EPU that have not yet been completed(but are planned to be installed prior to EPU implementation) do not have a significantimpact on the change in risk attributable to the power uprate as compared to the March2008 assessment and related analysis. Additionally, PRA insights gained over the pastseveral years while pursuing a major model update to conform to the ASME/ANSstandard, although currently anticipated to result in a net increase in overall baselineCDF/LERF, do not result in a significant change in the delta between baseline risk andEPU risk.The overall estimated impact attributable to the EPU is low, and remains within the "verysmall" category (i.e., Region III of the Regulatory Guide 1.174 Guidelines) for CDF andLERF. The next PRA model revision, which is currently in later stages of development,will incorporate all of the above changes with the exception of the new 13.8 KVswitchgear configuration. This electrical modification will have virtually no impact on themodel results. Final design of the (yet to be installed) 13.8 KV system was notcomplete as of the "freeze date" applied to the current model upgrade initiative.There are no proposed changes to EPU documentation resulting from this response.References13-1 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "LicenseAmendment Request: Extended Power Uprate (TAC MD9990)," L-MT-08-052,dated November 5, 2008. (ADAMS Accession No. ML091410120)Page 38 of 80 L-MT-12-114Enclosure 1ITEM 14 -COMPUTER CODE CHANGESNRC REQUESTED INFORMATION: L-MT-08-052, Enclosure 5, Table 1-1 indicatesthat GOTHIC Version 7.1 was used to perform the High Energy Line Break (HELB)Subcompartment Evaluation. NSPM used later codes including GOTHIC Version 7.2aand Version 7.2b to perform HELB evaluations. Identify GOTHIC 7.2a and 7.2b ascomputer codes used in EPU.NSPM RESPONSE:L-MT-08-052 (Reference 14-1), Enclosure 5, Table 1-1 indicates that GOTHIC Version7.1 was used to perform the High Energy Line Break (HELB) SubcompartmentEvaluation. NSPM used later codes including GOTHIC Version 7.2a to perform HELBevaluations and 7.2b for Containment Accident Pressure calculations.GOTHIC version 7.2a was used for HELB reconstitution analysis including somesubcompartment analyses. The results of these analyses were benchmarked toRELAP4/Mod5 previously approved code of record. See item 26 for details.GOTHIC version 7.2b was used for Containment Accident Pressure (CAP) analyses,and for the reactor heat balance evaluations associated with the multiple spuriousoperations analyses for Appendix R. In the CAP submittal (L-MT-12-082, Reference14-2) the results of the GOTHIC 7.2b analyses are benchmarked against SHEX andMonte Carlo results.See Enclosure 2 for a markup of L-MT-08-052, Enclosure 5, Table 1-1 reflecting thesechanges.References14-1 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "LicenseAmendment Request: Extended Power Uprate (TAC MD9990)," L-MT-08-052,dated November 5, 2008. (ADAMS Accession No. ML0832301 11)14-2 Letter from M A Schimmel (NSPM) to Document Control Desk (NRC), "MonticelloExtended Power Uprate and Maximum Extended Load Line Limit Analysis PlusLicense Amendment Requests: Supplement to Address SECY 11-0014 Use ofContainment Accident Pressure (TAC Nos. MD9990 and ME3145) (TACMD9990)," L-MT-12-082, dated September 28, 2012. (ADAMS Accession No.ML12276A057)Page 39 of 80 L-MT-12-114Enclosure 1ITEM 15 -TURBINE BYPASS VALVE CAPACITYNRC REQUESTED INFORMATION: L-MT-10-002, Enclosure 2 changed the TurbineBypass Valve Capacity value from 11.6% to 11.5% of the Nuclear Steam Supply. Thesubmittal did not identify that this change also applied to other documents, and identifythose documents as needing correction. Update only to supersede outdatedinformation. Include statement that confirms all affected analyses were performed atcorrect value. No changes to analysis outcomes for anticipated operations occurrences(AOOs).NSPM RESPONSE:The transient analysis completed for the EPU was reported to the NRC in L-MT-08-052(Reference 15-1), Enclosure 5, section 2.5.4.3 and in L-MT-09-049 (Reference 15-2),response to RAI 2.8.3 -11. Both documents reported a turbine bypass valve capacityof 11.6%. A change in turbine bypass valve capacity from 11.6% to 11.5% wasreported to the NRC under letter L-MT-10-002 (Reference 15-3). This letter stated:"TS Bases B 3.3.1.1 refers to bypass capacity in terms of "% of the THERMALPOWER," while B 3.7.7 (Main Turbine Bypass System) to bypass capacity in termsof "% ... rated steam flow." For consistency, it was decided that those statements(which refer to the same capability) should read the same. The only measurable andcalculated value is steam flow, which is the applicable parameter used in the safetyanalyses, and thus, "% of rated steam flow" is the more appropriate term to be usedin the TS Bases. Therefore, the TS Bases turbine bypass value statements arechanged from "THERMAL POWER" to "of rated steam flow," and the latestcalculated value (11.5%) supersedes the 11.6% in the original TS Bases markups."Turbine bypass valve capacity is not used as an input for containment analysis or forthe ECCS analysis. This value is used in the evaluation of plant transients. Theevaluation of plant transients is performed on a cyclic basis for MNGP and has beencompleted for EPU core design using a value of 11.5% for the evaluation of transientsfor Cycle 26 and beyond. Cycle 26 started operation in 2011. The results of thistransient evaluation are available in the MNGP cycle 26 supplemental reload licensingreport (SRLR) that includes MELLLA+ conditions and evaluations provided asEnclosure 3 to L-MT-12-054 (Reference 15-4).See Enclosure 2 for a markup of L-MT-08-052, Enclosure 5, reflecting these changes.References15-1 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "LicenseAmendment Request: Extended Power Uprate (TAC MD9990)," L-MT-08-052,dated November 5, 2008. (ADAMS Accession No. ML0832301 11)Page 40 of 80 L-MT-12-114Enclosure 115-2 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), " MonticelloExtended Power Uprate: Response to NRC Reactor Systems Review Branchand Nuclear Code and Performance Review Branch Request for AdditionalInformation (RAI) dated March 23, 2009 and Nuclear Code and PerformanceReview Branch Request for Additional Information dated April 27, 2009 (TAC No.MD9990)," L-MT-09-049, dated July 23, 2009. (ADAMS Accession No.ML092090219)15-3 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "

Subject:

Monticello Extended Power Uprate: Updates to Enclosures 1, 3, 5 and 7 of L-MT-08-052, and Enclosure 3 of L-MT-09-047, (TAC MD9990)," L-MT-10-002, datedJanuary 25, 2010. (ADAMS Accession No. ML100270020)15-4 Letter from M A Schimmel (NSPM), to Document Control Desk (NRC), "

Subject:

Supplement to Maximum Extended Load Line Limit Analysis Plus LicenseAmendment Request (TAC ME3145)," L-MT-12-054, dated June 27, 2012.(ADAMS Accession No. ML12192A1 04)Page 41 of 80 L-MT-12-114Enclosure 1ITEM 16 -REACTOR HEAD SPRAY NOZZLE FATIGUE ASSESSMENTNRC REQUESTED INFORMATION: L-MT-08-052, Enclosure 5, Section 2.2.3,including Table 2.2-3, indicates that the Reactor Head Spray Nozzle piping exists.However, this piping has been removed and the nozzle is now permanently blankflanged. Provide corrected information.NSPM RESPONSE:NSPM letter L-MT-08-052 (Reference 16-1), Enclosure 5, Section 2.2.3, including Table2.2-3, indicates that Reactor Head Spray Nozzle piping exists. However, otherlocations in the EPU documentation contain reference only to the Reactor Head Spraynozzle (Reference 16-1, Enclosure 5, pgs 2-42 and 2-44; Reference 16-2, Enclosure 1,pgs 1, 2 and 4). Further, NSPM stated in Reference 16-3, Enclosure 1, RAI responseNo. 14 that the Reactor Head Spray line (piping) and valves have been removed.For clarification, the Reactor Head Spray piping has been removed from the plant andthe remaining Reactor Head Spray nozzle is blank flanged off. References to ReactorHead Spray piping or Reactor Head Spray Nozzle piping are incorrect and are beingdeleted.See Enclosure 2 for a markup of L-MT-08-052, Enclosure 5, reflecting these changes.References16-1 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "LicenseAmendment Request: Extended Power Uprate (TAC MD9990)," L-MT-08-052,dated November 5, 2008. (ADAMS Accession No. ML0832301 11)16.2 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "MonticelloExtended Power Uprate (USNRC TAC MD8398): Acceptance ReviewSupplemental Information Package 6", L-MT-08-043, dated June 12, 2008.(ADAMS Accession No. MIL081640435)16-3 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "MonticelloExtended Power Uprate: Response to NRC Containment and VentilationReview Branch (SCVB) Request for Additional Information (RAI) dated March19, 2009, and March 26,2009 (TAC No. MD9990)", L-MT-09-048, dated July13, 2009. (ADAMS Accession No. ML092170404)Page 42 of 80 L-MT-12-114Enclosure 1ITEM 17 -EMERGENCY OPERATING PROCEDURE FLOW CHART FOR ATWSNRC REQUESTED INFORMATION: EOP Flow Chart for ATWS -Copy of C.5-2007,Rev. 15 was sent to NRC (Reference 17-1, Enclosure 1). C.5-2007 is now at Rev. 17.Briefly describe the change made and that this is a newly implemented change with noimpact on event response. Separate MELLLA+ from EPU in this discussion as bothneed to be addressed separately. NRC will verify that safety evaluations (SEs) arecompatible.NSPM RESPONSE:In NSPM letter L-MT-09-049 (Reference 17-1), Enclosure 1; in response to NRC SRXBRAI 2.8.3-3, NSPM submitted EOP flow chart C.5-2007, Failure to Scram, Revision 15to the NRC. Since that submittal, the flow chart has been revised and is now at revision17.This change is in response to concerns regarding response to a high power ATWS withloss of the main condenser. The changes place some of the non-time critical power legsteps into a separate procedure to allow the operators to rely on a single procedure andexpedite getting to the time critical operator action (TCOA) of injecting standby liquidcontrol (SBLC) in 124 seconds. The step to run back recirculation flow and then trip therecirculation pumps has been moved to a separate procedure. No steps wereeliminated, only moved to a separate procedure.See Enclosure 2 for a markup of L-MT-09-049 reflecting these changes.A revised copy of C.5-2007 is provided in Enclosure 3.References17-1 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), " MonticelloExtended Power Uprate: Response to NRC Reactor Systems Review Branchand Nuclear Code and Performance Review Branch Request for AdditionalInformation (RAI) dated March 23, 2009 and Nuclear Code and PerformanceReview Branch Request for Additional Information dated April 27, 2009 (TAC No.MD9990)," L-MT-09-049, dated July 23, 2009. (ADAMS Accession No.ML092090219)Page 43 of 80 L-MT-12-114Enclosure 1ITEM 18 -MAIN STEAM THERMOWELLSNRC REQUESTED INFORMATION: L-MT-09-044 (Reference 18-1), RAI 28 responsediscussed a modification to remove or shorten the Main Steam (MS) thermowells in2011 refueling outage to reduce the ratio of the vortex shedding frequency to the naturalfrequency of the MS thermowells to the CLTP value to minimize the potential of thesystem jumping into resonance. Please confirm the status of this modification.NSPM RESPONSE:NSPM will be performing a modification in the upcoming 2013 refueling outage toremove the existing MS thermowells and install plugs in their place.See Enclosure 2 for a markup of L-MT-09-044 reflecting these changes.References18-1 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "MonticelloExtended Power Uprate: Response to NRC Mechanical and Civil EngineeringReview Branch (EMCB) Requests for Additional Information (RAIs) dated March28, 2009 (TAC MD9990)," L-MT-09-044, dated August 21, 2009. (ADAMSAccession No. ML092390332)Page 44 of 80 L-MT-12-114Enclosure 1ITEM 19 -EPU MODIFICATIONS LIST CHANGESNRC REQUESTED INFORMATION: Some modifications described in L-MT-08-052,Enclosure 8 have been eliminated from consideration as not required to support EPU.One new modification has been added. Provide updated information.NSPM RESPONSE:NSPM letter L-MT-08-052 (Reference 19-1), Enclosure 8 provided plannedmodifications to implement the EPU at MNGP. Some information in this table isincorrect and requires revision. In addition, letter L-MT-08-052, Enclosure 5, Section2.5.4.4, also provided information related to planned modifications to implement theEPU at MNGP. Some information in this section is incorrect and requires revision.NSPM has identified three planned modifications that are included in the abovereference correspondence that are no longer planned for the EPU implementation. Thethree modifications are:0 Reactor Feed Pump Discharge Check Valve Replacement* Generator Hydrogen Coolers Replacement* #11 Drain Cooler Replacement/ReanalysisThe bases for not performing these modifications are as follows:* Reactor Feed Pump (RFP) Discharge Check Valve Replacement -The existing 14"RFP discharge check valves were going to be replaced with 16" check valves whenthe RFP discharge piping was replaced with 16" piping. It was subsequentlydetermined that the 14" RFP discharge piping does not need to be replaced. Sincethe RFP discharge piping will stay 14", the valves are no longer being replaced.* Generator Hydrogen Coolers Replacement -NSPM determined that thereplacement of the Hydrogen Coolers is not required due to existing proceduralguidance for monitoring hydrogen cold gas temperatures which provides adequatealarm margins and operator actions. Currently, operators monitor generatorhydrogen temperature during operator rounds by procedure and annunciator. Themaximum operating H2 cold gas temperature at 45 psig of H2 pressure is 46°C(1140F) with a 50C margin to the high cold gas alarm setpoint of 51'C (123°F).In addition, NSPM evaluated hydrogen cooler performance at EPU conditions with aservice water temperature of 900F. The evaluation concluded that the maximumexpected generator cold gas temperature at EPU conditions with a service watertemperature of 90OF is 47.9°C. Therefore, there is a 3°C margin to the alarm setpointof 51 °C where operator action to reduce generator power would be required.* #11 Drain Cooler Replacement/Reanalysis -Calculations determined that the #11feedwater heater drain coolers, E-DC-1 1A and E-DC-1 1 B, can pass the higherrequired EPU flows. This is based on the assumption that the 14" diameter pipePage 45 of 80 L-MT-12-114Enclosure 1segments between the coolers and condenser, as well as the associated condenserpenetrations, are increased to 16" in diameter. Portions of these heater drain lineswere modified to increase their diameter to 16" during the 2011 refuel outage. Theremaining portions of the piping modifications will occur during the 2013 refueloutage. Monitoring of the drain cooler's condition will continue to be performedunder the plant's life cycle management (LCM) process.NSPM also identified one new modification required to support EPU conditions. Thismodification is based on the discussion provided in Item 9, which identified a change tothe Post-LOCA heatup of the RHR and CS rooms (see Item 9 for details).Pipe Support SR-530 modification -NSPM reviewed the Post-LOCA torus roomtemperature and determined that it increases to about 1800F. Based on theseresults, piping and components in the torus and surrounding areas were reviewedfor effects of this change. NSPM determined that these results affected the ResidualHeat Removal Service Water (RHRSW) discharge pipe from the RHR heatexchangers and the RHR heat exchanger supports.Based on the revised Post-LOCA temperature increase, NSPM reanalyzed thepiping, supports, grouted penetrations and equipment nozzles for compliance withthe ANSI B31.1, AISC & ACI code acceptance criteria, and manufacturers' allowablestresses. The analysis revealed increased applied loads to pipe supports SR-530.However, pipe support SR-530 was determined to require modification to remainwithin code allowables under the new loading.Pipe Support SR-530 supports line SW6-16"-JF. It is located in the "B" RHR room atapproximate elevation 929'. This line transports service water from the ReactorBuilding Closed Cooling Water (RBCCW) heat exchangers to the SW discharge.The modification consists of replacing the support pipe clamp, strut, and structuralattachment.An engineering change has been initiated to issue the updated piping calculationsand to document the modification of support SR-530 for Extended Power Uprate(EPU) conditions.In addition, the titles of Tables 8-2 and 8-3 were modified to remove reference to theplanned implementation of the modifications. The planned dates and refueling outagesare not pertinent information and do not reflect the final implementation of themodifications.See Enclosure 2 for a markup of the EPU documentation reflecting these changes.Page 46 of 80 L-MT-12-114Enclosure 1References19-1 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "LicenseAmendment Request: Extended Power Uprate (TAC MD9990)," L-MT-08-052,dated November 5, 2008. (ADAMS Accession No. ML0832301 11)Page 47 of 80 L-MT-12-114Enclosure 1ITEM 20 -ANNULUS PRESSURE (AP) LOADSNRC REQUESTED INFORMATION: Determine if the EPU documentation includescoverage of Annulus Pressure (AP) loads. Add to EPU LAR documentation ifnecessary.NSPM RESPONSE:GE Hitachi Nuclear Energy (GEH) has investigated a concern related to the impact ofvarious plant improvements with regard to changes in the evaluation of AP loads andthe subsequent impact of changes in AP loads on the performance of the Bio-ShieldWall (BSW) doors during events where the AP loads were postulated to increase.While reviewing the AP loads analysis for another plant, it was found that off-ratedconditions, which generate higher total mass release than the design power and coreflow point, result in higher peak pressure differential on the BSW door. These loadshave been evaluated at MNGP. A modification was completed in order to remove thebricks in the bioshield to prevent the potential for higher energy missiles during the off-rated conditions. In addition, NSPM verified that the design differential pressurecapability of the bioshield doors bounds the expected LOCA during the evaluated off-normal conditions.Although not part of the design basis, the Minimum Pump Flow Point on the MELLLAline (1210.4 MWt/43.3% Core Flow) is also evaluated. The energy release at this pointis calculated to be 17.4% greater than the release at the original basis of 1670MWt/100% Core Flow resulting in an annulus pressure of 42.3 psid. This is the limitingdifferential pressure analyzed. This differential pressure (dp) bounds the 40 psid valuecalculated for both current licensed thermal power (1775 MWt) and extended poweruprate (2004 MWt). The BSW doors are designed for a dp of 54 psi. Therefore theBSW doors have adequate margin for expected dp loads.There are no proposed changes to EPU documentation resulting from this response.Page 48 of 80 L-MT-12-114Enclosure 1ITEM 21 -EMERGENCY CORE COOLING SYSTEM (ECCS) ANALYSISCONFIRMATIONNRC REQUESTED INFORMATION: Need to confirm that the EPU 10CFR 50.46ECCS analysis includes all the latest GEH reported changes to the Appendix Kanalysis. Add to EPU LAR documentation if necessary.NSPM RESPONSE:GEH has confirmed to NSPM that the EPU ECCS-LOCA analysis includes all relevant10 CFR 50.46 notifications, with the exception of the 10 CFR 50.46 Notification Letter2012-01.Notification 2012-01, which is related to implementation of the GEH PRIME thermal-mechanical model, is not considered an Evaluation Model Error, but rather a Change.No fault is implied or inferred with current analyses and analyses pending NRC review.No operation out of compliance to Acceptance Criteria with the GESTR-based model isreported. Rather, it is seen as an evolution of the model and the reported change inPeak Clad Temperature (PCT) is an estimated impact if the PRIME thermal-mechanicalmodel is used instead of the GESTR-based model. It is considered "implemented" inthat the GEH Evaluation Model will henceforth be performed using PRIME.The impact for Monticello of the PRIME implementation is assessed as 45°F, asreported in the GEH 10 CFR 50.46 Notification Letter 2012-01 dated November 29,2012. Given the EPU Large Break PCT (LBPCT) of 2140 OF, this impact will present noviolation to the 2200°F limit. As it is under the 50OF significance threshold, andconfirming resolution of all prior Notification Letters in the analysis as it stands, noreporting requirement would be seen as necessary for the EPU ECCS-LOCA basis inresponse to Notification 2012-01.There are no proposed changes to EPU documentation resulting from this response.Page 49 of 80 L-MT-12-114Enclosure 1ITEM 22 -CONFIRMATION THAT OSCILLATION POWER RANGE MONITOR(OPRM) TESTING IS COMPLETEDNRC REQUESTED INFORMATION: Statements in the EPU LAR describe pre-operational testing of the OPRMs and the results of that testing and that MNGP waspermitted 90 days of testing before declaring OPRMs operable. NSPM please clarifythe accuracy of this language, or supersede it.NSPM RESPONSE:NSPM letter L-MT-09-049 (Reference 22-1), Enclosure 1, RAI SRXB RAI No. 2.8.3-4provided a response to the NRC request concerning an update on OPRM-based LongTerm Stability Solution (LTSS) Option III implementation at MNGP. The NSPMresponse in part stated:"The OPRM-based Option Ill LTS equipment was installed in the plant as part of thePRNMS modification at MNGP. Both OPRM trip outputs will be disabled during theOPRM monitoring and evaluation period. The period extends from the startupfollowing PRNM system installation to 90 days of steady-state operation afterreaching full power. The monitoring period is described in Section 5.1.2 of EnclosureI of the MNGP PRNM licensing amendment request dated February 6, 2008 and inNSPM letter dated November 6, 2008. It is currently scheduled to be armed onAugust 31, 2009."The OPRM-based Option III LTSS equipment is installed and was turned over to plantOperations in September 2009. The monitoring and evaluation period is complete.See Enclosure 2 for a markup of L-MT-09-049 reflecting these changes.References22-1 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), " MonticelloExtended Power Uprate: Response to NRC Reactor Systems Review Branchand Nuclear Code and Performance Review Branch Request for AdditionalInformation (RAI) dated March 23, 2009 and Nuclear Code and PerformanceReview Branch Request for Additional Information dated April 27, 2009 (TAC No.MD9990)," L-MT-09-049, dated July 23, 2009. (ADAMS Accession No.ML092090219)Page 50 of 80 L-MT-12-114Enclosure 1ITEM 23 -FATIGUE MONITORING PROGRAMNRC REQUESTED INFORMATION: EPRI Fatigue Monitoring Program is using theGreen's Function, which is not satisfactory to NRC. Nine Mile Point had a licensecondition for this issue. NSPM please assess if any changes to the Fatigue Monitoringprogram are necessary and document that to NRC. If NSPM is going to use stressbased program, NSPM will need to include a description of the six components.NSPM RESPONSE:RIS 2008-30 describes a concern regarding the methodology used by some licenseesto demonstrate the ability of nuclear power plant components to withstand the cyclicloads associated with plant transient operations for the period of extended operation.This particular analysis methodology (called FatiguePro) involves the use of the Green's(or influence) Function to calculate the fatigue usage during plant transient operationssuch as startups and shutdowns. Specifically, RIS-2008-30 expresses concerns aboutwhether the use of a single stress component (as opposed to the standard six stresscomponents required by ASME Code) as an input to Green's Function used in thesoftware is sufficiently conservative with regard to determining fatigue accumulation.RIS-2008-30 was evaluated in January 2009 for impact on the Monticello FatigueMonitoring Program. Monticello does not currently use FatiguePro or any other fatiguemonitoring software that uses the simplified approach of a single stress component asinput to the Green's Function for determining fatigue usage. Monticello performs manualcycle counting in accordance with ASME Code,Section III requirements and all thermaltransient calculations used in monitoring fatigue accumulation are derived from the sixstress components as required by the ASME Code.The most recent fatigue monitoring program update was performed with the support ofStructural Integrity Associates (SIA). SIA confirmed that the FatiguePro software wasnot used during the update of the Monticello Fatigue Monitoring Program and thesoftware that was used during the update did not use the simplified approach for inputto the Green's Function.There are no proposed changes to EPU documentation resulting from this response.Page 51 of 80 L-MT-12-114Enclosure 1ITEM 24 -MOTOR OPERATED VALVE (MOV) PROGRAM CHANGESNRC REQUESTED INFORMATION: Changes to HELB environmental profiles,changes to valve component performance assessments and implementation of newcalculations associated with an MOV program update has resulted in need to adjust 10MOV switches versus the one switch previously reported. After EPU submittal to theNRC, NSPM performed a comprehensive evaluation and design basis reconstitution ofthe MNGP GL 89-10 MOV program. The HELB and EPU dependencies andprogrammatic improvements resulted in increased maximum expected differentialpressures (MEDP) for certain valve stroke scenarios. This included new thrustrequirements and modified torque switch settings above thrust setting to maintainmargin. Identify the MOVs that changed. State the functional performancerequirements for the MOVs. Identify how they meet GL 89-10 and GL 95-06 and anyASME OM code requirements. Provide a background of the change to the analysis thatled to the change in the number of MOVs. Discuss how this impacts the IST 1Oyrinterval testing of the MOVs.NSPM RESPONSE:In NSPM letter L-MT-08-039 (Reference 24-1), Enclosure 2, NSPM provided responsesto RAIs 1, 2 and 3 that included discussion concerning the MNGP Motor OperatedValve (MOV) program and details concerning changes required to the MOV program toaccommodate EPU conditions. Since this submittal, changes have occurred to theMNGP MOV program that require NSPM to update the NRC regarding the MOVprogram and the impact on EPU documentation. The following discussion provides thebases for the changes to the MOV discussion in EPU documentation.NSPM performed a comprehensive reconstitution of the MNGP MOV program sincesubmittal of the EPU LAR (Reference 24-2). The HELB and EPU dependencies andprogrammatic improvements resulted in increased MEDP for certain valve strokescenarios. This included new thrust requirements and modified torque switch settingsabove the current thrust setting to maintain margin.The reconstitution consisted of:* Development of revised MOV functional analyses (system calculations) fordifferential pressures, temperatures, and flows with regard to system conditionchanges pursuant to the EPU, HELB and original system requirements.* Revision of the MOV functional analyses to document the results satisfactorily forCLTP conditions.* Updating of the valve coefficient of friction (COF) analysis.* Updating of voltage (effects of RHR / CS Pump Motor Starting Transients on MOVPerformance) and environmental temperature (MOV Environmental Temperatures)analysis.Page 52 of 80 L-MT-12-114Enclosure 1Updating of the analysis to include the most recent diagnostic test data and testequipment accuracies.The function performance requirements did not change from those described in the L-MT-08-052, Enclosure 5. Only the valves requiring switch setting adjustments changedbased on the reconstitution effort. Based on this reconstitution effort Table 24-1identifies MOVs that require switch adjustments to fully comply with the EPUperformance requirements:Table 24 MOVs Requiring Switch Adjustment to Support EPUValve NameMO-2009 12 RHR Torus Cooling Injection ValveMO-2014 11 LPCI Inboard Injection ValveMO-2015 12 LPCI Inboard Injection ValveMO-2020 11 Containment Spray Outboard ValveMO-2021 12 Containment Spray Outboard ValveMO-2023 12 Containment Spray Inboard ValveMO-2034 HPCI Steam Line Isolation ValveMO-2035 HPCI Steam Line Isolation ValveMO-2061 HPCI Torus Suction Inboard Isolation ValveMO-2062 HPCI Torus Suction Isolation ValveThe switch adjustments are scheduled for completion in the 2013 refueling outage.Once the switch adjustments are completed, the valves listed above will be fully capableof performing their post-EPU safety functions, including meeting the requirements of GL89-10 and GL 96-05.The reconstitution determined that all affected valves have positive periodic verification(PV) margin and all valves are within their respective PV testing intervals as defined byGL 89-10 / GL 96-05 requirements. Additionally, because the valves meet the PVrequirements of GL 96-05, they also meet the requirements of the ASME OM code case(i.e., OMN-1 code case relies on the periodic verification testing program set-up by theMNGP GL 89-10 / 96-05 testing program).Finally, the MNGP IST program establishes (under ASME OMN-1 Code Case) a testinterval for a given MOV based on risk and margin up to a maximum of 10 yearsbetween tests. The test interval requirements of the MNGP IST program are notimpacted by the changes from the reconstitution of the MNGP MOV program.See Enclosure 2 for a markup of L-MT-08-52 and L-MT-08-039 reflecting thesechanges.Page 53 of 80 L-MT-12-114Enclosure 1References24-1 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), " MonticelloExtended Power Uprate (USNRC TAC MD8398): Acceptance ReviewSupplemental Information," L-MT-08-039, dated May 28, 2008. (ADAMSAccession No. ML081490639)24-2 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "LicenseAmendment Request: Extended Power Uprate (TAC MD9990)," L-MT-08-052,dated November 5, 2008. (ADAMS Accession No. ML0832301 11)Page 54 of 80 L-MT-12-114Enclosure 1ITEM 25 -SHROUD SCREENING CRITERIA FLAW EVALUATION ANDRECIRCULATION LINE BREAK (RLB) LOADSNRC REQUESTED INFORMATION: GEH issued Safety Communication SC-09-03 in2009 concerning Shroud Screening criteria flaw evaluation and Recirculation Line Break(RLB) loads. Make a statement concerning the results of the NSPM review of that SCand identify the scope of any corrective actions (if necessary) that are being taken.NSPM RESPONSE:GEH Safety Communication 09-03 determined that faulted shroud loading conditionsdid not consider RLB loads in screening for several plants. NSPM entered thiscommunication into the MNGP corrective action program and requested GEH reviewthe MNGP faulted shroud loading evaluation.GEH determined that the MNGP shroud loading evaluation did not include RLB loads.NSPM corrected this condition by having GEH provide revised faulted shroud loadingvalues including RLB loads. The loads evaluated were applicable to EPU conditions.NSPM then updated the shroud inspection criteria evaluation for the MNGP with thenew faulted shroud loading values and determined there was no effect on the inspectioninterval for the shroud as a result of the additional RLB loads.There are no proposed changes to EPU documentation resulting from this response.Page 55 of 80 L-MT-12-114Enclosure 1ITEM 26 -HIGH ENERGY LINE BREAK (HELB) ANALYSIS RECONSTITUTIONNRC REQUESTED INFORMATION: NSPM identified the following changes to theHELB Analysis:1. Environmental profiles changed due to final resolution of various corrective actionsdiscussed in L-MT-08-052, Enclosure 5.2. Completion of detailed design of modifications3. Changes in GOTHIC software versions4. Final assessment of cracks for new feedwater piping design is not yet complete.NRC requested that NSPM discuss changes to HELB, provide tables of changedprofiles, temperatures, flood levels, etc. NSPM should state that licensee has notchanged the method for determining break locations. NSPM should state that theprogram maintains compliance with the Giambusso letter and IEB 79-01 B. NSPMshould reference the discussion in L-MT-10-025. Complete discussion regarding jetimpingement and pipe whip. NSPM should state that there are no new break locationsor if new break locations why are they acceptable.NSPM RESPONSE:Changes to the HELB model and CodeSince November 2008, the MNGP HELB program performed a reconstitution to providegreater accuracy in calculations representing conditions in the Reactor and Turbinebuildings following a HELB event. This reconstitution resulted in enhancements to theGOTHIC model which incorporated better modeling practices and more accuratebreak/crack characteristics. As a result of an internal audit of the model, severalchanges were made to the program. It should be noted that the enhancements wereapplied to the model, and as such, changes were applied once the HELB conditionswere reanalyzed. The enhancements are:1. Adjust the liquid drop size to the GOTHIC manual recommended size of 0.0039inches.2. Adjust the wall and floor HTC (heat transfer coefficient) to better account fortransition from vapor to liquid heat transfer.3. Adjust the boundary condition pressure to more closely match the break pressurewhere there was a substantial difference.The updated HELB calculations did not incorporate any changes in pipe breakmethodology. Most changes involved a re-analysis of breaks using more conservativeassumptions of mass and energy release with more accurate plant conditions. Theliquid break calculation inputs were updated to consider:1. Double-ended break flow to include flow from both ends of postulated breaks.Page 56 of 80 L-MT-12-114Enclosure 12. System depletion to include mass and energy that exists in system piping andpressure vessels.3. A conservative change in the assumption for isolation valve stroke time fromASME Section XI Limiting Stroke Time to the value listed as the maximum valveoperating time in the USAR.4. A conservative change for flow reduction assumptions with valve closure. CLTPanalysis assumed flow was reduced proportional to isolation valve percent closedposition. The EPU analysis assumed 100% break flow until isolation valve wasfully closed.5. The liquid mass from fire protection sprinkler systems postulated to actuate fromHELB events was included.6. Upgrade computer code from GOTHIC version 4.0 to GOTHIC version 7.1 orlater versions.Steam breaks also have been updated to consider the above conditions. The onlyscenarios not accounting for all of the above were steam breaks isolated by steamisolation valve closure. These analyses assume the break flow reduces proportionallywith the valve as it closes. The break flow decreases throughout the valve closure time.The initial analyses performed to support the EPU LAR submittal used GOTHIC version7.1 as the evaluation tool. For the reconstitution of HELB performed after the LARsubmittal, version 7.2a was used. Both versions of GOTHIC (7.1 and 7.2a) have beenbenchmarked in calculations in accordance with NSPM requirements. Thesebenchmark calculations determined that both versions of GOTHIC are acceptable foruse. Both versions are supported by the software developer, and meet the requirementsfor use in evaluation of safety related activities as they are included in the MNGPSoftware Quality Assurance (SQA) Program.Because no fundamental change to HELB methodology occurred, the program remainsin compliance with the Giambusso Letter and IEB 79-01 B, as implemented in the MNGPdesign and licensing bases. Therefore, a 10 CFR 50.59 evaluation was not required forthe reconstitution effort, and MNGP remains compliant with the statements regardingapplicability of 10 CFR 50.59 provided in NRC correspondence L-MT-10-025, datedApril 6, 2010.The following tables, Tables 26-1 and 26-2 are provided to update the HELBtemperatures, pressures and flood levels.Page 57 of 80 L-MT-12-114Enclosure 1Updated temperatures, pressures and flood levels (Note: underlined values represent CLTP to EPU increases):Turbine Building: (Note: Turbine Building volumes were consolidated from 44 volumes to 37 to more accurately represent areas thathad been partitioned in the model but did not have a physical door or wall separating the volumes. CLTP columns with an

• indicate thatthe effects of the consolidation no longer permit a direct comparison of these volumes)Table 26 Turbine Building HELB Results [ PU Analys RsultsEQ CLTP values from EQ Part BPart B Turbine Building Maximum MaxmuMximumVolume Volume Description Presur Temperatur Level Pressure Temperature Flooding_____) (degF) (ft) psia deg F ft1 Motor Control Center B-33A & B, and B-12 1.2 2126 15.3 212.2 5.582 Turbine Building Southeast Corner near MCC B-33 3 15.27 212.2 2.613 Lube Oil Reservoir and Reactor Feed Pump Area1 212.3 3 15.13 212.3 2.254 Lube Oil Storage Tank Room 214.8 105.6 0 14.75 104.6 05 Turbine Building Corridor Northeast 911' El 1.24 3 14.82 204.1 2.856 Water Box Scavenging System Area 1 1 3 14.8 188.2 3.027 Turbine Building Sump & MCC B-31 Area 3 14.71 106.03 08 4 KV and Load Center Division A 0 14.71 106.6 09 Hallway outside Air Ejector Room Entrance Door 15 14.5 15.3 * * *10 Hydrogen Seal Oil Unit and Condensate Pump Area North 1 187.3 3 15.01 139.9 0.1311 Hydrogen Seal Oil Unit and Condensate Pump Area South 1525 19 13 * * *12 Mechanical Vacuum Pump Area 1.26 189.4 6 14.73 203.7 0.0513 Condensate Backwash -Receiving Tank Area ..27 184 614.73 120.9 0.0314 Air Ejector Room 154 2 29 15.26 284.95 1.4415 Turbine Basement Condenser Area i1.58 211.9 5 15.79 247.15 1.1216 Pipe Tunnel to Intake 9.1 14.76 115.14 017 Intake EntryArea 14.75 104.9 018 Intake Structure Pump Room 1 0U 14.75 104.58 019 Circ Water Pump Area 192. 14.76 104.6 020 Turbine Building 931'El East 120.1 0 14.71 171.4 0.2321 FW Pipe & Cable Tray Penetration Room I094 0 14.84 149.8 0.0122 Turbine Building 931' El East Vent Chase 211 15.08 211.3 0.0423 Auxiliary Boiler Room 14.7 10. 0 14.7 104 0Page 58 of 80 L-MT-12-114Enclosure 1Thhl~ 2R~1 -Tiirhin~ Riiilrlinn HEI B Rc~.ilt~3011 E~nfl.lId~ Annkinlin D*.mH.Tabe 2 -1* -T b .-L R u 9U0 n.a.Mew... ..ewEQ CLTP values from EQ Part BPart B Turbine Building M MaxVolume Description Pressure Temperature Level Pressure Temperature Flooding__(po) (deg F) (f0t psia deg F ft24 East Electrical Equipment Room and 13 EDG 14.7 104.3 0 14.7 104 025 Hot Machine Shop 14.94 107.9 0 14.7 104 026 Turbine Building Corridor Southeast Corner 931' El 15.12 178.4 0 14.85 187.9 0.0627 Turbine Building Corridor Northwest and Hallway to No. 11 15.14 174.1 0 14.8 105 0D.G. Entry 931' El28 No. 11 Diesel Generator Room Entry Area 14.7 10.6 0 14.7 104 029 No. 11 Diesel Generator Room 14,7 0 14.7 104 030 No. 12 Diesel Generator Room 14.7 0 14.7 104 031 4KV and Load Center Division B 14.84 131.2 0 14.71 115.78 032 Stator Water Cooling Area 14.84 129-5 0 14.71 118.34 033 Valve Operating Gallery and Condensate Demin Panels Area 15.21 0 15 186.3 0.0134 Turbine Building Railroad Car Shelter 15.16 203.4 14.98 195.92 0.0435 Cable Chase 941' El 124.4 0 14.71 123.58 036 Turbine Building Northwest Stairway from 941' to 951' El 15.18 200. 0 14.71 104.1 037 Turbine Deck 951' to 1004' El 15.16 248.2 0.2 15.08 231.5 0.35Page 59 of 80 L-MT-12-114Enclosure 1Reactor Building: (Note: LOCA GOTHIC results included for EQ peaks)Table 26 Reactor Building HELB ResultsEPU HELB/LOCA Analvsis ResultsEQ Maximum Maximum Maximum CLTP values from EQ part BPart B Reactor Building Volume Leve Temp. Pressure Flooding Temp. PressureVolume Description F I ft deg F psia1234567891011121314151617181920212223242526RHR and Core Spray Pump Room, Division IRHR and Core Spray Pump Room, Division I StairwayRHR and Core Spray Pump Room, Division IIRHR and Core Spray Pump Room, Division II StairwayRCIC RoomReactor Bldg Elevation 896' Equipment and Floor Drain TankCRD Pump RoomHPCI RoomSuppression Pool Area -NortheastSuppression Pool Area -SoutheastSuppression Pool Area -SouthwestSuppression Pool Area -NorthwestEast Shutdown Cooling RoomB.1.9 CRD Hydraulic Control Unit Area -East 935' ElevationTIP RoomSteam ChaseTIP Drive RoomCRD Hydraulic Control Unit Area & HVAC Areas- NW 935' ElCST Pump Transfer DW Equip Hatch Entrance Areas -SW 935'West Shutdown Cooling Room 21 1/3B B.1.14 PIPE Chase 974'Pipe Chase 974'MCC and Standby Liquid Control System Area -East 962' ElContaminated Tool Storage -East 962' ElMG Set Airlock962' North of Reactor Shield WallReactor Recirculation Pumps MG Set Room116.714.960.05142.9714.860 124.3 14.9 0.01 142.97 14.850.6 146.7 14 0.05 143.8 14.980 143.9 14.95 0 144.4 14.97.6 288.9 15.08 0.05 256 15.150.7 28 15.81 3.95 263.6 15.630.6 293.7 15.01 4.38 240.4 15.190 0 272.6 16.050. 20. 57 0.01 187.6 15.590.6 2 0 159.9 15.590. 0.9 1.9 0 158.7 15.590. 2 1 0.01 193 15.590 174 14.82 0.24 127.3 14.880 185.7 14.82 0.27 153.3 14.830.1 211.8 15.03 0.05 209.6 15.35.8 3109 20.88 6.68 311.3 21.160 2 0 222.4 15.140 22 14.92 0.68 208.1 15.110.1 291 14. 0.53 175.9 15.13S 148 0 112.5 15.140 18.5 14.81 0 112.2 14.870 3 14.8 0 170.4 14.840 17. 4.82 0 143.7 14.870 04 14.7 0 104 14.70 1 1 14.82 145.8 14.850 118 14.71 0 109.1 14.89Page 60 of 80 L-MT-12-114Enclosure 1I able 2.6 Rem o~r BuildIing flr-Lo Results EIU I1ELB/LOCA Aflas IS KsuItsEQ Maximum Maximum Maximum CLTP values from EQ part BPart B Reactor Building Volume Level Temp. Pressure Flooding Temp. PressureVolume Description ft d.gF Psia .ft deg F psia27 Cooling Water Pump and Chiller Area -West 962' El 0 245.8 14.86 0.01 203.6 14.9928 RWCU Pump Room B and Hallway 1 212.2 14.88 0.38 216.7 15.8529 RWCU Pump Room A 1 212.5 14.94 0.3 214.6 15.8530 RWCU Heat Exchanger Area 1 221.1 17.59 0.27 220.5 17.231 RWCU Area Behind Hx Exchanger 1j 1. 17.58 0.27 188.3 17.1932 RWCU Isolation Valve Room 218.6 143 0.19 164.1 15.8533 MCC and Instrument Rack C-55 Area 0 14.88 0 128.3 14.9934 CGCS-A Recombiner Area 0 J1§ 14.81 0.005 168.3 14.8335 Cooling Water Heat Exchanger and CGCS-B Recombiner Area 0 207.4 14.81 0.02 207.8 14.8436 Standby Gas Treatment System B -Train Room 0 1 14.84 0 142.4 14.8837 Standby Gas Treatment System Fan Room 0 178.8 14.84 0 112.8 14.8838 Standby Gas Treatment System Airlock 0 100.3 14.7 0 100 14.739 Standby Gas Treatment System A -Train Area 0 129.5 14.85 0.01 215.3 14.8740 Reactor Plenum Room 0 128.4 14.83 0 126.2 14.8441 Reactor Recirculation MG Set Fan Room 0 117. 14.7 0 106.9 14.8842 Corridor Outside Main Exhaust Plenum 0 207.2 14.81 0.01 204.7 14.8543 Skimmer Surge Tank and Fuel Pool Pumps Area 0 123.6 14.8 0.01 128.3 14.8344 Snubber Rebuild and Decontamination Area 0 128.8 14.8 0.01 160.8 14.8245 Northeast Stairway 1001' El 0 2D6 14.8 0.01 169.7 14.8546 Contaminated Equipment Storage Area 0 116.1 14.79 0.02 219.2 14.8647 Northwest Stairway 1001' El 0 168.3 14.81 0 101.5 14.8448 Refueling Floor 1027' El 0 1.39.7 1 !478 0.01 131.1 14.8Page 61 of 80 L-MT-12-114Enclosure 1Pipe Whip and Jet Impingement:Pipe whip and jet impingement loads resulting from high energy pipe breaks are directlyproportional to system pressure. Because EPU conditions do not result in an increase inthe pressure considered in the high-energy piping evaluations, there is no increasedpipe whip or jet impingement loads on HELB targets or pipe whip restraints.Installation of new condensate and feedwater pumps with associated pipingmodifications include an evaluation of HELB target impact as part of the plannedmodification. Pipe whip and jet impingement analyses are pending for the Condensatepump, Feedwater pump and piping replacement modifications.New Break Locations:EPU modification to the feedwater system resulted in one new limiting (for flooding)postulated 14" line crack at the inlet to the 14 feedwater heater. The results of thisevaluation indicated slightly higher temperatures near the end of some Turbine Buildingbounding temperature profiles; however, there was no resultant impact to EQequipment. The new crack did not result in any new jet impingement or pipe whiptargets. Peak profile temperatures increased in volumes that did not contain EQequipment. No mild volumes changed to harsh with this additional HELB analysis.Changes to EPU documentationThe following locations contained information related to HELB in the EPUdocumentation:L-MT-08-052, Enclosure 5, Sections 2.2.1.2, 2.2.2.1and associated tables are markedup to indicate the changes identified in this review.L-MT-08-052, Enclosure 17 -Provided a section entitled "NSPM Revised Response toNRC Electrical Engineering Branch (EEEB) Review Item documented in L-MT-08-042."Included within that response NSPM provided a document entitled "Monticello ExtendedPower Uprate Task Report T1004 -Environmental Qualification." Also. included weredraft markups to EQ files. This information is superseded by the revised informationprovided in this item and the information provided in item 27. No further markup isprovided.L-MT-09-044, EMCB RAIs 3(a), 5, 6(a), 6(b), 7, 8, 12(b), 13 including Table 1, 17(a) and17(b) are marked up to indicate the changes identified in this review.L-MT-09-046, SBPB RAI 2.5-1See Enclosure 2 for a markup of EPU documentation reflecting these changes.Page 62 of 80 L-MT-12-114Enclosure 1References26-1 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "LicenseAmendment Request: Extended Power Uprate (TAC MD9990)," L-MT-08-052,dated November 5, 2008. (ADAMS Accession No. ML0832301 11)26-2 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), " MonticelloExtended Power Uprate: Response to NRC Mechanical and Civil EngineeringReview Branch (EMCB) Requests for Additional Information (RAIs) dated March28, 2009 (TAC MD9990)," L-MT-09-044, dated August 21, 2009. (ADAMSAccession No. ML092390332)26-3 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "MonticelloExtended Power Uprate: Response to NRC Balance of Plant Review Branch(SBPB) Request for Additional Information (RAI) dated March 23, 2009 (TAC No.MD9990)," L-MT-09-046, dated June 12, 2009. (ADAMS Accession No.ML092390332)Page 63 of 80 L-MT-12-114Enclosure 1ITEM 27 -EQUIPMENT QUALIFICATION PROGRAM RECONSTITUTIONNRC REQUESTED INFORMATION: EQ files were in draft form when presented inEPU LAR. Confirm EQ files complete to NRC. MNGP EQ program meets Division ofOperating Reactors (DOR) Guidelines and USAR requirements. Identify that thecalculations, radiation levels and temperature changes have been reconstituted.Identify what has changed (all changed values).NSPM RESPONSE:Environmental Qualification Extended Power Uprate UpdateThe Environmental Qualification (EQ) Program has been reconstituted to incorporatethe environmental conditions associated with increasing reactor thermal power from1775 MWt to 2004 MWt. Revised environmental conditions were incorporated intodocument EQ-PART-B, Environmental Specifications. All equipment within the EQProgram was evaluated to ensure that qualification would be maintained in accordancewith 10 CFR 50.49 under these new conditions. Changes to the EQ files and EQ-PART-B are complete.The EQ Program at MNGP was developed to the guidance and requirements containedin the DOR Guidelines and category II of NUREG-0588 for equipment that predates theissuance of 10 CFR 50.49 as delineated in 10 CFR 50.49 paragraph (k). The EQProgram maintains compliance with 10 CFR 50.49 with incorporation of EPU plantconditions.Normal Ambient TemperatureThere is no impact of EPU conditions on normal plant temperature inputs to qualified lifeassessments. Normal plant area ambient temperature will continue to be monitored bythe EQ program in lieu of using the maximum design temperature for assessingqualified lifetimes.Normal and Accident Radiation EvaluationEnvironmental Qualification radiation analyses are based on the total combined normaland accident doses. Under EPU, the normal plant doses are generally increased by13% over CLTP doses while some steam line containing areas also experienceincreased doses during shut-down due to moisture carry-over issue related to EPU. Theaccident dose calculation determined increases ranging from 2.5% to 8.3% for EPUover CLTP conditions. The normal and accident EPU radiological conditions have beenincorporated into EQ-PART-B and the equipment specific qualification files.Qualification is maintained with the exception of two level transmitters in the Toruscompartment, LT-7338A and LT-7338B. These transmitters were replaced forcompliance with the EQ program under EPU conditions.Page 64 of 80 L-MT-12-114Enclosure 1The beta dose specified for the Drywell in the MNGP EQ Program is taken from theDOR Guidelines as an unshielded 200 Mrad dose which was developed for a 4,100MWt reactor. Therefore, there is significant beta dose margin included in the beta doseas it applies to MNGP because there is no increase in the Drywell beta dose for EPU.Drywell Environmental ConditionsThe time-dependent Drywell EQ accident temperature profile is graphically comparedfor CLTP and EPU plant conditions in Figure 27-1.Figure 27 Drvwell Pre/Post-EPU EQ Temperature ComparisonDrywell Pre/Post-EPU EQ Temperature Comparison3502S0I200ISOII100 I.-- -,0---- 0 1.001+01 1.---- 02 --- I.E 1. ,* ... I I 1.OOE,0,1.0OE-02 1.OOE,.O1 1.00E+O0 1.00(.401 1.00(0e02 1.00(4.03 1.00(004 1.00E40.O 1.001E+06 1.00E+07 1.001.,06Time (seconds)-EPU Temperature --CLTP TemperatureThe CLTP EQ Drywell accident temperature did not bound the peak EPU accidenttemperature in the short term (by 30F within the first 600 seconds) and also at greaterthan a million seconds in the long term. Also, the EPU EQ Drywell accident pressurehas increased to 58.8 psia vs. the CLTP accident pressure of 54.2 psia. Thesechanges have been incorporated into EQ-PART-B, Environmental Specifications, asshown in Figure 27-2. All affected EQ components are now evaluated to these newaccident conditions in their respective qualification files and remain qualified.Page 65 of 80 L-MT-12-114Enclosure 1Figure 27 Post-EPU Drywell Temperature and Pressure ProfilesDrywell Temperature and Pressure Profiles350 7060300// \ 50 020 T iiE0 /2/ 150 ___I20100 101.OE-3 1.OE-2 1,OE-1 1.OE+O 1.OE+1 1.OE+2 1.OE+3 1.OE+4 1.OE+5 1.OE+6 1.OE+7 1.OE+8Time (Seconds)-Temperature --PressureDrywell flooding is not affected by EPU conditions and remains at the 922-footelevation. The maximum ECCS flow (from the four RHR and two CS pumps) is 25,560gpm, which is bounded by the calculated flow through containment vents at 27,233gpm.Reactor Buildinq Environmental ConditionsThe comparison of CLTP and EPU accident conditions for HELB has been submittedunder Item 26. Non-EPU issues associated with the previous HELB models werereconstituted which led to revision of EQ parameters. These issues were resolvedduring the EPU update and contributed to many of the large changes in calculatedaccident conditions. Some decreases in post-accident submergence levels areattributed to model enhancements.There are four volumes that are now considered a harsh temperature environmentduring a HELB with the new accident conditions. These volumes are 13, 33, 37 and 47.Volumes 13 and 33 were already considered harsh environments. The equipment inthese volumes is now evaluated to the higher EPU accident temperatures in thequalification files and qualification is maintained. Equipment contained in volume 37supports the Standby Gas Treatment system, which is only required for design basesLOCA conditions. LOCA does not create a harsh temperature environment during thePage 66 of 80 L-MT-12-114Enclosure 1time the Standby Gas Treatment equipment is required to function. Volume 47 does notcontain EQ end devices.The comparison of CLTP to EPU accident temperatures for post-LOCA heat up isshown in Table 27-1. Volume 16 is now considered a harsh environment during a DBALOCA. However, this volume is already a harsh environment during a HELB accident.Table 27-1, Post-LOCA Temperature ComparisonReactor EPU CLTPBuilding Temperature TemperatureVolume (OF) (OF)1 109.7 142.972 111.5 142.973 146.7 143.84 142.5 143.85 112.6 109.96 140.3 140.47 123.9 116.38 <125 <1259 179.1 160.410 179.1 159.911 179.1 158.712 179 157.313 118.3 112.614 115.6 107.515 122.5 106.316 154.4 135.217 115.7 108.118 121.4 109.319 121.4 108.320 119.9 112.521 118.5 112.222 119.1 106.723 118.2 105.424 104 10425 119.1 113.926 118.2 109.127 121.3 109.128 124.7 12029 124.1 120.130 130.1 120.231 132.2 120.232 125.4 120.233 121.3 115.6Page 67 of 80 L-MT-12-114Enclosure 1Reactor EPU CLTPBuilding Temperature TemperatureVolume (OF) (OF)34 119.3 107.935 119.3 107.836 129.1 134.437 129.1 112.838 100 10039 129.5 126.340 116.7 105.641 117.2 106.942 119.2 104.643 114.3 109.744 117.8 108.145 115.2 10446 116.1 107.247 118.8 10048 115.4 103.9EQ equipment has been evaluated to the new conditions associated with EPU in eachequipment specific qualification file in terms of pressure, temperature and flooding.However, the revised heat balance for an increased as-built FW temperature (see item10) remains to be evaluated in terms of bounding EQ profile. Changes to the boundingprofile are expected to be very minor (as discussed in Item 10), as the overall peaktemperatures are not affected. Final documentation will assure compliance with the EQprogram. Qualification is maintained for all equipment (note: two level transmitters inthe Torus compartment, LT-7338A and LT-7338B required replacement to maintainqualification).Turbine Building Environmental ConditionsThe EPU HELB evaluation identified areas within the Turbine Building that changedfrom a mild to harsh environment. EQ-PART-B volumes 7, 8, 9, 10, 11, 13, 16, 27, and36 become harsh under EPU. Walkdowns of these volumes were performed to identifysafety related equipment in these new harsh areas that may fall under the scope of theEQ program. No discrete equipment was identified; however, some safety-relatedcabling was discovered. These cables already existed in the EQ Program. The newlocations were incorporated into the EQ Program Master List and the cable files wereupdated to include turbine building conditions.In addition to the cable identified above, there is a single Valcor solenoid valve in theEQ program located in Volume 21. The solenoid valve remains qualified for thepostulated conditions in the TB under EPU.Page 68 of 80 L-MT-12-114Enclosure 1Previous NRC SubmittalsL-MT-08-052, Enclosure 17, provided a revised response to information submitted in L-MT-08-042.The NRC requested that NSPM provide the full and completed EQ analysis. The NRCsaid this should include any reanalysis, re-qualification, or replacement of equipment.The licensee must also describe how the equipment was evaluated (e.g., calculations,assessments, etc.) and show how the equipment remains bounded (i.e., provide theoriginal design parameters and the updated values including the supportingcalculations).At that time the "full EQ analysis" was not completed. In order to support NRC review,NSPM submitted task report T1004 and draft markups to EQ files. The drafts of thefinal EQ file changes included expected changes in temperature, pressure, andsubmergence by volume for the reactor building were provided.As indicated above the full EQ analysis is now completed with only minor exceptions.Therefore, NSPM is including in this response a comparison of CLTP vs EPU for theReactor building. Tables 27-2, 27-3, 27-4 and 27-5 provide comparisons for pressure,water level and temperature between the final EPU analysis and the EQ-Part-B resultsthat represent CLTP conditions. Therefore, statements in the task report T1004 and thedraft markups to EQ files are no longer applicable. This work is now complete andsuperseded by the data provided in Tables 27-2, 27-3, 27-4 and 27-5 below.Page 69 of 80 L-MT-12-114Enclosure 127-2 Reactor Building HELB Peak Ambient Pressure ComparisonsRB Volume EPU Pressure EQ-Part-B CLTP Delta(psia) Pressure (psia) (psia)1 14.96 14.86 0.12 14.95 14.85 0.13 14.96 14.98 -0.024 14.95 14.97 -0.025 15.06 15.15 -0.096 15.81 15.63 0.187 15.01 15.19 -0.188 16.22 16.05 0.179 15.79 15.59 0.210 15.79 15.59 0.211 15.79 15.59 0.212 15.79 15.59 0.213 14.82 14.88 -0.0614 14.82 14.83 -0.0115 15.03 15.3 -0.2716 20.88 21.16 -0.2817 15.02 15.14 -0.1218 14.92 15.11 -0.1919 14.9 15.13 -0.2320 14.83 15.14 -0.3121 14.81 14.87 -0.0622 14.82 14.84 -0.0223 14.82 14.87 -0.0524 14.7 14.7 025 14.82 14.85 -0.0326 14.71 14.89 -0.1827 14.86 14.99 -0.1328 14.86 15.85 -0.9929 14.94 15.85 -0.9130 17.59 17.2 0.3931 17.58 17.19 0.3932 17.43 15.85 1.5833 14.86 14.99 -0.1334 14.81 14.83 -0.0235 14.81 14.84 -0.0336 14.84 14.88 -0.0437 14.84 14.88 -0.0438 14.7 14.7 0Page 70 of 80 L-MT-12-114Enclosure 1RB Volume EPU Pressure EQ-Part-B CLTP Delta(psia) Pressure (psia) (psia)39 14.85 14.87 -0.0240 14.83 14.84 -0.0141 14.7 14.88 -0.1842 14.81 14.85 -0.0443 14.8 14.83 -0.0344 14.8 14.82 -0.0245 14.8 14.85 -0.0546 14.79 14.86 -0.0747 14.81 14.84 -0.0348 14.78 14.8 -0.02Page 71 of 80 L-MT-12-114Enclosure 127-3 Reactor Building HELB Water Level ComparisonsRB Volume EPU Level EQ-Part-B Level, Delta(inches) CLTP (inches) (inches)1 7.2 0.6 6.62 0 0.12 -0.123 7.2 0.6 6.64 0 0 0.005 7.2 0.6 6.66 8.4 47.4 -39.007 7.2 52.56 -45.368 7.2 13.32 -6.129 7.2 0.12 7.0810 7.2 0 7.211 7.2 0 7.212 7.2 0.12 7.0813 0 2.88 -2.8814 0 3.24 -3.2415 1.2 0.6 0.616 69.6 80.16 -10.5617 0 0 0.0018 0 8.16 -8.1619 1.2 6.36 -5.1620 1.2 0 1.2021 0 0 0.0022 0 0 0.0023 0 0 0.0024 0 0 0.0025 0 0 0.0026 0 0 0.0027 0 0.12 -0.1228 14.4 4.56 9.8429 14.4 3.6 10.8030 12 3.24 8.7631 12 3.24 8.7632 14.4 2.28 12.1233 0 0 0.0034 0 0.06 -0.0635 0 0.24 -0.2436 0 0 0.0037 0 0 0.0038 0 0 0.00Page 72 of 80 L-MT-12-114Enclosure 1RB Volume EPU Level EQ-Part-B Level, Delta(inches) CLTP (inches) (inches)39 0 0.12 -0.1240 0 0 0.0041 0 0 0.0042 0 0.12 -0.1243 0 0.12 -0.1244 0 0.12 -0.1245 0 0.12 -0.1246 0 0.24 -0.2447 0 0 0.0048 0 0.12 -0.12Page 73 of 80 L-MT-12-114Enclosure 127-4 Reactor Building HELB Peak Temperature ComparisonRB EPU EQ-Part- Delta (OF)Volume Temperature(° BTemperature,F) CLTP (-F)1 116.7 119.2 -2.52 124.3 138.1 -13.83 117.3 119.3 -2.04 143.9 144.4 -0.55 288.9 256 32.96 282 263.6 18.47 293.7 240.4 53.38 296.1 272.6 23.59 202.9 187.6 15.310 202.7 159.9 42.811 202.9 158.7 44.212 203.4 193 10.413 172.4 127.3 45.114 185.7 153.3 32.415 211.8 209.6 2.216 310.9 311.3 -0.417 273.4 222.4 51.018 272.8 208.1 64.719 269.1 175.9 93.220 209 112.5 53.821 118.5 112.2 6.322 193.1 170.4 22.723 175.4 143.7 31.724 104.4 104 0.425 191.1 145.8 45.326 118.2 109.1 9.127 245.8 203.6 42.228 212.2 216.7 -4.529 212.5 214.6 -2.130 221.1 220.5 0.631 215.7 188.3 27.432 218.6 164.1 54.533 243.7 128.3 115.434 198.2 168.3 29.935 207.4 207.8 -0.436 178.7 142.4 36.337 178.8 112.8 66.0Page 74 of 80 L-MT-12-114Enclosure 1RB EPU EQ-Part- Delta (OF)Volume Temperature(* BTemperature,F) CLTP (-F)38 100.3 100 0.339 129.5 215.3 -85.840 128.4 126.2 2.241 117.2 106.9 10.342 207.2 204.7 2.543 123.6 128.3 -4.744 128.8 160.8 -32.045 206 169.7 36.346 116.1 219.2 -103.147 168.3 101.5 66.848 140.5 (139.7) 131.1 9.4Page 75 of 80 L-MT-12-114Enclosure 127-5 Difference Between CLTP & EPU Reactor Bldgfor Post-LOCA and SBAVolume TemperaturesVolume HELB Volume Description EPU CLTP EPU(OF) (OF) Change (OF)1 RHR and Core Spray Pump Room, 109.7 142.97 -33.27Division I2 RHR and Core Spray Pump Room, 111.5 142.97 -31.47Division I Stairway3 RHR and Core Spray Pump Room, 146.7 143.8 2.9Division II4 RHR and Core Spray Pump Room, 142.5 143.8 -1.3Division II Stairway5 RCIC Room 112.6 109.9 2.76 Reactor Bldg Elevation 896' 140.3 140.4 -.01Equipment and Floor Drain Tank7 CRD Pump Room 123.9 116.3 7.68 HPCI Room <125 <125 09 Suppression Pool Area -Northeast 179.1 160.4 18.710 Suppression Pool Area -179.1 159.9 19.2Southeast11 Suppression Pool Area -179.1 158.7 20.4Southwest12 Suppression Pool Area -179 157.3 21.7Northwest13 East Shutdown Cooling Room 118.3 112.6 5.714 CRD Hydraulic Control UnitArea- 115.6 107.5 8.1East 935' Elevation15 TIP Room 122.5 106.3 16.216 Steam Chase 154.4 135.2 19.217 TIP Drive Room 115.7 108.1 7.618 CRD Hydraulic Control Unit Area 121.4 109.3 12.1and HVAC Areas -NW 935' El19 CRD Hydraulic Control Unit Area 121.4 108.3 13.1and HVAC Areas -SW 935' El.20 West Shutdown Cooling Room 119.9 112.5 7.421 PIPE Chase 974' 118.5 112.2 6.322 MCC and Standby Liquid Control 119.1 106.7 12.4System Area -East 962' El23 Contaminated Tool Storage -East 118.2 105.4 12.8962' El24 Recirc M/G Set Airlock 104 104 025 962' North of Reactor Shield Wall 119.1 113.9 5.2Page 76 of 80 L-MT-12-114Enclosure 1Volume HELB Volume Description EPU CLTP EPU(OF) (OF) Change (°F)26 Reactor Recirculation Pumps MG 118.2 109.1 9.1Set Room27 Cooling Water Pump and Chiller 121.3 109.1 12.2Area -West 962' El28 RWCU Pump Room B and 124.7 120 4.7Hallway29 RWCU Pump Room A 124.1 120.1 430 RWCU Heat Exchanger Area 130.1 120.2 9.931 RWCU Area Behind Hx Exchanger 132.2 120.2 1232 RWCU Isolation Valve Room 125.4 120.2 5.233 MCC and Instrument Rack C-55 121.3 115.6 5.7Area34 CGCS-A Recombiner Area 119.3 107.9 11.435 Cooling Water Heat Exchanger 119.3 107.8 11.5and CGCS-B Recombiner Area36 Standby Gas Treatment System B 129.1 134.4 -5.3-Train Room37 Standby Gas Treatment System 129.1 112.8 16.3Fan Room38 Standby Gas Treatment System 100 100 0Airlock39 Standby Gas Treatment System A 129.5 126.3 3.2-Train Area40 Reactor Plenum Room 116.7 105.6 11.141 Reactor Recirculation MG Set Fan 117.2 106.9 10.3Room42 Corridor Outside Main Exhaust 119.2 104.6 14.6Plenum43 Skimmer Surge Tank and Fuel 114.3 109.7 4.6Pool Pumps Area44 Snubber Rebuild and 117.8 108.1 9.7Decontamination Area45 Northeast Stairway 1001' El 115.2 104 11.246 Contaminated Equipment Storage 116.1 107.2 8.9Area47 Northwest Stairway 1001' El 118.8 100 18.848 Refueling Floor 1028' El 115.4 103.9 11.5Page 77 of 80 L-MT-12-114Enclosure 1Updated T1004 RecommendationsItem 1, Radiation DosesQualification is maintained for EPU radiological conditions and documented in theequipment specific qualification files for the following items:* General Electric Fan Motors* Microswitch Limit SwitchesRosemount Model 1153 Series A transmitters in the Torus compartment at functionallocations LT-7338A/B were replaced due to the increased radiological conditions.Item 2, Turbine Building Areas Reclassified as EQ HarshThe associated EQ Files have been updated to ensure the cables routed through thenewly created harsh Turbine Building areas under EPU are addressed.Item 3, Post-LOCA Heatup in RBNew EPU post-LOCA heat up conditions have been incorporated in the EQ files. Acorrective action remains associated with completing documentation of replacementintervals due to qualified life changes.Also, Rosemount level transmitters LT-7338A/B were replaced because they would notpossess adequate life margin when accounting for the higher post-LOCA heat upconditions in the Torus compartment.Item 4, ITT Royal CableA thermal lag analysis has been performed to demonstrate cable temperatures willremain below qualification temperatures for RWCU line breaks.Item 5, EQ Supporting Documentation (Configuration Management Issues)EQ-Part-B has been revised for EPU conditions.Update to RAI Response L-MT-09-045Due to several changes in the calculated EPU conditions, MNGP's response to EEEBRAIs dated March 28, 2009, submitted in letter L-MT-09-045 (Reference 27-1), requiressome minor revisions. Revisions to this RAI response do not affect the conclusionsmade by the original submittal.RAI No. 4 -The specific values that were discussed in this response associated withthe submergence profiles have changed. These submergence values have beenreduced. Therefore, the previous response is conservative and bounding.Page 78 of 80 L-MT-12-114Enclosure 1RAI No. 7 -The HELB profiles have changed since this response. ITT Royal cable isevaluated to the new HELB profiles in the equipment specific qualification file and in thethermal lag calculation. The cables remain qualified for EPU conditions.RAI No 13(c) -Pressure switches PS-4664 through PS-4672 have been replaced.Enclosure 2 contains the affected markups.References27-1 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "MonticelloExtended Power Uprate: Response to NRC Electrical Engineering ReviewBranch (EEEB) Request for Additional Information (RAI) dated March 28, 2009,(TAC No. MD9990)," L-MT-09-045, dated May 26, 2009. (ADAMS AccessionNo. ML091470559)Page 79 of 80 L-MT-12-114Enclosure 1ITEM 28 -EFFECTS OF LOSS OF STATOR WATER COOLING ANALYSISNRC REQUESTED INFORMATION: Generic issue from 10CFR21 notificationregarding a slow transient resulting from a loss of stator cooling (LOSC). The NRCunderstands that this event could result in an operating limit maximum critical powerratio (OLMCPR) penalty change. Provide confirmation to NRC that this event iscovered in the EPU analyses.NSPM RESPONSE:NSPM requested GEH perform an evaluation of the LOSC event for the MNGP. Thisevaluation focused on determining if the LOSC event is non-limiting with respect to theGEH reload licensing analysis basis for Monticello EPU Cycle 27. The analysisaddressed all applicable thermal limits including rated power Operating Limit MinimumCritical Power Ratio (OLMCPR) limits, APRM Rod Block Technical Specification (ARTS)Improvement Program power dependent operating limits for off rated core flow and offrated core power conditions, and Linear Heat Generation Rate (LHGR) limits.The LOSC for Monticello is characterized by a turbine load runback, which results in aTurbine Control Valve closure. The turbine runback results in reduced steam flowcapacity in the turbine pressure regulation system, which leads to a significant increasein reactor pressure. The event is terminated by an automatic RPS actuation on highpressure or high flux.These analyses confirm that a LOSC event with Monticello's configuration is not limitingfor OLMCPR, LHGRFAC, or MAPFAC on a cycle-independent basis. Additional caseswere run to confirm this conclusion for the MELLLA+ and CLTP operating domains.The LOSC event is bounded for these plant operating conditions as well.The evaluation of the LOSC event for Monticello confirms that there is sufficient marginto the existing thermal limits. This conclusion remains applicable for future cycles forCLTP, EPU, and MELLLA+.No markup to the EPU documentation is required.Page 80 of 80 L-MT-12-114Enclosure 2ENCLOSURE 2MARKED UP PAGE CHANGES TO EPU DOCUMENTATIONBASED ON THE GAP ANALYSIS RESULTSItem 1 -Markup to L-MT-08-052, Enclosure 14Item 2 -Markup to L-MT-08-039, Enclosure 4, RAIs 2, 3 and 4; and L-MT-08-043,Enclosure 2, RAI 2Item 3 -No Markup requiredItem 4 -Markup to L-MT-09-043, Enclosure 3, EMCB-SD RAI Nos. 5, 6 and 7Item 5 -Markup to L-MT-08-052, Enclosure 5, Section 2.1.7 including Table 2.1-4Item 6 -Markup to L-MT-09-042, Enclosure 1, NRC RAI No. 2(b)Item 7 -Markup to L-MT-08-052, Enclosure 5, Section 2.11.1Item 8 -Markup to L-MT-09-048, Enclosure 1, RAIs 12 and 29; and markup to L-MT-09-073, Enclosure 1, RAts 5 and 6Item 9 -Markup to L-MT-08-052, Enclosure 5, Section 2.7.5 and L-MT-09-048, NRC(SCVB) RAI No. 34Item 10 -No Markup requiredItem 11 -Markup to L-MT-08-052, Enclosure 5, Section 2.2.2.1 including Table 2.2-2dand L-MT-09-044, Enclosure 1, EMCB RAI No. 17Item 12 -Markup to L-MT-08-036, Enclosure 6Item 13 -No Markup requiredItem 14 -Markup to L-MT-08-052, Enclosure 5, Table 1-1Item 1.5 -Markup to L-MT-08-052, Enclosure 5, section 2.5.4.3 and L-MT-09-049,Enclosure 1, RAI 2.8.3-11Item 1.6 -Markup to L-MT-08-052, Enclosure 5, Section 2.2.3, including Table 2.2-3Item 17 -Markup to L-MT-09-049, Enclosure 1, RAI SRXB RAI No. 2.8.3-3Item 18 -Markup to L-MT-09-044, Enclosure 1, EMCB RAI No. 28Item 19 -Markup to L-MT-08-052, Enclosure 5, Section 2.5.4.4 and markup to L-MT-08-052, Enclosure 8.Item 20 -No Markup requiredItem 21 -No Markup requiredItem 22 -Markup to L-MT-09-049, Enclosure 1, RAI SRXB RAI No. 2.8.3-4Item 23 -No Markup requiredItem 24 -Markup to L-MT-08-039, Enclosure 2, RAls 1, 2 and 3, and markup to L-MT-08-052, Enclosure 5, Section 2.2.4Item 25 -No Markup requiredItem 26 -Markup to L-MT-08-052, Enclosure 5, Section 2.2.1.2, Section 2.2.2.1including Tables 2.2-1, 2.2-2a, 2.2-2b and 2.2-2c; L-MT-09-044, Enclosure 1,EMCB RAIs 3(a), 5, 6(a), 6(b), 7, 12(b), 13, 17(a) and 17(b); and L-MT-09-046, Enclosure 1, SBPB RAI 2.5-1Item 27 -Markup to L-MT-09-045, Enclosure 1, RAIs No. 4, 7 and. 13(c)Item 28 -No Markup required100 pages follow FItem 1IENCLOSURE 14IntroductionTwo System Impact Studies (SIS) (References 1 & 2) were performed by the MidwestIndependent System Operator, Inc (MISO) to evaluate the impact of the Monticello NuclearGenerating Plant (MNGP) Extended Power Uprate (EPU) operation on transmissionsystem reliability. The Reference 1 study analyzed an Interconnection Request for 13MWe to ...pprt an EPU Phase , powor ..n.roAc.;.... fo..,,~ng the 200.0. rc-fuc-A-l TheReference 2 study analyzed an Interconnection Request for 60.8 MWe t c .upport an EP,A cn.e.. Phase ..po .o .....r. increac followin.g the 2011 , ro ,.fuol outago. A summary and results of bothIr these studies is provided herein.Design BasisThe design basis for the electrical power system is defined in the MNGP Updated SafetyAnalysis Report (USAR) Sections 1.2.6 and 8.1:"Sufficient normal and standby auxiliary sources of electrical power are provided toattain prompt shutdown and continued maintenance of the plant in a safe conditionunder all credible circumstances. The capacity of the power sources is adequate toaccomplish all required engineered safeguards functions under all postulated designbasis accident conditions.""The plant electrical power system is designed to provide a diversity of dependablepower sources which are physically isolated so that any one failure affecting onesource of supply will not propagate to alternate sources. The plant auxiliary electricalpower systems are designed to provide electrical and physical independence andadequate power supplies for startup, operation, shutdown, and for other plantrequirements which are important to safety."The Nuclear Management Company, LLC (NMC) provided MNGP's docketed position on10 CFR 50 Appendix A, General Design Criteria (GDC) 17 compliance in a letter(Reference 3) dated July 21, 2006, "Response to Generic Letter 2006-02, 'Grid Reliabilityand the Impact on Plant Risk and the Operability of Offsite Power.'" The following is anexcerpt from this letter:"Generally, the NMC-operated plants were licensed to comply with the Atomic EnergyCommission General Design Criteria as proposed on July 10, 1967 (AEC GDC) asdescribed in the plant Final (Updated) Safety Analysis Report. AEC GDC proposedCriterion 39, which provides guidance applicable to the design of the AC electricalpower system supplies to the engineered safety features, states:"Alternate power systems shall be provided and designed with adequateindependency, redundancy, capacity, and testability to permit the functioningrequired of the engineered safety features. As a minimum, the onsite powersystem and the offsite power system shall each, independently, provide thiscapacity assuming a failure of a single active component in each power system.Page 1 of 8 Iltem 1IENCLOSURE 14"Thus, many of the provisions of GDC Criterion 17 are not applicable to the NMCoperated plants, the responses to the questions reflect that the plants are notcommitted to GDC Criterion 17, and the responses do not in any manner commit to orimply compliance with GDC Criterion 17 for the NMC-operated plants."Offsite Power System General DescriptionTransmission Interconnections r--three IThe plant electrical output is connected tthe grid via an on-site switchyard. Existingtransmission outlet facilities consist of two 345 KV, two 230 KV, and three 115 KVtransmission lines as shown in USAR Section 15, Drawing NH-1 78635.threeThe 345 KV portion of the switchyard has positions for connecting the generator output,{twe transmission lines, a 345-230-13.8 KV autotransformer, a 345-13.8 KV transformer, a345-34.5 KV transformer, and a 345-115-13.8 KV autotransformer. The 345 KV bus andcircuit breaker arrangement is based on ultimate d.eyelpment inmt a breaker-and-one-halfsystem. TI ie p it iistallatiuio is a ing bus cc ,,,figurati,,. One 345 KV transmission lineis routed to connect into the 345 KV loop around the Twin Cities Metropolitan Area at theElm Creek Substation. The ether line connects to the 345 KV transmission system at theSherburne CountynSubstatn. *-----The third 345 KV transmission line connects to theFsecond lQuarry Substation near St. Cloud, Minnesota. IThe 230 KV portion of the switchyard is provided to establish an interconnection with thetransmission system of Great River Energy. An autotransformer connects the 345 KV and230 KV busses.The 115 KV portion of the switchyard is connected to the 345 KV bus through anautotransformer. The 115 KV bus is arranged in a ring bus configuration. In addition to theautotransformer connection to the 115 KV bus, there are three transmission lineconnections. One of the three transmission lines connects into the 115 KV transmissionsystem at Lake Pulaski and at Dickinson Substation. The second line connects at HassanSubstation. The third 115 KV line connects to the Sherburne County substation.The 13.8 KV portion of the switchyard is provided to establish reliable power sources tovarious plant equipment. These include the plant auxiliary reserve transformer (1AR);discharge structure transformers (X7, X8); cooling tower fan transformers (X50, X60, X70,X80); transformer XP91, which powers the hydrogen water chemistry cryogenic systempanel, and an alternate feed (through transformer 6) to the training center.Plant Auxiliary Power SuppliesThree transformers are provided to supply the plant with offsite power from the substation.All three sources can independently provide adequate power for the plant's safety-relatedloads. These transformers and their interconnections to the substation are as follows:Page 2 of 8 Item 1IENCLOSURE 14The primary station auxiliary transformer, 2R, is fed from 345 KV Bus No. 1 via 345 KV to34.5 KV transformer 2RS, a cunt limiting racto.. and fuse assembly., and undergroundcabling from the substation to the area northwest of the turbine building where 2Rtransformer is located. The 2R transformer is of adequate size to provide the plant's fullauxiliary load requirements.The reserve transformer, 1 R, is fed from the 115 KV substation via an overhead line fromthe substation to the area northwest of the turbine building where 1 R transformer islocated. The 1 R transformer is of adequate size to provide the plant's full auxiliary loadrequirements.The reserve auxiliary transformer, 1AR, is located southwest of the reactor building andmay be fed from two separate 13.8 KV sources in the substation. One method of supplyingthe 1AR transformer is from the tertiary winding of the 10 transformer, the auto-transformer.that interconnects the 345 KV and 115 KV systems. Power is routed from the te jjrjýJisubstationinding of 10 transformer to 1AR via circuit breaker 1N2 and underground cqIifig from the61buUbstation to 1AR transformer. The alternate method of feeding 1AR is from T345 KV &ieNe. via 345 KV to 13.8 KV transformer 1ARS, circuit breaker 1 N6, and undergroundcabling from the substation to 1AR. Circuit breakers 1N2 and 1N6 are interlocked toprevent having both breakers simultaneously in the closed position. The 1AR transformeris sized to provide only the plant's essential 4160 Volt buses and connected loads.TRAncformcrc 214 and lAR aro concidered as a singlc offitc cou~rc when IAR ic, suppliedfrom 346 KV Bus No. 1 A A- nmRou common6GF~fl_ RRodc failurocF- c-44-t MWhic coul d cAUsoc~imultaneouc deenRgffiZatiGn of both tranzformcrc. To miniimizo the petcntial for oommoflnPAoed- f ailuro, thc normal aligwnmnt of of sitc cOurczc to tho plant is 2R tFranformzresuppl';ing plant load, 1 R trancformcr cncgizcd iA Fescrye, and IAIR tranzeformor oergliZcd4fro 10 trancformcr ~ac a third dictinct oA ciWtoe corco.. to tho occcntial bursco.Transmission Line ReliabilityThe ftek3 and 115 Ky) transmission line connections to the switchyard are allconnected into the Xcel Energy interconnected transmission grid. The points of connectionto the grid are arranged by routes and intra-right-of-way spacing to minimize multiple lineoutages while performing the requirement of delivering power to locations which bestsatisfy system growth needs. The 345 KV and 115 Ky lines, as well as the lines to whichthey interconnect, are designed and built to exceed the requirements of the NationalElectric Safety Code for heavy loading districts, Grade B construction. Lightningperformance design of the transmission lines is based on less than one outage per 100miles per year. E -~The fhoe Xcel Energy transmission lines leave the Monticello substation through tl~ee-separate rights-of-way: Sherburne County line corridor; St. Cloud line czrrideF; and acommon corridor for the Elm Creek, Dickinson-Lake Pulaski, d Hassan lines. Theserights-of-way are considered independent as they are greatqr than 1/4 mile apart at adistance of one mile from the plant. two St. Cloud corridor linesI(Liberty and Quarry);Page 3 of 8 Item 1IENCLOSURE 14AnalysisriginallyThe power increase related to the EPU project is anned in twe-phas,6 onefollowing the 29 euln uaeadteF- n~aefleigte21 _refueling outage. A request for interconnection rights of an additional 13 MWe wasidentified by MISO as Project G725. The 13 MNe is an increase above the currentinterconnection rights of 607.2 MWe and was requested to accommodate the first phasepower increase following the 2009 refuel outage. A request for interconnection rights of anadditional 60.8 MWe was identified by MISO as Project G929. The 60.8 MWe request willaccommodate the electrical output expected at EPU reactor thermal power of 2004 MWth.A summary of each study is provided below.Proiect G725, 13 MWe Increase Request:Study Methodology and Assumptions:Both projects (G725 and G929) arecurrently planned to be implementedfollowing the 2013 refueling outage.A benchmark case computer model was developed for the study from the MAPP 2005series models. This model was used for steady state power flow analysis focused onthermal loadings under both normal and N-1 contingency conditions. The model includedtransmission system updates and prior-queued generation projects in the region that couldhave an impact on the MNGP generation increase. Monticello output was set at 607 MWenet and additional generation near the Monticello unit that was not at maximum output or inservice was set at maximum and put into service. This represents a summer peakconditionexpected at the time of the MNGP output increase. A subsequent study case model wasdeveloped incorporating the MNGP requested 13 MWe increase in electrical output. Theanalysis was done for station load supplied from both the 345 KV substation and the 115KV substation.For the transient stability analysis, a computer model called the Northern MAPP stabilitypackage was used. Again, benchmark case and study case models were developed. Thisis a summer off-peak model. Regional generation was added and adjusted for peak output.Corresponding load sinks were adjusted as appropriate. The stability of the grid was thenanalyzed for regional single-line ground faults with breaker failure and 3-phase faultswithout breaker failure.The Interconnection Request for this project asked that the total MNGP electrical output beclassified as Network Resource Interconnection Service (NRIS). In order to be classifiedas NRIS, the project request must pass a generator deliverability study. This study wasincluded in the SIS.Page 4 of 8 Item 1IENCLOSURE 14verified for both the cases where house loads are supplied from the 345 kV bus or the 115kV bus. Screening results using only the reactive capability of the generator showed nochange to the conclusions.For transient conditions no violations of stability criteria were identified. The 345 kV & 115kV substation bus voltages remain within acceptable values with and without additionalreactive capability.The deliverability analysis concluded that the full electrical output of the MNGP can beclassified as NRIS; therefore non-injection constraints identified in the steady stateanalysis do not need to be mitigated under this project.The short circuit analysis concluded the interrupting capability of NSP 345 kV, 230 kV and115 kV substation breakers at Monticello and adjacent substations are adequate for theincreased generator output.Insert ASince submittal of the original stability study an additional 345 KV line has been added to the MNGPsubstation which increased the number of transmission lines from 5 to 6 connecting to this substation. Thisincluded an upgrade of the 345 KV bus from a ring bus to a breaker-and-one-half system (see USAR Section8.2.1).The power increase related to the Extended Power Uprate (EPU) project was originally planned in two phasesin 2009 and 2011. Midwest Independent Transmission System Operator, Inc. (MISO) has approved the fullpower increase in a signed Interconnection Agreement (IA) as executed in MISO Projects (G725 13MWe andG929 60.8MWe) on October 6, 2009. EPU currently plans to implement both of these MISO projects followingthe 2013 outage.The Large Generator Interconnection Agreement did not identify the need for any additional interconnection,or system protection facilities, or require any distribution, generator, or network upgrades.On February 22, 2011, Xcel notified MISO ISO that the Commercial Operation Date (COD) for MNGP ProjectsG725 and G929 have been extended from May, 2011 to August 2013. This change notification was notconsidered a material change in accordance with Midwest ISO electric tariff and a LGIA restudy was notrequired.By email dated September 24, 2012 from Vikram Godbole of MISO to various individuals, MISO reported theresults of a restudy evaluation of projects with permanent Generator Interconnection Agreements (GIAs). Thestudy included:1. Stability Analysis2. NRIS analysis3. Per project summary results.The MNGP EPU is covered by GIA G929. No adverse impacts were identified for this study.Page 7 of 8 The onsite buses are designed to provide acceptable voltage to the safety related loadsunder worst case grid voltage conditions. The AC power requirements for the operationof safety related loads will not change under EPU.Monticello's AC Load Study program controls and maintains the databases andcomputer models used to evaluate and record electrical load study cases andcalculations that are performed. This program is used to assure that the distributionsystem voltage ranges meet the underlying electrical system design bases for plantconditions. The following loading conditions are analyzed to ensure that the electricalsystem design bases are maintained:A. Full plant loadB. Emergency Core Cooling System (ECCS)/Loss of Coolant Accident (LOCA)plant loadC. Minimum plant loadThe AC Load Study program has established the following electrical system designbases for determining acceptable distribution system voltages:1. 120 VAC Instrument AC System Voltages:Maximum -132 VAC, Minimum -108 VAC (+/- 10% of rated 120 VAC)2. 480 VAC System Voltages:Maximum -506 VAC, Minimum -426 VAC (+/- 10% voltage at the terminalsof 460 VAC)3. 4160 VAC System Voltage:Maximum -4400 VAC at the 4 kV motor terminals (110% of rated 4000 VAC),Minimum -3975 VACA separate analysis verifies that the bases for degraded voltage relay setpoint remainsvalid under the EPU configuration and loading conditions. This analysis will include thetransformer and balance of plant (BOP) modifications planned for EPU. Plantprocedures incorporate these limits.Non-safety Related AC System LoadsAt EPU eenditinc themc will be an inRo~aco in the non cafot, related eleetrical leadsprimarily due to inrezased eendcncatolfocdwatcr pumHp flow Fequ*rcmcnts. The ipcof this inerease Fesults in sevcrol ohallenges. The eapoity of the I R tFROrmr imerginal. The tatot of a larger fecdwator pumpI inRecases the voltage drop toth4..16 WV switohgcar rczulting in Fedueed margins to protectiye relaying sctpOintS. Also,the fault oontributien fromR lrgor mROtOre reducoc the mnargOR to the fault ratingseof theswxitehgcaF and any increase in the capacity of the I R trancfermer Will eXaccrbatc thesituation. Conscquently, the configuration of the 1 R anid 2R courcoc and non safetyonsitc dictribution system will be modified to increaco eapaeit' and improvc margins toequipment ratingse and protective relaying sctpoints. The modificatione to the 1R andPage 2 of 10 Insert AImplementation of the Extended Power Uprate (EPU) at Monticello requiresincreasing the reactor feedwater flow. This requires additional pumping capacityfor the condensate and feedwater systems, with an attendant increase inelectrical power to the pumps. The additional power to support these increasesis not within the capabilities of the existing 1 R and 2R Transformers and 4 kVBuses 11 and 12. The approach selected to supply the increased pumping loadwas to install a new 13.8 kV Distribution System and replace reserve transformer1 R and auxiliary transformer 2R. Consistent with the existing plant design, new13.8 kV Buses 11 and 12 will continue to supply the Reactor Feed Pump andReactor Recirculation MG (RRMG) drive motors. The new voltage at thesebuses requires replacing the RRMG drive motors, although there is no change inmotor hp. In addition to increasing their horsepower, the condensate pumpmotors are being relocated to new 13.8 kV Buses 11 and 12.

Item 2 IEnclosure 42R offitoW pGO eroumrcc Wre in the conceptual stage at this time and erc sehedulced fare intaflotion in the 2011 i utacgc.Offsite Power System Grid VoltagesThe offsite power system is designed to provide adequate power to site loads given thatthe steady state source 345 kV and 115 kV grid voltages are within the ranges specifiedby plant procedures. The ranges are derived from the plant AC load studies. Operationwithin these ranges provides adequate voltage for operability of safety relatedequipment, provides for proper operation of various automatic voltage regulatingequipment such as load tap changers, and will result in the avoidance of inadvertentbus transfers of the safety related buses due to degraded voltage when starting plantequipment. This performance will be demonstrated by the AC load studies completedas part of the off-site source (1 R and 2R) modifications.Modification Control for EPUThe configuration changes noted above will be controlled by the Monticello ModificationProcess. This process requires compliance with site work instructions for theFuse/Breaker Coordination Study and AC Electrical Load Study. Conformance to theMonticello licensing bases is controlled by required load studies for changes to the siteAC electrical system. The AC load study is described in the Updated Safety AnalysisReport USAR) and references the associated NRC review and approvalcorrespondence. AC load studies become formal plant calculations. The AC load studyassumptions and the EPU impact are noted below." Loads shed by ECCS load shedding are not included in the Offsite AC Systemloading determination for the Design Basis Accident (DBA) LOCA loads.EPU Impact: EPU does not involve any changes to load shedding circuits.* The AC load studies include minimum and maximum equipment voltages forsteady state operation and motor starting. It also includes, by reference, thedegraded voltage setpoints.EPU Imoact: The load study established voltage limits based on equipmentdesign. These limits were established with NRC approval. EPU does notchange these limits. All of the new EPU AC motors will be designed to start andoperate within the existing voltage limits or, if operated at a different voltagebase, new limits will be established based on equipment design. EPU does notrequire any changes to the setpoints for the degraded bus voltage and loss ofvoltage logic." The Offsite AC System load application is based on ECCS load sequencing.EPU Impact: EPU does not affect any of the timing associated with ECCS loadsequencing.Page 3 of 10 FItf m lEnclosure 4" The Demand and Diversity Factors for AC Load Studies are included in the ACload study.EPU Impact: EPU does not require any changes to this load applicationmethodology.* Steady state voltage profile studies are completed using the maximum (WeakSystem) switchyard impedance with the minimum specified distribution systemvoltage. Short circuit studies use the minimum (Strong System) switchyardimpedance with the maximum distribution system voltage.EPU Impact: EPU does not change these conservative assumptions.DC Onsite Power System (PUSAR Section 2.3.4)DC Onsite Power System changes remain bounded by battery capacity. Revision ofstation DC battery calculation verified acceptable margin remains after EPU* Monticello 125 VDC Division I Battery has spare capacity of 16.83 percent underEPU conditions. The CLTP analysis had a battery margin of 40.60 percent." Monticello 250 VDC Division I Battery has spare capacity of 20.64 percent underEPU conditions. The CLTP analysis had a battery margin of 2313* Monticello 125 VDC Division II Battery has spare capacity of 26.8 percent underEPU conditions. The CLTP analysis had a battery margin of 20.24E26.58_ J -1o22.81J* Monticello 250 VDC Division II Battery has spare capa--of-- percent underEPU conditions. The CLTP analysis had a battery margin of 2.04 percent prior toEPU.in mlargin wc.c based eR hangr,, in the Station .ut (SBO) se'nariaoumptiens ac providcd in Montiocllo EPU L'AR Enoelocur 5 (PUSAR Soetion 2.3.6)and use ef marce rcalistio asaumptiens on battery loading in the calculation. The revisedLoad changesto the SafetyRelated DCOnsite PowerSystem remainbounded by thecapacity of theexisting stationbatteries.Approvedrevisions tostation cellsizingcalculationsconfirmedpositivecapacity marginremains for theanalyzedscenariosfollowingimplementationof EPU.a'l'ulati-ns in^"ud^d a'l pending miOr .hange. to thc ealoulatione. No changes areexpected for 250 VDC battery loads. Potential loading changes to the 125 VDCsystems are not expected to be significant based on 10 CFR 50.59 screening orevaluation of the proposed changes.Station Blackout and DC Loadingl (PUSAR Section 2.3.5)The design basis loading for the safety related DC systems is the loading profile thatoccurs during an SBO event. The DC System electrical design parameters at the endof the four hour design basis SBO load discharge remain within design.The DC battery calculations for EPU demonstrate that, given conservative assumptionsfor the timing and application of DC loads during this event, sufficient DC power isPage 4 of 10 Item 2 1Enclosure 4sufficient battery capacity exists to start and operate all connected DC loads for theworst case loading scenario.NRC Question3) In Section 2.3 of the LAR (Specifically Sections 2.3.3 and 2.3.4), the licenseestated that some equipment may change.In order for EEEB to start its review, the licensee must provide assurance that allrequired plant modifications are accounted for In its EPU application.NMC Response:The Monticello EPU LAR, Enclosure 8, "Planned Modifications for Monticello ExtendedPower Uprate," contains a comprehensive list of all modifications that are planned forEPU. As noted in Enclosure 8, some of the listed modifications have been completed,some are planned for installation in 2009, and some are planned for installation in 2011.These tables also include modifications that are not required for EPU, but are beingplanned as part of the life cycle management (LCM) program.Modifications that have already been completed were those required to obtain data forsteam dryer analysis. The remaining modifications are required to support full poweroperation at 2004 MWt. Completion of turbine modifications planned for 2009 willenable operation at power levels above CLTP. None of the planned modifications listedbelow are safety related except for the modification providing upgrades to EQequipment. Modifications associated with the Monticello EPU LAR Enclosure 5(PUSAR), Section 2.3 are described below:PUSAR Section 2.3.1, Environmental Qualification of Electrical Equipment.Modifications:* HELB Update/EQ Update -The response to EEEB Question 1 will provide moredetailed information. Question 1 will be submitted at a later date as discussedwith the NRC staff on May 23, 2008.PUSAR Section 2.3.2. Offsite Power Systems, Planned Modifications:* 1AR Transformer Replacement -replacement due to aging not EPU -Installed]* Main Transformer and Isophase Duct -increased capacity <-- -Installed* Reactor Feed Pump Replacement -new higher horsepower 13.8kV motor* Condensate Pump Upgrades -new higher horsepower 13.8kV motor* New 13.8kV Bus Installation -replace existing 11 and 12 4kV buses with 13.8kVbus including replacement of the 1 R and 2R transformers* Replace the Recirculation M-G Set Motors -new 13.8kV motorIncreases in required condensate and feedwater pump capacity for EPU result inelectrical loads for onsite non-safety related AC power systems that exceed thecapacity of the existing system. The modifications listed above provide upgrades toPage 6 of 10 Iltem 2 1Enclosure 4plant non-safety related AC electrical distribution systems to correct this deficiency.There are no changes required to safety related buses.The existing non-safety related #11 and #12 4kV buses will be replaced with a newbus rated at 13.8kV. This will require replacing all motors associated with the newbus to provide motors rated at 13.8kV. These modifications will insure compliancewith design requirements as fined in the Technical Evaluation of PUSAR Section2.3.2. " for operationThe electrical modifications planned for upgrade of the Offsite Power Systems arerequired due to the upgrades to the onsite AC systems. Potential grid modificationswill be identified, if required, as part of the Midwest Independent System Operator(MISO) grid stability study associated with approval of the interconnectionapplication for generation needed to support 2004 MWt reactor power. Thesemodifications will be provided to the NRC for review by a later submittal as describedin Sections 1.0 and 2.0 of the Monticello EPU LAR Enclosure 1, "NMC Evaluation ofProposed Changes to Operating License and Technical Specifications for ExtendedPower Uprate." A separate license amendment request will be submitted to increasethe power level to 2004 MWt.The MISO grid stability study for approval of the interconnection application forgeneration needed to support 1870 MWt did not identify any grid modifications asbeing required. This study will be submitted to the NRC by June 30, 2008.PUSAR Section 2.3.3. Onsite AC Power System, Planned Modifications:There are no modifications required for the alternating current (AC) onsite powersystem for those standby power sources, distribution systems, and auxiliarysupporting systems provided to supply power to safety-related equipment.EPU does not affect the timing associated with ECCS load sequencing and has noeffect on Emergency Diesel Generators (EDG) transient performance. There are nochanges to the sequencing and timing of AC ECCS loads during a DBA LOCA. EPUhas no effect on the functional requirements for the instrumentation and controlsubsystems of the safety-related EDG power systems and there are no changes tothe instrumentation and control systems of the essential AC systems.The EDG design basis loading is not affected by EPU. The EDG continuous loadrating of 2500 kW envelopes the initial and steady state loading for the EDG. Inaddition, EDG transient voltage and frequency performance is not affected since theEDG loading does not change. See PUSAR Section 2.8.5.6.2, Emergency CoreCooling System and Loss-of-Coolant Accidents, for the evaluation of ECCS loads.PUSAR Section 2.3.4. DC Onsite Power System, Planned Modifications:There are no currently identified modifications to the DC Onsite Power Systems.The DC System may be modified to include changes for certain EPU modifications.Page 7 of 10 Iltem 2Enclosure 4of the proposed EPU. As noted in the response to Question 2 above, somemodifications are required for non-safety related onsite AC power systems.PUSAR Section 2.3.4. DC Onsite Power SystemDC Onsite Power System changes remain bounded by battery capacity. Revision ofstation DC battery calculations verified acceptable margin remains after EP" Monticello 125 VDC Division I Battery has spare capacity of 16.8 percent underEPU conditions. The CLTP analysis had a battery margin of 10.6 percent." Monticello 250 VDC Division I Battery has spare capacity of 20.64 percent underEPU conditions. The CLTP analysis had a battery margin of 23.63 P t.* Monticello 125 VDC Division II Battery has spare capacity of 26 percent underEPU conditions. The CLTP analysis had a battery margin of 29.24 percent..26.58 __l-" Monticello 250 VDC Division II Battery has spare c iof 8UnderEPU conditions. The CLTP analysis had a battery margin of 2.04 percent prior toEPU.kmpro':cments in mSrgin werc based on ohangoc in the SBBC onas i asmpin3Pro~ided on PUSAR Sootion 2.3.5 and use of mor8e roalistie assumptions on beAttz!au, .!" fk ^ -i 1. ...*- ..... .0T .. ...r- -. .-.. i,., ^ 1 .^-A%- *.. k' .*to the caloulatnci.. No changes are expected for 250 VDC battery loads, jPotentialloading changes to the 125 VDC systems are not expected to be signifi nt based on10 CFR 50.59 screening or evaluation of the proposed changes.PUSAR Section 2.3.5. Station BlackoutThe evaluation states that the plant will continue to meet the requireme ts of 10 CFR50.63 following implementation of the proposed EPU.Load changes on the Safety Related DC Onsite Power System remainbounded by the capacity of the existing station batteries. Approvedrevisions to station cell sizina calculations confirmed Dositive caoacitvmargin remains for the analyzed scenarios following implementation ofEPU.Page 10 of 10 Iltem 2Enclosure 2NRC Question:1. Provide the staff with the USAR section number that describes the AC loadStudy.NMC Response:The AC load study is described in Monticello USAR Section 8.10, "Adequacy of StationElectrical Distribution System Voltages."NRC Question:2. The licensee will provide statements that the margins discussed in theacceptance review response for the batteries will be met during the developmentof the modifications.C,-- he-:These are the finalINMWC Response: ,In Refee^Rcn 2, Ene- ......, NMC epo,.. d the following with .. s.pot t. DC batterycapacity margins at Current Licensed Thermal Power (CLTP) and Extended PowerUprate (EPU) conditions:Table I -Battery Margin_ CLTP (% Batte M i I EPU (% Batterv Margin)125 VDC Division I Battery 15.831 9.29250 VDC Division I Battery 23.63 20.64125 VDC Division 11 Battery 2 v=-426.58 26.68 8.11250 VDC Division 11 Battery 2.04 8-9 22.81Expeeted EPU eleetrieal mediflcatiens that eewid impact DG leads arc rcplaczmcnets ikind IFr and trl leads on the 142 VO) system. The additieRal 126 VDlj eads due to these EPU moediflcations will no~t roducoe the ropo~tod 125 VOCG battomnargin by mor~e than Five perccnt of the calculated capacity' Fcpeotd. For eXam~ple, the[PU medifieaticns will be controlled such that the rcmaining 125 VDC Diyicion 1 batteryist Iat .ast 10.83 perent.Additionally, no changes to the margin for the 250V DC battery loads will result fromEPU modifications.Page 1 of 7

[Item 4 IL-MT-09-043Enclosure 3Page 11 of 64EMCB-SD RAI No. 5CDI Report 07-25P discusses noise removal from the CLTP signal. The licensee isadvised to note the staff's position that using noise removal from CLTP signals basedon LP signals is only acceptable when the LP signals are not corrupted by backgroundelectrical interference (EIC) noise, otherwise the dryer stresses should be computedusing original CLTP signals, not those reduced by the LP signals corrupted by EICnoise. The licensee is requested to provide a discussion of the LP noise that wassubtracted from CLTP and clearly substantiates that the LP signal is affected orcorrupted by EIC. NSPM may submit new data and stress analyses based on lowpower signals not corrupted by EIC noise, for the staffs consideration.Response superseded by WCAP-1 7548NSPM Response p-IProvided in L-MT-12-056, Enclosure 2.Te original CLTP and low power data were collected in May and April of 2007. At thtimonticello did not record EIC data. Low power and EIC data were subsequ ycollectei September and October 2008; however, the EIC data at CLTP c itionswas judged usable because of the large frequency exclusion that woul e requiredat 60 Hz. Thus,f all analyses discussed, the 2007 CLTP did NOT e the 2008CLTP EIC data rem d, whereas for a conservative result, the,8 Low Power datadid have the 2008 Low er EIC data removed. Figures 5bo 5.4 plot the CLTP (EICnot removed) and low power ta (EIC removed). Note t the low power signals areconsistently lower at each strain e location than CLTP signals for the frequencyrange considered here.Comparisons between EIC and low po da ith EIC included) are shown inFigures 5.5 to 5.8. It may be seen th low o data are consistently higher thanthe EIC data, except at the excl ion frequencies (60, 0, 180 Hz) where the twosignals (at each strain gag cation) are essentially the saFurther compariso , etween the CLTP data collected in 2007 an e CLTP datacollected in 20 (again, with EIC not removed are shown in Fi ures .to 5.12. Bothcinfe nf cinn e r= r mnr!in r[Note: No change has been made to blacked out information. Informationredacted to preserve integrity of proprietary information.NOTE: RAI No. 5 contains graphs on the following pages that are notreproduced here which are also superseded by the response inWCAP-17548 provided in L-MT-12-056, Enclosure 2.

Iltem 4 IL-MT-09-043Enclosure 3Page 24 of 64EMCB-SD RAI No. 6There appears to be an inconsistency among the different NSPM reports regarding howthe CLTP signals are reduced by the low power signals. On Page 16 of 24 of Enclosure11 to L-MT-08-052, "Steam Dryer Dynamic Stress Evaluation", NSPM states that, "Forconsistency, the low power strain gage signals are filtered in the same manner as theCLTP data and are fed into the ACM model to obtain the monopole and dipole signalsat the MSL inlets." In Report CDI 07-25P, "Acoustic and Low Frequency HydrodynamicLoads at CLTP Power Level on Monticello Steam Dryer to 200 Hz", Rev. 4, November2008, NSPM states that up to 80% of the low power strain gage signals was subtractedfrom those measured at CLTP. In a third report, CDI Report 07-26P, "StressAssessment of Monticello Steam Dryer", Rev. 2, November 2008, Equation 8 indicatesthat the CLTP signal is reduced by up to 80% (not that up to 80% of the LF signal issubtracted from the CLTP signals). Clearly, the wording in these three reports iscontradictory. NSPM is requested to resolve the discrepancies and explain clearly howthe low power noise removal was implemented. In addition, NSPM is requested tomodify the above mentioned reports so that the procedure of low power noise removalis consistent among the three reports. Response superseded by WCAP-17548provided in L-MT-12-056, Enclosure 2.NSPM ResponseT-he.equation, as defined in C.D.I. Report No.07-25P (the loads report) and C.D.I.Repo 07-26P (the stress report), iswhere PR(0O) is the CLTP signal Ps(co) co or Low Power P&0o), computed as aThis interpretation is consis with the wording in both C. .reports. Page 16 of 24 ofEnclosure 11 toLM 052 (supplied by NSPM) is in error.See also response to EMCB-SD- RAI 20, where it is shown itat noise s ction isnot ired for stress ratios above 2.0 at EPU conditions.

L-MT-09-043Enclosure 3Page 25 of 64EMCB-SD RAI No. 7The proper filtering of the plant noise (low power signal) from the CLTP signal requiresthat the corresponding EIC signals are accounted for. That is, the low power and CLTPsignals are modified by subtracting the corresponding EIC signals from them, and thenthe modified LP signal is filtered out from the modified CLTP signal. Such a procedurewas considered acceptable during staffs review of previous EPU application that CDIwas involved in. However for the Monticello steam dryer, as stated in CDI Report 07-25P, NSPM has decided not to modify the LP and CLTP signals by subtracting thecorresponding EIC signals. The licensee is requested to justify that this approach of notusing the EIC signal is conservative compared to the one used for the BFN Unit 1 steamdryer. ., .. , 4-, ., Iro.ile iupnrsUdU Uy VVT.t--, -I Encosue2 Iprovided in L-MT-12-056, Enclosure 2.1NSPM ResponseTI 2008 low power and EIC data sets have been used with the 2007 CLTP data. FAC"data a oved from the 2008 low power data (the low power EIC data), b fromthe 2007 CL a (the CLTP EIC data). The result is conservativPreviously, when noise subtr was performed, as left in the CLTP signal butsubtracted from low power. This app pr .d a conservative signal after noisesubtraction, since the low power sign gin AAfter EIC sbtractionis everywhereless than or equal to the low signal without E traction. Heca mleamplitude low power s was subtracted from the CLTP siNote th rrently no low power subtraction is performed, so this issue is n vantt e current stress analysis.EMCB-SD RAI No. 8NSPM ResponseNote: No change has been made to blacked out information. Informationredacted to preserve integrity of proprietary information.

Item 57NEDC-33322P, Revision 3While Monticello is not generally licensed to the current GDC or the 1967 AEC proposedGeneral Design Criteria, a comparison of the current GDC to the applicable AEC proposedGeneral Design Criteria can usually be made. For the current GDC listed in the RegulatoryEvaluation above, the Monticello comparative evaluation of the comparable 1967 AEC proposedGeneral Design Criteria (referred to here as "draft GDC') is contained in Monticello USARAppendix E: draft GDC-9, draft GDC-33, draft GDC-67, draft GDC-68. draft GDC-69, anddraft GDC-70.The Reactor Water Cleanup System is described in Monticello USAR Section 10.2.3. "ReactorCleanup Demineralizer System."In addition to the evaluations described in the Monticello USAR. Monticello's systems andcomponents were evaluated for License Renewal. Systems and system component materials ofconstruction, operating history, and programs used to manage aging effects were evaluated forplant license renewal and documented in the Monticello Nuclear Generating Plant LicenseRenewal Safety Evaluation Report (SER), NUREG-1865, dated October 2006 (Reference 5).The license renewal evaluation associated with the Reactor Water Cleanup System isdocumented in NUREG-1865, Section 2.3.3.15. Management of aging effects on the ReactorWater Cleanup System is documented in NUREG-1865, Section 3.3.2.3.15.Technical EvaluationRWCU system operation at the EPU RTP level slightly decreases the temperature (< I°F) withinthe RWCU system. This system is designed to remove solid and dissolved impurities fi'omrecirculated reactor coolant, thereby reducing the concentration of radioactive and corrosivespecies in the reactor coolant. The system is capable of performing this function at the EPU RTPlevel.RWCU flow is usually selected to be in the range of 0.8% to 1.0% of FW flow based onoperational history. fit; exising iVt'U fla slightl) exed thi niw (I .6"b of FW lluv4.The RWCU flow analyzed for EPU is within this range. Furthermore, the EPU review includedevaluation of water chemistry, heat exchanger performance, pump performance. flow controlvalve capability, and filter / demineralizer performance. Performance of each was found to bewithin the design of RWCU system at the analyzed flow. The RWCU analysis concludes:" There is negligible heat load effect." A small increase (z-!5%) in filter / demineralizer backwash frequency occurs, but thisis within the capacity of the Radwaste system.* The slight changes in operating system conditions result from a decrease in inlettemperature and increase in FW system operating pressure." The RWCU filter / demineralizer control valves may operate in a slightly more openposition to compensate for the increased FW pressure. These valves do not haveposition indication, preventing quantification of this change. However, there are two2-13

,Item 5 ITable 2.1-4 shows that the changes in RWCU system operating conditions arecomparable to current conditions. The reactor water iron and conductivityparameters at Monticello are maintained well below the EPRI BWRVIP-1 30:BWR Chemistry Guidelines -2004 Revision guidelines for these parameters.h r .5NEDC-33322P, Revision 3valves and each valve is designed to provide a flowtotal RWCU flow is divided equally through each val*ate of 0 to 100 gpm. Typicallye.No changes to instrumentation are required for EPI), and no setpoint changes areexpected due to the negligible system process paramen er changes.Previous operating experience has shown that the FW iron inpu!as a result of the increased FW flow. This predicts an increaseconcentration from < 1.7 ppb to < 2.0 ppb. However, this changdoes not affect RWCU.to the reactor increases for EPUin the typical reactor water ironis considered insignificant, andeffects of EPU on the RWCU system functional capability have been reviewed, andsfrm adequately at EPU RTP with the original RWCU system flow. U theoriginal R ,system flow at EPU RTP results in a slight increase in the calculd reactorwater conductivi rom 0.100 4S/cm to 0.115 pS/cm) because of the increasei W flow. Thecurrent reactor water ductivity limits are unchanged for EPU and -actual conductivityremains within these Table 2.1-4 shows that the change i, RWCU system o-rating conditions are small. Thesystem flow rate is unchanged.The reactor water iron and conductivity par ter Monticello are maintained well below theEPRI BWRVIP-1 30: BWR Water Che stry Guidelin -2004 Revision guidelines for theseparameters. Table 2.1-5 shows t -cal values for these pa eters based on CLTP rive yearmonthly' averages. The es .ated EPIJ values are included. This estimated increase isproportional to the RW System flow capacity as a percentage o edwater flow at EPUconditions. No it is assumed for passive removal mechanisms s as source termreduction.Tab] -.1-5 shows that the estimated increase in these parameters is not significant a thaticient operating margin to.the conservative limits remains under EPU conditions.The increase in FW line pre ure has a slight effect on the system operating conditions. Theeffect of this increase is inclu d in Section 2.6.1.3 Containment Isolation.ConclusionNSPM has evaluated the cffc ts of the proposed EPU on the RWCU system. The evaluationindicates that the RWCU syst will continue to be acceptable following implementation of theproposed EPU and will con inue to meet the requirements of the current licensing basis.Therefore, the proposed EPU i acceptable with respect to the RWCU system.Table 2.1-5 assumes an increase, which is not anticipated, in theseparameters and demonstrates that this is not significant and that sufficientoperating margin to the conservative limits remains under EPU conditions.2-14 NEDC-33322P, Revision 3Table 2.1-4 RWCU System Parameter Comparison for EPURWCU System Parameter CLTP EPURWCU Inlet Temperature, °F 530.2 529.7RWCU Inlet Pressure (RPV dome pressure. 1010 1010neglecting head), psigRWCU Outlet Temperature, 'F 449.2 449.RWCU Outlet Pressure (at the feedwater line), psig 1045 1057Design RWCU Flow. Ibm/hr 80,000 8 6 :Maximum RWCU Flow. Ibm/hr 85,000 0--]449.11-oF9 o -0'00 18 Iltem 6m6L-MT-09-042Enclosure 1Page 5 of 11Table 1:Ambient Gamma Radiation as Measured by ThermoluminescentDosimetry, Average Quarterly Dose Rates, Inner vs. Outer RingLocationsInner Ring Outer RingYear Dose rate (mRem tr)1991 15.2 1992 15.1 5.115.9 I-nsert A1994 N,14.6 141995 14.4 13.61996 14,/" 13.51997 .3 12.81998 15 14.41999 .1 14.32000 1, 14.52001 14.3 13.72002 " 15.9 \_ 14.820p 15.6 15____2005 16 5.42005 ~15.6 l22006 16.5 15.6N,Average 15.5125 14.8125_ _

Fit- m -1Insert AInner Ring Outer RingYear Dose rate (mRem/qtr)1991 15.2 15.81992 15.1 15.11993 15.6 15.91994 14.6 141995 14.4 13.61996 14 13.51997 13.3 12.81998 15 14.41999 15.1 14.32000 15.1 14.52001 14.3 13.72002 15.9 14.82003 15.6 152004 16 15.42005 15.6 15.22006 16.5 15.62007 16.1 15.12008 15.2 14.62009 14.9 14.42010 14.7 14.32011 14.8 14.32012 15.7 15.3Average 15.12 14.62 Iltem 6 1L-MT-09-042Enclosure 1Page 6 of 11Table 1A below compares the mean for all locations in both the inner and outerrings and the mean of the peak location in each ring for the last 11 years. Themaximum difference between the inner and outer ring peak locations is 1.7mrem/qtr. If this is taken as skyshine, as done above, it represents a maximumof 6.8 mrem/yr at current conditions. Scaling this by 34.4 percent results in amaximum projected upper bound for offsite dose due to skyshine of 9.1 mrem/yr.Adding this to the average exposure from Table 2 of I mrem/yr results in a totalof approximately 10 mrem/yr maximum potential dose to any member of thepublic. This is well within the 40 CFR 190 limit of 25 mrem/yr.Table 1A Off Site Ambient Gamma Radiation as Measured by TLD at the PeakInner and Outer Ring Locations Compared to the Mean of all Locations inEach RingInner Ring Mean Inner Ring Peak Outer Ring Mean Outer Ring Pepk"ar All Locations Location Mean All Locations Locatioq>a-1an(mr/qtr) (mr/qtr) (mr/qtr) f r/qtr)1997 ::',,3.3 14.1 12J-f14.81998 15.,, 16.4 .,-ý .4 15.91999 15.1 7.0 14.3 15.92000 15.1 "' -,J6.,,,' 14.5 16.22001 14.3 13.7 15.02002 15.9 -17.4 14ý8 16.22003 15.. 17.6 ".15. 0 16.22004 -I0~ 18.4 P--4 16.72005 jf 15.6 17.4 15.2 16.520p:ý16.5 18.6 15.6 17.016.1 18.1 15.1,,-,erage Mean 1 51.3 17.1 t 4. 16.1ý Iltem 6Insert BInner Ring Outer RingMean All Inner Ring Mean All Outer RingLocations Peak Location Locations Peak LocationYear (mr/qtr) Mean (mr/qtr) (mr/qtr) Mean (mr/qtr)1997 13.3 14.1 12.8 14.81998 15 16.4 14.4 15.91999 15.1 17 14.3 15.92000 15.1 16.9 14.5 16.22001 14.3 16 13.7 152002 15.9 17.4 14.8 16.22003 15.6 17.6 15 16.22004 16 18.4 15.4 16.72005 15.6 17.4 15.2 16.52006 16.5 18.6 15.6 172007 16.1 18.1 15.1 16.52008 15.2 17.5 14.6 16.22009 14.9 15.8 14.4 15.62010 14.7 15.9 14.3 15.62011 14.8 16.3 14.3 15.82012 15.7 17.8 15.3 16.9Average Mean 15.24 16.95 14.61 16.06 Iltem 6 mL-MT-09-042Enclosure IPage 7 of 11Table 2: Offsite Radiation Dose Assessments from 2001 through 20064ýjSource: AnnuRadioactiveEffluentReleaseReports forMNGP10 CFR 50 Appendix I Limits10 CFR 2010 20 15 5 15 15 3 10 1Gaseous Releases Liquid Releases , ýGaseous ReleasesMax Site Boundary Maximum Dose to Most Likely Exposed M.,`'o Max Dose to Individuals due toGamma OMember of General Public (1) Activities Inside Site Boundary (1)leI MaxGamma Beta Body WhOrgan Bode Thyroid OrganIB Wole Body Ira Whod (Skin)mrad/vrmrad/vrmrem/vrmremrvr-,-6em/vrm?'4y, Yrmremmremmremmremmrem2001 3.OOE-03 4.OOE-03 1.10E-02 6.00,- 7.OOE-03 1.E-2 J.61E-05 1.72E-04 1.20E-02 1.40E-02 1.50E-022002 1.OOE-03 2.00E-03 1.40E-02 ,50E-03 8.OOE-03 1.40E-02 0.0 0.OOE+00 1.40E-02 1.80E-02 1.60E-022003 2.20E-02 1.70E-02 4.7pg " 3.90E-02 7.30E-02 4.70E-02 2.45E-07 '-,655E-07 2.00E-02 3.OOE-02 3.OOE-022004 1.30E-02 1.OOE-02,,.70E-02 2.20E-02 3.70E-02 3.70E-02 1.94E-10 1.9 9.OOE-03 1.10E-02 9.OOE-032005 3.00E-03 3 -03 2.50E-02 1.60E-02 2.50E-02 2.50E-02 0.OOE+00 0.OOE+00 ý' E-02 1.60E-02 1.90E-022006 1 .00E; I .00E-03 1.40E-02 8.OOE-03 6.OOE-03 9.OOE-03 0.00E+00 0.OOE+00 8.00E--'0 8.OOE-03 1.OOE-02Averages , .E-03 6.17E-03 2.47E-02 1.62E-02 2.60E-02 2.38E-02 2.72E-06 2.88E-05 1.30E-02 1.-2 1.65E-02Note 1: Maximum doses are calculated using the GASPAR code to provide data from the airborne pathways combined with themaximum site boundary doses.'I nsert C Item 6 IInsert C10 CFR 50 Appendix I Limits 10 CFR 2010 20 15 5 15 15 3 100Source. Gaseous Releases Liquid Releases Gaseous ReleasesRadioactive Max Site Boundary Maximum Dose to Most Ukely Max Dose to Individuals due toEffluent Gamma Exposed Member of General Max Offsite Dose Activities Inside Site BoundaryRelease Organ Public (1) (1) MaxReports for Whole Whole Whole MaxMNGP Gamma Beta Body Skin Thyroid Body Organ Body Thyroid Organ(skin)mrad/yr mrad/yr mrem/yr mrem/yr mrem/yr mrem/yr mrem mrem mrem mrem mrem2001 3.OOE-03 4.OOE-03 1.10E-02 6.OOE-03 7.OOE-03 1.10E-02 1.61E-05 1.72E-04 1.20E-02 1.40E-02 1.50E-022002 1.OOE-03 2.OOE-03 1.40E-02 6.OOE-03 8.OOE-03 1.40E-02 0.OOE+00 0.OOE+00 1.40E-02 1.80E-02 1.60E-022003 2.20E-02 1.70E-02 4.70E-02 3.90E-02 7.30E-02 4.70E-02 2.45E-07 5.55E-07 2.OOE-02 3.OOE-02 3.OOE-022004 1.30E-02 1.00E-02 3.70E-02 2.20E-02 3.70E-02 3.70E-02 1.94E-10 1.94E-10 9.OOE-03 1.1OE-02 9.OOE-032005 3.OOE-03 3.OOE-03 2.50E-02 1.60E-02 2.50E-02 2.50E-02 0.OOE+00 0.OOE+00 1.50E-02 1.60E-02 1.90E-022006 1.OOE-03 1.OOE-03 1.40E-02 8.OOE-03 6.OOE-03 9.OOE-03 0.OOE+00 0.OOE+00 8.OOE-03 8.OOE-03 1.00E-022007 9.OOE-04 1.00E-03 1.05E-02 7.00E-03 7.OOE-03 1.05E-02 2.90E-03 5.92E-03_ 1.50E-02 2.30E-02 1.70E-022008 1.90E-02 1.80E-02 8.40E-02 3.60E-02 3.50E-02 8.40E-02 0.OOE+00 0.OOE+00 3.80E-02 6.40E-02 4.80E-022009 1.95E-02 2.07E-02 6.24E-02 3.62E-02 2.54E-02 6.24E-02 3.21E-10 3.21E-10 3.57E-02 5.02E-02 4.40E-022010 1.53E-02 2.12E-02 1.15E-01 4.46E-02 3.15E-02 1.15E-01 0.OOE+00 0.OOE+00 1.39E-02 1.78E-02 1.92E-022011 1.18E-02 1.24E-02 1.25E-01 3.59E-02 5.30E-02 1.25E-01 0.OOE+00 0.OOE+00 2.42E-02 3.1OE-02 3.00E-02Averages 9.95E-03 1.00E-02 4.95E-02 2.33E-02 2.80E-02 4.91 E-02 2.65E-04 5.54E-04 1.86E-02 2.57E-02 2.34E-02Note 1: Maximum doses are calculated using the GASPAR code to provide data from the airborne pathways combined with themaximum site boundary doses.

Item 7 1NEDC-33322P, Revision 3Technical EvaluationIn accordance with RS-O01, Review Standard for Extended Power Uprates, Revision 0,December 2003 Section 2.11.1, five specific questions are identified associated with the humanfactors area. Each question has been included below with the applicable response.1. Changes in Emergency and Abnormal Operating ProceduresDescribe how the proposed EPU will change the plant emergency (EOP) and abnormal (AOP)operating procedures.Response:The Monticello 10 CFR 50 Appendix B plant procedure program governs changes to the AOPsand EOPs. The procedure change program and operator training program (discussed in question5) will assure that operator performance will not be adversely affected by the proposed EPU.The following describes the procedure changes that will be implemented prior to operation at up-rated conditions and/or installation of the associated modification.The following are the AOP procedural changes:-inc backprcssure limits have changed as a result of modifications to the low- reanged at low power conditions.* The Station Blackout (SBO) analysis was changed to include using the HPCi suctionfrom the Condensate Storage Tanks (CST). The AOP will be revised to require theoperator to align the [IPCe suction to the Condensate Storage Tanks from the maincontrol room, prior to the three-hour point in the event. This action was previouslyperformed by the operators within the EOPs and is not a new action." Installation of new non-safety related 13.8 kv electrical buses and switchgear will resultin changes to the electrical failure AOPs.The following are the EOP procedural changes:" The EPU will result in additional heat being added to the suppression pool during certainaccident scenarios. The Heat Capacity Temperature Limit (HCTL) curve in the EOPswill be revised to reflect the increase in decay heat loading on the suppression pool." The Pressure Suppression Pressure curve in the EOPs will be revised to reflect theincrease in reactor power and increase in decay heat loading.2. Changes to Operator Actions Sensitive to Power UprateDescribe any new operator actions needed as a result of the proposed EPU. Describe changes toany current operator actions related to emergency or abnormal operating procedures that willoccur as a result of the proposed EPU. (SRP Section 18.0) (i.e., Identify and describe operatoractions that will involve additional response time or will have reduced time available. Your2-348 Item 87L-MT-09-048Enclosure 1Page 16 of 50NRC RAI No. 12PUSAR Section 2.6.5, please define the various pump flows for RHR and CS pumpsused in the DBA LOCA, Appendix R, SBO, ATWS, SBA analysis, i.e., whether these arepump runnout flow, rated flow or design flow. Please verify if these flows are consistentwith the current analysis in the USAR and with operating procedures. If these are notthe same, provide a tabulation of the EPU values, the current analysis values used foranalyzing these events, and the operating procedure values and provide justification forthe differences. How do these pump flows compare with flows used in the DBA LOCAanalysis for long term suppression pool temperature response in PUSARSection 2.6.1.1.1.NSPM ResponsePUSAR Section 2.6.5 includes a discussion of long-term suppression pool temperatureresponse that applies to both design basis accident profiles done to maximizecontainment response and to those profiles done to minimize containment response forthe evaluation of ECCS pump NPSH. DBA LOCA evaluations assume pump runoutcapabilities for the first 10 minutes of the event sequences. Other events such as SBO,ATWS and Appendix R have these pumps started by operator action at the design flowrates specified below. For DBA LOCA sequences it is assumed that at 10 minutesoperator actions will establish containment heat removal and throttle pumps in serviceto maintain these pumps within NPSH limits as required by the Emergency OperatingProcedures (EOPs).In the first 600 seconds of the event flow rate assumptions vary between the DBALOCA containment response and NPSH analysis. For this period of time operatingprocedures maximize injection to the reactor. The flow rates assumed by analysis areshown below:Pump Flow <600 Seconds for Containment AnalysisCLTP1' EPU3 NPSHWRHR 1 pump -NA I pump- 4320 gpm 'A' Pump -4278 gpm2 pumps -8000 gpm 2 pumps -8641 gpm 'B' Pump -4327 gpm4 pumps -17,400 gpm 'C' Pump -4330 gpm'D' Pump -4347 gpmCS 4370 gpm per pump 4245 gpm per pump 'A' Pump -4M86 gpm E,I_ I_ I _ _ _ I'B' Pump -4204 gpm14129 ]--- 105 I1. The containment analysis assumptions for CLTP are shown in USAR Table 5.2-7. Table 5.2-7 showsthat for the first 10 minutes 1 CS and 2 RHR pumps were running at nominal flow rates. The 4 pumpcase was used to evaluate containment response for NPSH only.2. The flow rates for the NPSH analysis are based on a hydraulic model that provides an evaluation ofactual capability based on individual pump characteristic curves and system hydraulic resistance. Thesevalues are the same for CLTP and EPU and were used to evaluate NPSH.3. The EPU containment analysis is an average of all pumps from the NPSH analysis.

Item 8 8L-MT-09-048Enclosure 1Page 17 of 509I Event I RHR Flow (gpm)A 1 CS Flow (gpm _, 4129I CLTP I EPU I Procedure I CLTP [EPU I IDBA 4278 4278 As Needed1 4285 42864" As Needed1<600 seconds 4327 4327 4204 4204 < 4058(RHR pumps 4330 4330A, B, C, D 4347 4347 3388CS pumps Aand B) ..DBA >600 4000 4000 4000 / pump 3035 a036' 2.2 vseconds 3029 302-_SBA3 NW -4320 As Needed1 NA4 3020 As Needed'<600 secondsSBA NWA 4000 4000 /pump NA4 3020 28.>600 secondsATWS6 NA4 4000 / 4000 / pump NA4 3035 See Notepump Number 5.SBO NA4 4000 / 4000 / pump NA" 0' Not usedpump6Appendix R 4000 4000 4000 3029 3029 2700-41008 1 --RHR and CS will initiate with the injection valves fully open, i.e. in pump runout flow. Procedures allowthe operators to inject as needed to achieve desired reactor water levels to establish adequate corecooling. NPSH limits are provided in EOPs which allow pump flow at analytical values shown or higher.Cautions against exceeding NPSH limits are provided in EOPs to insure pump reliability. CS ratedpump flow rate is 3020 gpm at 145 psig reactor pressure. RHR pump design rated flow rate is 4000gpm/pump in containment cooling mode. LA>3150 1CS flow is required by EOPs to be >2800-gpm if at 2/3 core height to insure adequate core cooling.3 For the SBA prior to 600 seconds the event is bounded by the DBA LOCA since makeup requirementsare substantially lower. The use of one RHR and one CS pump was assumed.4 SBA, ATWS and SBO were not evaluated as part of the CLTP license basis and therefore are shownas not applicable, NA, in table above.6 The EOPs for an ATWS event control water level in a band that insures acceptable power reduction.CS is not a preferred injection source and other systems would be expected to be used to maintainvessel inventory, therefore the use of CS flow of 3035 gpm for NPSH evaluation is conservative. RHRis identified as a preferred injection source; however the maximum flow requirement (16,000 gpm)would be associated with suppression pool cooling which is assumed above.6 RHR flow for suppression pool cooling does not start until restoration of power after 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. All pumpsare started in torus cooling mode after 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.7 Core cooling is provided by HPCI for this event and therefore CS is not used.8 The analysis assumed a maximum CS flow of 3029 gpm, the discrepancy between the procedure andanalysis is being addressed by CAP 01176349.9 The RHR pumps are assumed to provide 4000 gpm. The procedures control this flow rate. L-MT-12-048,Section 6.6.2 notes that actual pump flow can be 4178 gpm if the minimum flow valve fails open. Cautionsagainst exceeding NPSH limits are provided in EOPs to insure pump reliability. CS rated pump flow rate is3020 gpm at 145 psig reactor pressure. RHR pump design rated flow rate is 4000 gpm/pump incontainment cooling mode.

L-MT-09-048Enclosure 1Page 37 of 50NRC RAI No. 29PUSAR Section 2.6.5, for the NPSH cases analyzed, DBA LOCA, Appendix R Fire,ATWS and SBA, it is stated that containment overpressure (COP) is required to meetthe required pump NPSH. Please clarify whether the COP required is necessitated dueto conservatism in the analysis, and whether it can be (or has been) shown that with arealistic analysis, COP is not needed.Additional information is provided in NSPM letters L-MT-12-082NSPM Response Iand L-MT-12-107 that considers the conservatism required byNSECY 11-0014 (References 29-3 and 29-4).At MNGP only the DBA and Appendix R fire events were previously evaluateneed for containment overpressure to satisfy NPSH requirements for the ECThe most recent NRC approval of the use of containment overpressure at Mwas with approval of Amendment 139 (Reference 1) on June 2, 2004. Theis the first review of the other events for containment overpressure needs.,d for theCS pumps.:nticello-PU projectThe m~aimum wct::cl prcccuro roquirod in tho tablc bolow i6 the preraUre abovatmozphi I przzzUrl needecd to support ECCS pump NPSH i.e.,eelntainmznt evcrprcccurc. !n all eaecoc atmocphori perocure wa6 dofinod As 11.2pcoia. The containmonet ovorproccuro~ roquired ;A- b-RAcod- onR *ha u of A dete1rMdinitic..Event EP6U Maximum We't~vlPrcsswe Reguircd(.Ap~e"* R--Gese-Ner-24Small Break Aeozktnt&r&Design Besio Aeeident 6741-PRFO Caco No. IA4WG 2-94PRFO9 Case Ne. 26G4GFStatien Blaokout 0-Iltem 8L-MT-09-048Enclosure IPage 38 of 50The evaluation of ECCS pump NPSH for the DBA LOCA was performed undercalculation CA-07-038, Rev. 0, "Determination of Containment Overpressure Requiredfor Adequate NPSH for Low Pressure ECCS Pumps with Suction Strainer DebrisLoading at EPU Conditions." This calculation was provided to the NRC as part of letterL-MT-09-004 (Reference 2) on December 18, 2008.Cases 5 and 6 of this calculation provided a statistical evaluation of the limiting designbasis accident to determine if a more realistic approach would support that COP is notneeded. The statistical design basis accident evaluation provided by these casesassumed the availability of only 1 division of power consistent with the deterministicdesign basis accident analysis approach. These evaluations showed the need for1.8 psig of containment overpressure with these assumptions.Case 10 of the calculation did an evaluation assuming containment failure, i.e., nooverpressure but realistically assumed the availability of both divisions of ECCSequipment. In this case no containment overpressure is required.The remaining events were not evaluated statistically.

Reference:

29-1: Amendment 139 to Facility Operating License No. DPR-22 on June 2, 2004.29-2: NSPM letter L-MT-09-004 from Timothy O'Connor to U.S. NRC, "Response toNRC Containment & Ventilation Branch Request for Additional Information (RAIs)dated December 18, 2008 (TAC No. MD9990)."29-3: NSPM letter L-MT-12-082 from M A Schimmel to U.S. NRC, "Monticello Extended PowerUprate and Maximum Extended Load Line Limit Analysis Plus License Amendment Requests:Supplement to Address SECY 11-0014 Use of Containment Accident Pressure (TAC Nos.MD9990 and ME31145)," dated September 28, 2012.29-4: NSPM letter L-MT-12-107 from M A Schimmel to U.S. NRC, "Monticello Extended PowerUprate and Maximum Extended Load Line Limit Analysis Plus License Amendment Requests:Supplement to Address SECY 11-0014 Use of Containment Accident Pressure, Sections 6.6.4and 6.6.7 (TAC Nos. MD9990 and ME31145)," dated November 30, 2012.

FIt em L-MT-09-073Enclosure 1Page 6 of 11SCVB RAI No. 5Please provide numerical values in the following table in the blank cells and verify the information in the filled-in cells:NSPM RESPONSEThe information provided here is for the evaluation of NPSHr for the ECCS pumps.

Item 8-1L-MT-09-073Enclosure 1Page 7 of 11ATWS- CS 1 3035 23PRFO CS 2 0 NACase 1 RHR 1 4000 189.03 16.173 21.163 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> 33.913 3, 22RHR 2 4000 188.804 16.204 20.434 32.084 22RHR 3 4000 22RHR 4 4000 22ATWS- CS 1 3035 23PRFO CS2 0 NACase 2 RHR 1 4000 191.33 17.263 22.493 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> 34.503 3% 22RHR 2 4000 191.04 17.204 22.414 34.444 22RHR 3 4000 22RHR 4 4000 22ATWSLOOPCS 1CS 2RHR 1RHR 2RHR 3RHR 430350447-349.44,,2494-!23886 horsF7.6 h-ou-ris123.95S-Hreff 3%23NANA'23NA4 223.5NA'NIAAPP R-SORV(Case 1)CS 1CS2RHR 1RHR 2RHR 3RHR 40 \3029004178195i.14 4 1f7.6F24-1.2-3128.7 hour8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />s31.2.:2,APP R- CS 1 0 7 NANo SORV CS 2 3029 /23(Case 2) RHR 1 0 RHR2 49W 194.7 4969 17. 1;,- 21.11 3- 3 %2-RHR 3 0 28.8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> _ NARHR 4 0 3.8NASmall CS 1 3929Steam Line CS 2 0 NABreak RHR 1 0 a 0" 24-.44 0 i4 4 3 NAShort RHR 2 0 [~uded by DBA LOCA and not required by SECY 11-0014 NATerm RHR 3 4&2Q EI Item 8L-MT-09-073Enclosure 1Page 8 of 11(<600 RHR 4 0 NAseconds)Small CS 1 3G29 2QSteam Line CS 2 0 NABreak RHR 1 0 2-7. 43O .. NALong Term RHR 2 0 4 1 ....... 1 NA(>600 RHR 3 499 [Bounded by DBA LOCA and not required by SECY 11-0014 ]4seconds) RHR 4 0I__ NAStation CS 1 0 NABlackout CS 2 0 NAEvent RHR 1 0 157.4@3 hrs 14.26@3 hrs 36.74@3 hrs NA(4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> RHR 2 0 for HPCI for HPCI2 for HPCI 0 28.42 1% NAduration) RHR 3 0 NARHR 4 0 NAHPCI 3000 17Station CS 1 0 NPsHreff3% NABlackout CS 2 0 NA(RHR used RHR 1 4000 41.27@4 hrs /22after 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> RHR 2 4000 175.5@4 hrs 14.22 for RHR 086.2 3% 22point) RHR 3 4000 22RHR 4 4000 22HPCI 0 NANotes:IN ot U sed .,,_,,. I 411A '13A.......... .It .... I*.

• J---- '=IPL L I I --WaSFU run Y io onlyazy. +R no cPProcc1Ion p981 iGomporFiur FoquIFrc to cuIppon PlraM MROr :nc IR iimtn PUMPSoPheric ProeurcF Of 11.26 pc6im at *ho- And of4* thcporiod. ThoDA LORCAI ropoc foA ~n drt ic Fmoro........-....... ............2. NPSHA for HPCI for the SBO event is based on use of atmospheric pressure only not the actual containment pressure that would exist atthat point in the containment time history. HPCI is not required to start again after 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> for this event.3. Review of time histories resulted in slight differences in limiting data as compared to values shown in partial time histories provided inPUSAR Section 2.6.5, Tables 2.6-2 through 2.6-9. All time steps are reflected in Figures 2.6-1A through 2.6-8 showing complete timehistory results.4. Limiting time step provided in PUSAR Section 2.6.5 tables.5. Assumes suction strainer debris loading per PUSAR Section 2.6.5 L-MT-09-073Enclosure 1Page 9 of 11SCVB RAI No. 6aPlease provide the basis for each of the flows in the above table and why the flows areconservative for analyses using containment accident pressure. This question hasbeen changed to "provide a description of conservative assumptions in COP analysis"NSPM RESPONSEThe basis for the DBA LOCA short term (runout) and long term (throttled) flows is theoriginal NPSH calculation of record, which were developed during power rerate(MNGP's first EPU) for containment overpressure amounts that were subsequentlyapproved by the NRC. These flows were derived from hydraulic models of the differentphases of ECCS pump operation during a DBA LOCA. The flow values are consistentwith ECCS pump design flows as described in the USAR and with periodic pumpoperational testing.For the DBA LOCA short term, the time to reactor vessel level recovery is less than 10minutes such that the timing of the runout flows are conservative with respect to actualflows after level recovery. The 10 minute time is the standard time period prior tocrediting manual operator actions. The short term (runout) flow values were developedfrom FLO-SERIES hydraulic models with all ECCS pumps running.The steady state floWc for the PRA. OCAS and Appendi* R ovont arc eencistcnt withflows used for the CLT-P COP Analysis which wcrc used by NSPIV to establish theexisting COP design bacis as approved by Lioonse Amendment 130. Please see thefloW .The flow rates used for accidents and AOOs are shown in L-MT-09-073, SCVB[RAI No. 5 and are further discussed in L-MT-12-082, Enclosure Section 2.0.According to Section 6.2.3.2.1 of the MNGP USAR, each RHR pump is designed todeliver greater than or equal to 4000 gpm. This provides margin above the minimumrequired injection flow (3870 gpm) assumed for the plant safety analysis. For the toruscooling mode, the design flow rate is 4000 gpm. A plant periodic surveillance testingdemonstrates that each RHR Heat Exchanger is capable of passing the single RHRpump containment cooling requirement of 4000 gpm.According to ction 6.2.2.1 of the MNGP USAR, each CS pump is required to inject2800 gpm with "-.g gpm allowance for leakage. Per section 6.2.2.2.1 of the USAR,the CS design flow capacity is 3020 gpm. At MNGP, each CS pump is equipped with alocked-open minimum flow line. The hydau.li mo., del , hew, d that the ..r.lting Gs .floW to proey:dc 2800 gpm was 3036 gpmn (235 gpmn minimum flow !*Re) durfing a DBAperiodic plant surveillance testing confirms that the CS pumps can deliv flow rate of80gpm. L-MT-12-082 provides additional information on CS and RHR pumpcapabilities.

It em 91NEDC-33322P, Revision 352.90F* Turbine Building -Feedwater and Condensate pump areas, andissociated switchgearThe increase in temperature in the Reactor Building areas will be _48 as a result of minor heatload increases and is within the design temperatures for the areas. Modifications for thecondensate and feedwater pumps/motors are necessary for full EPU operation, which willincrease heat loads in the Turbine Building. The ventilation systems in the condensate andfeedwater pump areas, and associated switchgear, will be evaluated in more detail when themodification designs are confirmed and the ventilation systems will be modified for EPU toaccommodate the increased heat loads to maintain these area temperatures within acceptablevalues if necessary.ConclusionNSPM has evaluated the effects of the proposed EPU on the power dependent HVAC systemsthat serve the Turbine Building and Radwaste Building. Several plant areas will have higherheat loads but HVAC system operation is not adversely affected. The HVAC systems in thecondensate and feedwater pump areas, and associated switchgear, will be evaluated in moredetail and modified if necessary to support EPU operation as a result of the modifications tothose systems for EPU. Therefore, the proposed EPU is acceptable with respect to I IVACsystem operation in the Turbine Building, Reactor Building, and drywell.2.7.6 Engineered Safety Feature Ventilation SystemReaulatory EvaluationThe function of the engineered safety feature ventilation system (ESFVS) is to provide a suitableand controlled environment for ESF components following certain anticipated transients andDBAs.The NRC's acceptance criteria for the ESFVS are based on (1) GDC-4, insofar as it requires thatSSCs important to safety be designed to accommodate the effects of and to be compatible withthe environmental conditions associated with normal operation, maintenance, testing. andpostulated accidents; (2) GDC-l 7, insofar as it requires onsite and offsite electric power systemsbe provided to permit functioning of SSCs important to safety; and (3) GDC-60, insofar as itrequires that the plant design include means to control the release of radioactive effluents.Specific NRC review criteria are contained in SRP Section 9.4.5.Monticello Current Licensing BasisThe general design criteria listed in RS-001 are those currently specified in 10 CFR 50,Appendix A. The applicable Monticello principal design criteria predate these criteria. TheMonticello principal design criteria are listed in USAR Section 1.2, "Principal Design Criteria."In 1967, the Atomic Energy Commission (AEC) published for public comment a revised set ofproposed General Design Criteria (Federal Register 32FR10213, July Ii, 1967). Although notexplicitly licensed to the AEC proposed General Design Criteria published in 1967, NorthernStates Power Company (NSP), the predecessor to NSPM, performed a comparative evaluation ofthe design basis of the Monticello, Unit 1, with the AEC proposed General Design Criteria of2-232 Item 9flL-MT-09-048Enclosure 1Page 43 of 50NRC RAI No. 34PUSAR Section 2.7.5, under heading "Technical Evaluation", please describe how theincrease in the area temperature of 1.8 OF or less is calculated. Is this based on theEPU revised design heat load in that area while the currently designed HVAC systemserving that area is operating?N S- PMo- 13" -s--INSPM peprformed a calculation that determined that the maximumroM PMpAreas in the Reactor Building that will experience higher loads due to EPU are theSteam Tunnel, HPCI Room, and the RHR and Core Spray Pump Rooms. The SteamTunnel (less than 1°F) and the RHR and Core Spray Pump Rooms ( 8-42F) are expectedto see a small increase in the calculated room temperature. The HPCI is notexpected to see an increase in the calculated room temperature. The mnthod used tocalculate these increases is given below.Steam Tunnel -The less than V 0F increase is calculated as follows:Heat loads to the room considered in design calculations are from system piping (MainSteam and Feedwater). EPU does not impose changes to the Main Steamtemperature, therefore there are no changes to heat loads from the Main SteamSystem. For Feedwater, EPU results in a 12.6°F increase (383.70F to 396.30F) at 2004MWt (LPU). Based on a reference temperature of 90°F this 12.60F increase in pipetemperature represents a 4.3 percent increase [12.61(383.7-90)] in the differencebetween the reference temperature and piping temperature.From existing design calculations at a room temperature of 104°F and a pipe insulationtemperature of 160°F, which are the worst case heat load conditions evaluated, thefeedwater piping accounts for approximately 15 percent of the piping heat load. Giventhat room temperature is linearly proportional to heat load and the feedwatertemperature increases 4.3 percent and that the feedwater piping accounts for 15percent of the total heat load, the feedwater increase results in a 0.7 percent increase(4.3 percent of 15 percent) in room temperature above the reference temperature.Conservatively, taking a 1 percent increase and applying it to the difference betweenthe maximum measured room temperature (121.80F) and the reference temperature of90'F, results in a EPU room temperature increase of 0.3°F [0.01*(121.8-90)]. Inaddition to the heat load increase, it was assumed that the cooling coil returns anincreased air temperature to the room. Assuming a 10°F approach for the coiling coiland applying the same percentage increase results in an additional 0.1°F increase tothe room. Therefore, the estimated total room temperature increase was determined tobe 0.40F.

Iltem 9L-MT-09-048Enclosure IPage 44 of 50RHR & Core Spray Pump Rooms -The 4--. increase is calculated as follows:lectrical heat loads in the room remain unchanged. Piping heat loads are from RHR/a Core Spray piping, with the majority of the piping containing torus water, with thtoru water temperature following a LOCA increasing as a result of EPU. The torutemp ture used in existing design calculations is based on a maximum torustemper re of 191OF. The maximum EPU torus water temperature following OCA is208°F. T 170F increase was evaluated for its affect on the piping heat lo and theresulting ro temperature. The RHR piping and heat exchanger surface areinsulated. E ing design calculations calculate the temperature of the " sulationsurface and con ude that this temperature will quickly be exceeded b he roomtemperature and t refore the RHR piping does not play a significa role in the roomheat load. The EP rus water temperature was used to repeat e calculations andthe same conclusion) s reached for EPU operation.The Core Spray piping is n tinsulated and thus pipe surfac mperature was assumedto be the torus water tempe ure. The contribution of thi iping to the overall heatload varies as the room and to s water temperature ch ge. Existing designcalculation tabulate Core Spray ing heat loads as unction of room temperature andtorus water temperature. The max um Core Spra/piping load of 63,293 Btu/hr occursat a room temperature of 115°F and e maximu orus water temperature of 191°F.Using the fixed electrical load (341,500 tu/hr) r suits in a maximum total heat load of404,793 Btu/hr of which the piping accou s f 15.6 percent (63,293 / 404,793) of theoverall load.Based on a reference temperature of 9 F the OF increase in pipe temperaturerepresents a 16.8 percent increase [1 /(191-90)] the difference between thereference temperature and piping t perature. A 1 .8 percent increase in themaximum Core Spray piping hea oad results in an U piping load of 73,927 Btu/hr(1.168 x 63,293). Adding this t the Electrical Heat Loa (341,500 Btu/hr) results in amaximum EPU heat load of 5,447 Btu/hr.From above, the worst c e piping heat load accounts for 15. ercent of the total heatload. Given that room mperature is linearly proportional to he load, the torustemperature increas 16.8 percent, and that the core spray pipin accounts for 15.6percent of the total eat load, the torus water temperature increase sults in a 2.7percent increase 16.8 percent of 15.6 percent) in room temperature.Existing desi n calculations calculate the maximum room temperature to b 143.80F.Taking a 2 percent increase and applying it to the difference between the ximummeasur room temperature (143.80F) and the reference temperature of 90`F sults ina EPU oom temperature increase of 1.50F [0.027*(143.8-90)]. In addition to the eatload/ 'crease it was assumed that the cooling coil returns an increased air temper reto e room. Assuming a 10°F approach for the cooling coil and applying the same Iltem 9 1L-MT-09-048Enclosure 1Page 45 of 50BUF6raenea inomnas es2eJts in an Amififitn~iiit.- L- ...I..0.270F ces to the roani. Therefore,-mu tutat ro~~m tcmDcrature increaa~ w~m ~LU I .U I......................... OThe original response to this RAI indicated a 1.80F increase was determined usingengineering judgment based on heat load increases in the rooms. Since that response, aformal calculation for the building heatup resulting from the LOCA scenario at EPUconditions has been finalized. This calculation concluded that an increase of 2.9*F for RHRand CS pump room temperatures following a LOCA at EPU conditions would occur.GOTHIC 7.2a was used for the modeling software which in combination with enhancedReactor building conductors, volumes, and surface areas updated for EPU, provides a moreaccurate analysis of the LOCA event than previous modeling versions. No methodologychanges were made. The 2.90F temperature increase for the RHR and CS pump rooms hasbeen evaluated and determined to be acceptable. No modifications in the RHR and CSpump rooms are required due to the higher LOCA temperatures at EPU conditions.

ilt-em 1-1NEDC-33322P, Revision 32a and 2.2-2b). These piping systems have been evaluated using the process defined inAppendix K of ELTR I and found to meet the appropriate code criteria for the EPU conditions,based on the design margins between actual stresses and code limits in the existing design. Theoriginal construction code was USAS B31.1.0 -1967 Power Piping Code. The existing code ofrecord for many systems is ANSI B31.1.0, 1977 Edition with Addenda up to and includingWinter 1978 and ASME Boiler and Pressure Vessel Code -Section II, Division 1 1977 Editionthrough the Winter 1978 Addenda for torus attached piping. The existing code of record forother specific systems includes other versions of ANSI B31.1.0 and/or ASME Section 1i1,Division 1. The Codes of Record as referenced in the appropriate calculations, code allowablevalues, and analytical techniques were used and no new assumptions were introduced. For thosesystems that do not require a detailed analysis, pipe routing and flexibility were evaluated anddetermined to be acceptable.Pipe break criteria were evaluated in accordance with Monticello Design Criteria, which arebased on the Giambusso letter, SRP 3.6.2 and Generic Letter 87-1 1. Where required, percentageincreases were applied to the calculated stress levels at applicable piping system node points.The combination of stresses was evaluated to meet the requirement of pipe break criteria. Basedon these criteria, no new postulated pipe break locations were identified.Pipe SupportsOperation at the EPU conditions increases the pipe support loadings on some BOP pipingsystems due to increases in the temperature of the affected piping systems (see Tables 2.2-2a,2.2-2b. and 2.2-2c).The pipe supports for the systems affected by EPU loading increases were reviewed to determineif there is sufficient margin to code acceptance criteria to accommodate the increased loadings.This review shows that, in most cases, support loads under EPU conditions are in compliancewith the appropriate Code criteria. Additional e will be0 L, & p M &O ... /ee.4hequpe~ will be mediii ripd 8!z~tina EPU eenditicns (see Table 2.2 2d) io enzurz ccdelimnits arc Nt c.c:de.d.'_l\ Detailed analyses of EPU loading has been completed and the results/indicate that code limits are not exceeded.Main Steam and Associated Piping System Evaluation (Outside containment)The MS piping system (outside containment) was evaluated for compliance with Monticellocriteria, including the effects of EPU on piping stresses, piping supports, and the associatedbuilding structure, turbine nozzles, and valves.Because the MS piping pressures and temperatures outside containment are not affected by EPU,there was no effect on the analyses for these parameters. The increase in MS flow results inincreased forces from the turbine stop valve closure transient (TSVC). The turbine stop valveclosure loads bound the MSIV valve loads because the MSIV closure time is significantly longerthan the stop valve closure time. Due to the magnitude of the TSVC transient load increase, thetransient event was reanalyzed. The MS piping was then reanalyzed using this revised loaddefinition. The MS turbine stop valve closure transient analysis pipe stress and support results areprovided in Table 2.2-2c.2-37 Item 1IiNEDC-33322P, Revision 3Pipe StressesThe results of the Main Steam system piping analysis indicate that piping load changes do notresult in load limits being exceeded for the MS piping system outside containment except for afew small bore lines. Aadditional aic:tail.d ana...e. will be p...p.r.. andl.r !he piping %,ill bemed~fled for these small befe lines prier tz EPU4 implemenwaizr. ie ensure eede litmits aft notz,..eeded (S:e Table 2.2 2d). No new postulated pipe break locations were identified.Peu r Detailed analyses of EPU loading has been completed and the resultsPipe Supports "' indicate that code limits are not exceeded.The pipe supports and turbine nozzles for the MS piping system outside containment wereevaluated for the increased loading and movements associated with the turbine stop valveclosure transient at EPU conditions. The evaluations demonstrate that the supports and turbinenozzles have adequate design margin to accommodate the increased loads and movementsresulting from EPU except for a few supports. Aidi:inal detailed an.lyss ..ill be prepa...anJ_'zr the suppert1 will kb mcadfied pri@ to 611W impk-m.ntatiztn le ....u.. eed1 limits are ...temeeeded (See Table2.2 2d) Based on existing margins available for the outside containment MSpiping supports, except for those supports that may require modification, it was concluded that EPUdoes not result in reactions on existing structures in excess of the current design capacity. Structuralcapacity associated with modified supports will be evaluated prior to EPU implementation to ensuredesign capacity is not exceeded.ConclusionNSPM has evaluated the structural integrity of pressure-retaining components and their supportsand has addressed the effects of the proposed EPU on these components and supports. Theevaluation indicates that pressure-retaining components and their supports will continue to meetthe requirements of 10 CFR 50.55a and Monticello's current licensing basis followingimplementation of the proposed EPU. Therefore, the proposed EPU is acceptable with respect tothe structural integrity of the pressure-retaining components and their supports.2.2.3 Reactor Pressure Vessel Internals and Core SupportsReaulatory EvaluationReactor pressure vessel internals consist of all the structural and mechanical elements inside thereactor vessel, including core support structures.The NRC's acceptance criteria are based on (1) 10 CFR 50.55a and GDC-l, insofar as theyrequire that SSCs important to safety be designed, fabricated, erected, constructed, tested, andinspected to quality standards commensurate with the importance of the safety functions to beperformed; (2) GDC-2, insofar as it requires that SSCs important to safety be designed towithstand the effects of earthquakes combined with the effects of normal or accident conditions;(3) GDC-4, insofar as it requires that SSCs important to safety be designed to accommodate theeffects of and to be compatible with the environmental conditions associated with normaloperation, maintenance, testing, and postulated accidents; and (4) GDC-10, insofar as it requiresthat the reactor core be designed with appropriate margin to assure that specified acceptable fuel2-38 Iltem 11NEDC-33322P, Revision 3Table 2.2-2d Piping Components Requiring Further ReconciliationSystemI Vi~m team (Outside Containment)'2 Feedwa and Condensate (from condensvalves dw of the HP Heaters), 3 Torus Attached 4 RHR (BOP Condensate Se ce Water Lin5 Cross Around Piping 1,2ite pump'to the MOto pending p p changes6 CARV Discharge Piping *'Notes:1. Walkdowns in H' iation Areas are required to complete calcula s.2. Scope of ross Around Piping Analysis is being determined upon turbinemodi tion.3. ope of CARV Analysis is being determined based upon turbine modification.Table 2.2-2d is no longer required as piping analyses have been completed.The results from the piping analyses indicate that code limits are notexceeded.2-63 Iltem 11 ]L-MT-09-044Enclosure 1Page 26 of 46EMCB RAI No. 17Steam flow and feedwater flow will increase as a result of the CPPU implementation.The load due to the TSV fast closure transient is used in the design of the MS pipingsystem. Page 2-31 states that "Due to the magnitude of the TSVC transient loadincrease [at EPU], the transient event was reanalyzed. The main steam piping was thenreanalyzed using this revised load definition."a) Provide a quantitative summary of the MS and associated piping system evaluation(inside and outside containment), including pipe supports, that contains theincreased loading associated with the TSV closure transient at EPU conditions,along with a comparison to the code allowable limits. For piping, include maximumstresses and data at critical locations (i.e. nozzles, penetrations, etc), includingfatigue evaluation CUFs, where applicable. For pipe supports, state the method ofevaluation for EPU conditions and confirm that the supports on affected pipingsystems have been evaluated and shown to remain structurally adequate to performtheir intended design functions. For non-conforming piping and pipe supports,provide a summary of the modifications required to ensure that piping and pipesupports are structurally adequate to perform their intended design functions and theschedule for completion of these modifications.b) For FW and condensate, please respond as in part (a) of this RAI.NSPM RESPONSEResponse to Part aThe Main Steam system piping analysis results, including TSV closure loads aresummarized below. The piping system was evaluated (by re-analysis versus scaling)using requirements from the existing code of record. The supports in the Main Steampiping remain adequate to perform their intended design functions. An updated statusfor PUSAR Table 2.2-2d is provided in response to RAI 12, Part b above. There are nonon-conforming pipes or supports requiring modifications on the main steam system.

Item 11L-MT-09-044Enclosure 1Page 27 of 46Main Steam Inside ContainmentMaximum EPU Results (Highest Interaction Ratio):Maximum Pipe StressesLoad ServiceCombination Level Node Stress Allowable Ratio_ _ _i___i S/AllowP+DW B 161 7709 15000 0.51TH Range B 203 22940 22998 1.00P+DW+OBE B U08 17823 18000 0.99DW+TSV+SRV+SSE D U08 31261 36000 0.87Note: 1. High Energy Line Breaks locations are not postulated inside containment.2. Due to the revised analysis of the turbine stop valve closure loads, comparison to pre-EPUvalues is not meaningful.Maximum SRV Flange LoadsInlet FlaneService 1 Node Moment Allowable RatioLoad Condition LevelI ft-lb ft-lb M/AllowDW+TH B U07 14558 34083 0.427DW + TH + Level B Dynamic B U07 39362 68167 0.577DW + TH + Level D Dynamic D U07 65909 99750 0.661Outlet FlangeService Node Moment Allowable RatioLoad Condition Level ft-lb ft-lb M/AllowDW+TH B U08 13663 31000 0.441DW + TH + Level B Dynamic B U08 34907 62083 0.562DW + TH + Level D Dynamic D U08 57547 91250 0.631Maximum RPV Nozzle LoadsRPV Nozzle N-3DService Node Fx Fy Fz Mx My MzLoads TLevel IIb lb lb ft-lb -ft-lbI ft-lbMaximum Loads B 101 6667 18555 4979 67422 18193 98764Allowables B 101 19392 51712 19392 .258562 32320 258562Maximum/Allowable B 101 0.344 0.359 0.257 1 0.261 0.563 0.382Maximum Flue Head Anchor LoadsPenetrations X7A, X7B1, X7C, X7D -Side Bolt EvaluationService Node Tension Shear Tallow Sallow IRLoad Condition Level I lb lb lb Ib T/Ta+S/SaDW+TH+SSE+BREAK (X7D) I 2 106702 17509 157500 96250 0.859DW+TH+SSE+BREAK (X7A) D 30 1 107227 16683 157500 96250 0.854 L-MT-09-044Enclosure 1Page 28 of 46Maximum Support LoadsMS Relief Valve Dischar e Line Support RV25A-H1 (spring hanger)Max MinService Node Load Allowable IR Load Allowable IRLoad Condition Level lb lb Max/Allow lb lb Allow/Min_1 RDW+TH+ I 17. RS(TS, RV OB) B 285 11341 1344 0.9 1121 780 10.671Ilnsert Aftaln Steam Outside ContainmentEPIU Results (Highest Interaction Ratio):Maximum pe Stressesd* Service Node Stress Allowable RatioLevel psi psi S/Allow -P+DW B X7A 6877 15000 01.4TH Range B TURB 19441 22500 -T6P+DW+TSVB 268 12236 18000 0.68DW+TSV+SRV+SSEl 268 13795 26 0.52HELB DW+TH+OBE B TURB 1 27559 ,ý000 0.92z'11ZMaximum Turbine Loads N. yLoad Service Node Mx 8le Ratio Mz Allowable RatioCombination Level ft-lb ft-lb MxIAllow ft-lb ft-lb Mz/AllowDW B

• 32 1 413000 78 171446 722000 0.237DW+TH B

• 1321 413000 0.6ý 302310 1722000 0.419*Note: Loads from all turbine nod ere combinedMaximum Support L sMain Steam Line 'DDort PS-16. Node 283MaxService Load Allowable IRLoad ,ndition Level Component lb lb Max/Allow+TH+SRSS(TSV,SRV,OBE) B Anchor bolt 20026 20731 0.966Response to Part bThe maximum Feedwater system operating temperature is 397.70F at EPU conditionsfor the Feedwater piping from the outboard containment isolation valve to thecontainment and inside containment. This value is bounded by the original analysistemperature of 4000F. The design pressure for this portion of the Feedwater system isunchanged by EPU. Therefore this piping is unaffected by EPU relative to HELBpostulation. The current design basis for Feedwater piping analysis does not includefluid transient analysis. The stress analyses for the Feedwater piping from the outboard Item 11 1Insert AMaximum Flued Head Anchor LoadsPenetrations X7A, X7B, X7C, X7D -Bolt EvaluationMaximum Pipe Stresses (Outside Containment)Load Combination Service Node Stress Allowable InteractionLevel (psi) (psi) RatioP-+ DW A TURD 7650 15000 0.51TH Range A TURB 16618 22500 0.74P + DW + TSV B TURC 12288 18000 0.68P + DW + OBE* B X7A 14289 18000 0.79DW+SRSS(TSV, D X7A 21026 26325 0.80SSE)*HELB TH N/A TURB 16618 18000 0.92HELB N/A TURD 32631 30000 1.09**DW+TH+OBE I I I*Excluding seismic category II pipe between Stop Valves and Turbine**Indicates a HELB at this locationMaximum Turbine LoadsLoad Service Mx Allowable Interaction Mz Allowable InteractionCombination Level (fi-lb) (ft-lb) Ratio (ft-lb) (fi-lb) RatioDW B 37143 413000 0.090 184886 722000 0.256DW + TH B 284603 413000 0.689 163155 722000 0.226Note: Loads from all turbine nodes were combinedMaximum Support Loads (Outside Containment)Main Steam Line Support PS-16, Node 283