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#REDIRECT [[NG-15-0234, License Amendment Request (TSCR-143) to Extend Containment Leakage Test Frequency]]
| number = ML15246A445
| issue date = 08/18/2015
| title = Duane Arnold, License Amendment Request (TSCR-143) to Extend Containment Leakage Test Frequency
| author name = Vehec T A
| author affiliation = NextEra Energy Duane Arnold, LLC
| addressee name =
| addressee affiliation = NRC/Document Control Desk, NRC/NRR
| docket = 05000331
| license number = DPR-049
| contact person =
| case reference number = NG-15-0234
| document type = Letter, License-Application for Facility Operating License (Amend/Renewal) DKT 50
| page count = 97
}}
 
=Text=
{{#Wiki_filter:NExTera"ENERGY@August 18, 2015 NG-I 5-023410 CFR 50.90U.S. Nuclear Regulatory CommissionATTN: Document Control DeskWashington, DC 20555Duane Arnold Energy CenterDocket No. 50-331Renewed Facility Operating License No. DPR-49License Amendment Request (TSCR-143) to Extend Containment Leakagqe Test FreqiuencyIn accordance with the provisions of Section 50.90 of Title 10 of the Code of FederalRegulations (!0 CFR), NextEra Energy Duane Arnold, LLC (hereafter, NextEra Energy DuaneArnold) is submitting a request for an amendment to the Technical Specifications (TS) forDuane Arnold Energy Center (DAEC).The proposed amendment revises Technical Specifications (TS) Section 5.5.12, "PrimaryContainment Leakage Rate Testing Program," by requiring compliance with Nuclear EnergyInstitute (NEI) topical report NEI 94-01, Revision 3-A, "Industry Guideline for ImplementingPerformance-Based Option of 10 CFR Part 50, Appendix J," instead'of Regulatory Guide 1.163,"Performance Based Con~tainment Leak Test Program," including exemption 1.Attachment I provides an evaluation of the proposed chlanges. Attachment 2 provides marked-up pages of the existing TS to show the proposed changes. Attachment 3 provides revised(clean) TS pages. Attachment 4 provides a plant specific risk analysis. Attachment 5 providesdocumentation of probabilistic risk assessment technical adequacy. There are no newRegulatory Commitments or revisions to existing Regulatory Commitments.Approval is requested by September 1, 2016, to support Refueling Outage (RFO) 25, with thebeing implemented within 60 days of its receipt.In accordance with 10 CFR 50.9.1(b)(1), "Notice for Public Comment; State Consultation," acopy of this application, including attachments, is being provided to the designated State o~fIowa official.The DAEC Onsite ReView Group has reviewed the proposed license amendment request.If you have any questions or require additional information, please contact J. Michael Davis atNextEra Energy Duane Arnold, LLC, 3277 1JAEC Road, Palo, IA 52324 -C -j(.~.
Document Control DeskNG-1 5-0234Page 2 of 2I declare under penalty of perju~ry that the foregoing is true and correct.Executed on August 18, 2015.T. A. VehecVice President, Duane Arnold Energy CenterNextEra Energy Duane Arnold, LLCAttachments: As statedcc: Regional Administrator, USNRC, Region Ill,Project Manager, USNRC, Duane Arnold Energy CenterResident Inspector, USNRC, Duane Arnold Energy CenterA. Leek (State of Iowa)
ATTACHMENT I.to NG-15-0234NEXTERA ENERGY DUANE ARNOLD, LLCDUANE ARNOLD ENERGY CENTERLICENSE AMENDMENT REQUEST (TSCR-143)EXTEND CONTAINMENT LEAKAGE TEST FREQUENCY.EVALUATION OF PROPOSED CHANGES1.0 SUMMARY DESCRIPTION2.0 DETAILED DESCRIPTION2.1. PROPOSED CHANGE2.2 DESCRIPTION OF DAEC PRIMARY CONTAINMENT
 
==3.0 TECHNICAL EVALUATION==
3.1 LEAK TEST HISTORY3.1.1 TYPE A TESTING3.1.2 TYPE B AND C TESTING3.2 CONTAINMENT INSPECTIONS3.2.1 CONTAINMENT INSERVICE INSPECTION PROGRAM (IWE)3.2.2 CONTAINMENT VISUAL INSPECTIONS3.2.3 CONTAINMENT LINER TEST CHANNEL PLUGS3.2.4 CONTAINMENT CORROSION3.2.5 SUPPRESSION CHAMBER CORROSION3.2.6 SUPPRESSION CHAMBER CRACKING3.2.7 INACCESSIBLE AREAS3.2.8 CONTAINMENT COATINGS INSPECTIONS3.2.9 LICENSE RENEWAL COMMITMENTS ,3.3 NRC INFORMATION NOTICE 92-20, 'INADEQUATE LOCAL LEAK RATE TESTING"3.4 NRC LIMITATIONS AND CONDITIONS3.4.1 JUNE 25, 2008 NRC SAFETY EVALUATION3.4.2 JUNE 8, 2012 NRC SAFETY EVALUATION3.5 PLANT-SPECIFIC CONFIRMATORY ANALYSIS3.5.1 METHODOLOGY3.5.2 PROBABILISTIC RISK ASSESSMENT (PRA) TECHNICAL ADEQUACY3.
 
==5.3 CONCLUSION==
OF PLANT-SPECIFIC RISK ASSESSMENT RESULTS
 
==3.6 CONCLUSION==
Page 1 of 30 4.0 REGULATORY SAFETY ANALYSIS4.1 NO SIGNIFICANT HAZARDS CONSIDERATION DETERMINATION4.2 APPLICABLE REGULATORY REQUIREMENTS/CRITERIA
 
==4.3 CONCLUSION==
S
 
==5.0 ENVIRONMENTAL CONSIDERATION==
 
==6.0. PRECEDENT==
 
==7.0 REFERENCES==
Page 2 of 30 1.0 SUMMARY DESCRIPTIONIn accordance with the provisions of 10 CFR 50.90, NextEra Energy Duane Arnold, LLC (NextEraEnergy Duane Arnold) hereby requests an amendment to Duane Arnold Energy Center (DAEC)Technical Specifications (TS). This proposed change will allow extension of the Type A test intervalup to one test in 15 years and extension of the Type C test interval up to 75 months, based onacceptable performance history as defined in NEI 94-01, Revision 3-A.The requested amendment would revise TS Section 5.5.12, "Primary Containment Leakage RateTesting Program," to follow guidance developed by Nuclear Energy Institute (NEI) topical report NEI94-01, Revision 3-A, "Industry Guideline for Implementing Performance-Based Option of 10 CFRPart 50, Appendix J," (Reference 7.1) that was found by the NRC to describe an acceptableapproach for implementing the optional performance-based requirements of Option B to 10 CFR 50,Appendix J, as modified by the conditions and limitations in the Safety Evaluation (Reference 7.2).The purpose of NEl 94-01, Revision 3-A guidance is to assist licensees in the implementation ofOption B to 10 CFR 50, Appendix J, "Leakage Rate Testing of Containment of Light Water CooledNuclear Power Plants," (hereafter referred to as Appendix J, Option B). Revision 2-A of NEl 94-01(Reference 7.3) added guidance for extending containment integrated leak rate test (ILRT or Type Atest) surveillance intervals beyond ten years., and Revision 3-A of NEl 94-01 adds guidance forextending containment isolation valve (Type C test) local leakage-rate test (LLRT) surveillanceintervals beyond sixty months.The technical basis for the proposed license amendment utilizes risk-informed analysis augmentedwith non-risk related considerations. A risk impact evaluation performed by Westinghouse ElectricCompany (WEC) concluded that the increases in large early release frequency (LERF) are within thelimits set forth by the applicable guidance contained in Nuclear Regulatory Commission (NRC)Regulatory Guide (RG) 1.174 (Reference 7.4), NUREG-1 493, "Performance-Based ContainmentLeak-Test Program," and EPRI Technical Report TR-1 009325 (Reference 7.5).In accordance with the guidance of NEI 94-01 Revision 3-A, DAEC proposes to extend the maximumsurveillance interval for the ILRT to no longer than 15 years from the last ILRT based on satisfactoryperformance history. The current interval is no longer than 10 years and would require that the nextILRT for DAEC be performed during the Fall 2016 refueling outage. The proposed change wouldallow the DAEC ILRT to be performed in 2022. This will reduce the number of ILRTs performed overthe licensed period of operation resulting in significant savings in radiation exposure to personnel,cost, and critical path time during refueling outages.2.0 DETAILED DESCRIPTION2.1 PROPOSED CHANGEThe proposed license amendment would revise TS Section 5.5.12.b by changing the wording toindicate that the program shall be in accordance with NEl 94-01, Revision 3-A, instead of NuclearRegulatory Commission (NRC) Regulatory Guide 1.163.Current TS Section 5.5.12.b states in part that:This program shall be in accordance with the guidelines contained in Regulatory Guide1.163, "Performance-Based Containment Leak-Test Program," dated September 1995, asPage 3 of 30 modified by the following exception to NEI 9.4-01, Rev. 0, "Industry Guideline forImplementing Performance-Based Option of 10 CFR 50, Appendix J":1. The first Type A test after the September 1993 Type A test shall be performed nolater than September 2008.The proposed amendment would change this wording to indicate that the program shall be inaccordance with Nuclear Energy Institute (NEI) topical report NEI 94-01, Revision 3-A, "IndustryGuideline for Imnplementing Performance-Based Option of 10 CFR Part 50, Appendix J," andconditions and limitations specified in NE! 94-01, Revision 2-A. The proposed amendment wouldalso delete the reference to Regulatory Guide 1.163, 'Performance-Based Containment Leak-TestProgram," dated September 1995 and the listed Type A test exception.A marked-up copy of the proposed changes to the TS is provided in Attachment 2. Attachment 3provides revised (clean) TS pages. Attachment 4 provides a plant specific risk analysis.2.2 DESCRIPTION OF DAEC PRIMARY CONTAINMENTThe DAEC primary containment structure is a portion of the General Electric (GE) Mark I PrimaryContainment Pressure Suppression System. The complete pressure suppression system consists ofthe drywell which houses the reactor vessel and reactor coolant recirculation loops, the pressuresuppression chamber, the connecting vent system between the drywell and pressure suppressionchamber, isolation valves, vacuum relief system, and containment cooling systems.The drywell is a steel pressure vessel (0.75 to 3.0 inches thick), with a spherical lower portion andcylinder upper portion. It is enclosed in reinforced concrete, 4 to 7 feet thick, for shielding, and toprovide additional resistance to deformation and buckling over areas where the concrete backs upthe steel shell. Above the foundation transition zone, and below the flange, the drywell is separatedfrom the reinforced concrete by a gap of approximately 2 inches to allow for thermal expansion.Shielding over the top of the drywell is provided by removable, segmented, reinforced concreteshield plugs.The drywell vessel is provided with a removable head to facilitate refueling, one combination doubledoor personnel access lock/equipment lock, one equipment hatch, one personnel access hatch, andone control rod drive removal hatch. The head and hatches are all bolted in place and have doubleseals and test taps for leak tests.Special bellows seals are provided between the reactor vessel, the drywell vessel, and the reactorwell to form a watertight seal and enable flooding of the upper portion of the drywell during refuelingoperations. To protect the outer circumference of the bellows, a backing plate is provided which hasa test tap for leakage monitoring. During normal operation, six watertight hinged covers are openedpermitting circulation of ventilation air in the region above the reactor well seal bulkhead plate viaremovable air supply and return ducts.The pressure suppression chamber is a steel pressure vessel (0.50-0.534 inches thick) in the shapeof a torus located below and encircling the drywell. The pressure suppression chamber contains thesuppression pool and the gas space above the pool. The suppression chamber will transmit seismicloading to the reinforced concrete foundation slab of the Reactor Building. Space is provided outsidethe chamber for inspection. Access to the chamber is provided at two locations. There are two 4foot diameter manhole entrances with double gasketed, leak testable, and bolted covers connectedto the chamber by 4 foot diameter steel pipe inserts. These access ports will be closed whenPage 4 of 30 Primary Containment is required and will be opened only when the primary coolant temperature isbelow 212 0F and the pressure suppression capability is no longer required.The pressure suppression pool serves as a heat sink for postulated transient or accident conditions.Energy is transferred to the pool by either the discharge piping from the reactor pressure safety/reliefvalves or the drywell vent piping, which discharge below the water level. The pool condenses thesteam portion of the flow and collects any water carryover while non-condensable gases (includingany gaseous fission products) are released to the suppression chamber gas space. The pool alsoacts as a heat sink for High Pressure Coolant Injection (HPCI) System and Reactor Core IsolationCooling (RCIC) System steam exhaust. Energy is removed from the suppression pool when theResidual Heat Removal (RHR) System is operating in the suppression pool cooling mode.The suppression pool is also the primary source of water for the Core Spray System and the LowPressure Coolant Injection (LPCI) mode of the RHR System and the secondary source of water forthe RCIC and HPCI Systems. The quantity of water stored in the suppression pool is sufficient tocondense the steam from a design basis accident and to provide adequate water for the emergencycore cooling systems (ECCS). The suppression chamber is subject to the pressure associated withthe storage of a minimum of 58,900 -61,500 cubic feet of water distributed uniformly within thevessel during normal operation. Under accident conditions, the suppression chamber is designed for61,500 cubic feet of water and a maximum containment pressure of 62 psig.Eight 4'9" diameter vent pipes connect the drywell and the pressure suppression chamber. Jetdeflectors are provided in the drywell at the entrance of each vent pipe to prevent possible damageto the vent pipes from jet forces or projectiles that might accompany a pipe break in the drywell. Thevent pipes are provided with two-ply expansion bellows to accommodate differential motion betweenthe drywell and suppression chamber. These bellows have test connections that allow for leaktesting and for determining that the passages between the two-ply bellows are not obstructed.The drywell vents are connected to a 3'6" diameter vent header in the form of a torus, which iscontained within the air space of the suppression chamber. Projecting downward from the headerare 48 downcomer pipes, 24 inches in diameter and terminating 3 feet below the water surface of thepool and approximately 7 feet above the bottom of the Torus.Containment penetrations are designed for the same integrity as the primary containment structureitself. They will not limit the capabilities of the Prim~ary Containment System to act as a radiologicalbarrier before, during, or subsequent to any design basis accident.One combination personnel access lock/equipment lock is provided for access to the drywell.The personnel lock has two gasketed doors in series, with each door designed and constructed towitchstand the drywell design differential pressure. The doors are mechanically interlocked to ensurethat at least one door is locked at times when primary containment is required. The lockingmechanisms are designed so that a tight seal will be maintained when the doors are subjected toeither internal or external pressure. The seals on this access opening are capable of being testedfor leakage. The personnel access lock is bolted to an equipment insert barrel approximately 12 feetin diameter, which, in turn, provides double testable seals and is welded to the drywell shell. Thepersonnel access lock can be completely removed by an overhead monorail to increase the size ofthe opening should a larger access be required.A personnel access hatch is provided in the drywell head. There is a separate equipment accesshatch that provides access for larger equipment to pass though the containment. These hatches arebolted in place and provide double testable seals.Page 5 of 30 Personnel and equipment hatches are sized and located with full consideration of service required,accessibility for maintenance, and periodic testing programs._ A 2-inch minimum gap is maintainedaround the barrel of the personnel and equipment hatches as they pass through the concrete shieldwall.A control rod drive removal hatch with double, testable seals is provided. This hatch is bolted inplace and permits removal of the drive mechanisms when required.3.0 TECHNICAL .EVALUATION3.1 LEAK TEST HISTORY3.1.1 Type A TestingThe historical results of the Type A tests for DAEC are included in the table provided below. Thereported leak rate is at the 95 percent upper confidence level and includes any Type B and Type Cpenalties.The last DAEC Type A test was completed on March 13, 2007. Previous Type A testing confirmedthat the DAEC containment structure leakage is acceptable, with considerable margin, with respectto the TS acceptance criterion of 2.0 percent of primary containment air weight per day at the designbasis loss of coolant accident pressure (Pa). Since the last two DAEC Type A test as-found results,as shown in the table provided below, were less than 1.0 La, a test frequency of at least once per 10years was justified in accordance with NEI 94-01, Revision 0.Repair or replacement activities (including any unplanned activities) performed on the pressureretaining boundary of the primary containment prior to the next. scheduled Type A test would besubject to the leakage test requirements of American Society of Mechanical Engineers Boiler andPressure Vessel Code (ASME Code) Section Xl, Paragraph IWE-5221, "Leakage Test." There havebeen no pressure or temperature excursions in the containment that could have adversely affectedcontainment integrity. There are no anticipated repairs or modifications of the containment that couldaffect leak-tightness that would not be measured by local leak rate testing as required in Section9.2.4 of NEI 94-01, Revision 0.Following the approval of this license amendment, the next DAEC Type A test must be performed onor before March 13, 2022.DAEC Type A Test Historical Results Since 1985TsCopein AFonLek As Found As LeftDastCopeto RA t o ea Acceptance As Left Leak Rate AcceptanceCriteria Criteria1985 (RFO 7) Not quantified  2.0 %wt/day 0.478 %wt/day -< 1.5 %wt/day1987 (RFO 8) Not quantified < 2.0 %wt/day 0.503 %wt/day < 1.5 %wtlday1988 (RFO 9) 1.353 %wt/day <2.0 %wt/day 0.229 %wt/day < 1.5 %wt/day1990 (RFO 10) 1.633 %wt/day  2.0 %wt/day 1.146 %wt/day < 1.5 %wt/day-9/20/1993 (RFO 12) 0.511 %wt/day <2.0 %wt/day [0.254 %wt/day < 1.5 %wt/day-3/13/2007 (RFO 20) 0.355 %wt/day  2.0 %wt/day I0.342 %wt/day < 1.5 %wtlday%wt/day = Percent primary containment air weight per dayPage 6 of 30 The following is a description of the results from the latest two 1LRTs at DAEC.The March 2007 periodic Type A test was performed using BN-TOP-1 calculated at the 95% upper.confidence limit (UCL). The performance leak rate corresponding to the definition in NEI 94-01 wasequal to the as-left ILRT results of 0.342 %wt/day since no leakage paths were isolated during theILRT.The September 1993 periodic Type A test was performed using BN-TOP-1 calculated at the 95%UCLI which resulted in a value of 0.15356 %wt/day. The performance leak rate corresponding to thedefinition in NEl 94-01 was 0.254 %wt/day with corrections.As required by NEJ 94-01, Revision 3-A Section 9.1.2, further extensions in test intervals are basedupon two consecutive, periodic, successful Type A tests and requirements stated in Section 9.2.3 ofthis guideline. The results in the table show that there has been substantial margin to the maximumallowable leakage rate of 2.0 %wt/day.* 3.1.2.Type 13 and C TestinQThe Type B and Type C containment leakag'e rate testing program for DAEC requires pneumatictests intended to detect or measure leakage across pressure-retaining or leakage limiting boundariesand containment isolation valves. As discussed in NUREG-1493, Type B and Type C tests canidentify the vast majority of potential containment leakages.As discussed in NUREG-1493 and NEI 94-01, Revision 3-A, Type B and Type C tests can identifythe vast majority of all containment leakage paths. This amendment request adopts the guidance inNEl 94-01, Revision 3-A in place of NEI 94-01, Revision 0, but otherwise does not affect the scope,performance, or scheduling of Type B orType C tests. Type B and Type C testing will continue toprovide a high degree of assurance that containment leakage rates are maintained well within limits.A review of the Type B and Type C test results from the spring of 2003 through the fall of 2014 hasshown a large amount of margin between the actual as-found and as-left outage summations andthe TS leakage rate acceptance criteria (that is, less than 0.6 La).* The as-found minimum pathway leak rate for DAEC shows an average of 14.0 percent of 0.6La.* The as-left maximum pathway leak rate for DAEC shows an average of 23.8 percent of 0.6 Lawith a high of 35.5 percent or 0.22 La.Page 7 of 30 DAEC Type B and Type C Leak Rate Summation History Since 2003Refueling Outage As-Found Min Percentage of AsLf a ah PercnaeoPath 0.6 La 0.6 LaRFO 18Spring 2003 40,136 sccrn 18.3% 55,184 sccrn 25.1%SRing 200 37,522 scorn 17.1% 40,083 scorn 18.3%RHO~e 200 22,543 scorn 10.3% 77,918 sccmrn 35.5%RHO 21Winter 2009 18,212 scorn 8.3% 44,995 scorn 20.5%RHO 22Fall 2010 20,960 scorn 9.5% 53,525 scorn 24.4%RFO 23Fall 2012 53,212 scorn 24.2% 47,003 scorn 21.4%RFO 24Fall 2014 23,276 scorn 10.6% 47,346 scorn 21.6%scorn = standard cubic centimeters per minuteThere was one local leak rate test failure during RFO 24. The as-found test result for CV2211I was2865 scorn, which exceeds the administrative limit of 1500 scorn. After running the HPCI system, anas-left test was successfully performed on CV221 1. Therefore, the HPCI system flushed out debrison the valve disk and seat that caused the as-found test failure. The as-left LLRT was performedwith a measured leakage of 540 scorn.There were three test failur:es during RHo 23: CV5704B failed an as-found LLRT, CV4305 failed anas-found LLRT, and CV4300 failed an as-found LLRT.An LLRT was attempted on CV5704B during RFO 23, but the required test pressure could not beobtained. A packing leak on V57-0076 was identified. After repairing the packing leak, testing wasthen performed again. Test pressure could not be maintained and flow was noticed at the vent pointoutside of the test boundary. A work order was then initiated to repair the valve. Repairs wereperformed and the valve returned for as-left testing. During the setup of the valve prior to testing, itwas identified that there were air leaks at the diaphragm of PCV5704B, CV-5704B CONTROL AIRPRESSURE REGULATOR, and on the supply line. An as-left LLRT was performed which indicatedleakage above the acceptance criteria. That afternoon it was discovered that there was a loose fittingon the test equipment. The fitting was tightened and the LLRT was successfully completed.PCV5704B was replaced after the test had been completed.The inspection of CV5704B3 identified the following as-found degraded conditions: the valve bodyand piping contained dirt, indications of a packing leak on the stern, dirt on the stern, dirt on the seat,dirt on the disc, and excessive wear on the stem back seat. The as-found blue check on the valveseat to the disk seat was satisfactory as was the total indicated runout of the valve stem. The valvewas cleaned and reassembled. The only valve components replaced were the bonnet gasket andthe packing. The as-left LLRT was successfully performed at the end of RFO 23 with a measuredleakage of 1,917 scorn.Also during RFO 23, CV4305, TORUS VACUUM BREAKER V-43-168 ISOLATION, failed an LLRT.The administrative limit is 11,000 scorn, and the as-found result was unmeasurable. The test volumePage 8 of 30 could not be pressurized above 21.6 psig and air flow was felt coming from the vent path at V43-0037. A work order was initiated to repair the valve. The valve was disassembled and the T-sealand 0-rings replaced. Information provided by the mechanics involved with this work indicates thatnothing appeared to be abnormal with the T-seal or the 0-rings. The valve was reassembled. Theposition stop was adjusted during valve reassembly. An LLRT was again performed and the testvolume could not be pressurized above 14 psig. The vacuum breaker, V43-0 168, was opened and itwas observed that the disc was slightly off the seat. The actuator position stops were repositioned toallow the disc to fully close. Additionally, the set screw that actuates the spool valve to pressurize theT-seal was found loose. It is possible that the set screw would actuate the spool valve too earlywhich would prematurely inflate the T-seal and could restrict the valve disc from seating fully. Theset screw position was adjusted. The as-left LLRT was then performed with a measured leakage of382 sccm.The hex head screw is typically secured to the lever by a lock nut on CV4305. Following this failure,the set screw was able to be adjusted by hand indicating that the lock nut was not engaged. Afterreviewing the maintenance procedure, it was determined that there was no step to ensure that thelock nut is engaged. In order to prevent recurrence of this failure on CV4305, the maintenanceprocedure has been revised to include this step.The final contributing failure during RFO 23 was due to a potential T-seal problem on CV4300,TORUS VENT LINE INBOARD ISOLATION. LLRT Test pressure (46-48 psig) between CV4300,CV4301 -TORUS VENT LINE OUTBOARD ISOLATION, and CV4357 -TORUS HARD PIPE VENTLINE ISOLATION -was initially achieved and then pressure dropped sharply to about 38 psig.Pressure to the T-seal for CV4300 was noted to be about 80 psig before pressurizing the volumebetween CV4300, CV4301, and CV4357 and 20 psig after the test volume depressurized to about 38psig. T-seal pressure read about 20 psig at that point for CV4300. The administrative limit for thiscombined LLRT test is 22,000 sccm and the as-found result could not be determined.Initially, an LLRT of CV4300 was attempted but a test pressure of greater than 38 psig could not beobtained. Troubleshooting was performed with the LLRT boundary pressurized to try to identify thecause of the leakage. This troubleshooting identified that the hex head screw was not fixed in placeand would allow the plunger to reposition and deflate the seal. A work order was initiated to repairthe valve by applying Ioctite to threads of the hex head screw. The as-left LLRT was thensuccessfully performed with a measured leakage of 70 sccm.To prevent recurrence of this failure on CV4300, a reduced height locknut was installed. This locknutis sufficient to secure the hex head screw in place and not allow the plunger of the spool valve tomove and release the seal pressure.3.2 CONTAINMENT INSPECTIONSGeneral visual examinations of the accessible surfaces of the primary containment are performed inaccordance with the Primary Containment Inspection Program. These examinations are performedto assess the general condition of the primary containment surfaces and to satisfy the visualexamination requirements of ASME Code Section Xl, Subsection IWE. These examinations areperformed in sufficient detail to detect signs of deterioration.Detailed visual examinations are performed to determine the magnitude and extent of deteriorationof suspect surfaces initially detected by general visual examinations. The conditions reported duringthe examinations are evaluated to determine acceptability. The conditions are acceptable if it isPage 9 of30 determined that there is no evidence of damage or degradation sufficient to warrant furtherevaluation or performance of repair and replacement activities.The primary containment is visually examined under two separate programs. The first is the PrimaryContainment Inspection Program discussed in Section 3.2.1. This program includes provisions tosatisfy the visual examination requirements of ASME Code Section Xl, Subsection IWE and 10 CFR50, Appendix J, Option. B. A visual examination is made of the accessible interior surfaces ofcontainment in order to identify evidence of deterioration that may affect the containment structuralintegrity or leak tightness. If signs of corrosion are evident that exceed the acceptance standard(IWE-3500), they must be either corrected by a repair or replacement activity Or deemed acceptablefor continued service by an engineering evaluation. Both Regulatory Guide 1.163, September 1995,and the ASME Code require a general visual examination of the accessible liner surfaces threetimes in a ten year period.The second program .is the Containment Coatings Inspection and Assessment Program discussed inSection 3.2.8. This program mandates a visual inspection and assessment of the protective coatingson the containment structure and equipment in the readily accessible areas of the primarycontainment.This program is implemented to ensure that the integrity of the coatings is maintained and wasestablished in response to NRC Generic Letter 1998-04, "Potential for Degradation of theEmergency Core Cooling System and the Containment Spray System After a Loss-of-CoolantAccident Because of Construction and Protective Coatings Deficiencies and Foreign Material inContainment." The inspection frequency of the above programs ensures that when an area ofconcern is identified, it only affects a small localized area. Corrective action is taken following anySigns of coating blistering, peeling, or corrosion.3.2.1 Containment Inservice Inspection Program (IWE).The ASME Code Section III, Class B, 1968 Edition with the Summer 1968 Addenda and CodeCases 1177, 1330, and 1413 were used for the design, fabrication, erection, and testing of theDAEC Primary Containment. The Primary Containment Inspection Program applies to thecontainment vessel (ASME Code Section XI, Subsection IWE).ASME Code Section XI, Subsection IWE specifies that examinations will be performed on thepressure retaining boundary of the containment vessel, which includes the accessible surfaces of theliner plate, integral attachments and structures that are part of the reinforcing structure, surfaces ofpressure retaining welds, pressure retaining bolted connections, and the moisture barrier, whichprevents moisture intrusion at the concrete-to-metal interface at the basement floor. Also, thecontainment surfaces that may require augmented examination are included in this program.In accordance with the NRC final rule amending 10 CFR 50.55a that was effective September 9,1996, the IWE Program was developed with an initial interval start date of May 22, 1998. Asrequired by the rulemaking, the 1992 Edition, 1992 Addenda of ASME Code Section Xl was thebasis for the programs. The required Subsection IWE examinations were completed for the first 10year interval. The 2nd interval was scheduled to end with the end of the original operating license onFebruary 21, 2014. In December 201 0, DAEC received an extension of the operating license for 20years. The inspection interval has been modified to be parallel to the 4th Ten Year 1SI Programinterval. The three inspection periods during the second inspection interval are as follows:Page 10 of 30 First Period:Second Period:Third Period:May 22, 2008 -May 21, 2010May 22, 2010 -October 31, 2013November 1, 2013 -May 21, 2017The required Subsection IWE examinations are scheduled and tracked using a database. Thecurrent containment inspection interval is summarized in the table below:Current IWE Interval _____________System Examination Item Exam Period ScheduledIdentification Description Number MethodExamination Category E-A 1 2. 3Drywell/Torus/ Accessible Surface EI. 11 GV 1 1 1Torus Wetted Surfaces of E1. 12 GV 1Downcomers BWR Vent System EI.20 GV 3 3 2Drywell/Torus/ Moisture barrier EI.30 GV 1 1 1Downcbmers ___________________________________Examination Category E.-C 1 2 3Torus Visible Surfaces E4.11 VT-3 1 ITorus Surface Area Grid E4.12 UTTMinimum Wall____________ Thickness Location. ____ ___ __ __________ ____Item Number refers to item numbers listed in ASME Code Section Xl, Table IWE-2500-1, titled"Examination Categories."Exam Method GV -General Visual; UTT- Ultrasonic Thickness Test; and VT examination methoddefined in ASME Code Section Xl, Paragraph IWA-2213, "VT -3 Examination' Schedule.Containment Surfaces Subject To Augmented ExaminationsASME Code Section XI paragraph IWE-1 240 identifies containment surface areas requiringaugmented examination as those surface areas likely to experience accelerated degradation andaging. Such areas include: (a) interior and exterior containment surface areas that are subject toaccelerated corrosion with no or minimal corrosion allowance, or areas where the absence orrepeated loss of protective coatings has resulted in substantial corrosion and pitting and (b) interiorand exterior containment surface areas that are subject to excessive wear from abrasion or erosionthat causes a loss of protective coatings, deformation, or material loss.The submerged portion of the suppression pool at DAEC has been determined to be a surface areasubject to augmented examination. In 2009, the general visual inspection frequency was increasedto every outage. During the refueling outages in 2009 and 2010 only localized areas of corrosion(pitting) were observed and areas of significant depth were examined by UTT and determined to beacceptable. Significant areas of loss of protective coatings resulted in the recoating of thesubmerged areas during the 2012 refueling outage. The entire surface exposed after coatingPage 11 of 30 removal was visually examined. Detailed evaluations were performed of the substrate to determinethe acceptable thickness after coating removal. Nineteen localized areas were identified thatrequired weld repair to restore the shell to an acceptable thickness. The entire submerged surfacewas recoated. These nineteen areas were inspected in the 2014 refueling outage and theexamination was satisfactory and these nineteen areas no longer require successive inspections andhave been removed from the augmented inspection requirements.However, areas of coating degradation were identified in the 2014 refueling outage and theaugmented detailed visual requirements remain in place for the submerged surface area in thesuppression pool.3.2.2 Containment Visual JnspectionsInspection DescriptionA Suppression Chamber and Drywell Visual Examination procedure for DAEC is utilized to performgeneral visual observations of the accessible interior and exterior surfaces of the primarycontainment in order to identify evidence of deterioration that may affect the containment integrity orleak tightness in accordance with the following.* TS Surveillance Requirement 3.6.1.1.1 requires, in part, visual examinations in accordancewith the Containment Leak Rate Testing Program.*TS 5.5.12.b requires, in part, visual examinations in accordance with the guidelines containedin Regulatory Guide 1.163, "Performance-Based Containment Leak-Test Program," datedSeptember 1995. (Regulatory Position 3 requires that these examinations should beconducted prior to initiating a Type A test and during two other refueling outages before thenext Type A test if the interval for the Type A test has been extended to 10 years, in order toallow for early uncovering of evidence of structural deterioration.)*ASME Code Section Xl, Subsection IWE reqluires visual examinations. General visualobservations of the accessible interior and exterior surfaces of the primary containment areperformed on a frequency that meets ASME Code Section Xl, Subsection IWE, and 10 CFR50 Appendix J, Option B. A Suppression chamber Visual Examination of Submerged Areasprocedure is used specifically to meet the ASME Code Section Xl Subsection IWEsubmerged area examination requirements.With the implementation of the proposed change, TS 5.5.12 will be revised by replacing thereference to Regulatory Guide 1.163 with reference to NEI 94-01, Revision 3-A. A general visualexamination of accessible interior and exterior surfaces of the containment for structural deteriorationthat may affect the containment leak-tight integrity is required by NE! 94-01, Revision 3-A, prior toeach Type A test and during at least three other outages before the next Type A test if the intervalfor the Type A test has been extended to 15 years.Recent Examination ResultsThe following is a summary of results of examinations that were recently performed.An examination was successfully completed during the fall 2014 refueling outage (RFO24) for boththe exterior surfaces and interior steel surfaces of the DAEC primary containment exposed to theatmosphere. The conditions identified were minor in nature and would not affect the integrity of thePage 12 of 30 primary containment, Identified conditions were documented in the inspection report and do notrequire action. The typical condition noted was localized light rusting, some minor paint .chipping andflaking.An examination was completed of the submerged surfaces areas of the suppression pool during thefall 2014 refueling outage (RFO24). This inspection identified delamination of the coating on thetorus shell, structural steel and downcomers. There was no evidence of~degradation of the torusshell itself or other steel components. The delaminated coating was removed. Additional detail onthe remaining condition is provided in Section 3.2.8.ConclusionDAEC primary containment visual inspections were successfully completed during RFO24.Delaminated coating was discovered in the submerged portion of the suppression pool and removedto sound coating. Other identified deficiencies were accepted by an engineering evaluation orrepaired in accordance with ASME Code Section Xl, Subsection IWE. The DAEC primarycontainment continues toremain capable of performing its safety-related functions.3.2.3 Containment Liner Test Channel Plugs.*The U.S. Nuclear Regulatory Commission (NRC).issued information notice (IN) 2014-07 to informaddressees of issues identified by the NRC staff concerning degradation of floor weld leak-chasechannel systems of steel containment shell and concrete containment metallic liner that could affectleak-tightness and aging management of containment structures.The DAEC primary containment is a Mark I free standing steel containment vessel. The drawings of*the DAEC containment were reviewed and no leak chase system was incorporated into the design ofthe DAEC containment.3.2.4 containment CorrosionThe NRC over the years has issued several information notices concerning containment corrosion.These notices have been reviewed as they were received by DAEC to determine the impact on theDAEC containment. Several instances have been cited where organic material that is left lodgedbetween the containment and the surrounding has resulted in through-wall or significant corrosion.Other instances cited focus on the moisture barrier. These events have been evaluated andinspections have been conducted to determine the presence of these conditions at DAEC. Althoughcontainment visual inspections are required to be performed three times in a ten year period, DAEChas performed these visual inspections every refueling outage (five times in a ten year period).DAEC maintains the primary containment with an inerted internal atmosphere during plant operation.This has assisted DAEC in reducing the p~otential for corrosion..DAEC has observed corrosion in the submerged area of the suppression pool. This has. beenmonitored by the site staff for several years. The NRC issued IN 2011-15 and describes thecorrosion condition as observed several years ago. Section 3.2.5 provides additional detail on thistopic.3.2.5 .Suppression Chamber CorrosionIN 2011-15 provides the following information on the corrosion of the submerged areas in the DAECprimary containment:Page 13 of 30 "During its review of the Duane Arnold Energy Center license renewal application (LRA), theNRC staff noted that since 1977, when the applicant performed the first inspection of the torus afterthe initial coating application, the applicant has found numerous instances of localized corrosion anddepletion of the coating of the torus shell (see Enclosure Figures 1 and 2) of its boiling-water reactor(BWR) Mark I containment. The applicant performed repairs in 1980 and 1983 prior to a full recoatof the suppression chamber in 1985. Since 1988, the applicant has been repairing degradedcoatings and managing and tracking the effects of aging of the torus in accordance with theAmerican Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code Section XI,*'Rules for Inservice Inspection of Nuclear Power Plant Components,' Subsection IWE,'Requirements for Class MC and Metallic Liners of Class CC Components of Light-Water CooledPower Plants.' Since 1995, the torus coating has been repaired at more than 15,000 locations, allbelow the water line, which is equivalent to approximately 5 percent of the underwater coatingsurface inside the torus. The torus steel behind the degraded coating has corroded locally at someof these locations. The applicant evaluated this degradation of coating of the torus and determinedthat the degradation has not affected the structural integrity of the torus. In addition, the applicant*performed detailed analysis and determined that localized corrosion of the torus shell wasacceptable without repair. The NRC staff requested that the applicant address the possibility oflocalized galvanic corrosion (pitting) due to degraded coatings during the period of extendedoperation since the normal life of the underwater zinc coating is approximately 15 to 20 years andaging management of the torus steel minimizes the potential for pitting corrosion to extend through-wall. In response to NRC requests for additional information during the license renewal review, theapplicant committed to recoating the suppression pool interior surfaces below the water line prior tostartup from the first refueling outage during the period of extended operation (applicant letter, datedMarch 9, 20,10, Agencywide Documents Access and Management System (ADAMS) Accession No.ML1 00700248). The applicant subsequently stated that the current project plan ensures thatrecoating will extend well above any fluctuations in water level, including the 2-foot wide splash bandat the water level (applicant letter, dated April 2, 2010, ADAMS Accession No. ML1 00960277)."The submerged areas in the DAEC primary containment were recoated in the fall of 2012. Thesacrificial inorganic zinc coating was replaced with a 100% solids epoxy designed for the remainingplant life. This coating underwent qualification testing in accordance with approved industrystandards to demonstrate its acceptability for the specified service as a safety related coating. Thecoating was intended to be installed in a single coat application but failures in the control of theapplication process resulted in the need to apply a 2nd coat in some areas to achieve the specifiedcoating thickness. The initial coat and 2nd coat did not fully bond resulting in the delaminationobserved in the fall of 2014. This is discussed in greater detail in Section 3.2.8.As part of the recoating process the existing inorganic zinc coating was removed and the substrateblasted to a near white condition. The entire surface exposed after coating removal was visuallyexamined. Detailed evaluations were performed to determine the acceptable metal thickness aftercoating removal. Ultrasonic thickness readings were taken on all shell plates to determine the basethickness. Additionally, localized ultrasonic thickness readings were taken when significant pittingwas observed. Nineteen localized areas were identified that required weld repair to restore the shellto an acceptable thickness. The entire submerged surface was recoated.The nineteen areas that required repair in 2012 were inspected in the 2014 refueling outage and theexamination was satisfactory andthese nineteen areas no longer require specific inspections.Page 14 of 30 In summary, the corrosion condition described in IN 2011-15 has been corrected. The sacrificialcoating has been replaced. The substrate has been examined and has an acceptable thickness inall locations.3.2.6 Suppression Chamber CrackingThe U.S. Nuclear Regulatory Commission (NRC) issued IN 2006-01 to inform the owners of BWRMark I containments about the occurrence and potential causes of, the through-wall cracking of atorus in a BWR Mark I containment.The FitzPatrick licensee performed a root cause investigation of the event, and after eliminating anumber of possible causes (thermal fatigue, clearing load phenomena, metallurgical discontinuity,weld defects, corrosion, flow-induced phenomena, flow-accelerated cor'rosion, cavitation, and directjet impingement), the licensee concluded that the most likely/cause for the initiation and propagationof the crack was the hydrodynamic loads of the turbine exhaust pipe during HPCI operation coupledwith the highly restrained condition of the torus shell at the torus column support.The DAEC design has been reviewed and the turbine exhaust pipe configuration and hydrodynamicloading are sufficiently different at DAEC to eliminate the potential for this type of event.3.2.7 Inaccessible AreasFor a Class MC application, DAEC must evaluate the acceptability of inaccessible areas whenconditions exist in accessible areas that could indicate the presence of or result in degradation tosuch inaccessible areas. For each inaccessible area identified, DAEC will provide the following in theISI Summary Report, as required by 10 CFR 50.55a(b)(2)(ix)(A):* A description of the type and estimated extent of degradation, and the conditions that led tothe degradation;* An evaluation of each area, and the result of the evaluation, and;, A description of necessary corrective actions.DAEC has not needed to implement any new technologies to perform inspections of anyinaccessible areas at this time. However, IIAEC "actively participates in various nuclear utility ownersgroups and ASME Code committees to maintain cognizance of ongoing developments within the.nuclear industry. Industry operating experience is also continuously reviewed to determine itsapplicability to DAEC. Adjustmentsto inspection plans and availability of new, commerciallyavailable technologies for the examination of the inaccessible areas of the containment would beexplored and consider'ed as part of these activities.3.2.8 Containment Coatingqs InspectionsThe site Protective Coatings Program defines the requirements and responsibilities for a program toimplement inspectionis during refueling outages for the purpose of assessing the condition of theprotective coatings on structures and equipment in the primary containment. These inspectionsassure compliance with the DAEC commitments in response to NRC Generic Letter 98-04. DAECis not committed to following the requirements of Regulatory Guide 1.54, "Quality AssuranceRequirements for Protective Coatings Applied to Water-Cooled Nuclear Power Plants," but hasdeveloped a comparable program for monitoring and maintaining protective coatings inside primarycontainment. The DAEC program uses specific ASTM Standards that are acceptable to the NRC asstated in RG 1.54 Revision 1.Page 15 of 30 Containment coatings inspections are a scheduled activity conducted during refueling outages. Theexamination areas are selected such that painted surfaces are inspected every outage. This is doneto comply with the recommendations of ASTM D51 63-96, "Establishing Procedures to Monitor thePerformance of Service Level 1 Coating Systems in an Operating Nuclear Power Plant."Identified, degraded, or questionable coatings shall be remediated prior to the unit entering Mode 3at the end of an outage. The remediation may include recoating the affected area with a qualifiedcoating system, or removal of the degraded or questionable coatings to a sound and tightly adheredcondition.' Any coatings that are left as-is are evaluated, approved, and logged. DAEC maintains anunqualified coating log to track unqualified coatings materials, and degraded qualified coatings. Thisunqualified coating log is maintained to ensure the quantity of unqualified coating is less than theacceptable quantity of unqualified coating that could potentially reach the EGOS suction strainers ina design basis accident scenario.Results of Recent Coatings Inspections -Fall 2014 Refueling OutageThe condition of the protective coatings in the primary containment air space inspected during fall2014 refueling outage was typical and expected for the vintage of the coatings. In general thecoatings were found to be performing well. Conditions identified were minor in nature and limited intheir extent. The coatings were found to be performing acceptably and no negative trends wereidentified besides minor spots of surface corrosion.A coating examination was completed of the submerged surfaces areas of the suppression poolduring the fall 2014 refueling outage (RFO24). This inspection identified delamination of the coatingon the torus shell, structural steel and downcomers. The delamination was the result of inadequatebonding between coats during the torus recoat in the fall of 2012.The submerged coating originally installed was a sacrificial inorganic zinc coating. The submergedcoating was reapplied in 1985 and the coating required replacement again in 2012. Thereplacement coating for the 2012 recoat was a single coat 100% solids epoxy. The application wasintended as a single coat application but failures in the control of the application process resulted inthe need to apply a 2nd coat in some areas to achieve the specified coating thickness. The initialcoat and 2nd coat did not fully bond resulting in the delamination observed in the fall of 2014.The delaminated coating was removed and adhesion testing was performed to determine that theremaining coating was adequately adhered. The coating thickness that was specified was reviewedand a minimum acceptable coating thickness was determined. Coating thicknesses of greater than18 mils will supply required corrosion protection. The areas where the coating thickness was belowthe minimum acceptable were determined to be unqualified coating and added to the unqualifiedcoating log.Additionally, areas were identified on the ring girders, supports, and downcomers that were withoutcoating. 'Areas of the shell~were identified that required coating application. The shell areas wererecoated in the fall of 2014 and the remaining areas Will be recoated during the next refueling outagein the fall of 2016.The operability of the primary containment and the ECCS were assessed prior to startup from the fallof 2014 refueling outage. The evaluation of EGOS suction strainer loading was reassessed andsufficient margin was present to determine the as-found degraded condition as operable and the as-left condition was also determined to be operable.Page 16 of 30 3.2.9 License Renewal CommitmentsLicense renewal activities led to one commitment related to the DAEC containment. The followingprovides a status of the action that was identified and committed to by DAEC in the DAEC LicenseRenewal Application.DAEC Updated Final Safety Analysis Report (UFSAR) Commitment 50:Perform recoating of suppression pool interior surfaces below the water line. Complete recoatingprior to startup from the first refuel outage during the period of extended operation.Status:The suppression pool interior surfaces below the water line were recoated in refueling outage 23(RF023) in October 2012. This was the last outage prior to entering the period of extendedoperation and meets the scheduling requirement.3.3 NRC INFORMATION NOTICE 92-20, 'INADEQUATE LOCAL LEAK RATE TESTING"NRC IN 92-20 was issued to alert licensees to problems involving local leak rate testing ofcontainment penetrations under 10 CFR 50, Appendix J. Problems were identified with the testing oftwo-ply stainless steel bellows used on piping penetrations at some plants. Specifically, local leakrate testing could not be relied upon to accurately measure the leakage rate that would occur underaccident conditions since, during testing, the two plies in the bellows were in contact with each other,restricting the flow of the test medium to the crack locations. Any two-ply bellows of similarconstruction may be susceptible to this problem.The bellows at DAEC are designed to ASME Section III -1971 edition, and have two independentcorrugated stainless steel elements -i.e., no section of straight pipe between them. The corrugatedelements are constructed with two plies. Sandwiched between the two plies is a wire mesh, whichassures that an annulus will be maintained throughout the entire bellows surface.The flexible metallic bellows are tested during the ILRT. The ILRT pressurizes the area between thebellows and the guard pipe. If the inner ply of the corrulgated elements is leak tight, the outer plydoes not see the test pressure. The corrugated elements are tested by a LLRT. The LLRTpressurizes the area between the plies. At IDAEC, the test is configured so that both corrugatedelements are tested at the same time. Isolation valves have been provided so that each element canbe tested independently. The test pressurizes both elements through a common supply and acommon pressure gauge is installed at the other end of each element.In 1992, in response to NRC IN 92-20, a test was performed for several penetrations to determinethat restrictions were not present in the element to preclude a valid LLRT. This test measured thetime to achieve pressure equalization in each element.This test is similar to the test required by Specification BECH-MRS-M126 paragraph 6.2.1 .b. Perthat test stabilization time shall not exceed 3 minutes. The acceptance requirement for the test wasno observable pressure drop in one minute. The stabilization time requirement ensures that there isno restriction in the plies and the pressure drop requirement ensures the test boundary is leak tight.This is accomplished by a simple pressure decay test.Page 17 of 30 The testing of two ply bellows was discussed with the bellows manufacturer. The time to achievepressure equalization depends on the profile of the bellows. On a typical bellows of our size thepressurization .only takes seconds. Manufacturer quality control personnel typically use a value of 10minutes as a time of concern unless a time is specified by the customer. Based on this discussion,the previous methodology used by DAEC to verify an adequate gap was sufficient.In 2005, DAEC repeated the testing on all penetrations with an established acceptance criteria of notto exceed 3 minutes to achieve an outlet pressure within 0.2 p~sig of the inlet pressure. All of theexpansion bellows penetrations were tested in 2005 with satisfactory .results since all of thestabilization times were less than or equal to 41 seconds.The special testing performed in 1992 and in 2005 was similar to the manufacturing acceptance testperformed per the specification. This test is appropriate to demonstrate that the penetration bellowshas sufficient space between the plies to perform its design function.3.4 NRC LIMITATIONS AND CONDITIONS3.4.1 June 25, 2008 NRC Safety EvaluationThe limitations and conditions from the June 25, 2008 safety evaluation to NEI 94-01 Revision 2 arepresented in the table below with the NextEra Energy Duane Arnold response for DAEC.June 25, 2008 NRC Safety Evaluation (SE) Limitations and ConditionsLimitation/Condition (From Section 4.0 of Response for DAECSafety Evaluation)1. For calculating the Type A leakage rate, the DAEC will utilize the definition in NEI 94-01,licensee should use the definition in NEI TR Revision 3-A, Section 5.0. This definition has94-01, Revision 2, in lieu of that in ANSI/ANS- remained unchanged from Revision 2-A to56.8-2002. (Refer to SE Section 3.1.1.1). Revision 3-A of NEI 94-01.2. The licensee submits a schedule of Reference Section 3.2.1 and 3.2.2.,containment inspections to be performed prior General visual observations of the accessibleto and between Type A tests. (Refer to SE interior and external surfaces of theSection 3.1.1.3) containment structure shall continue to beperformed in accordance with containmentstructural integrity test procedures to meet therequirements of th~e proposed .revision to TS5.5.12, the inspection requirements of ASMECode Section XI, subsection IWE and NEI 94-_____________________________01, Revision 3.A, Sections 9.2.1 and 9.2.3.2.3. The licensee addresses the areas of Reference Section 3.2.1 through 3.2.9.containment structure potentially subjected to General visual observations of the accessibledegradation. (Refer to SE Section 3.1.3). interior and external surfaces of thecontainment structure shall continue to beperformed, in accordance with containmentstructural integrity test procedures to meet therequirements of the proposed revision to TS5.5.12, the inspection requirements of ASMECode Section Xl, subsection IWE and NEI 94-01, Revision 3.A, Sections 9.2.1 and 9.2.3.2.Page 18 of 30 Limitation/Condition (From Section 4.0 of Response for DAECSafety Evaluation)4. The licensee addresses any tests and Engineering Change (EC) 281 991 is to install ainspections performed following major new Hardened Containment Vent Systemmodifications to the containment structure, as (HCVS). The design will remove the existing 8"applicable. (Refer to SE Section 3.1.4). containment isolation control valve CV-4357.The new cap installed on the remaining 8"-HBC-140 piping within the SE corner room willbe the containment boundary. Themodification adds two new 10" PCI Vs and.actuators and a new rupture disk. The two newPCIlVs provide a containment isolatiop function.The rupture disk prevents the use Of thissystem prior to the containment pressureexceeding 50 psig, unless the rupture disk ismanually ruptured. The new pipe and valvesare the containiment penetration boundaries.The system is manually operated from thecontrol room or remote location. Associatedtests and inspections will confirm the leaktightness of the abandon penetration, the newPCI Vs, and the piping from the containment tothe new PCIVs. Testing procedures have yetto be developed.5. The normal Type A test interval should be DAEC will follow the requirements of NEI 94-less than 15 years. If a licensee has to utilize 01, Revision 3-A, Section 9.1. Thisthe provisions of section 9.1 or NEl TR 94-01, requirement has remained unchanged fromRevision 2, related to extending the ILRT Revision 2-A to Revision 3-A of NEl 94-01.interval beyond 15 years, the licensee must In accordance with section 3.1.1.2 of the NRCdemonstrate to the NRC staff that it is an safety evaluation dated June 25, 2008 (ADAMSunforeseen emergent condition. (Refer to SE Acc~ession No. ML 081140105), NextEraSection 3.1.1.2). Energy Duane Arnold willalso demonstrate tothe NRC staff that an unforeseen emergentcondition exists in the event an extensionbeyond the 15 year interval is required.Justification for such an extension request willbe in accordance with the staff position inRegulatory Issue Summary..(RIS) 2008-27.6. For plants licensed under 10 CFR Part 52, Not applicable. IJAEC was not licensed underapplications requesting a permnanent extension 10 CFR Part 52.of the ILRT surveillance interval to 15 yearsshould be deferred until after the constructionand testing of containments for that design hasbeen completed and applicants haveconfirmed the applicability of NEI TR 94-01,Revision 2, and [Electric Power ResearchInstitute] EPRI Topical .Report No. TR-1009325, Revision 2, ["Risk-ImpactAssessment of Extended Integrated Leak RateTesting Intervals,"] including the use of.pastcontainment ILRT data.Page 19 of30 3.4.2 June 8, 2012 NRC Safety EvaluationThe two conditions from Section 4.0 of the June 8, 2012 safety evaluation to NEI 94-01 Revision 3are stated below with the NextEra Energy Duane Arnold response for DAEC.Condition 1NEI TR 94-01, Revision 3, is requesting that the allowable extended interval for Type C LLRTs beincreased to 75 months, with a perrmissible extension (for non-routine emergent conditions) of ninemonths (84 months total). The staff is allowing the extended interval for Type C LLRTs to beincreased to 75 months with the requirement that a licensee's post-outage report include the marginbetween Type B and Type C leakage rate summation and its regulatory limit. In addition, a correctiveaction plan shall be developed to restore the margin to an acceptable level. The staff is also allowingthe non-routine emergent extension out to 84 months as applied to Type C valves at a site, withsome exceptions that must be detailed in NE! 94-01, Revision 3. At no time shall an extension beallowed for Type C valves that are restricted categorically (e.g., BWR MSIVs), and those valves witha history of leakage, or any valves held to either a less than maximum interval or to the baserefueling cycle interval. Only non-routine emergent conditions allow an extension to 84 months. Thisis Topical Report Condition 1.Response to Condition 1Condition 1 presents three (3) separate issues that are addressed as follows:ISSUE 1 -The allowance of an extended interval for Type C LLRTs of 75 months carries therequirement that a licensee's post-outage report include the margin between the Type B and Type Cleakage rate summation and its regulatory limit.Response to Condition 1, Issue 1The post-outage report shall include the margin between the Type B and Type C minimum pathwayleak rate summation value, as adjusted to include the estimate of applicable Type C leakageunderstatement, and its regulatory limit of 0.60 La.ISSUE 2 -A corrective action plan shall be developed to restore the margin to an acceptable level.Response to Condition 1, Issue 2.When the potential leakage understatement adjusted Type B and Type C minimum pathway leakrate total is greater than the DAEC administrative leakage summation limit of 0.50 L2, but less thanthe regulatory limit of 0.60 La, then an analysis and determination of a corrective action plan shall beprepared to restore the leakage sumrhiation margin to less than the DAEC administrative leakagelimit. The corrective action plan shall focus on those components which have contributed the most tothe increase in the leakage summation value and the manner of timely corrective action (as deemedappropriate) that best focuses on the prevention of future component leakage performance issues.ISSUE 3 -Use of the allowed 9 month extension for eligible Type C valves is only authorized fornon-routine emergent conditions:Page 20 of 30 Response to Condition I, Issue 3DAEC will apply the 9 month grace period only to eligible Type C components and only for non-routine emergent conditions. Such occurrences will be documented in the record of tests.Condition 2The basis for acceptability of extending the ILRT interval out to once per 15 years was the enhancedand robust primary containment inspection program and the local leakage rate testing ofpenetrations. Most of the primary containment leakage experienced has been attributed topenetration leakage and penetrations are thought to be the most likely location of most containmentleakage at any time. The containment leakage condition monitoring regime involves a portion of thepenetrations being tested each refueling outage, nearly all LLRTs being performed during plantoutages. For the purposes of assessing and monitoring or trending overall containment leakagepotential, the as-found minimum pathway leak rates for the just tested penetrations are summed withthe as-left minimum pathway leak rates for penetrations tested during the previous 1 or 2 or even 3refueling outages. Type C tests involve valves which, in the aggregate, will show increasing leakagepotential due to normal wear and tear, some predictable and some not so predictable. Routine andappropriate maintenance may extend this increasing leakage potential. Allowing for longer intervalsbetween LLRTs mi-eans that more leakage rate test results from farther back in time are summedwith fewer just tested penetrations and that total used to assess the current containment leakagepotential. This leads to the possibility That the LLRT totals calculated understate the actual leakagepotential of the penetrations. Given the required margin included with the performance criterion andthe considerable extra margin most plants consistently show with their testing, any understatementof the LLRT total using a 5-year test frequency is thought to be. conservatively accounted for;Extending the LLRT intervals beyond 5 years to a 75-month interval should be similarly conservativeprovided an estimate is made of the potential understatement and its acceptability determined aspart of the trending specified in NEI 94-01, Revision 3, Section 12.1. When routinely scheduling anyLLRT valve interval beyond 60-months and up to 75-months, the primary containment leakage ratetesting program trending or monitoring must include an estimate of the amount of understatement inthe Type B & C total, and must be included in a licensee's post-outage report. The report mustinclude the reasoning and determination of the acceptability of the extension, demonstrating that theLLRT totals calculated represent the actual leakage potential of the penetrations. This is TopicalReport Condition 2.Response to Condition 2Condition 2 presents two separate issues that are addressed as follows:ISSUE 1 -Extending the LLRT intervals beyond 5 years to a 75-month interval should be similarlyconservative provided an estimate is made of the potential understatement and its acceptabilitydetermined as part of the trending specified in NEI 94-01, Revision 3, Section 12.1.Response to Condition 2, Issue IThe change in going from a 60 month extended test interval for Type C tested components to a 75month interval, as authorized under NEI 94-01, Revision 3-A, represents an increase of 25 percent inthe local leak rate test periodicity. As such, NextEra Energy Duane Arnold will conservatively apply apotential leakage understatement adjustment factor of 1.25 to the as-left leakage total for each TypeC component currently on the 75 month extended test interval. This will result in a combinedconservative Type C total for all 75 month local leak rate tests being carried forward and includedPage 21 of 30 whenever the total leakage summation is required to be updated (either while operating on-line orfollowing an outage). When the potential leakage understatement adjusted leak rate total for thoseType C components being tested on a 75 month extended interval is summed with the non-adjustedtotal of those Type C components being tested at less than the 75 month interval and the total of theType B tested components, if the minimum pathway leak rate is greater than the DAECadministrative leakage summation limit of 0.50 La, but less than the regulatory limit of 0.60 La, thenan analysis and corrective action plan shall be prepared to restore the leakage summation value toless than the administrative leakage limit. The corrective action plan shall focus on thosecomponents that have contributed the most to .the increase in the leakage summation value and themanner of timely corrective action (as deemed appropriate) that best focuses on the prevention offuture component leakage performance issues.ISSUE 2 -When routinely scheduling any LLRT valve interval beyond 60-months and up to 75-months, the primary containment leakage rate testing program trending or monitoring must includean estimate of the amount of understatement in the Type B & C total, and must be included in alicensee's post-outage report. The report must include the reasoning and determination of theacceptability of the extension, demonstrating that the LLRT totals calculated represent the actualleakage potential of the penetrations.Response to Condition .2, Issue 2If the potential leakage understatement adjusted minimum pathway leak rate is less than the ,administrative leakage summation limit of 0.50 La, then the acceptability of the 75-month local leakrate test extension for all affected Type C components has been adequately demonstrated and thecalculated local leak rate total represents the actual leakage potential of the penetrations.In addition to Condition 1, Issues I and 2, which deal with the minimum pathway leak rate Type Band Type C summation margin, NEI 94-01, Revision 3-A, also has the following margin relatedrequirement contained in Section 12.1, 'Report Requirements.'A post-outage report shall be prepared presenting results of the previous cycle's Type B and Type Ctests, and Type A, Type B and Type C tests, if performed during that outage. The technical contentsof the report are generally described in ANSI/ANS-56.8-2002 and shall be available on-site for NRCreview. The report shall show that the applicable performance criteria are met, and serve as a recordthat continuing performance is acceptable. The report shall also include the combined Type B andType C leakage summation, and the margin between the Type B and Type C leakage ratesummation and its regulatory limit. Adverse trends in the Type B and Type C leakage ratesummation shall be identified in the report and a corrective action plan developed to restore themargin to an acceptable level.In the event an adverse trend in the potential leakage understatement adjusted Type B and Type Csummation is identified, an analysis and a corrective action plan shall be prepared to restore themargin to an acceptable level thereby eliminating the adverse trend. The corrective action plan shallfocus on those components that have contributed the most to the adverse trend in the leakagesummation value and what manner of timely corrective action, as deemed appropriate, best focuseson the prevention of future component leakage performance issues.An adverse trend is defined as three consecutive increases in the final pre-reactor coolant systemMode change Type B and Type C minimum pathway leak rate summation value adjusted to includethe estimate of applicable Type C leakage understatement, as expressed in terms of La.Page 22 of 30 3.5 PLANT-SPECIFIC CONFIRMATORY ANALYSIS3.5.1 MethodologqyAn evaluation has been performed to assess the risk impact of extending the DAEC Type A testinterval from the current 10 years to 15 years. A simplified bounding analysis consistent with theElectric Power Research Institute (EPRI) approach was used for evaluating the change in riskassociated with increasing the test interval to fifteen years. The approach is consistent with thatpresented in:o Appendix H of Electric Power Research Institute, "Risk Impact Assessment of ExtendedIntegrated Leak Rate Testing Intervals: Revision 2-A of 1009325," EPRI Topical Report TR-1018243, dated October 2008,o Electric Power Research Institute, "Risk Impact Assessment of Revised Containment LeakRate Testing Intervals," EPRI Topical Report TR-1 04285, dated August 1994,o Nuclear Regulatory Commission, "Performance-Based Containment Leak-Test Program,"NUREG-1493, dated September 1995, and theo Calvert Cliffs liner corrosion analysis described in a letter to the NRC dated March 27, 2002(ADAMS Accession No. ML020920100).The analysis uses results from a Level 2 analysis of core damage scenarios from the current DAECprobabilistic risk assessment models and subsequent containment responses resulting in variousfission product release categories (including intact containment or negligible release) to determinelarge early release frequency (LERF).In the safety evaluation issued by NRC letter dated June 25, 2008 (ADAMS Accession No.ML081 140105), the NRC concluded that the methodology in EPRI TR-1 009325, Revision 2, isacceptable for referencing by licensees proposing to amend their.Technical Specifications topermanently extend the Type A surveillance test interval to 15 years, subject to the conditions notedin Section 4.2 of the safety evaluation. The following table addresses each of the four conditions forthe use of EPRI TR-1 009325, Revision 2.EPRl TR-1009325, Revision 2, Limitations and ConditionsConditions (From Section 4.2 of Safety Response for DAECEvaluation)1. The licensee submits documentation DAEC PRA technical adequacy is addressedindication that the technical adequacy of their in Section 3.5.2.(probabilistic risk assessment) PRA isconsistent with the requirements of[Regulatory Guide] RG 1.200 relevant to the[integrated leakage rate test] ILRT extensionapplication.2. The licensee submits documentation EPRI TR-1 009325, Revision 2-A, incorporatesindicating that the estimated risk increase these population dose and conditionalassociated with permanently extending the containment failure probability acceptanceILRT surveillance interval to 15 years is small, guidelines, and these guidelines have beenand consistent with the clarification provided in used for the DAEC plant specificSection 3.2.4.5 of this [safety evaluation] SE. assessments.Page 23 of 30 Specifically, a small increase in populationdose should be defined as an increase inpopulation dose of less than or equal to either1.0 person-remn per year or 1 percent of thetotal population dose, whichever is lessrestrictive.In addition, a small increase in [conditionalcontainment failure probability] CCFP shouldbe defined as a value marginally greater thanthat accepted in a previous one-time 15 yearILRT extension requests. This would requirethat the increase in CCFP be less than orequal to 1.5 percentage points.The increase in population dose is discussedin Section 3.5.3.The 'increase in the conditional containmentfailure probability is discussed in Section 3.5.3.3. The methodology in EPRI Report No.1009325, Revision 2, is acceptable except forthe calculation in the increase in expectedpopulation dose (per year of reactoroperation). In order to make the methodologyacceptable, the average leak rate for the pre-existing containment large leak rate accidentcase (accident case 3b) used by the licenseesshall be 100 La instead of 35 La.EPRI TR-1 009325, Revision 2-A, incorporatesthe use of 100 La as the average leak rate forthe pre-existing containment large leakagerate accident case (accident class 3b), andthis value has been used in the DAEC plantspecific risk assessment.4. A [license amendment request] LAR is DAEC does not rely on containmentrequired in instances where containment over- overpressure.pressure is relied upon for [emergency corecooling system] ECCS performance.3.5.2 Probabilistic Risk Assessment (PRA) Technical Adeq~uacyDAEC has Level 2 models that include both internal and external events. Severe accidentsequences have been developed from internally and externally initiated events, including internalfloods and internal fires. The sequences have been developed to determine the frequency for theradiological release end states to the environment. Information developed for Revision 6 of the PRAto support the Level 2 release categories is also used in this analysis.The DAEC PRA models are highly detailed and include a wide variety of initiating events, modeledsystems, operator actions, and common cause events. The DAEC model of record and supportingdocumentation has been maintaine~d as a living program, with periodic updates to reflect the as-built,as-operated plant. The DAEC Individual Plant Examination (IPE) and Individual Plant Examinationof External Events (IPELE) PRA models underwent NRC reviews, and updates to these modelshave been the subject of several assessments to establish the technical adequacy of the PRA.Documentation of DAEC technical adequacy was previously submitted to the NRC in support of thelicense amendment request for adoption for NFPA-805 and Risk Informed TS Initiative Sb. Thispreviously submitted documentation of PRA technical adequacy is deemed to be applicable for thisType A test interval extension submittal.Page 24 of 30 3.5.3 Conclusion of Plant-Specific Risk Assessment ResultsThe findings of the DAEC risk assessment confirm the general findings of previous studies that theimpact associated with extending the Type A test interval from three in ten years to one in 15 yearsis small. The DAEC plant-specific results for extending the Type A test interval from the current 10years to 15 years is summarized below.Core damage frequency (CDF) is not significantly impacted by the proposed change. DAEC doesnot rely on containment overpressure to assure adequate net positive suction head is available foremergency core cooling system pumps taking suction from the containment sump following designbasis accidents.Regulatory Guide 1.174 provides guidance for determining the risk impact of plant-specific changesto the licensing basis. Regulatory Guide 1.174 defines very small changes in risk as resulting inincreases of CDF less than 1.0 x 10.6 per reactor year and increases in LERF less than 1.0 x 10.7 perreactor year.There was essentially no change in total (internal and external) CDF, which meets Regulatory Guide1.174 acceptance guidelines for very small changes in CDF, and confirms that the impact on CDFfrom the Type A test extension is negligible. Thus, the relevant acceptance criterion is LERF.The increase in LERF based on consideration of internal events only resulting from a change in theType A test interval from three in ten years to one in fifteen years with corrosion included isconservatively estimated as 2.57 x 10.8 per year, which falls within the very small change region ofthe acceptance guidelines in Regulatory Guide 1.174. Regulatory Guide 1.174 also states that whenthe calculated increase in LERE is in the range of 1 .0 x 10.6 to 1.0 x 10T~per reactor year,applications will be considered only if can be reasonably shown that the total LERF is less than 1.0 xper reactor year. When external events contribution is also considered, the total increase inLERF due to both internal and external events including corrosion goes to 8.14 x 10.8 per year, withassociated total LERF of 9.79 x 10-6 per year. As such., the estimated change in total LERF isdetermined to be small using the acceptance guidelines of Regulatory Guide 1.174 acceptancecriteria for total LERF of 1.0 x 105 Sensitivity analysis using.EPRI Expert Elicitation methodology,estimate the change in total LERF as 2.56 x 10-8 per year, which falls within the very small region.The calculated increase in total 50-mile population dose risk for changing the Type A test frequencyfrom three per 10 years to once per 15 years is measured as an increase to the total integrated doserisk for all accident sequences. The total 50-mile population dose risk increase (relative to the basecase with corrosion) is 1.55 x 10.2 person-rem per year using the EPRI guidance. EPRI TR-1009325, Revision 2-A, states that a very small population dose is defined as an increase of lessthan or equal to 1.0 person-remn per year, or less than or equal to 1 percent of the total populationdose, whichever is less restrictive. Thus, the calculated 50-mile population dose increase at DAECis small using the guidelines of EPRI TR-1 009325, Revision 2-A. Moreover, the risk impact whencompared to other severe accident risks is negligible.The increase in the conditional containment failure probability from the three per 10 years to once in15 years interval including corrosion effects is 0.61 percent for DAEC. EPRI TR-1 009325, Revision"2-A, states that increases in conditional containment failure probability of less than or equal to 1.5percentage points are very small. Therefore this increase is judged to be very small at DAEC.Page 25 of 30 Increasing the Type A test interval on a permanent basis to a once in fifteen years frequency is notconsidered to be significant since it represents only a small change in DAEC risk profiles.Details of the DAEC risk assessments are contained in Attachment 4 for DAEC.
 
==3.6 CONCLUSION==
NEI 94-01, Revision 3-A, describes an NRC accepted approach for implementing the performance-based requirements of Appendix J, Option 13. It incorporates the regulatory positions stated inRegulatory Guide 1.163 and includes provisions for extending Type A test intervals to 15 years andType C test intervals to 75 months. NEI 94-01, Revision 3-A, delineates a performance-basedapproach for determining Type A, Type B, and Type C leakage rate surveillance testfrequencies.Based on the previous Type A tests conducted at DAEC, extension of the containment Type A testinterval from 10 to 15 years represents minimal risk to increased leakage. The risk is minimized bycontinued Type B and Type C testing performed in accordance with Appendix J, Option B, and theoverlapping inspection activities performed as part of the following DAEC inspection programs:oPrimary Containment Inservice Inspection ProgramoContainment Coatings Inspection and Assessment ProgramThis experience is supplemented by risk analysis studies, including the DAEC risk analysis provi~dedin Attachment 4. The findings of the risk assessment confirm the general findings of previousstudies, on a plant-specific basis, that extending the Type A test interval from 10 to 15 years resultsin a very small change to the DAEC risk profile.4.0 REGULATORY SAFETY ANALYSIS4.1 NO SIGNIFICANT HAZARDS CONSIDERATION DETERMINATIONNextEra Energy Duane Arnold has evaluated the proposed changes to the TechnicalSpecifications (TS) using the criteria in 10 CFR 50.92 and has determined that the proposedchanges do not involve a significant hazards consideration.Description of Amendment Request: An amendment is proposed to the Duane Arnold EnergyCenter (DAEC) Technical Specification (TS) 5.5.12, "Primary Containment Leakage RateTesting Program." The proposed amendment to the TS would revise DAEC TS 5.5.12, byreplacing the reference to Nuclear Regulatory Commission (NRC) Regulatory Guide 1.163,"Performance-Based Containment Leak-Test Program," with a reference to Nuclear EnergyInstitute (NEI) topical report NEI 94-01, Revision 3-A, "Industry Guideline for ImplementingPerformance-Based Option of 10 CFR Part 50, Appendix J," and conditions and limitationsspecified in NEI 94-01, Revision 2-A, as the implementation document used by DAEC toimplement the performance-based containment leakage rate testing program.Basis for proposed no significant hazards determination: As required by 10 CFR 50.91 (a), theNextEra analysis of the issue of no significant hazards consideration is presented below:Page 26 of 30
: 1. Does the proposed change involve a significant increase in the probability or consequencesof an accident previously evaluated?Response: NoThe proposed amendment adopts the NRC-accepted guidelines of NEI 94-01, Revision 3-A,"Industry Guideline for lmplem~enting Performance-Based Option of 10 CFR Part.50, AppendixJ," for development of the DAEC performance-based containment testing program. NEI 94-01allows, based on risk and performance, an extension of Type A and Type C containment leaktest intervals. Implementation of these guidelines continues to provide adequate assurancethat during design basis accidents, the primary containment and its components will limitleakage rates to less than the values assumed in the plant safety analyses.The findings of the DAEC risk assessment confirm the general findings of previous studies thatthe risk impact with extending the containment leak rate is small. Per the guidance provided inRegulatory Guide 1.174, an extension of the leak test interval in accordance with NEI 94-01-,Revision 3-A results in an estimated change within, the very~small change region.Since the change is implementing a performance-based containment testing program, theproposed amendment does not involve either a physical change to the plant or a change in themanner in which the plant is operated or controlled. The requirement for containment leakagerate acceptance will not be changed by this amendment. Therefore, the containment willcontinue to perform its design function as a barrier to fission product releases.Therefore, the proposed changes do not involve a significant increase in the probability orconsequences of an accident previously evaluated.2. Does the proposed change create the possibility of a new or different kind of accident from*any accident previously evaluated?Response: NoThe proposed change to implement a performance-based containment testing program,associated with integrated leakage rate test frequency, does not change the design oroperation'of structures, systems, or components of the plant.The proposed changes would' continue to ensure containment integrity and would ensureoperation within the bounds of existing accident analyses. There'are no accident initiatorscreated or affected by these changes. Therefore, the proposed changes will not create thepossibility of a new or different kind of accident from any accident previously evaluated.Therefore, the proposed changes do not create the' possibility of a new or different kind ofaccident from any accident previously evaluated.3. Does the proposed change involve a significant reduction in a margin of safety?Response: NoMargin of safety is related to confidence in the, ability of the fission product barriers (fuelcladding, reactor coolant system, and primary containment) to perform their design functionsduring and following postulated accidents. The proposed change to implement a performance-Page 27 .of 30 based containment testing program, associated with integrated leakage rate test frequency,does not affect plant operations, design functions, or any an'alysis that verifies the capability ofa structure, system, or component of the plant to perform a design function. in addition, thischange does not affect safety limits, limiting safety system setpoints, or limiting conditions foroperation.The specific requirements and conditions of the TS Primary Containment Leakage RateTesting Program exist to ensure that the degree of containment strulctural integrity and leak-tightness that is considered in the plant safety analysis is maintained. The overall containmentleak rate limit specified by TS is maintained. This ensures that the margin of safety in the plantsafety analysis is maintained. The design, operation, testing methods and acceptance criteriafor Type A, B, and C containment leakage tests specified in applicable codes and standardswould continue to be met, with the acceptance of this proposed change, since these are notaffected by implementation of a performance-based containment testing program.Therefore, the proposed changes do not involve a significant reduction in a margin of safety.4.2 APPLICABLE REGULATORY REQUIREMENTS/CRITERIAThe proposed amendment has been evaluated to determine whether applicable regulationsand requirements continue to be met.10 CFR 50.54(o) requires primary reactor containments for water-cooled power reactors to besubject to the requirements of Appendix J to 10 CFR 50, 'Primary Reactor ContainmentLeakage Testing for Water-Cooled Nuclear Power Reactors.' Appendix J specifies containmentleakage testing requirements, including the types required to ensure the leakage through theprimary reactor containment and systems and components penetrating primary containmentshall not exceed allowable leakage rate values and periodic surveillance of reactor containmentpenetrations and isolation valves is performed so that proper maintenance and repairs aremade during the service life of the containment, and systems and components penetratingprimary containment. In addition, Appendix J di~scusses leakage rate test methodology,frequency of testing, and reporting requirements for each type of test.Regulatory Guide 1.163, "Performance Based Containment Leak Test Program," (September1995) provides a method acceptable to the NRC for implementing the performance-basedoption (Option B) of 10 CFR 50, Appendix J. The regulatory positions stated in RegulatoryGuide 1.163 (September 1995) as modified by NRC Safety Evaluations of June 25, 2008(ADAMS Accession No. ML0811401 05) and June 8, 2012 (ADAMS Accession No.ML121030286) are incorporated in NEI .94-01, Revision 3-A, "Industry Guideline forImplementing Performance-Based Option of 10 CFR Part 50, Appendix J."The proposed license amendment would revise DAEC TS 5.5.12, "Primary ContainmentLeakage Rate Testing Program," Item b, by changing the wording to indicate that the programshall be in accordance with NEI 94-01, Revision 3-A, "Industry Guideline for ImplementingPerformance-Based Option of 10 CFR Part 50, Appendix J," and conditions and limitationsspecified in NEl 94-01,'Revision 2-A, instead of Regulatory Guide 1.163, "Performance BasedContainment Leak Test Program," and the listed Type A test exception.The purpose of NEI 94-01 is to assist licensees in the implementation of Option B to 10 CERPart 50, Appendix J. The NRC staff has reviewed NEI 94-01, Revision 3, and found that thisPage 28 of 30 guidance, as modified to include two limitations and conditions, is acceptable for referencing bylicensees proposing to amend their TS in regards to containment leakage rate testing.NextEra has evaluated the proposed changes against the applicable regulatory requirementsand acceptance criteria. Based on the foregoing, the proposed amendment will continue toensure compliance with 10 CFR 50.54(o), and Option B of 10 CFR Part 50, Appendix J.
 
==4.3 CONCLUSION==
SIn conclusion, based on the considerations discussed above, (1) there is reasonable assurance thatthe health and safety of the public will not be endangered by operation in the proposed manner, (2)such activities will continue to be conducted in compliance with the Commission's regulations, and(3) the issuance of the amendment will not be inimical to the common defense and security ortto thehealth and safety of the public.
 
==5.0 ENVIRONMENTAL CONSIDERATION==
10 CFR 51,22(c)(9) provides criteria for and identification of licensing and regulatory actions eligiblefor categorical exclusion from performing an environmental assessment. A proposed amendment ofan operating license for a facility requires no environmental assessment, if the operation of thefacility in accordance with the proposed amendment does not: (1) involve a significant hazardsconsideration, (2) result in a significant change in the types or significant increase in the amounts ofany effluents that may. be released offsite, or (3) result in a significant increase in individual orcumulative occupational radiation exposure. NextEra has reviewed this license amendment requestand determined that the proposed amendment meets the eligibility criteria for categorical exclusionset forth in 10 CFR 51 .22(c)(9). Pursuant to 10 CFR 51.22(b), no environmental impact statement orenvironmental assessment needs to be prepared in connection with the issuance of the amendment.The basis for this determination is as follows.BasisThis change meets the eligibility criteria for categorical exclusion set forth in 10 CFR 51 .22(c)(9) forthe foilowing reasons:As demonstrated in the 10 CFR 50.92 evaluation, the proposed amendment does not involve asignificant hazards consideration.The proposed amendment does not result in a significantchange in the types or significant increasein the amounts of any effluents that may be released offsite. The proposed amendment does notchange or modify the design or operation of any plant systems, structures, or components. Theproposed amendment does not affect the amount or types of gaseous, liquid, or solid wastegenerated onsite. The proposed amendment does not directly or indirectly affect effluentdischarges.The proposed amendment does not result in a significant increase in individual or cumulativeoccupational radiation exposure. The proposed amendment does not change or modify the designor operation of any plant systems, structures, or components. The proposed amendment does notdirectly or indirectly affect the radiological source terms.Page 29 of 30 6.0 PRECEDENTThis. License Amendment Request is similar to a License Amendment Request approved by letterdated April 8, 2015 (ML15078AA058), "Beaver Valley Power Station, Unit Nos. 1 and 2 -Issuance ofAmendment Re: License Amendm~ent Request to Extend Containment Leakage Rate Frequency(TAG NOS. MF3985 and MF3986)."
 
==7.0 REFERENCES==
7.1 Nuclear Energy Institute (NEI) Topical Report, 94-01, Revision 3-A, "Industry Guideline forImplementing Performance-Based Option of 10 CFR Part 50, Appendix J," dated July 2012(ML1 222 1A202)7.2 Letter from S. Bahadur (NRC) to B. Bradley (NEI), "Final Safety Evaluation of Nuclear EnergyInstitute (NEI) Report, 94-01, Revision 3, 'Industry Guideline for Implementing Performance-based Option of 10 CER Part 50, Appendix J,' (TAG No. ME2164)," dated June 8, 2012(ML1 21030286)7.3 Nuclear Energy Institute (NEI) Topical Report, 94-01, Revision 2-A, "Industry Guideline forImplementing Performance-Based Option of 10 CFR Part 50, Appendix J," dated October 2008(MLI100620847)7.4 U.S. Nuclear Regulatory Commission, Regulatory Guide 1.174, Revision 2, "An Approach forUsing Probabilistic Risk Assessnient in Risk-Informed Decisions on Plant-Specific Changes tothe Licensing Basis," dated May 2011 (ML100910006)7.5 Electric Power Research Institute, TR-1009325, Revision 2, "Risk Impact Assessment ofExtended Integrated Leak Rate Testing Intervals," dated August 2007 (ML072970208)Page 30 of 30 ATTACHMENT 2 to NG-15-0234NEXTERA ENERGY DUANE ARNOLD, LLCDUANE ARNOLD ENERGY CENTERLICENSE AMENDMENT REQUEST (TSCR-143)EXTEND CONTAINMENT LEAKAGE TEST FREQUENCYPROPOSED TECHNICAL SPECIFICATIONS CHANGES(MARKUP COPY)1 page follows Programs and Manuals5.55.5 Programs and Manuals5.5.11 Safety Function Determination Program (SFDP) (continued)2. Provisions for ensuring the plant is maintained in .a safecondition if a loss of function condition exists;3. Provisions to ensure that an inoperable supported system'sCompletion Time is not inappropriately extended as a result ofmultiple support system inoperabilities; and4. Other appropriate limitations and remedial or compensatoryactions.b. A loss of safety function exists when, assuming no concurrent single* failure, no concurrent loss of offsite power or no concurrent loss ofonsite diesel generator(s), a safety function assumed in the accidentanalysis cannot be performed. For the purpose of this program, aloss of safety function may exist when a support system isinoperable, and:1. A required system redundant to system(s) supported by theinoperable support system is also inoperable; or2. A required system redundant to system(s) in turn supported bythe inoperable supported system is also inoperable; or3. A required system redundant to support system(s) for thesupported systems (I) and (2) above is also inoperable.c. The SFDP identifies where a loss of safety function exists. If a lossof safety function is determined to exist by this program, theappropriate Conditions and Required Actions of the LCO in whichthe loss of safety function exists are required to be entered. When aloss of safety function is caused by the inoperability of a singleTechnical Specification support system, the appropriate Conditionsand Required Actions to enter are those of the support system.5.5.12 Primary Containment Leakagqe Rate Testingq ProgqramNEI94-1 Rvison A program shall be established to implement the leakage rate testingNE..94-01 Rvso3A, of the primary containment as required by 10 CFR 50.54(o) and 10"Industry :Guideline for CFR 50, Appendix J, Option B, as modified by approved exemptions.ImplementingPerformance-Based b. This program shall be in accordance with the guidelines contained inOption of 10 C 50,.Re'ul-te' Guie1.6, "P'erformnce Based' Containment Leak TestAppendix J," and ,rogr.m" dat.&#xf7;d September 1995, as modificd by thec followingconditions and limitations Performance-Based Option"o 10 CFR 50, Appnd.. j,,:Specified inNE.I 94-01,ReVision 2-,A, as modified 1. The-f.....T.po. test after....... th September. 19 Type ...te..tby the following .h.l.e.e.ored.o ,.......... th....n. Septmbe 2008....IBxceptions:/-DELETED! (continued)DAEC5.0-17DAE 5.-17Amendment No. 2 ATTACHMENT 3 to NG-15-0234NEXTERA ENERGY DUANE ARNOLD, LLCDUANE ARNOLD ENERGY CENTERLICENSE AMENDMENT REQUEST (TSCR-1 43)EXTEND CONTAINMENT LEAKAGE TEST FREQUENCYREVISED TECHNICAL SPECIFICATIONS PAGES1 page follows Programs and Manuals5.55.5 Programs and Manuals5.5.11 Safety Function Determination Progqram (SFDP) (continued)2. Provisions for ensuring the plant is maintained in a safecondition if a loss of function condition exists;3. Provisions to ensure that an inoperable supported system's*Completion Time is not inappropriately extended as a result ofmultiple support system inoperabilities; and4. Other appropriate limitations and remedial or compensatoryactions.b. A loss of safety function exists when, assuming no concurrent singlefailure, no concurrent loss of offsite power or no concurrent loss oonsite diesel generator(s), a safety function assumed in the accidentanalysis cannot be performed. For the purpose of this program, aloss of safety function may exist when a support system isinoperable, and:.1. A required system redundant to system(s) supported by the.inoperable support system is also inoperable; or2. A required system redundant to system(s) in turn supported bythe inoperable supported system is also inoperable; or3. A required system redundant to support system(s) for thesupported systems (1) and (2) above is also inoperable.c. The SFDP identifies where a loss of safety function exists. If a lossof safety function is determined to exist by this program, theappropriate Conditions and Required Actions of the LCO in whichthie loss of safety function exists are required to be entered. When aloss of safety function is caused by the inoperability of a singleTechnical Specification support system, the appropriate Conditionsand Required Actions to enter are those of the support system.5.5.12 Primary Containment Leakagqe Rate Testingq Progqrama. A program shall be established to implement the leakage rate testingof the primary containment as required by 10 CFR 50.54(o) and 10CFR 50, Appendix J, Option B, as modified by approved exemptions.b. This program shall be in accordance with the guidelines contained inNEI 94-01, Revision 3-A, "Industry Guideline for ImplementingPerformance-Based Option of 10 CFR 50, Appendix J," and conditionsand limitations specified in NEI 94-01, Revision 2-A, as modified by thefollowing exceptions:1. DELETED(continued)DAEC5.0-17DAEC .0-17Amendment No.
ATTACHMENT 4 to NG-15-0234NEXTERA ENERGY DUANE ARNOLD, LLCDUANE ARNOLD ENERGY CENTERLICENSE AMENDMENT REQUEST (TSCR-143)*EXTEND CONTAINMENT LEAKAGE TEST FREQUENCYPLANT SPECIFIC RISK ANALYSIS57 pages follow Duane Arnold Energy CenterPRA EvaluationPermanent ILRT Extension Risk impact AssessmentRisk Applications and Methods 11Attachment 1 to LTR-RAM-15-18Page 1 of 57 ContentsSection Page--1 Purpose of Analysis ............. ..................................................................... 3:1.1 Purpose........................................................................................... 31.2 Background .......................... ............................................................ 31.3 Criteria............................................................................................ 42 References............................................................................................ 52.1 Acronyms......................................................................................... 73 Methodology.......................................................................................... 84 Groundrules .......................................................................................... 95 Inputs ................................................................................................ 115.1 General Resources Available.................................................................. 115.2 Plant Specific Inputs ........................................................................... 155.3 Impact of Extension on Detection of Component Failures That Lead to Leakage (Smalland Large) .............................................................................................. 255.4 Impact of Extension on Detection of Steel Liner Corrosion that Leads to Leakage.....266 Results ............................................................................................... 326.1 Step 1 -Quantify the Base-Line Risk in Terms of Frequency Per Reactor Year.......... 336.2 Step 2 -Develop Plant Specific Person-Rem Dose (Population Dose) Per Reactor Year376.3 Step 3 -Evaluate Risk Impact of Extending Type A Test Interval From 10 to 15 Years .426.4 Step 4 -Determine the Change in Risk in Terms of LERF................................... 476.5 Step 5 -Determine the Impact on the Conditional Containment Failure Probability(CCFP).................................................................................................... 476.6 Summary ofResults...................:......................................................... 487 Sensitivities.......................................................................................... 507.1 Sensitivity to Corrosion Impact Assumptions............................................... 507.2 Sensitivity to Class 3B Contribution to LERF ................................................ 517.3 Potential Impact from External Events ...................................................... 518 Conclusions.......................................................................................... 56*8.1 Previous Assessments ......................................................................... 56Page 2 of 57 I. Purpose of AnalysisI.1 PurposeThe purpose of this analysis is to provide a risk assessment of extending the currently allowedcontainment Type A Integrated Leak Rate Test (ILRT) interval to a permanent fifteen (15) years.The extension would allow for substantial cost savings as the ILRT could be deferred foradditional scheduled refueling outages for Duane Arnold Energy Center (DAEC). The riskassessment follows the guidelines from NEI 94-01 (Reference 1), the methodology used in EPRITR-104285 (Reference 2), the NEI "Interim Guidance for Performing Risk Impact Assessments InSupport of One-Time Extensions for Containment Integrated Leakage Rate Test SurveillanceIntervals" from November 2001 (Reference 3), the NRC regulatory guidance on the use ofProbabilistic Risk Assessment (PRA) as stated in Regulatory Guide 1.200 (Reference 30) asapplied to ILRT interval extensions, and risk insights in support of a request for a plant'slicensing basis as outlined in Regulatory Guide (RG) 1.174 (Reference 4), the methodology usedfor Calvert Cliffs to estimate the lilelihood and risk implications of corrosion induced leakage ofsteel liners going undetected during the extended test interval (Reference 5), and themethodology used in EPRI 1009325, Revision 2-A (Reference 20).1.2 BackgroundRevisions to IOCFR5O, Appendix J (Option B) allow individual plants to extend the IntegratedLeak Rate Test (ILRT) Type A surveillance testing frequency requirement from three in ten yearsto at least once in ten years. The revised Type A frequency is based on an acceptableperformance history defined as two consecutive periodic Type A tests at least 24 months apartin which the calculated performance leakage rate was less than the limiting containmentlea kage rate of 1La1.The basis for the current fifteen (15) year test interval is provided in Section 11.0 OfReference 1, and was established in 2008. Section 11.0 of NEI 94-01 states that NUREG-1493,"Performance-Based Containment Leak Test Program," September 1995 (Reference 6),provides the technical basis to support rulemaking to revise leakage rate testing requirementscontained in Option B to Appendix J. The basis consisted of qualitative and quantitativeassessments of the risk impact (in terms of increased public dose) associated with a range ofextended leakage rate test intervals. To supplement the NRC's rulemaking basis, NEI undertooka similar study. The results of that study are documented in Electric Power Research Institute(EPRI) Research Project Report TR-104285, "Risk Impact Assessment of Revised ContainmentLeak Rate Testing Intervals."' La (percent/24 hours) is the maximum allowable leakage rate at pressure Pa (calculated peak containmaent internalpressure related to the design basis accident) as specified in the technical specifications.Page 3 of 57 The NRC report on performance-based leak testing, NUREG-1493 (Reference 6), analyzed theeffects of containment leakage on the health and safety of the public and the benefits realizedfrom the containment leak rate testing. In that analysis, it was determined that for arepresentative PWR plant, containment isolation failures contribute less than 0.1% to the latentrisks from reactor accidents. Consequently, it is required to show that extending the ILRTinterval will not lead to a substantial increase in risk from containment isolation failures forDAEC.The Guidanceprovided in Appendix H of EPRI Report No. 1009325, "Risk Impact Assessmen tofExtended Integrated Leak Rate Testing Intervals," (Reference 20) for performing risk impactassessments in support of I LRT extensions builds on the EPRI Risk Assessment methodology,[PR] TR-104285. This methodology is followed to determine the appropriate risk informationfor use in evaluating the impact of the proposed ILRT changes.It should be noted that containment leak-tight integrity is also verified through periodic inservice inspections conducted in accordance with the requirements of the American Society ofMechanical Engineers (ASME) Boiler and Pressure Vessel Code Section Xl. More specifically,Subsection IWE provides the rules and requirements for inservice inspection of Class MCpressure-retaining components and their integral attachments, and of metallic shell andpenetration liners of Class CC pressure-retaining components and their integral attachments inlight-water cooled plants. Furthermore, NRC regulat~ions 10 CFR 50.55a(b)(2)(ix)(E) requirelicensees to conduct visual inspections of the accessible areas of the interior of thecontainment..The associated change to NEI 94-01 (Reference 1) will require that visual examinations beconducted, during at least three other outages, and in the outage during which the ILRT is beingconducted. These requirements will not be changed as a result of the extended ILRT interval. Inaddition, Appendix J, Type B local leak tests performed to verify the leak-tight integrity ofcontainment penetration bellows, airlocks, seals, and gaskets are also not affected by thechange to the Type A test frequency.1.3 CriteriaThe acceptance guidelines in RG 1.174 (Reference 4)-are used to assess the acceptability of thispermanent extension of the Type A test interval beyond that establishe~dduring the Option B.rulemaking of Appendix J. RG 1.174 defines very small changes in the risk-acceptance guidelinesas. increases in Core, Damage Frequency (CDF) less than 10-6 per reactor year and increases inLarge Early Release Frequency (LERE) less than 10-7 per reactor year. As the DAEC Level I PRAsdo not credit containment features, the Type A test does not impact CDF. Therefore, therelevant r~isk metric is the change in LERF. RG 1.174 also defines small changes in LERF as below10-6 per reactor year. RG 1.174 discusses defense in depth and encourages the use of riskanalysis techniques to help ensure and show that key principles, such as the defense in depth,philosophy, are met. Therefore, the increase in the Conditional Containment Failure Probability(CCFP) that helps to ensure that the defense-in-depth philosophy is maintained is alsoPage 4 of 57 calculated. The criteria described below are taken from the NRC Final Safety Evaluation for NEI94-01 and EPRI Report No. 1009325, Revision 2 (Reference 25).Regarding Conditional Containment Failure Probability (CCFP), the NRC concluded that a smallincrease in CCFP should be defined as a value marginally greater than that accepted in previousone time fifteen (15) year ILRT extension requests. To this end the NRC has endorsed a smallincrease in CCFP as an increase in CCFP less than or equal to 1.5% (Reference 25).ln addition, the total annual risk (person rem/yr population dose) is examined to demonstratethe relative change in this parameter. The NRC concluded that for purposes of assessing therisk impacts of the Type A ILRT extension in accordance with the EPRI methodology, a smallincrease in population dose should be defined as an increase in population dose of less than orequal to either 1.0 person-remn per year or 1% of the total population dose, whichever is lessrestrictive (Reference 25).2 References1. Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50,Appendix J, NEI 94-01, Revision 2-A, November 2008.2. Risk Impact Assessment of Revised Containment Leak Rate Testing Intervals, EPRI, PaloAlto, CA EPRI TR-104285, August 1994.3. Interim Guidance for Performing Risk Impact Assessments In Support of One-TimeExtensions for Containment Integrated Leakage Rate Test Surveillance Intervals, Rev. 4,Developed for NEI by EPRI and Data Systems and Solutions, November 2001.4. An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on PlantSpecific Changes to the Licensing Basis, Regulatory Guide 1.174, Revision 2, May 2011.5. Response to Request for Additional Information Concerning the License Amendment.Request for a One-Time Integrated Leakage Rate Test Extension, Letter from Mr. C. IH.Cruse (Calvert Cliffs Nuclear Power Plant) to NRC Document Control Desk, Docket No.50-317, March 27, 2002.6. Performance-Based Containment Leak-Test Program, NUREG-1493, September 1995.7. Evaluation of Severe Accident Risks: Peach Bottom Unit 2, Main Report NUREG/CR-4551, SAND86-1309, Volume 4, Revision 1, Part 1, December 1990.8. Letter from R. i. Barrett (Entergy) to U.S. Nuclear Regulatory Commission, IPN-01-O07,January 18, 2001.9. United States Nuclear Regulatory Commission, Indian Point Nuclear Generating Unit No.3 -Issuance of Amendment Re: Frequency of Performance-Based Leakage Rate Testing(TAC No. MB0178), April 17, 2001.10. Impact of Containment Building leakage on LWR Accident Risk, Oak Ridge NationalLaboratory, NUREG/CR-3539, ORNIL/TM-8964, April 1984.Page 5 of 57
: 11. Reliability Analysis of Containment Isolation Systems, Pacific Northwest Laboratory,NUREG/CR-4220, PNL-5432, June 1985.12. Technical Findings and Regulatory Analysis for Generic Safety Issue 11.E.4.3 'ContainmentIntegrity Check', NUREG-1273, April 1988.13. Review of Light Water Reactor Regulatory Requirements) Pacific Northwest Laboratory,NUREG/CR-4330, PNL-5809, Vol. 2, June 1986.14. Shutdown Risk Impact Assessment for Extended Containment Leakage Testing IntervalsUtilizing ORAMTM, EPRI, Palo Alto, CA TR-105189, Final Report, May 1995.15. Severe Accident Risks: An Assessment for Five U.S. Nuclear Power Plants, NUREG-1150,December 1990.16. United States Nuclear Regulatory Commission, Reactor Safety Study, WASH-1400,October 1975.17. Anthony R. Pietrangelo, One-time extensions of containment integrated leak rate testinterval -additional information, NEI letter to Administrative Points of Contact,November 30, 2001.18. Letter from J.A. Hutton (Exelon, Peach Bottom) to U.S. Nuclear Regulatory Commission,Docket No. 50-278, License No. DPR-56, LAR-01-00430, dated May 30, 2001.19. Letter from D.E. Young (Florida Power, Crystal River) to U.S. Nuclear RegulatoryCommission, 3F0401-11, dated April 25, 2001.20. Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals, Revision 2-Aof 1009325, EPRI, Palo Alto, CA: 2008 (issued under EPRI TR-1018243).21. Letter from P.P. Sena Ill (FENOC) to Document Control Desk (NRC), dated June 18, 2009,Beaver Valley Power Station, Unit No. 1, Docket No. 50-334, License No. DPR-66, LER2009-003-00, ".Containment Liner Through Wall Defect Due to Corrosion."22. Letter from E.A. Larson (FENOC) to Document Control Desk (NRC), dated February 14,2014, Beaver Valley Power Station, Unit No. 1, Docket No. 50-334, License No. DPR-66,LER 2013-002-01, "Containment Liner Through Wall Defect Discovered During PlannedVisual Inspection."23. Letter from J.E. Pollock (AEP Indiana Michigan Power) to Document Control Desk (NRC),dated March 16, 2001, submitting LER 316/2000-001-01, "Through-Liner HoleDiscovered in Containment Liner."24. Duane Arnold Energy Center Individual Plant Examinations of External Events (IPEEE),November 1995.25. Final Safety Evaluation For NEI Topical Report 94-01 Revision 2, "Industry Guideline forImplementing Performance-Based Option of 10 CFR Part 50, Appendix J" and EPRiReport No. 1009325 Revision 2, "Risk Impact Assessment of Extended Integrated LeakRate Test Intervals".Page 6 of 57
: 26. 0493080001.004, Rev. 3, Duane Arnold Energy Center (DAEC) Fire Probabilistic RiskAssessment Quantification.27. LTR-RAM-Il-15-013, Revision 1 Duane Arnold Energy Center Inputs used for IntegratedLeak Rate Test Interval Extension.28. Virgil C. Summer Nuclear Station, Unit 1- Issuance of Amendment Extending IntegratedLeak Rate Test Interval (TAG No. MF1385), February 5th, 2014. Adams ML13326A204.29. DAEC-PSA--L2-15 DAEC PSA Level 2 PSA Analysis, Revision 3, February 2011.30. An Approach for Determining the Technical Adequacy of Probabilistic Risk AssessmentResults for Risk-Informed Activities, Regulatory Guide 1.200, Revision 2, March 2009.31. NFPA 805 "Performance-Based Standard for Fire Protection for Light Water ReactorElectric Generating Plants," 2015.32. EPRI NP-6041, "A Methodology for Assessment of Nuclear Power Plant Seismic Margin,"Revision 1, August 1991.33. Professional Loss Control, Inc., Fire-Induced Vulnerability Evaluation (FIVE), TR-100370,EPRI Research Project 3000-41, Revision 1, September 1993.34. USNRC Letter to Mr. Richard L. Anderson, "Duane Arnold Energy Center -Issuance ofAmendment Regarding Transition to a Risk-Informed, Performance-Based FireProtection Program in Accordance with 10 CER 50.48(c) (TAG No. ME6818)", Docket No.50-331, Amendment No. 286to DPR-49, September 10, 2013.35. ERIN Report Number 0493080001.006, "Duane Arnold Energy Center (DAEC) FireProbabilistic Risk Assessment NFPA 805 RAI Model Updated Quantification Report,"Revision 3.2.1 AcronymsANS American Nuclear SocietyAPB Accident Progression BinASM E American Society of Mechanical EngineersBWR Boiling Water ReactorCAFTA Computer Aided Fault Tree AnalyzerCCFP Conditional Containment Failure ProbabilityCD Core DamageCDF Core Damage FrequencyCET Containment Event TreeCLRT Containment Leak Rate TestDAEC Duane Arnold Energy CenterDCH Direct.Containment HeatingEPRI Electric Power Research InstituteFIVE Fire-Induced Vulnerability EvaluationsPage 7 of 57 ILRT Integrated Leak Rate TestIPE Individual Plant ExaminationIPEEE Individual Plant Examinations for External EventsISI in-Service InspectionISLOCA Interfacing System Loss of Coolant Accident1ST In-Service TestingLER Large Early ReleaseLERF Large Early Release FrequencyLLRT Local Leak Rate TestLOCA Loss of Coolant AccidentLWR Light Water ReactorNEI Nuclear Energy InstituteNFPA National Fire Protection AssociationNRC Nuclear Regulatory CommissionORNL Oak Ridge National LaboratoryPRA Probabilistic Risk AssessmentPWR Pressurized Water ReactorRG Regulatory GuideRPV Reactor Pressure VesselSAMA Severe Accident Mitigation AlternativesSER Safety Evaluation ReportSMA Seismic Margins AssessmentSSE Safe Shutdown Earthquake3 MethodologyA simplified bounding analysis approach consistent with the EPRI approach is used forevaluating the change in risk associated with increasing the test interval to fifteen years. Theapproach is consistent with that presented in Appendix H of EPRI Report No. 1009325, Revision2-A, "Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals"(Reference 20), EPRI TR-104285 (Reference 2), NUREG-1493 (Reference 6) and the Calvert Cliffsliner corrosion analysis (Reference 5). The analysis uses results from the current DAEC Level 2PRA models to establish frequency of fission product releases. Fission product releasemagnitudes are extrapolated from results of NUREG/CR-4551 (Reference 7) to account for plantspecific characteristics. This risk assessment is applicable to DAEC.The six (6) general steps of this assessment are as follows:-1. Quantify the baseline risk in terms of the frequency of events (per reactor year) for each ofthe eight containment release scenario types identified in the EPRI report No. _1009325,Revision 2-A (Reference 20).2. Develop plant specific person-rem (population dose) per reactor year for each of thePage 8 of 57 eight containment release scenario types from plant specific consequence analyses.3. Evaluate the risk impact (i.e., the change in containment release scenario typefrequency and population dose) of extending the ILRT interval to fifteen years.4. Determine the change in risk in terms of Large Early Release Frequency (LERF) inaccordance with RG 1.174 (Reference 4) and compare with the acceptance guidelines ofRG 1.174.5. Determine the impact of the ILRT interval extension on the Conditional ContainmentFailure Probability (CCFP) and the population dose and compare with the acceptanceguidance of Reference 25.6. Evaluate the sensitivity of the results to assumptions in the liner corrosion analysis,external events and to the fractional contribution of increased large isolation failures(due to liner breach) to LERF.This approach is based on the information and approaches contained in the previouslymentioned studies. Furthermore:*Consistent with the other industry containment leak risk assessments, the DAEC*assessment uses LERF and delta LERF in accordance with the risk acceptance guidance ofRG 1.174 (Reference 4). Changes in population dose and conditional containment failureprobability are also considered to show that defense-in.-depth and the balance ofprevention and mitigation is preserved.oThe evaluation for DAEC uses groundrules and methods to calculate changes in riskmetrics that are consistent with those Used in Appendix H of EPRI Report No. 1009325(Reference 20), Revision 2-A, "Risk Impact Assessment of Extended Integrated Leak RateTesting Intervals."4 GroundrulesThe following groundrules are used in the analysis:* The technical adequacy of the DAEC PRA models is consistent with the requirements ofRegulatory Guide 1.200 (Reference 30) as is relevant to this ILRT interval extension.* The current DAEC Levell1 and Level 2 internal events PRA models are explicitly used inthis analysis to assess fission product release frequencies.* It is appropriate to use the DAEC internal events PRA models as gauges to effectivelydescribe the risk change attributable to the ILRT extension. It is reasonable to assumePage 9 of 57 that the impact from the ILRT extension (with respect to percent increases in populationdose) will not substantially differ if fire and seismic events Were to be included in thecalculations; this is evaluated in the sensitivity analysis which uses available informationfrom the DAEC IPEEE (Reference 24) and DAEC Fire PRA (Reference 26).eDose results for the containment failures modeled in the PRA can be characterized byscaling information provided in NUREG/CR-4551 (Reference 7) for Peach Bottom.Specifically, Duane Arnold population dose estimates are obtained by scaling theNUREG/CR-4551 reference plant results by differences in population, reactor powerlevel (assumed proportional to fission product inventory), *and nominal containmentmaximum leakage rate (La). Using this reference plant is judged .rea~sonable as it wasused for the BWR example plant in Reference 20. Results of sensitivity studies areincluded which utilize ,release class doses modified to account for differences in ILRTmethodology and appropriately, adjusted for power level and population growth.oAccident classes describing radionuclide release end states are defined consistent withEPRI methodology (Reference 2) and are summarized in Section 4.2 of the EPRImethodology.oThe representative containment leakage for Class 1 sequences is iLa. Class 3 accountsfor increased leakage due to Type A inspection failures.* The representative containment leakage for Class 3a sequences is lOL~a based on thepreviously approved methodology performed for Indian Point Unit 3 (Reference 8 andS Reference 9).*The representative containment Iealkage for Class 3b sequences is lOOLa based on theguidance provided in EPRI Report No. 1009325, Revision 2-A (Reference 20) and the NRCSE for NEI-94-01 Revision 2-A (Reference 25).*The Class 3b is very conservatively categorized as LERE based on the previouslyapproved methodology (References 8 and 9).*The impact on population doses from containment bypass scenarios is not altered bythe proposed ILRT extension, but is accounted for in the EPRI methodology as a separateentry for compar~ison purposes. Since the containment bypass contribution topopulation dose is fixed, no changes on the conclusions from this analYsis will resultfrom this separate categorization.*The, reduction in ILRT frequency does not impact the reliability of containment isolationvalves to close in response to a containment isolation signal.*Where possible, the analysis should include a quantitative assessment of thePage 10 of 57 contribution of external events (e.g., fire and seismic) in the risk impact assessment forextended JLRT intervals. As DAEC has developed fire and seismic PRAs, these modelswere used in the assessment of external event risks. Where existing PRAs were notavailable or if the external event analysis is not of sufficient quality or detail to directlyapply the methodology provided in this document, the quality or detail will be increasedor a suitable estimate of the risk impact from the external events should be performed.This assessment can be taken from existing, previously submitted and approvedanalyses or other alternate method of assessing an order of magnitude estimate forcontribution of the external event to the impact of the changed interval.5 InputsThis section summarizes the general resources available as input (Section 5.1.) and the plantspecific resources required (Section 5.2).5.1 General Resources AvailableVarious industry studies on containment leakage risk assessment are briefly summarized here:1. NUREG/CR-3539 (Reference 10)2. NUREG/CR-4220 (Reference 11)3. NLUREG-1273 (Reference 12)4. NUREG/CR-4330 (Reference 13)-5. EPRI TR-105189 (Reference 14)6. NUREG-1493 (Reference 6)7. EPRI TR-104285 (Reference 2)8. NUREG-1150 (Reference 15) and NUREG/CR-4551. (Reference 7)9. NEI Interim Guidance for One-Time Extension of ILRT (Reference 3 and Reference 17)10. Calvert Cliffs Liner Corrosion Analysis (Reference 5)11. EPRI Report No. 1009325, Revision 2-A, Appendix H (Reference 20)The first study is applicable because it provides one basis for the threshold that could be used inthe Level 2 PRA for the size of containment leakage that is considered significant and is to beincluded in the model. The second study is applicable because it provides a basis of theprobability for significant pre-existing containment leakage at the time of a core damageaccident. The third study is applicable because it is a subsequent study to NUREG/CR-4220 thatundertool a more extensive evaluation of the same database. The fourth study provides anassessment of the impact of different containment leakage rates on plant risk. The fifth studyprovides an assessment of the impact on shutdown risk from ILRT test interval extension. Thesixth study is the NRC's cost-benefit analysis of various alternative approaches regardingextending the test intervals and increasing the allowable leakage rates for containmentintegrated and local leak rate tests. The seventh study is an EPRI study of the impact ofextending ILRT and LLRT test intervals on at-power public risk. The eighth study provides an ex-plant consequence analysis for a 50 mile radius surrounding a plant that is used as the bases forPage 11 of 57 the consequence analysis of the ILRT interval extension for DAEC. The ninth study includes theNEI recommended methodology (promulgated in two letters) for evaluating the risk associatedwith obtaining a one-time extension of the ILRT interval. The tenth study addresses the impactof age-related degradation of the containment liners on ILRT evaluations. Finally, the eleventhstudy builds on the previous work and includes a recommended methodology and template forevaluating the risk associated with a permanent fifteen year extension of the ILRT interval.5.1.1 NUREG/CR-3539 (Reference 1.0)Oak Ridge National Laboratory (ORNL) documented a study of the impact of containment leakrates on public risk in NUJREG/CR-3539. This study uses information from WASH-1400(Reference 16) as the basis for its risk sensitivity calculations. ORNL concluded that the impactof leakage rates on LWR accident risks is relatively small.5.1.2 NUREG/CR-4220 (Reference 11)NUREG/CR-4220 is a study performed by Pacific Northwest Laboratories for the NRC in 1985.The study reviewed over two thousand LERs, ILRT reports and other related records to calculatethe unavailability of containment due to leakage.5.1.3 NUREG-1273 (Reference 12)A subsequent NRC study, NUREG-1273, performed a more extensive evaluation of theNUREG/CR-4220 database. This assessment noted that about one-third of the reported eventswere leakages that were immediately detected and corrected. In addition, this study noited thatlocal leak rate tests can detect "essentially all potential degradations" of the containmentisolation system.5.1.4 NUREG/CR-4330 (Reference 13)NUREG/CR-4330 is a study that examined the risk impacts associated with increasing theallowable containment leakage rates. The details of this report have no direct impact on themodeling approach of the ILRT test interval extension, as NUREG/CR-4330 focuses on leakagerate and the ILRT test interval extension study focuses on the frequency of testing intervals.However, the general conclusions of NUREG/CR-4330 are consistent with NUREG/CR-3539 andother similar containment leakage risk studies:"...the effect of containment leakage on overall accident risk is small since risk is dominatedby accident sequences that result in failure or bypass of containment."5.1.5 EPRI TR-105189 (Reference 14)The EPRI study TR-105189 is useful to the ILRT test interval extension risk assessment because itprovides insight regarding .the impact of containment testing on shutdown risk. This studycontains a quantitative evaluation (using the EPRI GRAM software) for two reference plants (aPage 12 of 57 BWR-4 and a PWR) of the impact of extending ILRT and LLRT test intervals on shutdown risk.The conclusion from the study is that a small but measurable safety benefit is realized fromextending the test intervals.5.1.6 NUREG-1l493 (Reference 6)NUREG-1493 is the NRC's cost-benefit analysis for proposed alternatives to reduce containmentleakage testing intervals and/or relax allowable leakage rates. The NRC conclusions areconsistent with other similar containment leakage risk studies:Reduction in ILRT frequency from three per ten years to one per twenty years results in an"imperceptible" increase in risk.Given the insensitivity of risk to the containment leal' rate and the small fraction of leak pathsdetected solely by Type A testing, increasing the interval between integrated leak rate tests ispossible with minimal impact on public risk.5,1.7 EPRI TR-104285 (Reference 2)Extending the risk assessment impact beyond. shutdown (the earlier EPRI TR-1051.89 study), theEPRI TR-104285 study is a quantitative evaluation of the impact of extending ILRT and LLRT testintervals on at-power public risk. This study combined IPE Level 2 models with NUREG-1150Level 3 popuration dose models to perform the analysis. The study also used the approach ofNUREG-1493 in calculating the increase in pre-existing leakage probability due to extending theILRT. and LLRT test intervals.EPRI TR-104285 uses a simplified Containment Event Tree to subdivide representative coredamage frequencies into eight classes of containment response to a core damage accident:1. containment intact and isolated2. Containment isolation failures dependent upon the core damage accident3. Type A (ILRT) related containment isolation failures4. Type B (LLRT) related containment isolation failures5. Type C (LLRT) related containment isolation failures6. Other penetration related containment isolation failures7. Containment failures due to core damage accident phenomena8. Containment bypassConsistent with the other containment leakage risk assessment studies, this study concluded:"... the proposed CLRT (containment leak rate tests) frequency changes would have aminimal safety impact. The change in risk determined by the analyses is small in bothabsolute and relative terms. For example, for the PWR analyzed, the change is about0.04 person-rem per year..."Page 1.3 of 57 k5.1.8 NUREG-1150 (Reference 15) and NUREG/CR 4551 (Reference 7)NUREG-li50 and the technical basis, NUREG/CR-4551, provide an ex-plant consequenceanalysis for a spectrum of accidents including a severe accident with the containmentremaining intact (i.e., Tech Spec leakage). This ex-plant consequence analysis is calculated forthe 50 mile radial area surrounding Peach Bottom. The ex-plant calculation can be delineated tototal person-remn for each identified Accident Progression Bin (APB) from NUREG/CR-4551. Withthe DAEC Level 2 model end-states assigned to one of the NUREG/CR-4551 APBs, it isconsidered adequate to represent Duane Arnold. (The meteorology and site differences otherthan population are assumed not to play a significant role in this evaluation.)5.1.9 NEI Interim Guidance for Performing Risk Impact Assessments In Support of One-TimeExtensions for Containment Integrated Leakage Rate Test Surveillance Intervals(Reference 17)The guidance provided in this document builds on the EPRI risk impact assessmentmethodology (Reference 2) and~the NRC performance-based containment leakage test program(Reference 6), and considers approaches utilized in various submittals, including indian Point 3(and associated NRC SER) and Crystal River.5.1.10 Calvert Cliffs Response to Request for Additional Information Concerning the LicenseAmendment for a One-Time Integrated Leakage Rate Test Extension (Reference 5)This submittal to the NRC describes a method for determining the change in likelihood, due toextending the ILRT, of detecting liner corrosion, and the corresponding change in risk. Themethodology was developed for Calvert Cliffs in response to a request for additionalinformation regarding how the potential leakage due to age-related degradation mechanismswas factored into the risk assessment for the ILRT one-time extension. The Calvert Cliffsanalysis was performed for a concrete cylinder, dome and a concrete basemat, each with asteel liner. Licensees may consider approved LARs for one-time extensions involvingcontainment types similar to their facility.5.1.1:1 EPRI Report No. 1009325, Revision 2-A, Risk Impact Assessment of ExtendedIntegrated Leak Rate Testing Intervals (Reference 20)This report provides a generally applicable assessment of the risk involved in the extension ofILRT test intervals to permanent 15-year intervals. Appendix H of this document providesguidance for performing plant specific suppl~emental risk impact assessments and builds on theprevious EPRI risk impact assessment methodology (Reference 2) and the NRC performance-based containment leakage test program (Reference 6), and considers approaches utilized invarious submittals, including Indian Point 3 (and associated NRC SER) and Crystal River.The approach included in this guidance document is used in the DAEC assessments todetermine the estimated increase in risk associated with the ILRT extension. This documentincludes the bases for the values assigned in determining the probability of leakage for the EPRIPage 14 of 57 Classes 3a and 3b scenarios in this analysis as described in Section 6. The Duane Arnold fifteen(15) year ILRT extension used an early version of this methodology.5.2 Plant Specific InputsThe plant specific information (Reference 27) used to perform the DAEC ILRT Extension RiskAssessments includes the following:o Level 1 Model resultso Level 2 Model resultso Release category definitions used in the Level 2 ModeloPopulation within a 50 mile radius for the year 2040 based on the extrapolation of theactual population in 2000 (Reference 27). This represents the most recent projectedgrowth for the area and by assuming positive pop~ulation growth past the 2040 end oflicense this number conservatively bounds population estimates.* Containment Fragility Curves5.2.1 Level 1 ModelThe Level 1 PRA models that are used for DAEC are characteristic of the as-built plants. Thecurrent Level 1 model is a linked fault tree model, and was quantified with the total CoreDamage Frequency (CDF) = 4.24E-05/yr using a truncation value of 1.00E-12 (Table 1. ofReference 27). The model accounts for an increased CDF due to internal flood.5.2.2 Level 2 ModelThe Level 2 Models that are used for DAEC were developed to calculate the LERF contributionas well as the other release .categories evaluated in the model. Table 5-1 summarizes thepertinent DAEC results in terms of release category (from Reference 27). Note that theenumerated total internal events Level 2 release frequency is slightly larger than that of theinternal events CDF. This difference arises as a result of the numerical truncation issuesresulting from the full integration of core damage end-states into the Level 2 model and theimpact of the CAFTA small number approximation as applied to the detailed containmentfailure model. The small number approximation is a standard modeling practice. While thisdifference is observable, it does not significantly impact the results of the simplified Level 2 PRAor the associated conclusions drawn with regard to the ILRT extension.Page 15 of 57
*Tablie 5-1: DAiEC Level 2 IPSA Modlel Release Ca tegories and :FrequenciesRelease Category ...Definition .... RelieaseCategoryIntact Containment Intact (Tech Spec Leakage 2.40E-07only)DAEC-L_2-H-E-RELEASE High Eariy Releases 1.46E-06DAEC-L2-H-l-RELEASE High Intermediate Releases 5. 02E-07DAEC-L2-H-L-RELEASE High Late Releases 1.76E-07DAEC-L2-M-E-RELEASE Medium Early Releases 1.27E-06DAEC-L2-M-I-RELEASE Medium Intermediate Releases 3.52E-08DAEC-L2-M-L-RELEASE Medium Late Releases 2.25E-07DAEC-L2-L-E-RELEASE *Low Early Releases 5.69E-08DAEC-L2-L-I-RELEASE' Low Intermediate Releases 5.74E-08DAEC-L2-L-L-RELEASE Low Late Releases 2.08E-08DAEC-L2-LL-E-RELEASE Low-Low Early Releases 2.37E-09DAEC-L2-LL-l-RELEASE Low-Low Intermediate Releases 2.90E-09DAEC-L2-LL-L-RELEASE Low-Low Late Releases 1.95 E-07CNTMT BYPASS Associated with ISLOCA CD Scenarios 1.89E-08Associated with CD scenarios withCNTMT ISO FAILURES containment isolation failures leading to 1.26E-08_________________ LERF____________Total Release Category Frequency 4.00E-06-Note:.1. These values were quantified using a truncation value of l.O0E-12.5.2.3 Population Dose CalculationsThe population dose is calculated by using data provided in NUREG/CR-4551 and adjusting theresults to reflect t~he demographics around DAEC. Each of the release categories from Table 5-1was associated with an applicable collapsed Accident .Progression Bin (APB) fromNUREG/CR-4551 (see below). The collapsed APBs are characterized by 5 attributes related tothe-accident progression. Unique combinations of the 5 attributes result in a set of 10 bins thatare relevant .to the analysis. The definitions of the 10 collapsed APBs are provided inNUREG/CR-4551 and, are reproduced in Table 5-2Error! Reference source not found. forreference purposes. Table 5-3 summarizes the calculated population dose for Peach Bottomassociated with each APB from NUREG/CR-4551.Page 16 of 57 Table 5-2: Summary Accident ProgreSsion Bin Descrip3tions (Refere'nc'e 7)summaryAPB DescriptionNumnber ......_________.........______________1 CD, VB, Early CF WW Failure, RPV Pressure > 200 psi at VBCore damage occurs, followed by vessel breach. The containmentfails early in the wetwell (i.e., either before core damage, during coredamage, or at vessel breach), and the RPV pressure is greater than200 psi at the time of vessel breach (this means Direct ContainmentHeating [DCH] is possible).2 CB, VB, Early CF, WW Failure, RPV Pressure < 200 psi at VBCore damage occurs, followed by vessel breach. The containmentfails early in the wetwelf (i.e., either before core damage, during coredamage, or at vessel breach), and the RPV pressure is less than 200_________________psi at the time of vessel breach (this means DCH is not possible).3 CD, VB, Early CF, DW Failure, RPV Pressure > 200 psi at VBCore damage occurs, followed by vessel breach. The containmentfails early in the drywell (i.e., either before core damage, during coredamage, or at vessel breach), and the RPV pressure is greater than200 psi at the time of the vessel breach (this means DCH is possible).4 CD, VB, Early CF, DW Failure, RPV Pressure < 200 psi at VBCore damage occurs, followed by vessel breach. The containmentfails early in the drywell (i.e., either before core damage, during coredamage, or at vessel breach), and the RPV pressure is less than 200psi at the time of the vessel breach (this means DCH is not possible).5 CD, VB, Late CF, WW Failure, N/ACore damage occurs, followed by vessel breach. The containmentfails late in the wetwell (i.e., after vessel breach during Molten Core-Concrete Interaction [MCCI]), and the RPV pressure is not importantsince, even if DCH occurred, it did not fail containment at the time itoccurred.6 CD, VB, Late CF, DW Failure, N/ACore damage occurs, followed by vessel breach. The containmentfails late in the drywell (i.e., after vessel breach during MCCI), and theRPV pressure is not important since, even if DCH occurred, it did notfail containment at the time it occurred.7 CD, VB, No CF, Vent, N/ACore damage occurs, followed by vessel breach. The containmentnever structurally fails but is vented some time during the accidentprogression. RPV pressure is not important (characteristic 5 is N/A)since, even if it occurred, DCH does not significantly affect the sourceterm as the containment does not fail and the vent limits its effect.Page 17 of 57
...Table 5-2: Sum mary Accident Progression Bin (APB) Descriptions (Reference 7), ,s u m m .a ry ..... ......... .... ..... .... ......... ..... ...APB DescriptionNumber8 CD, VB, No CF, N/A, N/ACore damage occurs, followed by vessel breach. The containmentnever fails structurally (characteristic 4 is N/A) and is not vented. RPVpressure is not important (characteristic 5 is N/A) since, even if itoccurred, DCH did not fail containment. Some nominal leakage fromthe containment exists and is accounted for in the analysis so thatwhile the risk will be small it is not completely negligible.9 CD, No VB, N/A, N/A, N/ACore damage occurs but is arrested in time to prevent vessel breach.There are no releases associated with vessel breach or MCCI. It imustbe remembered, however, that the containment can fail due tooverpressure or venting even if vessel breach is averted. Thus, thepotential exists for some of the in-vessel releases to be released tothe environment.10 No CD, N/A, N/A, N/A, N/ACore damage did not occur. No in-vessel or ex-vessel release occurs.The containment may fail on overpressure or be vented. The RPV maybe at high or low pressure depending on the progressioncharacteristics. The risk associated with this bin is negligible.For the baseline analysis dose estimates are based on extrapolation of the results of the PeachBottom assessment presented below, based on the values in Table 5-18 of Reference 20.Tabl!e 5-i3" of Peach lBottom 'Risk, at 50O Miles, ' :.Bi i .......e.....es c:nri ton't1 9.55E-08 0.021 0.166 1.74E+062 4.77E-08 0.0066 0.0521 1.09E+063 1.48E-06 0.556 4.39 2.97E+064 7.94E-07 0.226 1.79 2.25E+065 1.30E-08 0.0022 0.0174 1.34E+066 2.04E-07 0.059 0.466 2.28E+067 4.77E-07 0.118 0.932 1.95E+068 _ 7.99E-07 0.0005 3.95E-03 4.94E+039 3.85E-07 0.01 0.079 2.05E+0510 4.34E-08 0 0 0Totals 4.34E-06 1 7.9 N/APage 18 of 57 Notes for Table 5-3:(1) The total CDF of 4.34E-06 per year and the CDF subtotals by APB are taken from Figure 2.5-6 ofNUREG/CR-4551, Volume 4, Revision 1, Part I.(2) The individual APB contributions to the total 50-mile radius dose rate are taken from Table 5.2-3of NUREG/CR-4551, Volume 4, Revision 1, Part I.(3) The APB 50-mile dose rate is calculated by multiplying the individual APB dose rate fractionalcontributions (column 3) by the total 50-mile radius dose rate of 7.9 person-rem per year (takenfrom Table 5.1-1 of NUREG/CR-4551, Volume 4, Revision 1, Part I).(4) The individual doses are calculated by dividing the individual APB dose risk (column 4) by theAPB frequencies (column 2).5.2.4 Population Dose Estimate MethodologyIn accordance with Reference 1, the person-remn results in Table 5-3 can be used as anapproximation of the dose for DAEC if it is corrected for allowable containment leak rate (La),reactor power level and the population density surrounding Duane Arnold.La adjustment:F~k -La of Duane Arnold Energy Center (wt%/day)Feakage = La of reference plant (applicable only to those APBs affected by normal leakage)La for DAEC is 2.0 wt%/day (Table 2 of Reference 27). La for Peach Bottom is 0.5 wt%/day(Reference 20).FLea kage = 2.0 / 0.5Fkeakage = 4Power level adjustment:Rated power level of Duane Arnold Energy Center (MWt)FPowerRated power level of reference plant (MWt)The rated power level for DAEC is 1912 MWt (Table 2 of Reference 27). The rated power levelfor Peach Bottom is 3293 MWt (Reference 2).FPower = 1912 MWt/ 3293 MWtFPower = 0.5 81,Populatidn density adjustment:,The total population within a 50 mile radius of DAEC is 9.626E+5 persons (Reference 27).Page 19 of 57 This population value is compared to the population value that is provided in NUREG/CR-4551. in order to get a "Population Dose Factor" that can be applied to the APBs to get doseestimates for DAEC. Note that the numbers reported below may represent a rounded resultas displayed in the attached spreadsheets.Total 2040 estimated DAEC Population within 50 miles = 9.626E+5 persons.Peach Bottom Population within a 50 mile radius from the NUREG/CR-4551 reference plant=3.2E+06 persons (Reference 2).FPopulation =9.626E+5 persons / 3.2E+06 persons =0.301The factors developed above are used to adjust the population dose for the surrogate plant(Peach Bottom) for DAEC. For intact containment endstates, the total population dose factor isas follows:Flntact = FPopulation
* FPower
* FLeakageFlntact =0.301
* 0.581* 4Flntact -0.699For EPRI accident classes not dependent on containment leakage, the population dose factor isas follows:FOthers =FPopulation
* FPowerFOthers = 0.301
* 0.581FOthers =0.175The difference in the doses at 50 miles is assumed to be in direct proportion to the difference inthe population within 50 miles of each site. The above adjustments provide an approximationfor DAEC of the population doses associated with each of the release categories fromNUREG/CR-4551.Table 5-4 shows the results of applying the population dose factor to the NUREG/CR-4551population dose results at 50 miles to obtain the adjusted population dose at 50 miles forDAEC.Page 20 of 57 Table 5-4: Calculation of DAEC Population Dose Risk at 50 MilesAcidnt Pac Bttm Bin.M.u!ltipl.ier used to D uane Arnoldi AdijustedProgre~ssi~on Popula:tio~n Dose at obtain Arnoldci Populatio~n :Dose .at 50 miles1 1.74E+06 FOthers 0.175 3.04E+052 1.09E+06 FOthers 0.175 1.90E+053 2.97E+06 FOthers 0.175 5.19E+054 2.25E+06 FOthers 0.175 3.93E+055 1.34E+06 FOthers 0.175 2.34E+056 2.28E+06 FOthers 0.175 3.98E+057 1.95 E+06 FOthers 0.175 3.41E+05 .8 4.94E+03 Flntact 0.699 3.45E+039 2.05E+05 FOthers 0.175 3.58E+0410 O.OOE+O0 FOthers 0.175 O.OOE+O0Notes:* These values follow the template in EPRI Report 1009325, Section 5.2.2, Table 5-18.** These values follow the guidance in EPRI Report 1009325 (See page 5-25).5.2.5 Application of DAEC PRA Model Results to NUREG/CR-4551 Level 3 OutputA major factor related to the use of NUJREG/CR-4551 in this evaluation is that the results of theDAEC. PRA Level 2 models are not defined in the same terms as reported in NUREG/CR-4551. Inorder to use the Level 3 model presented in that document, it was necessary to match theDuane Arnold PRA Level 2 release categories to the collapsed APBs. The APB definitions areshown in Table 5-2. TheDuane Arnold Level 2 release categories and frequencies are fromReference 27. The assignments are shown in Table 5-5, along with the corresponding EPRIclasses (see below). The EPRI classes and descriptions are listed in Table 5-6.Page 21 of 57 Table 5-5: :;DAEC Level Model for Application ;the NUREG/CR-4551 :Accident Progression Bi ns and !EPR!.* ..... : :..:. .--~c~cidcent ~iClass~es:-..-.- > .:... .. :... ;,. ~~.. .:DAEC.Leve1.2 .... :;: ...L. : ..;:- :-;l ..:Peach iBottom : .: .:.;<!Release Clas .-.';. :.EPRI "B ... :!;;.::APB ;for ;Dose. ;iCategory%:. (oR oth.:erbais~~_rContainment4IntactFrequency1 No containment failure La. 8. 2.08E-07 CnanetItc rqec______________(Intact-3a-3b)2 Large Containment Isolation Plant. 3 '1.26E-08 Containment Isolation FailureFailure value (highest dose) (H-E with IS=F)3a Small pre-existing failure 10*La 10*dose of APB 8 2.56E-08 By MetF-hodology093b Large pre-existing failure 100*La 100*dose of APB 8 6.39E-09 =ByCDehodo)..0gySmall isolation failure.-Typ BN/A N/A .N/A N/ASmall isolation failure -N/NANANA_____Type C6 Small isolation-failure -N/A. N/A N/A N/A______ Dependent failureSum of the Class 77 Severe Accident Sequences .See below 3.97E-06suctgrePlant 3uctgre7a Subcatego~ry (not EPRI) value (hgetds) 1.43E-06 HEwtotl= n(weighted67b Subcategory (not EPRI) avrg) (high does, late -6.78E-07 H-I and H-LDW failure) ______________Page 22 of 57 Table 5-5: :=DAEC Level Model :Assumptions ;for Application~tothe NUJREG/CR-4551 Accident Progression Bins and .. , .A.ciden Classes- ::.. .. :.. .. ... ... .. .:D A EC L~evel. 2.....7c Subcategory (not EPRI) 1W falr al) 1.27E-06 M-E7d Sbaery(not EPRI) 2W alr ae 2.60E-07 M-l and M-L97e Subcategory (not EPRI) (CD, no vessel 3.35 E-07 L & LLbreach)8 otinetbyasPlant 3Cotimn yasvalue (highest dose) 1.89E-O8 H-E Class V ScenariosPage 23 of 57 5.2.6 Release Category DefinitionsTable 5-6 defines the accident classes used in the ILRT extension evaluation, which is consistentwith the EPRI methodology (Reference 2). These containment failure classifications are used inthis analysis to determine the risk impact of extending the Containment Type A test interval asdescribed in Section 6 of this report.Table 5-6: EPRI Conitai nment Fail ure C lass D....... ...... : " ' .: ; ... ... escrip t~ion .......... " :' ..... ......1. Containment remains intact including accident sequences that donot lead to containment failure in the long term. The release offission products (and attendant consequences) is determined by themaximum allowable leakage rate values La, under Appendix J for thatplant2 Containment isolation failures (as reported in the IPEs) include thoseaccidents in which there are a failure to isolate the containment.3 Independent (or random) isolation failures include those accidents inwhich the pre-existing isolation failure to seal (i.e., provide a leak-tight containment) is not dependent on the sequence in progress.4 Independent (or random) isolation failures include those accidents inwhich the pre-existing isolation failure to seal is not dependent onthe sequence in progress. This class is similar to Class 3 isolationfailures) but is applicable to sequences involving Type B tests andtheir potential failures. These are the Type B-tested components thathave isolated but exhibit excessive leakage.5 Independent (or random) isolation failures include those accidents inwhich the pre-existing isolation failure to seal is not dependent onthe sequence in progress. This class is similar to Class 4 isolationfailures, but is applicable to sequences involving Type C tests andtheir potential failures.6 Containment isolation failures include those leak paths covered inthe plant test and maintenance requirements or verified per inservice inspection and testing (ISI/IST) program.7 Accidents involving containment failure induced by severe accidentphenomena. Changes in Appendix J testing requirements do notimpact these accidents.8 Accidents in which the containment is bypassed (either as an initialcondition or induced by phenomena) are included in Class 8. Changesin Appendix J testing requirements do not impact these accidents.Page 24 of 57 5.3 Impact of Extension on Detection of Component Failures That Lead to Leakage (Smalland Large)The ILRT can detect a number of component failures such as liner breach, failure of certainbellow arrangements and failure of some sealing surfaces, which can lead to leakage. Theproposed ILRT test interval extension may influence the conditional probability of detectingthese types of failures. To ensure that this effect is properly accounted for, the EPRI Class 3accident class as defined in Table 5-6 is divided into two sub-classes, Class 3a and Class 3b,which represent small and large leakage failures, respectively.The probability of the EPRI Class 3a and 3b failures is determined consistent with the EPRIGuidance (Reference 20). For Class 3a, the probability is based on the maximum likelihoodestimate of failure (arithmetic average) from the available data (i.e., 2 "small" failures in217 tests leads to 2/217=0.0092). For Class 3b, Jefferys non-informative prior distribution isassumed for no "large" failures in 217 tests (i.e., 0.5 / (217&#xf7;1) = 0.0023).In a follow-on letter (Reference 17) to their ILRT guidance document (Reference 3), NEI issuedadditional information concerning the potential that the calculated delta LERF values for severalplants may fall above the "very small change" guidelines of the NRC Regulatory Guide 1.174.This additional NE! information includes a discussion of conservatisms in the quantitativeguidance for delta LERF. NEI describes ways to demonstrate that, using plant specificcalculations, the delta LERF is smaller than that calculated by the simplified method.The supplemental information states:The methodology employed for determining LERF (Class 3b frequency) involvesconservatively multiplying the CBF by the failure probability for this class (3b) of accident.This was done for simplicity and to maintain conservatism. Howev/er, some plant specificaccident classes leading to core damage are likely to include individual sequences that eithermay already (independently) cause a LERF or could never cause a LERF, and are thus notassociated with a postulated large Type A containment leakage path (LERE). Thesecontributors can be removed from Class 3b in the evaluation of LERF by multiplying the Class3b probability by only that portion of CDF that may be impacted by type A leakage.The application of this additional guidance to the analysis for DAEC, as detailed in Section 6involves the following:oThe Class 2 and Class 8. sequences are subtracted from the CDF that is applied to Class3b. To be consistent, the same change is made to the Class 3a CDF, even though theseevents are not considered LERF. Class 2 and Class 8 events refer to sequences witheither large pre-existing containment isolation failures or containment bypass events.These sequences are already considered to contribute to LERF in the DAEC Level 2 PRAanalyses.Page 25 of 57
* Class 1 accident sequences may involve availability and or successful operation ofcontainment sprays. It could be assumed that, for calculation of the Class 3b and 3afrequencies, the fraction of the Class 1 CDF associated with successful operation ofcontainment sprays can also be subtracted. However, in this assessment DAEC does notcredit containment spray as a means of reducing releases from Class 3 events.Consistent with the NEI Guidance (Reference 3), the change in the leak detection probabilitycan be estimated by comparing the average time that a leak could exist without detection. Forexample, the average time that a leak could go undetected with a three year test interval is 1.5years (3 yr/2), and the average time that a leak could exist without detection for a ten yearinterval is five years (10 yr/2). This change would lead to a non-detection probability that is afactor of 3.33 (5.0/1.5) higher for the probability of a leak that is detectable only by ILRT testing.An extension of the ILRT interval to fifteen years can be estimated to lead to about a factor of5.0 (7.,5/1.5) increase in the non-detection probability of a leak compared to a three yearinterval.It should be noted that using the methodology discussed above is very conservative comparedto previous submittals (e.g., the 1P3 request for a one-time ILRT extension (Reference 9))because it does not factor in the possibility that the failures could be detected by other tests(e.g., the Type B local leak rate tests that will still occur.) Eliminating this possibilityconservatively over-estimates the factor increases attributable to the ILRT extension.5.4 Impact of Extension on Detection of Steel Liner Corrosion that Leads to LeakageAn estimate of the likelihood and risk implications of corrosion-induced leakage of the steelliners occurring and going undetected during the extended test interval is evaluated using themethodology from the Calvert Cliffs liner corrosion analysis (Reference 5). The Calvert Cliffsanalysis was performed for a concrete cylinder; dome and a concrete basemat, each with asteel liner. DAEC employs a Mark I pressure suppression containment system which houses thereactor vessel, the reactor recirculation loops, and other branch connections of the ReactorCoolant System, a pressure suppression chamber that stores a large volume of water, a ventsystem connecting the drywell and the pressure suppression chamber, isolation valves,containment cooling systems, and other service equipment. The drywell is a steel pressurevessel with a spherical lower portion and a cylindrical upper portion. The drywell is surroundedby a reinforced-concrete structure for shielding purposes; The concrete provides no drywellstructural support. The pressure suppression chamber is a steel pressure vessel in the shape ofa torus located below and encircling the drywell, (Section 2.1 of Reference 29).The following approach is used to determine the change in likelihood, due to extending theILRT, of detecting corrosion of a containment steel liner. It should be noted that thiscomputation is being applied to provide an upper bound approach to quantify corrosioninduced risk. Furthermore, the likelihood of detection of significant corrosion for the 80% ofthe containment accessible for visual inspection is very high. Regardless, the Calvert Cliffscorrosion likelihood methodology is then used to determine the resulting change in risk.Page 26 of 57 Consistent with the Calvert Cliffs analysis, the following issues are addressed:o Differences between the containment basemat and the upper containment (cylinderand dome regions in Calvert Cliffs evaluation)SThe historical steel liner flaw likelihood due to concealed corrosiono The impact of agingo The corrosion leakage dependtency on containment pressureo The likelihood that visual inspections will be effective at detecting a flaw5.4.1 Assumptionso Consistent with the Calvert Cliffs analysis, a half failure is conservatively assumed forbasemat concealed liner corrosion due to the lack of identified failures (See Table 5-7,Step 1).* There are two corrosion events used to estimate the liner flaw probability in the CalvertCliffs analysis. These events have been determined to be applicable at Duane Arnold. Theevents included in the Calvert Cliffs corrosion assessment process, one at North Anna Unit 2and one at Brunswick Unit 2, were initiated from the nonvisible (backside) portion of thecontainment liner.o Consistent with the Calvert Cliffs analysis, the estimated historical flaw probability is basedon 70 steel-lined containments.*The Calvert Cliffs analysis used the estimated historical liner flaw probability based on5.5 years to reflect the years since September 1.996 when 1.0 CFR 50.55a started requiringvisual inspection. Additional success data was not used to limit the aging impact of thiscorrosion issue, even though inspections were being performed prior to this date. Since thetime of the Calvert Cliffs submittal, three additional relevant liner corrosion events involvingconcealed corrosion (corrosion initiated on the inaccessible liner surface) were observedand are considered in the corrosion risk assessment. Two of these events occurred atBeaver Valley Unit 1 (References 21 and 22). The third occurred at D.C. Cook( Unit 2(Reference 23). Consistent with the addition of the three observed events, the historicalliner flaw probability was established by incrementing the flaw observation time by 12.25years (September 1996 to July 2014). This re-evaluation resulted in a reduction of thehistorical liner flaw likelihood to 4.02E-03/year ((2+3) / [70 * (5.5 + 12.25)] = 4.02E-03/year).This value is smaller than the value of 5.2E-03 which is used in the Calvert Cliffs analysis.The conservative value of 5.2E-03 will be used in this Duane Arnold report to remainconsistent with the Calvert Cliffs analysis. This approach, while conservative, provides asimplified, direct comparison to the previously evaluated Calvert Cliffs analysis.* Consistent with the Calvert Cliffs analysis, the steel plate flaw likelihood is assumed to.double every five years. This is based solely orn judgment and is included in this analysis toPage 27 of 57 address the increased likelihood of corrosion as the steel ages. (See Table 5-7, Steps 2 and3). Sensitivity studies are included that address doubling this rate every ten years and everytwo years.oIn the Calvert Cliffs analysis, the likelihood of the containment atmosphere reaching theoutside atmosphere given that a finer flaw exists was estimated as 1.1% for the cylinder and"dome and 0.11% (10% of the cylinder failure, probability) for the basemat. These valueswere determined from an assessment of the probability versus containment pressure, andthe selected values are consistent with a pressure that corresponds to the Calvert Cliffs ILRTtarget pressure of 37 psig. For DAEC, the containment failure probabi~lities are less than thisat 37 psig because the DAEC design pressure is 56 psig (Reference 27). Givien the aboveinformation and consistent with recently approved 15 year ILRT extensions (Reference 28)probabilities of 1% for the shell above the basemat and 0.1% for the basemat are used inthis analysis, and sensitivity studies are included that increase and decrease the.probabilities by an order of magnitude (See Table 5-7, Step 4).*Consistent with the Cal vert Cliffs analysis, the likelihood of leakage escape (due to crackformation) in the basernat region is considered to be less likely than the upper containmentregion (See Table 5-7, Step 4).*Consistent with the Calvert Cliffs analysis, a 5%.visual inspection detection failure likelihoodgiven the flaw is visible and a total detection failure likelihood of 10% is used. To date, allliner corrosion events have been detected through visual inspection (See Table 5-7, Step 5).Sensitivity studies are included that evaluate total detection failure likelihood of 5% and15%, respectively.*Consistent with the Calvert Cliffs analysis, all non-detectable containment failures areassumed to result in early releases. This approach avoids a detailed analysis of containmentfailure timing and operator recovery actions.Page 28 of 57 5.4.2 AnalysisTable 5-7: Steel Liner corrosion Base CaseStep Up~per Containmient Conltainment Basemat1 Historical Steel Liner Flaw Events: 2 Events: 0Likelihood (Brunswick 2 & North Anna 2) (assume half a failure)Failure Data: Containment (2)/(70
* 5.5) --5.2E-03 0.5/(70
* 5.5) =1.3E-03____ location specific _______ ______2 Age Adjusted Steel Liner Year Failure Rate Year Failure RateFlaw Likelihood 1 2.1E-03 1 5.0E-04avg 5-10 5.2E-03 avg 5-10 1.3E-03During 15-year interval, 15 1.4E-02 15 3.5E-03assume failure ratedoubles every five years(14.9% increase per year).The average for 5th to 15 year average = 15 year average=10th year" is set to the 6.27E-03 1.57E-03historical failure rate(consistent with CalvertCliffs analysis).3 Flaw Likelihood at 3, 10, 0.71% (1 to 3 years) 0.18% (1 to 3 years)and 15 years 4.06% (1 to 10 years) 1.02% (1. to 10 years)9.40% (1 to 15 years) 2.35% (1 to 15 years)Uses age adjusted liner (Note that the Calvert (Note that the Calvertflaw likelihood (Step 2), Cliffs analysis presents the Cliffs analysis presentsassuming failure rate delta between 3 and 15 the delta between 3 anddoubles every five years years of 8.7% to utilize in 15 years of 2.2% to(consistent with Calvert the estimation of the utilizein the estimationCliffs analysis -SeelTable 6 delta-LERF value. For this of the delta-LERF value.of Reference 5). analysis, however, the For this analysis,values are calculated however, the values arebased on the 3, 10, and calculated based on the15 year intervals 3, 10, and 15 yearconsistent with the intervals co~nsistent withintervals of concern in the intervals of concern_____ _________________this analysis.) in this analysis.)Page 29 of 57 Table 5-7: Steel Liner Corrosion Base Case.... D~escrip~tio.n Upp~er Containment Con~tainmenit Basemat4 Likelihood of Breach inContainment Given SteelLiner FlawThe failure probability of 1% 0.1%the cylinder and dome isassumed to be 1%(compared to 1.1% in theCalvert Cliffs analysis). Thebasemat failure probabilityis assumed to be a factoroften less, 0.1%,(compared to 0.11% in theCalvert Cliffs analysis).5 Visual Inspection Detection 10% 100%Failure Likelihood5% failure to identify Cannot be visuallyUtilize assumptions visual flaws plus 5% inspected.consistent with Calvert likelihood that the flaw isCliffs analysis. not visible (not through-cylinder but could bedetected by ILRT)All events have beendetected through visualinspection. 5% visiblefailure detection is aconservative assumption.6 Likelihood of Non- 0.00071% (at 3 years) 0.00018% (at 3 years)Detected Containment 0.71%
* 1%
* 10% 0.18%
* 0.1%
* 100%Lea kage 0.0041% (at 10 years) 0.0010% (at 10 years)4.1%
* 1%
* 10% 1.0%
* 0.1%
* 100%(Steps 3
* 4* 5) 0.0094% (at 15 years) 0.0024% (at 15 years)____ ______________ 9.4%
* 1%
* 10% 2.4%
* 0.1%
* 100%The total likelihood of the corrosion-induced, non-detected containment leakage is the sum ofStep 6 for the leakages for the upper containment and the containment basemat assummarized below for DAEC.Total Likelihood of Non-Detected Containment Leakage Due To Corrosion for DAEC:At 3 years: 0.00071% + 0.00018% = 0.00089%Page 30 of 57 At 10 years: 0.0041% + 0.0010% = 0.0051%* At 15 years: 0.0094% + 0.0024% = 0.012%The above factors are applied to those core damage accidents that are not alreadyindependently LERF or that could never resuit in LERF. For example, the three in ten year case iscalculated as follows:oPer Table 5-5, the EPRI Class 3b frequency is 6.39E-09/yr. As discussed in Section 6.1,this is the DAEC CDF associated with accidents that are not independently LERF [CDF-(DAEC-L2-H-E-RELEASE)] = 2.78E-06/yr times the conditional probability of class 3b(0.0023).oThe increase in the base case Class 3b frequency due to the corrosion-inducedconcealed flaw issue is calculated as 2.78E-06/yr
* 0.00089% = 2.47E-11/yr where0.00089% was previously shown above to be the cumulative likelihood of non-detectedcontainment leakage due to corrosion at three years.* The three in ten year Class 3b frequency including the corrosion-induced concealed flawissue is then calculated as 6.39E-Og/yr + 2.47E-11/yr = 6.42E-O9/yr.Page 31 of 57 6 ResultsThe application of the approach based on the guidance contained in EPRI Report No. 1009325,Revision 2-A, Appendix H (Reference 20), EPRI-TR-104285 (Reference 2) and previous riskassessment submittals on this subject (References 5, 8, 18 and 19) have led to the followingresults. The results are displayed according to the eight accident classes defined in the EPRireport. Table 6-1 lists these accident classes.The analysis performed examined DAEC specific accident sequences in which the containmentremains intact or the containment is impaired. Specifically, the breakdown of the severeaccidents contributing to risk was considered in the following manner:o Core damage sequences in which the containment remains intact initially and in thelong term (EPRI TR-104285 Class 1 sequences).oCore damage sequences in which containment integrity is impaired due to randomisolation failures of plant components other than those associated with Type B or Type Ctest components. For example, liner breach or bellows leakage. (EPRI TR-104285 Class 3sequences).*Core damage sequences in which containment integrity is impaired due to containmentisolation failures of pathways left "opened" following a plant post-maintenance test.(For example, a valve failing to close following a valve stroke test. (EPRI TR-104285 Class6 sequences). Consistent with the NEI Guidance, this class is not specifically examined*since it will not significantly influence the results of this analysis.*Accident sequences involving containment bypassed (EPRI TR-104285 Class 8sequences), large containment isolation failures (EPRI TR-104285 Class 2 sequences),and small containment isolation "failure-to-seal" events (EPRI TR-104285 Class 4, and 5sequences) are accounted for in this evaluation as part of the baseline risk profile.However, they are not affected by the ILRT frequency Change.*Class 4 and 5 sequences are impacted by changes in Type B and C test intervals;therefore, changes in the Type A test interval do not impact these sequences......... .... T. able 6-1: .Acciden~t Classes" " .........A ccid e ~t C la sses .... ......."........".... : .. ... .... ...1 No Containment Failure2 Large Isolation Failures (Failure to Close)3a Small Isolation Failures. (Liner Breach)3b Large Isolation Failures (Liner Breach)4 Small Isolation Failures (Failure to Seal-Type B)Page 32 of 57
........... ...... ....... ............ Table 6-1: Accident ClassesAccident Classes ..... ...(Containment De scriptionReleae Type)5 Small Isolation Failures (Failure to Seal-Type C)6 Other Isolation Failures (e~g., Dependent Failures)7 Failures Induced by Phenomena (Early and Late)8 Bypass (Interfacing System LOCA)CDF All CET End states (including Very Low and No Release)The steps taken to perform this risk assessment evaluation are as follows:Step 1 -cQuantify the base-line risk in terms of frequency per reactor year for each of the eightaccident classes presented in Table 6-1.Step 2 -Develop plant specific person-remn dose (population dose) per reactor year for each ofthe eight accident classes.Step 3 -Evaluate risk impact of extending Type A test interval from three to fifteen and ten tofifteen years.Step 4 -Determine the change in risk in terms of Large Early Release Frequency (LERF) inaccordance with RG 1.174.Step 5 -Determine the impact on the Conditional Containment Failure Probability (CCFP).6.1 Step 1- Quantify the Base-Line Risk in Terms of Frequency Per Reactor YearAs previously described, the extension of the Type A interval does not influence those accidentprogressions that involve large containment isolation failures, Type B or Type C testing, orcontainment failure induced by severe accident phenomena.For the assessment of ILRT impacts on the risk profile, the potential for pre-existing leaks isincluded in the model. (These events are represented by the Class 3 sequences in EPRITR-104285). The question on containment integrity was modified to include the probability of aliner breach or bellows failure (due to excessive leakage) at the time of core damage. Twofailure modes were considered for the Class 3 sequences. These are Class 3a (small breach) andClass 3b (large breach).The frequencies for the severe accident classes defined in Table 6-1 were developed for DAECby first determining the frequencies for Classes 1, 2, 7 and 8 using the categorized sequencesand the identified correlations shown in Table 5-5, determining the frequencies for Classes 3aand 3b, and then determining the remaining frequency for Class 1. Furthermore, adjustmentsPage 33 of 57 were made to the Class 3b. and hence Class 1 frequencies to account for the impact ofundetected corrosion per the methodology described in Section 5.4.For DAEC, the total frequency of the categorized sequences is 4.24E-06/yr,.the same as totalCDF, Table 6-2 and Table 6-3 summarize the results.Table 6-2:..DAEC Categorized Aclcident Classes and Frequl~encies .. ....la..ssan Arnold Release Category (p'er 1 Intact containment (INTACT) 2.08E-072 Containment Isolation failures 1.26E-087 Containment Failure due to Severe Accident Phenomena 8 Containment Bypass (Associated ,with ISLOCA CD 18E08 Scenarios) 18E0Class 1 Sequences: This group consists of all core damage accident progression bins for which.the containment remains intact (modeled as Technical Specification Leakage). The frequencyper year is initially determined from the Containment Intact Level 2 Release Category listed inTable 5-6 minus the EPRI Class 3a and 3b frequency, which are calculated below.Class 2 Seqiuences: This group consists of all core damage accident progression bins for which afailure to isolate the containment occurs. The frequency per year for these sequences isobtained from the Large Containment Isolation Failures Level 2 Release Category listed in Table5-5.Class 3 Sequences: This group consists of all core damage accident progression bins for which apre-existing leakage in the containment structure (e.g., containment liner) exists. Thecontainment leakage for these sequences can be either small (in excess of design allowable but<lOLa) or large (>1OOLa).T:he respective frequencies per year are determined as follows:PROBciass__BaPROBciass_Bb=probability of small pre-existing containment liner leakage=0.0092 [see Section 5.3]=probability of large pre-existing containment liner leakage= 0.0023 [see Section 5.31As described in Section 5.3, additional consideration is made to not apply these failureprobabilities on those cases that are already LERF scenarios (i.e., the Class 2 and Class 8contributions).Page 34 of 57 Cl ass 3a Frequency= 0.0092 * (CDF -DAEC-L2-H-E-RELEASE)= 0.0092 * (4.24E-06 -1.46E-06) =2.56E-08/yrClass 3b Frequency =0.0023 * (CDF -DAEC-L2-H-E-RELEASE)=0.0023 * (4.24E-06 -1.46E-06) =6.39-09/yrFor this analysis, the associated containment leakage for Class 3a is lOLa and for Class 3b islOOLa. These assignments are consistent with the guidance provided in EPRI ReportNo. 1009325, Revision 2-A (Reference 20).Note, in the above equations for the Class 3a and 3b release frequencies, the total adjustedrelease frequency from the appropriate columns of Table 5-5 has been substituted for CDF. Asdiscussed previously this process marginally over-estimates the Class 3 releases.Class 4 Seqiuences: This group consists of all core damage accident progression bins for whichcontainment isolation failure-to-seal .of Type B test components occurs. Because these failuresare detected by Type B tests which are unaffected by the Type A ILRT, this group is notevaluated any further in the analysis.Class 5 Seqiuences: This group consists of all core damage accident progression bins for whichcontainment isolation failure-to-seal of Type C test components occurs. Because the failures aredetected by Type C tests which are unaffected by the Type A ILRT, and their frequency is verylow compared with the other classes, this group is not evaluated any further in this analysis.The frequency for Class 5 sequences is subsumed into Class 7, where it contributesinsignificantly. Therefore, changes in the frequency of Type C tests do not affect theconclusions of this analysis.Class 6 Sequences: This group is similar to Class 2. These are sequences that involve coredamage accident progression bins for which a failure-to-seal containment leakage due to failureto isolate the containment occurs. These sequences are dominated by misalignment ofcontainment isolation valves following a test/maintenance evolution, typically resulting in afailure to close smaller containment isolation valves. All other failure modes are bounded bythe Class 2 assumptions. Consistent with guidance provided in EPRI Report No. 1009325,.Revision 2-A, this accident class is not explicitly considered since it has a negligible impact onthe results.Class 7 Sequences: This group consists of all core damage accident progression bins in whichcontainment failure induced by severe accident phenomena occurs (e.g., overpressure). For thisanalysis, the frequency is determined from Severe Accident Phenomena-Induced FailuresRelease Category from the DAEC Level 2 results shown in Table 5-5.Class 8 Sequences: This group consists of all core damage accident progression bins in whichcontainment bypass occurs. For this analysis, the frequency is determined from theContainment Bypass Release Category from the DAEC Level 2 results shown in Table 5-1Page 35 of 57 6.1.1 Summary of Accident Class FrequenciesIn summary, the accident sequence frequencies that can lead to radionuclide release to thepublic have been derived consistent with the definitions of accident classes defined in EPRI-TR-104285 the NEI Interim Guidance, and guidance provided in EPRI Report No. 1009325, Revision2-A. Table 6-3 summarizes these accident frequencies by accident class for DAEC.Page 36 of 57 Table 6-3.: Radionuclide Release Frequencies as a Function of Accid~ent Class (iBase "Case)}1 No Containment Failure 2.08E-07 2.08E-072 Large Isolation Failures (Failure to Close) 1.26E-08 /[.26E-083a Small Isolation Failures (liner breach) 2.56E-08 2.56E-083b Large Isolation Failures (liner breach) 6.39E-09 6.42E-09Small Isolation Failures (Failure to seal- N/A N/AType B)Small Isolation Failures (Failure to seal- N/A N/AType C)___ ___Other Isolation Failures (e.g., dependent N/A N/A6failures)_ _ _ _F~ailures Induced by Phenomena (Early 3.97E-06 3.97E-06and Late)8 Bypass (Interfacing System LOCA) 1.89E-08 1.89E-08CDF All CET end states 4.24E-06 4.24E-06Notes:(1). Note that this is based on data developed in Section 5.4. Only Class 3b is impacted by the corrosion.6.2 Step 2 -Develop Plant Specific Person-Remn Dose (Population Dose) Per Reactor YearPlant specific release analyses were performed to estimate the person-remn doses to thepopulation within a 50 mile radius from the plant. The releases are based on informationprovided by NUREG/CR-4551 with adjustments made for the site demographic differencescompared to the reference plant as described in Section 5.2, and summarized in Table 5-4. Theresults of applying these releases to the EPRI containmentfailure classification are as follows:Class 1 =3,45E+03 Class 2 = 5.19E+05 person-remn(2)Class 3a =3.45E+03 person-remn x lOLa =3.45E+04 person-rem (3)Class 3b = 3.45E+03 person-remn x lOOLa = 3.45E+i05 person-remn (3)Class 4 = Not analyzedClass 5 = Not analyzedPage 37 of 57 Class 6 = Not analyzedCiass 7 =3.67E+05 person-rem (4)Class 8 = 5.19E+05 person-rem (5)Notes:(1) The derivation is described in Section 5.2 for DAEC. Class 1 is assigned the dose from the "no containmentfailure" APBs from NUREG/CR-4551 (i.e., APB #8).(2) The Class 2, containment isolation failures, dose is assigned from APB #*3 (Early CF).(3) The Class 3a and 3b dose are related to the Class 1 leakage, rate as shown. While no pre-existing leakage inexcess of 21 La has been identified for any historical ILRT event, Class 3b releases are conservatively assessedat lOOLa. Class 3a releases are conservatively assessed at lOLa. This is consistent with the guidance providedin EPRI Report No. 1009325, Revision 2-A.(4) The Class 7 population dlose and frequency are developed as follows:*Class :7 FrequJency Weighted Populat~ion DoseClass 7a 1.43E-06 3 5.19E+05 7.41E-01Class 7b 6.78E-07 6 3.98E+05 2.70E-01Class 7c 1.27E-06 1 3.04E+05 3.86E-01Class 7d 2.60E-07 2 1.90E+05 4.95 E-02Class 7e 3.35E-07 9 3.58E+04 1.20E-02Total 3.97E-06 N/A N/A 1.46E+O0DAEC Frequency weightedpopulation dose (person-remn)3.67E+05(5) Class 8 sequences involve containment bypass failures; as a result, the person-remn dose is riot based onnormal containment leakage. The releases for this class are assigned from APB #5 (Bypass).In summary, the population dose estimates derived for use in the risk evaluation per the EPRImethodology (Reference 2) containment failure classifications, and consistent with the NEIguidance (Reference 1) as modified by EPRI Report No. 1009325, Revision 2-A are provided inTable 6-4.Page 38 of 57 Table:6-4: "DAE:C Popu:[lation Dose iEstimiates fOr: PopuLlation Within 50 MJles,A ccideni:t ...... ........"': 'Classes.. ...--. Person-Remn1 No Containment Failure 3.45E+032 Large Isolation Failures (Failure to Close) 5.19E+053a Small isolation Failures (liner breach) 3.45E+043b Large Isolation Failures (liner breach) 3.45E+054 Small Isolation Failures (Failure to seal-Type B) N/A5 Small Isolation Failures (Failure to seal-Type C) .N/AOther Isolation Failures (e.g., dependent N/A6 failures)7 Failures Induced by Phenomena (Early and Late) 3.67E+058 Bypass (Interfacing System LOCA) 5.19E+05The above dose estimates, when combined with the results presented in Table 6-3, yield theDAEC baseline mean consequence measures for each accident class. These results arepresented in Table 6-5.Page 39 of 57 Table 6-5: !D u ane A rnold- Ann ual lD ose as; a Fu.nction :of !Accident ;Cha racteristi c of Conditi ons: for;;ILRT Required 3/10/ !!;; ;:;: : ;Y eairs ;:i ! ;Accident.... ......-.:.- .> .... ...< EPRI ..... ; ....:.:!EPRI .iM ethodologyi... Chane.DuNo Containment 3.45E+03 2.08E-07 7.18E-04 2.08E-07 7.:18E-04 -8.54E-081Failure (2)Large Isolation 5.19E+05 1.26E-08 6.54E-03 1.26E-08 6.54E-03 0.00E+002 Failures (Failure toClose)Small Isolation 3.45E+04 2.56E-08 8.83E-04 2.56E-08 8.83E-04 0.00E+003a Failures (liner breach)"3b Large Isolation 3.45E+05 6.39E-09 2.21E-03 6.42E-09 2;22E-03 8.54E-06Failures (liner breach) _____Small Isolation N/A N/A N/A N/A N/A N/A4Failures (Failure toseal -Type B)Small Isolation N/A N/A .N/A .. N/A N/A N/A5Failures (Failure toseal-Type C)________Other Isolation N/A. N/A N/A N/A N/A N/A6Failures (e~g.,dependent failures) _______________________Failures Induced by 3.67E+05 3.97E-06~ 1.46E+00 3.97E-06 1.46E+00 0.00E+007 Phenomena (Early 'andLate)-_______________________Page 40 of 57 Table 6-5: .Duane Arnold Dose as a Function of Accident:Class; Characteristic of Conditions for.lLRT.Required 3/10Accident ... ..::.... .. ..=. ....EPRI .... EPRlI Methodology Chn e" ula s s ..ethodology ..::.....:i: :;..:..:.::.!!:Plus ...to.Corrosion(ctmt ..i: D:!-i:iii: ion ii~~iii~... Rii em !.::Person-. ... ..:......,: ..:Person- ..Releasei .reuecy Re/y FeuecyRe/y .Ren:Bypass (Interfacing 5.:19E+05 l1.89E-08 9.80E-O3 l1.89 E-08 9.80E-03 O.OOE+OO_________System LOCA)_____________CDF All CET end states N/A ] 4.24E-06 :1.48E+OO.] 4.24E-06 1.48E+00 8.45E-06Notes:(:1) Only release Classes l and 3b are affected by the corrosion analysis.(2)'Characterized as i1La release magnitude consistent with the derivation of the ILRT-non-detection failure probability for ILRTs. ReleaseClasses 3a and 3b include failures of containment to meet the Technical Specification leak rate.Page 4:1 of 57 6.3 Step 3 -Evaluate Risl Impact of Extending Type A Test Interval From 10 to 15YearsThe next step is to evaluate the risk impact of extending the test interval from itscurrent ten year value to fifteen years. To do this, an evaluation must first be made ofthe risk associated with the ten year interval since the base case applies to a three yearinterval (i.e., a simplified representation of a three in ten interval).6.3.1 Risk impact Due to 10-year Test IntervalAs previously stated, Type A tests impact only Class 3 sequences. For Class 3 sequences,the release magnitude is not impacted by the change in test interval (a small or largebreach remains the same, even though the probability of not detecting the breachincreases). Thus, only the frequency of Class 3a and 3b sequences is directly impacted.As it is assumed that the new Class 3 endstates arise from previously intact containmentstates, the intact state frequency is reduced accordingly. The. risk contribution ischanged based on the NE! guidance as described in Section 5.3 by a factor of 3.33compared to the base case values. The results of the calculation for a ten year intervalare presented in Table 6-6.6.:3.2 Risk Impact Due to 15-Year Test IntervalThe risk contribution for a fifteen year interval is calculated in a manner similar to theten year interval. The difference is in the increase in probability of leakage in Classes 3aand 3b. For this case, the value used in the analysis is a factor of 5.0 compared to thethree year interval value, as described in Section 5.3. The results for this calculation arepresented in Table 6-7.Page 42 of 57 Table 6-6: -Duane Arnold Annual ;Dose as~a-Function of Accident Class;-Characteristic of Conditions for il:RT .Required 1l/10 :YearsAccident ..... ...... -. ..EPRi MVethodology. -Classes.Person ...EPRI MB/ethiodology:. ,. .... .:::., .... P .u Corrosion...... :.... :Change'Due(Cnm t: Description... '., Rem (50.. ;:.<...Person-.. ...:.. =....;.......:.:.:... .. Person-... .::-No Containment 3.45E+03 1.34E-07 4.61E-04 1.33E-07 4.61E-04 -2.84E-071 Failure (2)Large Isolation 5.19E+05 1.26E-08 6.54E-03 1.26E-08 6.54E-03 0.00E+002 Failures (Failure toClose)Small Isolation 3.45E+04 8.52E-08 2.94E-03 8.52E-08 2.94E-03 0.O0E+003a Failures (linerbreach)Large Isolation 3.45E+i05 2.13E-08 7.35E-03 2.14E-08 7.38E-03 2.84E-053b Failures (linerbreach) ________Small Isolation N/A N/A N/A' N/A N/A N/A4 Failures(Failure toseal-Type B)Small Isolation N/A N/A N/A N/A N/A N/AS Failures (Failure to__________seal-Type C)Other Isolation N/A N/A N/A N/A N/A N/A6 Failures (e.g.,dependent failures) _ _ _ _ _ _ _ _ _ _ ______ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _Page 43 of 57 Table :6-6: .Duane :Arnold Annual Dose~as .a Function of. Accident.,Ciass;.Characteristic of Conditions. for.ILRT:Requlired-1/10 YearsCA ssiest ' Person-:::" ... M etho'dolo y ..............::EP~lus ....... .-:--ChangeDue(cnmt.. i.-.:Descriptioni.::.;::!;:. i(5Oi! Person- .. Pesn ..... :-,to Corrosion:;iFrequency... ... :....P ron ...... .... R.. Frequency ..... Peser. ..so".n-.Failures Induced by 3.67E+05 3.97E-06 1.46E+00 3.97E-06 1.46E+00 O.OOE+O07 Phenomena (Earlyand Late)8 Bypass (Interfacing 5.19E+05 1.89E-08 9.80E-03 1.89E-08 9.80E-03 0.00E+008 System LOCA)CDF All GET end states N/A 4.24E-06 :[.49E+00O 4.24E-06 1.49E+00 2.82E-05Notes:(1) Only release Classes :1 and 3b are affected by the corrosion analysis. In these cases, the corrosion analysis causes more cases that werepreviously Class 1 (containment intact) to become Class 3b (large isolation failures (liner breach). This lowers the frequency of Class 1 andraises the frequency of Class 3b.(2) Characterized as iLa release magnitude consistent with the derivation of the ILRT non-detection failure probability for ILRTs. ReleaseClasses 3a and 3b include failures of containment to meet the Technical Specification leak rate.Page 44 of 57 Table 6-7: .Duane!Arnold 'Annua[:Dose~as a jFunction of Accident Class; :Characteristic of..Conditions for :Required 1/15 YearsAccident .Classes..i(Cnmt.::!:iD es cript Person-Rem (50miles)EPRI Methodology;EPRI !Meth odology Plus ... .....Frequency(per Rx-yr);:-.:..P erso n-:::..I::!ii(50 Frequency(per Rx-yr)Person-Rem/yr(50 miles)*i!......C ha ng e :!D ue 3i iNo Containment 3.45E+03 8.02E-08 2.77E-04 8.00E-08 2.76E-04 -4.27E-07Failure (2)Large Isolation 5.19E+05 1.26E-08 6.54E-03 1.26E-08 6.54E-03 O.OOE+O0Failures (Failureto Close)Small Isolation 3.45E+04 1.28E-07 4.41E-03 1.28E-07 4.41 E-03 O.OOE+OOFailures (linerbreach)Large Isolation 3.45E+05 3.20E-08 1.10E-02 3.21E-08 1.11E-02 4.27E-05Failures (linerbreach)_______ _________ _______ ___Small Isolation N/A N/A N/A N/A N/A N/AFailures (Failureto seal-Type B)Small Isolation N/A N/A N/A N/A N/A N/AFailures (Failureto seal-Type C) ________________Other Isolation N/A N/A N/A N/A N/A N/AFailures (e.g.,dependentfailures)_______ __________________________________________ ____Page 45 of 57 Table 6-7: .:Duane Arnod Dose as a Function of Accident Class; Characteristic of Conditions ifor. ILRT Required !1/15 YearsAccident,. ....RIMthdloy.. ER Mtodl.-Pus .Chne uClss s.. .. ..Prs n..... __ __ __ __ _. .Co ro io. .. ... .:; :i:i. -:LOrro iOn(Cnm t es'criptionfii..i! R~i~iem (50 Person.-.. t........... ..o.er o -.Corrosion.......... ........:...-Pe s n......... i:.:... z :. .... .Release.;. (prR-y (erR-r)RI1/ Rm/r1Failures Induced 3.67E+05 3.97E-06 1.46E+00 3.97E-06 1.46E+00. 0.00E+007 by Phenomena(Early and Late)Bypass 5.19E+05 1,89E-08 9.80E-03 1.89E-08 9.80E-03 0.00E+008 (InterfacingSystem LOCA)AllCE ed /A 4.4E06 $.9E00 4.4E061.49E+00 4.23E-05CDF AlGTedNA42E0 .9+O 42E0states ___________________Notes:(1) Only release Classes 1 and 3b are affected by the corrosion analysis., .In these cases, the corrosion analysis causes more cases that werepreviously Class 1 (containment intact) to become Class 3b (large isolation failures (liner breach). This lowers the frequency of Class :1 and raisesthe frequency of Class 3b.(2) Characterized as iLa release magnitude consistent with the derivation of the ILRT non-detection failure probability for ILRTs. Release Classes3a and 3b include failures of containment to meet the Technical Specification leak rate.Page 46 of 57 6.4 Step 4 -Determine the Change in Risk in Terms of LERFThe risk increase associated with extending the ILRT interval involves the potential that a core damageevent that normally would result in only a small radioactive release from an intact containment couldin fact result in a larger release due to the increase in probability of failure tO detect a pre-existing leak.With strict adherence to the EPRI guidance, 100% of the Class 3b contribution would be consideredLERF.Regulatory Guide 1.174 provides guidance for determining the risk impact of plant specific changes tothe licensing basis. RG 1.174 defines very small changes in risk as resulting in increases of core damagefrequency (CDF) below lOI6/yr and increases in LERF below lO-7/yr, and small changes in LERF as belowlO-6/yr. The DAEC PRA does not credit containment overpressure, so loss of overpressure due to anundetected leak does not affect CDF. Because the ILRT does not impact CDF, the relevant metric isLERF.For DAEC, 100% of the frequency of Class 3b sequences can be used as a very conservative first-orderestimate to approximate the potential increase in LERF from the ILRT interval extension (consistentwith the EPRI guidance methodology). Based on a ten year test interval from Table 6-6, the Class 3bfrequency (conservatively including corrosion) is 2.14E-O8/yr; and, based on a fifteen year test intervalfrom Table 6-7, it is 3.21E-OS/yr. Thus, the increase in the overall probability of LERF due to Class 3bsequences that is due to increasing the ILRT test interval from three in ten years to one in fifteen yearsfor DAEC is 2.57E-O8/yr as shown in Table 6-8. Similarly, the increase due to increasing the intervalfrom 10 to 15 years is 1.07 E-OS/yr.As can be seen, even with the conservatisms included in the evaluation (per the EPRI methodology),the estimated change in LERF for DAEC is below the threshold criteria for a very small change whencomparing both the fifteen year results to the current ten year requirement, and the fifteen yearresults compared to the original three year requirement. See Table 6F8 for more information.6.5 Step 5 -Determine the Impact on the Conditional Containment Failure Probability (CCFP)Another parameter that the NRC guidance in RG 1.174 states can provide inp~ut into the decision-making process is the change in the .conditional containment failure probability (CCFP). The change inCCFP is indicative of the effect of the ILRT on all radionuclide releases, not just LERF. The CCFP can becalculated from the results of this analysis. One of the difficult aspects of this calculation is providing adefinition of the "~failed containment." In this assessment, the CCFP is defined such that containmentfailure includes all radionuclide release end states other than the intact state. The conditional part ofthe definition is conditional given a severe accident (i.e., core damage).The change in CCFP can be calculated by using the method specified in the EPRI Report No. 1009325,Revision 2-A. The NRC has previously accepted similar calculations (Reference 9) as the basis forshowing that the propoJsed change is consistent with the defense-in-depth philosophy. The list belowshows the CCFP values that result from the assessment for the various testing intervals includingcorrosion effects. Note that the numbers used are rounded to the second decimal place.CCFP = [1 -(Class 1 frequency + Class 3a frequency) / CDF]
* 100%Page 47 of 57 CCFPS [1 -(2.08E-07/yr + 2.56E-08/yr) / 4.24E-06/yr]
* 100% = 94.50%CCFP3 = 94.50%CCFPlo = [1-~ (1.33E-07/yr + 8.52E-08/yr) / 4.24E-06/yr]
* 100% =94.85%CCFP1o = 94.85%CCFPls [1 -(8.00E-08/yr + 1.28E-07/yr) / 4.24E-06/yr]
* 100% =95.10%CCFP1s= 95.10%ACCFP1s_3 = CCFP1s- CCFP3 = 0.61%ACCFP151lo = CCFP1s -CCFP1o = 0.25%ACCFP1o-3= CCFP1o -CCFP3 = 0.35%The change in CCFP of approximately 0.61% by extending the test interval to fifteen years from theoriginal three in ten year requirement is judged to be very small (i.e., less than 1.5% per the EPRIsubmittal guidance).6.6 Summary of ResultsThe results from this ILRT extension risk assessment for DAEC are summarized in Table 6-8.Page 48 of 57 Table 6-8: Duane Arnold IIRT Cases: Base, 3 to 10, and 3 to 15 Yr Extensions (Including Age* : : ......A djusted ...Ste~el Liner .Corrosio.n. Li&#xa3;e!ih.o..od)., .... ..........:,..,,.:.........-......;. .. ...... 3 in .l0Y ears .. .. .... n..0.Years... ... l.:1in 15 Years ...EPR I D O SE : : .... .... : =' , , ;........ ..... Class Per-Rem
* Per- ..." Per- Per-... ...CDF/Yr Rem/Yr CD)F/Y'r Rem/Yr CDF/yr: Rem/Yr'.::1 3.45E+03 2.08E-07 7.18E-04 1.33E-07 4.61E-04 8.00E-08 2,76E-042 5.19E+05 1.26E-08 6.54E-03 1.26E-08 6.54E-03 1.26E-08 6.54E-033a 3.45E+04 2.56E-08 8.83E-04 8.52.E-08 2.94E-03 1.28E-07 4.41E-033b 3.45E+05 6.42E-09 2.22E-03 2.14E-08 7.38E-03 3.21E-08 1.11E-027 3.67E+05 3.97E-06 1.46E+O0 3.97E-06 1.46E+OO 3.97E-06 1.46E+008 5.19E+05 1.89E-08 9.80E-03 1.89E-08 9.80E-03 1.89E-08 9.80E-03Total N/A 4.24E-06 1.48E+00 4.24E-06 1.49E+00 4.24E-06 l.49E+O0ILRT Dose Rate from3aad3 e-e/r 3.10E-03 1.03 E-02 1.55 E-02Dta From 3 yr N/A 6.96E-03 :I.20E-02TotalDoseRate (1) From 10 yr N/A N/A 49E0change From 3 yr N/A 0.47%0.1in dose ________ratefrom From 10 yr N/A N/A 0.34%base3b Frequency (LERF) 6.42E-09 2.14E-08 3.21E-08Per-Rem/Yr_____________________Delta From 3 yr N/A 1.50E-08 2.57E-08LERF From 1:0 yr N/A N/A 1.07E-08CCFP % 94.50% 94.85% 95.10%Delta From 3 yrCCFP % From 10 yrN/A0.35%0.61%N/AN/A0.25%Notes:(1) The overall difference in total dose rate is less than the difference of only the 3a and 3b categoriesbetween two testing intervals. This is because the overall total dose rate includes contributions fromother categories that do not change as a function of time, e.g., the EPRI Class 2 and 8 categories, and alsodue to the fact that the Class 1 person-rem/yr decreases when extending the ILRT frequency.Page 49 of 57 7 Sensitivities7.1 Sensitivity to Corrosion Impact AssumptionsThe DAEC results in Table 6-5 through Table 6-8 show that including corrosion effects calculated usingthe assumptions described in Section 5.4 does not significantly affect the results of the ILRT extensionrisk assessment.Sensitivity cases were developed to gain an understanding of the sensitivity of the results to the keyparameters in the corrosion risk analysis= The time for the flaw likelihood to doubie was adjusted fromevery five years to every two and every ten years. The failure probabilities for the upper containmentand the basemat were increasedi and decreased by an order of magnitude. The total detection failurelikelihood was adjusted from 10% to 215% and 5%. The results are presented in Table 7-1. In every casethe impact from including the corrosion effects is very minimal. Even the upper bound estimates withvery conservative assumptions for all of the key parameters yield increases in LERE due to corrosion ofonly 2.47E-12/yr. The results indicate that even with very conservative assumptions, the conclusionsfrom the base analysis would not change..... ....iTable .7-1: ......Siteel P~late iCo rroision Senrsitiviy ..A.ge. .."... th.Se inth Non-Visual FlawsExeso3to1corroion corrosion analysis) er prR-rnayi) analysis) .. #tali Incre "iiase Due..... ... .... ..... ... Incr~ease .to CorrosionBaeBase Case Base CaseCaseDoubles (1% Upper .(10% Upper2.7-8 90E1Containment, 0.1% Containment,25E-8 99E1every 5 Basemat) 100% Basemat)yrsDoublesevery 2 Base Base 2.58E-08 1.7SF-IDyrs _______Doublesevery 10 Base Base 2.5 6E-08 2.86E-11yrs __________ _Base Base 15% 2.57E-08 1.38E-1OBase Base 5% 2.56E-08 5.95E-1110% UpperBase Containment, 1% Base 2.66E-08 9.90E-10Basemat0.1% UpperBase Containment, Base 2.56E-08 9.90E-120.01% Basemat____________Lower BoundPage 50 of 57 Doubles 0.1% Upper 5%UprCnametevery 10 Containment, 5 UpeCotimn, 2.56E-08 1.71E-15yrs 0.01% Basemat 1 aeaUpper Bound_______ _____Doubes 0% Uper 15% Upper Containment,every 2 Containment, 1% 100% Basemat 2.56E-08 2.47E-12yrs Basemat7.2 Sensitivity to Class 3B Contribution to LERFThe Class 3b frequency for the base case of a three in ten year ILRT interval including corrosion is*6.42E-O9/yr (Table 6-5). Extending the interval to one in ten years results in a frequency of 2.14E-O8/yr(Table 6-6). Extending it to one in fifteen years results in a frequency of 3.21E-08/yr (Table 6-7), whichis an increase of 2.57E-08/yr from three in ten years to once in fifteen years.If 100% of the Class 3b sequences are assumed to have potential releases large enough for LERF, thenthe increase in LERF for DAEC due to extending the interval from three in ten to one in fifteen is belowthe RG 1.174 threshold for very small changes in LERF of 1.OOE-07/yr.7.3 Potential Impact from External EventsThe DAEC has systematically considered risk posed by the following external hazards: seismicity, fire(historically considered an external hazard although the analysis focuses on fires originating within theplant), external flood, high winds and tornadoes, transportation and nearby facility hazards, and otherplant-unique hazards. These analyses are summarized in the DAEC individual Plant Examination forExternal Events (IPEEE) (Reference 24) submittal and supporting documentation. Additionally, DAEChas performed a comprehensive fire PRA update in accordance with more current methodologicalguidance in support of its transition to the risk-informed fire protection program, National FireProtection AssociatiOn (NFPA) 805 (Reference 31).Seismic AssessmentDAEC performed a Seismic Margins Assessment (SMA) in support of their IPEEE submittal(Reference 24) using the guidance of EPRI NP-6041 (Reference 32). While this analysis did not identifyany credible seismic sequences exceeding the reportability criteria of the IPEEE program, a number ofinsights were identified that led to plant modifications to reduce seismic risk. For example, onemasonry wall was identified as a potential outlier that could fall and damage seismic safe shutdownequipment, and this wall was subsequently qualified for Safe Shutdown Earthquake (SSE) loading.Elements of the control room ceiling were modified to improve integrity during an earthquake. Inaddition, unanchored gas storage bottles were identified near safe shutdown equipment, andmodifications were made to properly secure the bottles.While the SMA methodology used for the IPEEE does not estimate seismic CDF, in 2008 the DAECassessment of Severe Accident Mitigation Alternatives (SAMA) developed a seismic CDF estimate of6.99E 07/yr. This value had been relatively stable over five revisions to the PRA model and is used forthe current ILRT assessment.Page 51 of 57 Fire AssessmentIn the early 1990's DAEC performed a fire risk analysis in support of their IPEEE submittal(Reference 24) using the Electric Power Research Institute's Fire-Induced Vulnerability Evaluation(FIVE) methodology (Reference 33). This study identified the two essential 4kV switchgear rooms asthe dominant contributors to station fire risk, andl several controls were proposed to mitigate this risk,primarily involving configuration risk management of maintenance on the River Water System. FireCDF for the remaining plant areas was assessed to be below the reportability criteria of the IPEEEprogram and not pose a significant safety concern.More recently, DAEC completed a comprehensive fire~ PRA update in support of transition to therisk-informed fire protection program NFPA 805 (Reference 31). This upd~ate primarily applied theguidance of NUREG/CR-6850, was independently peer reviewed against ASME/ANS RA-Sa-2009, andwas extensively reviewed and judged by the NRC to be of acceptable scope and quality for the NFPA805 risk-informed application. Details of. the NRC review can be found in the DAEC NFPA 805 SER datedSeptember 10, 2013 (Reference 34) and its supporting references.The most current DAEC fire PRA quantification notebook (Reference 35), inclusive of the NFPA 805implementation items, reports a total fire CDF and LERF estimations of 1.20E-Q5/yr and 7.49E-06/yr,respectively. Note these values are lower than those identified in the NFPA 805 SER (Reference 34),and these reductions reflect refinements implemented during NFPA 805 implementation. Consistentwith the IPEEE insights, .fires in essential switchgear rooms, where fire can also fail offsite power, arethe dominant contributors to plant fire riskr.External The DAEC IPEEE (Reference 24) effort reviewed the plant design basis and confirmed that it meets the1975 Standard Review Plant (SRP) criteria related to external flooding. Based on this conformance,DAEC judged the external flood contribution to core damage frequency to be negligible, and thereforeexternal flooding risk is excluded numerically from this ILRT assessment.High Winds AssessmentThe DAEC IPEEE (Reference 24) included a conservative bounding evaluation of high winds andtornados, estimating a total wind-induced CDF of 1.41E-07/yr. The IPEEE submittal (Reference 24)f~urther judged that a more realistic approach would show this CDF contribution to be approximately anorder of magnitude lower. The analysis did rnot identify any significant vulnerabilities and concludedthat high winds present an insignificant contribution to plant risk..Transportation and Nearby Facility HazardsThe DAEC IPEEE (Reference 24) reviewed hazards involving marine, railroad, and. truck accidents andconcluded that they do not represent a significant contribution to plant risk, and this conclusion wasbased primarily on separation distance between the plant and these hazards.Page 52 of 57 The risk of aviation hazard associated with two nearby federal airways was assessed and determined tobe less than the IPEEE reportability criteria.Nearby facility hazards and hazardous material storage were reviewed and no accident could bepostulated that would impact safe operation of the plant.The storage of a propane* tank near the emergency diesel generator rooms was identified andevaluated. Large barriers were placed around the tank to reduce its associated core damage frequency(Reference 24).For this ILRT assessment, 1.OOE-06 is conservatively used as the transportation and nearby facilityhazard CDF. LERF impacts are judged to be negligible.Other Plant-Uniaue HazardsAn exhaustive list of other potential plant-unique hazards was evaluated using a formal screeningprocess. No other plant-unique events were identified as potentially significant contributors to plantrisk.External Events Total CDF. Total LERF, and ALERF for ILRT ApplicationTable 7-2 summarizes the conservative Duane Arnold external hazard CDF estimates used for the ILRTapplication.*Table 7-2: Con~servative Hazard~c CD1Fi ajid *::Seismicity 6.99E-07 <6.99E-07Fire 1.20E-05 7.49E-06External Flood negligible negligibleHigh Winds 1.41E-07 <1.41E-07Transportation and Nearby 1OO06 ngiblFacilities .__1.00E-0__ negligible__Other Plant-Unique insignificant insignificantTotal 1,38E-05 <8.33E-06An alternate estimate of the seismic and wind hazard LERF can be made assuming the ratio CDF toLERF for these hazards is similar to the ratio for internal events. The internal events CDF is 4.24E-O6/yr(per Section 5.2.1), and the internal events LERF is 1.46E-06 (per high early release frequency specifiedin Table 5-1). The internal event ratio of CDF to LERF is:CDFIE / LERFIE = 4.24E-06 / 1.46E-06 =2.90The total external events LERF is therefore .approximated as:Page 53 of 57 LERFEE-ajternate. (CDFseis/ 2.90) + (CDFwInd/ 2.90) + (LERFfire)-(6.99E-07 / 2.90) + (1.41E-07 / 2.90) + (7.49E-06)-7.78E-O6/yrExternal events LERF attributed specifically to non-detected containment failures is conservativelyestimated as follows, using the probabilities of a non-detected containment failure (PNDCF) described inSection 5.3:LERFNDcF -- * (CD FEE -LERFEE)Where, P NDCF,3/l0 0.0023PNDCF, 1Ilo =0.0023
* 3.33PNDcF, 1/15 0.0023
* 5.00CDFEE = 1.38E-O5/yrLERFEE-alternate = 7.78 E-O6/yr[Note CDFEE and LERFEE are the core damage and large early release frequencies,respectively, associated with external hazard sequences only]Note in the above equation, LERF is subtracted from CDF, such that the portion of CDF sequences thatalso progress to LERF (for example by containment isolation failures or severe accident processes thatare independent of a degraded containment condition undiscovered due to ILRT extension) areexcluded from the calculation. For conservatism, the lower estimated value of total LERF is used in thisequation, which is used in Table 7-3 to calculate ALERF, to maximize the frequency of non-LERF coredamage sequences in this ILRT evaluation. And also conservatively, the higher LERF estimate is usedwhen assessing total plant LERF.Table 7-3 summarizes the External Events LERF and ALERF values attributed specifically to non-detected containment failures. Reported ALERF values are relative to the 3 per 10 year surveillanceinterval.':iii:iTable "7-3: E~ixternal Events .LE RF. andI!:':..:3 per 10 years 1.39E-08-1 per 10 years 4164E-08 3.25 E-081 per 15 years 6.97E-08 5.58E-08Assessment against RG 1.174 ALERF and Total LERF Acceptance GuidelinesThe total Duane Arnold plant LERF across all hazards, based on the frequency of Internal Events LERFfrom Table 5-1 and the frequency of External Events LERF from Table 7-2, is calculated as follows:= LERFIE (per high early release frequency specified in Table 5-1i)+ LERFEE (Table 7-2)= 1.46E-06 + 8.33E-06 = 9.79E-O6/yrPage 54 of 57 The ALERF for the 1/10 and 1/15 ILRT intervals, relative to the base 3/10 interval, are as follows:ALERF111o = ALERFIE,1/10 (Table 6-8) + ALERFEE,l/lo= 1.50E-8 + 3.25E-08 =4.74E-OS/yrALERF111s = ALERFIE,l/lS (Table 6-8) + ALERFEE,/1/5 = 2.57E-08 + 5.58E-08 = 8.14E-O8/yrALERF for both the 1/10 and 1/15 ILRT intervals falls within RG 1.174 Region Ill .(Reference 4), whereALERF is less than 1.0E-O7/yr. Proposed changes in this region are acceptable provided total LERF is lessthan 1.0E-O4/yr. The Duane Arnold total LERF 9.79E-06/yr, and therefore the proposed 1/10 and 1/15ILRT intervals satisfy RG 1.174 Region Ill (Reference 4).Page 55 of 57 8 ConclusionsBased on the results from Section 6 and the sensitivity calculations presented in Section 7, the.following conclusions regarding the assessment of the plant risk associated with extending the Type AILRT test frequency to once in fifteen years is as follows:Regulatory Guide 1.174 (Reference 4) provides guidance for determining the risk impact ofplant specific changes to the licensing basis. Regulatory Guide 1.174 defines very small changesin risk as resulting in increases of CDF below 10-6/yr and increases in LERF below 10-7/yr. Sincethe ILRT does not impact CDF, the relevant criterion is LERF. The increase in LERF resulting froma change in the Type A ILRT test interval from three in ten years to one in fifteen years isconservatively estimated as 2.57E-0S/yr for DAEC. As such, the estimated change in LERF forDAEC is determined to be "very small" using the acceptance guidelines of RG 1.174 (Reference4).Regulatory Guide 1.174 also states that when the calculated increase in LERF is in the range ofl.OOE-07 per reactor year to 1.O0E-06 per reactor year, applications will be considered only if itcan be reasonably shown that the total LERF is less than 1.O0E-05 per reactor year. Anadditional assessment of the impact from External Events was also made. In this case, the totalLERF including External Events was conservatively estimated as <9.79-06/yr for Duane Arnold.This is below the RG 1.174 acceptance criteria for total LERF of 1.00E-O5/yr and therefore thischange satisfies both the incremental and absolute expectations with regard to the RG 1.174LERF metric.*The change in Type A test frequency to once per fifteen years, measured as an increase to thetotal integrated plant risk for those accident sequences influenced by Type A testing, is 1.55E-02 person-rem/yr for Duane Arnold. EPRI Report No. 1009325, Revision 2-A states that a verysmall population dose is defined as an increase of 1.0 person-rem per year or <1 % of the totalpopulation dose, whichever is less restrictive for the risk impact assessment of the extendedILRT intervals. This is consistent with the NRC Final Safety Evaluation for NEl 94-01 (Reference1) and EPRI Report No. 1009325 (Reference 20). Moreover, the risk impact when compared toother severe accident risks is negligible.*The increase in the conditional containment failure probability from the three in ten yearinterval to a permanent one time in fifteen year interval is 0.61% for Duane Arnold. EPRI ReportNo. 1009325, Revision 2-A states that increases in CCFP of 1.5 percentage points are verysmall. This is consistent with the NRC Final Safety Evaluation for NEI 94-01 (Reference 1) andEPRI Report No. 1009325 (Reference 20). DAEC proves to be below 1.5 percentage points andthus is considered to be very small.Therefore, permanently increasing the ILRT interval to fifteen years is considered to be a very smallchange to the DAEC risk profile.8.1 Previous AssessmentsThe NRC in NUREG-1493 (Reference 6) has previously concluded that:Page 56 of 57
*Reducing the frequency of Type A tests (ILRTs) from three per ten years to one per twenty yearswas found to lead to an imp~erceptible increase in risk. The estimated increase in risk is verysmall because ILRTs identify only a few potential containment leakage paths that cannot beidentified by Type B and C testing, and the leaks that have been found by Type A tests havebeen only marginally above existing requirements.*Given the insensitivity of risk to containment leakage rate and the small fraction of leakagepaths detected solely by Type A testing, increasing the interval between integrated leakage ratetests is possible with minimal impact on-public risk. Beyond testing the performance ofcontainment penetrations, ILRTs also test the integrity of the containment structure.The findings for DAEC confirm these general findings on a plant specific basis considering the severeaccidents evaluated for DAEC, the DAEC containment failure modes, and the local populationsurrounding DAEC.Page 57 of 57 ATTACHMENT 5 to NG-15-0234NEXTERA ENERGY DUANE ARNOLD, LLCDUANE ARNOLD ENERGY CENTERLICENSE AMENDMENT REQUEST (TSCR-1 43)EXTEND CONTAINMENT LEAKAGE TEST FREQUENCYDOCUMENTATION OF PROBABILISTIC RISK ASSESSMENT TECHNICAL ADEQUACY2 pages follow PRA QualityThe DAEC internal Events PRA includes both Level 1 and Level 2 models for internal initiatingevents. The model is maintained and upgraded in accordance with DAEC PRA maintenanceand update procedures. The model routinely incorporates plant design changes, procedurechanges, plant operating data, current industry PRA methods, review comments, and generalimprovements identified by the NRC. The PRA has undergone a variety of assessments of itstechnical capability, as summarized in the following paragraphs.DAEC was the first non-pilot plant to have a PRA Peer Evaluation (Reference 1) in 1997. ThePRA certification process used a team of experienced PRA and system analysts to provide bothan objective review of the PSA technical elements and a subjective assessment based on theirPRA experience regarding the acceptability of the PRA elements.During 2005 and 2006, the DAEC PRA model results were evaluated in the BWR OwnersGroup (BWROG) PRA cross-comparisons study performed in support of implementation of themitigating systems performance indicator (MSPI) process.Following issuance of the ASME PRA Standard and its endorsement by the NRC in RG 1.200Rev. 1 (Reference 4), DAEC performed a detailed self-assessment (Reference 2) of the DAECPRA model and documentation in preparation for the BWROG PRA Peer review in the fall of2007. This review was performed using the NEI recommended self-assessment process asendorsed by the NRC in RG 1.200, Rev. I (Reference 4).In December 2007 a peer review was held at the NextEra Energy offices in Juno Beach, FL,under the auspices of the BWROG, using the NEI 05-04 PRA Peer Review process and theASME PRA Standard ASME RA-Sb--2005 (Reference 2) (along with the NRC clarificationsprovided in Regulatory Guide 1.200, Rev. 1 (Reference 4).). The 2007 DAEC PRA Peer Reviewwas a full-scope review of all the Technical Elements of the internal evtents, at-power PRA. TheBWROG peer review final report was issued in May 2008 (Reference 6).A gap analysis for the DAEC PRA 5C model was completed in December 2007 with the finalreport being issued in May 2008. The 2007 DAEC PRA Peer Review was a full scope review ofall the technical elements of the internal events, at-power PRA. This gap analysis wasperformed against PRA Standard RA-Sb-2005 (Reference 3) and associated NRC comments inRegulatory Guide 1.200, Rev. 1 (Reference 4). The gap analysis identified 83 supportingrequirements for which potential gaps to Capability Category II existed. The PRA model wasrevised to address identified gaps.In March 2011, a focused PRA Peer Review assessed all previous 2007 full scope peer reviewfindings and observations, including the adequacy or their dispositions. This focused Scopereview was primarily performed to assess the internal events PRA model adequacy' in support ofthe fire PRA and NFPA 805 transition. The review identified 4 supporting requirements as 'NotMets and 3 as meeting Capability Category I (CC I) with a total of 12 findings. Letters NG-1 1-0299 (Reference 8) documents resolution of 5 of these findings, and NG-11-0135 (Reference 5)Page 1 of 2 documents evaluation and conclusion that the remaining 7 issues negligibly affect the RITS 5bapplication, and these dispositions also apply to the current ILRT application.In conclusion, the DAEC PRA is judged sufficient for the ILRT interval risk-informed applicationin accordance with Regulatory Guide 1.200, Rev. 1.References1. DAEC PSA Peer Review Certification Report, BWROG/PSA-9701, March 1997.2. Self-Assessment of the DAEC PRA against the ASME PRA Standard Requirements,November 2007.3. American Society of Mechanical Engineers, Standard for Probabilistic Risk Assessment forNuclear Power Plant Applications, (ASME RA-S-2002), Addenda RA-Sb-2005, December2005.4. Regulatory Guide 1.200, An Approach for Determining the Technical Adequacy ofProbabilistic Risk Assessment Results for Risk Informed Activities, Revision 1, January2007.5. Letter NG-1 1-01 35 from DAEC to USNRC, "Clarification of Information Contained in LicenseAmendment Request (TSCR-1 20): Application for Technical Specification ChangeRegarding Risk-Informed Justification for the Relocation of Specific Surveillance FrequencyRequirements to a Licensee Controlled Program (TSTF-425, Rev. 3)", dated April 20, 2011.Page 2 of 2}}

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