ML072780351

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Oyster Creek September 2007 Evidentiary Hearing - Applicant Exhibit 41, Amergen'S Oyster Creek Generating Station ACRS Full Committee Presentation
ML072780351
Person / Time
Site: Oyster Creek
Issue date: 02/01/2007
From:
AmerGen Energy Co
To:
Office of Nuclear Reactor Regulation, NRC/SECY
SECY RAS
References
50-219-LR, AmerGen-Applicant-41, FOIA/PA-2009-0070, RAS 14255
Download: ML072780351 (45)
v • d • e


Text

RA5 ILIR,5115-APPLICANT'S EXHIBIT 41 Iw DOCKETED USNRC Art Exelon Coi-n pa October 1, 2007 (10:45am)

OFFICE OF SECRETARY RULEMAKINGS AND ADJUDICATIONS STAFF Oyster Creek License Renewal Presentation to ACRS U.S. NUCLEM$ pEOULATORy COMMISSION

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Agenda LI.,

e Summary of Drywell Corrosion e Resolution of Drywell Shell Corrosion Issues from January 18, 2007 Subcommittee Meeting

Al ExeLi P1ol dI AmerGen Representatives

" Mike Gallagher

" Fred Polaski

" John O'Rourke

" Dr. Hardayal Mehta

" Dr. Clarence Miller

  • Ahmed Ouaou 3

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DRYWELL AND REACTOR CAVITY SECTION DETAIL "A" 5

AnerGen IOP IkLAIh PRO )TECTIVE WLING SHIE LEAKAUE PATH STAINLESS STEEL LINER DRYWELL TO REACTOR CAVITY SEAL DETAIL GUSSET DETAIL B REFUELING BELLOWS D RYWELL GAS8FT i

FIRMR-D BOTTOM PLATE IINSULATION MITERIAL OBQNSW DAMAGE AI LIpFO I OUQ, I - DIRAIN FOR OORRECTED IN 1088 SIrC-L TflOUGH (21 DRUAIN WOM CONCRETEi THDUUH W")

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Summary of Drywell Corrosion

  • Leakage from the reactor cavity liner accumulated in the sand bed region, corroding the exterior surface of the drywell shell
  • Corrective actions

- Water has been prevented from entering the sand bed region

- The sand was removed and the exterior of the drywell shell coated with an epoxy coating

- Analysis performed to determine code required thickness of the drywell shell 8

Summary of Drywell Corrosion.' l 0 GE analysis of code required thickness (1992)

- Buckling analysis based on Code case N-284 for refueling condition with no sand in the sand bed region for a 360 section model with 736 mils uniform thickness and Safety Factor of 2.0 a 736 mils is the code required general thickness for buckling in the sand bed region

  • Local thickness criteria also established (e.g., 536 mils for a 12" x 12" area)
  • A Section Vill analysis for internal pressure was originally performed at a design pressure of 62 psig; later updated for 44 psig design pressure (1993)

- 44 psig is an Oyster Creek plant specific maximum design pressure, approved in Tech Spec amendment 165

- Analysis demonstrated increased margin for the minimum required thickness 9

Summary of Drywell Corrosion All 2006 Refueling outage monitoring results

- Low leakage from reactor cavity liner

  • Approximately 1 gpm No water in the sand bed region Epoxy coating 100% visual inspection in all bays
  • In good condition LUT grid measurements in sand bed region from inside the drywell
  • No corrosion Local UT measurements in sand bed from outside
  • The drywell shell exceeds required thickness UT grid measurements in upper elevations
  • No corrosion except 1 location shows 0.66 mils/yr 10

AmeGen, Sand Bed Region 1992 Drywell Shell Corrosion product on drywell vessel II

Gen Sand Bed Region 1992 Drywell I Shell Caulk Seal Sandbed Floor Finished floor, vessel with two top coats - caulking material applied 12

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Sand Bed Region 2006 Drywell Shell Sandbed Floor Caulk Seal DINw I v) Shel9lBy Drywell Shell Bay 19 13

Gen 2006 Measurement Locations In the Sandbed Region Color Cod* for thiolnimet Location I TyloofUT MlmualrWit Oreen -UT Measurements) 738 MIls A External Point UT Measurements Yellowm UT Measurements Betveen 636 and 736 Mils r': Internal Orid UT Measurements Red - UT Measurem ents Beteen 536 and 636 MIlo 0 Internal Point UT Measurements A

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C Minimum Available General Thickn ess Margins Bay No. 1 3 5 7 9 11 13 15 17 19 Minimum Available 365 439 432 397 256 84 101 306 74 64 Margin, mils 15

.AmerGen Figure 21 Sandbed Bay # 19A 1154 Mil Nominal Shell Plate Thickness 12N) i

~-15 5 Mits/yr l+y- 8,4 mils +/-9.9 mils +I-9,6 mils

"- /- 8,9 mile Margin = 64 Mils 736 Mil General Required Shell Thickness NX I i "s i l..g 6=

Drain Lines I 10-Strippable Coating p.-

Cleaned Complete Sand Added to Rx Cavity DhivIs hol?

Star Sand Removal and apply Relmoval Epoxy Coating

  • Strippable Coating Strippable

= Added to Rx Cavity Aet CatCoattng-Ue

Not Used Iday 1 006 KWP1611 Source: Raw Date - Am ergen Calculation C-1302-187-5300-021, C-1 302-187-5300-028, C-1 302-187-8610-030 16

erGen an Figure 1. Sandbed Bay# ID 120o 1154 Mil Nominal Shell Plate Thickness S+1- 13.6 mils 10 mils .4 mils 8/-

U+1-1000 Margin - 385 MiIs 736 Mul General Required Shell Thickness--___,,

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( .. Strippable Coating Complete Sand Added to Rx Cavity Drain Lines Removal and apply Cleaned Epoxy Coating i 1 Haib Yl Start Sand Removal S Coating Strippable I N IiW1*,i' Added to Rx Cavity 0" a in i I Bay~

Gt wpp 1 coable **otnn "-1=I01.

8@our*:~ Raw Data Arsve Cml Olutlmtion Col 302=18?:5300=02i, C~i 302*i 8?=5l300028, Co' 1*02=l87=8810O*

17

Drywell Shell Current Condition Afi [xelon Nominal Minimum Minimum Minimum DrywellMeasured Required Available Region Thickness, General General Thickness mils Thickness, Thickness, Margin, mils mils mils Cylindrical 640 604 452 152 Knuckle 2,625 2,530 2260 270 Upper 722 676 518 158 Sphere Middle Sphere 770 678 541 137 Sphere Lower Spher 1154 1160 629 531 Sphere Sand Bed 1104 800 736 64 18

Commitment Summary

  • UT thickness measurements in various areas of sand bed and upper drywell regions 0 Strippable coating will be applied to the reactor cavity liner every refuel outage 0 Leakage monitoring of cavity trough drain and sand bed drains 0 Visual inspection of sand bed region shell epoxy coating 0 Visual inspection of seal at junction between drywell shell and sand bed region floor
  • Visual inspections and UT measurements of the drywell shell in the trench areas 0 Visual inspection of moisture barrier inside drywell at junction between shell and floor/curb 19

Overall Conclusions 0 The corrective actions to mitigate drywell shell corrosion have been effective

  • The drywell shell corrosion has been arrested in the sand bed region and continues to be very low in the upper drywell elevations 0 The corrosion on the embedded portion of the drywell shell is not significant 0 The drywell shell meets code safety margins 0 We have an effective aging management program to ensure continued safe operation 20

Drywell Shell Corrosion Issues from January 18, 2007 Subcommittee Meeting

1. Capacity Reduction Factor
2. Buckling Analysis
3. Reactor Cavity Liner Leakage
4. Future Monitoring Programs
5. Interior Surface of the Embedded Drywell Shell 21

Capacity Reduction Factor Subcommittee Issue # 1:

The GE analysis and Sandia analysis are different. A key difference isthat the GE analysis increased the capacity reduction factor for the refueling load combination case when there isno internal pressure present. Isthis acceptable?

Response

The increased capacity reduction factor used inthe GE analysis isacceptable.

22

Capacity Reduction Factor ________

Conclusions 4n[Xdoi 0 The GE analysis in 1992 increased the capacity reduction factor from 0.207 to 0.326 to account for orthogonal tensile stresses in a sphere 0 Buckling tests conducted on spheres show a reduction in the effect of imperfections on the buckling strength 0 The application of an increased capacity reduction factor to the Sandia analysis produces results similar to the GE analysis 0 AmerGen's conclusion is that the GE analysis, including a minimum uniform thickness in the sand bed region of 736 mils, is valid 23

Buckling Analysis Details Buckling Analysis followed the methodology outlined in ASME Code Case N-284 Allowable Compressive Stress = il acO1elFS n = Plasticity Reduction Factor al = Capacity Reduction Factor al= Theoretical Elastic Buckling Stress FS = Factor of Safety (2.0 for refueling condition and 1.67 for post-accident condition)

  • Capacity Reduction Factor, a, was increased to account for the effect of a coexisting orthogonal tensile stress

- The increase was based upon tests conducted on cylinders

- Tests conducted on spherical segments concluded that the modified a, based on cylinder test results is conservative 24

Modified Capacity Reduction Factor 0 ASME Code Case N-284 allows modifying the capacity reduction factor to account for the effect of orthogonal tensile stress on buckling strength.

- The effect of orthogonal tensile stress due to internal pressure is well documented for cylinders.

  • The N-284 capacity reduction factor is modified using formulas developed by C. D. Miller. The formulas are based on tests conducted on cylinders.

0 Tests conducted on spheres, without internal pressure, show that the coexistence of orthogonal tensile stress reduces the effect of imperfections on the buckling strength of spheres

- Orthogonal tensile stresses are a result of in-plane tension or compression loads, 0 The modified capacity reduction factor is now used in ASME Code Case 2286-1 for spheres.

0 The following figure shows that the modified formula is conservative for spheres.

25

en, Capacity Reduction Factor for Spheres 0,9 0.8 Odland (EQ2)

(From Sphere Tests Assume e/t = 1 8) 0.7 0.7 ., .. (no Internal pressure was used in sphere test) 0.6 Yao Lx 1 0 U., 0.5 LN2 Oý 2 0 LU't 0.4 Miller (Eq, 1) AP (From Cylinder Tests) 00.2 .2..... Also Eq 8-6o m of ASME CC2286-1

&0o- 0.207 1713.1.2(b) 0.1 0

-3 -2.5 -2 -1.5 -1 -0.5 0 0.5 I 26

'p Impact of Modified Capacity Reduction Factor .

on Buckling Stress Parameter Sandia without Sandia with Modified 0 Modified a, As analyzed Thickness 0,842 0,842 Theoretical Elastic Instability Stress, ksi 46.49 46.49 Capacity Reduction Factor 0.207 0,207 Circumferential Stress (Orthogonal tensile stress), ksi 2,5*

Equivalent Pressure, psi 10.02 "X" Parameter 0,042 AC 0.039 Modified Capacity Factor 0.272 Elastic Buckling Stress, ksi 12.65 Proportional Limit Ratio 0.253 0.333 Plasticity Reduction Factor 1.0 1,0 Inelastic Buckling Stress, ksi 9.62 12,65 Code Required Factor of Safety, FS 2,0 2.0 Allowasle Compressive Stress, ksi 4.81 6.33 Applied Compressive Stress, ksi 4,47 4,47 Calculated Safety Factor 2.15 2.83 Assumed average orthogonal tensile stress based on 8 ksi orthogonal tensile stress given in Sandia Report Table 3-2, 27

rOen Impact of Modified Capacity Reduction Factor on the Effective Factor of Safety with Uniform Sand Bed Thickness Note: Re-drawn from Sandia Report SAND2007-0055 page 79 (Red Curve) 5 Sandia Analysis based on modified capacity 4.5 reduction factor 4

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3.5 1993 GE Analysis 3 0.736" Thickness Sandia Analysis based on 0

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2.5 Safety Factor of 2.0 SO capacity reduction factor of 0.207 2 v 15 0.6 0.7 0.8 0.9 1 1.1 1.2 Sand Bed Thickness, in.

28

NRC Issued SER for Drywell --

Analysis - April 24, 1992

  • Numerous exchanges of technical information between Licensee, GE, Code Case Expert and NRC in early 1990s 0 In its SER, the Staff discussed the methodology Oyster Creek used to perform buckling analysis and specifically addressed the use of a modified capacity reduction factor 0 Brookhaven National Laboratory supported the NRC Staff in performance of this review 0 The Staff concluded that the drywell meets ASME Section III Subsection NE requirements 29

Capacity Reduction Factor ________

Conclusions Am ,

nn 0 The GE analysis in 1992 increased the capacity reduction factor from 0.207 to 0.326 to account for orthogonal tensile stresses in a sphere 0 Buckling tests conducted on spheres show a reduction in the effect of imperfections on the buckling strength 0 The application of an increased capacity reduction factor to the Sandia analysis produces results similar to the GE analysis 0 AmerGen's conclusion is that the GE analysis, including a minimum uniform thickness in the sand bed region of 736 mils, is valid 30

Buckling Analysis Subcommittee Issue # 2:

Thickness margin may be better understood with a modern 3D finite element model where various thickness and thickness configurations in the sand bed region could be evaluated.

Response

1. Our current licensing basis analysis demonstrates that code requirements are met.
2. Use of a modern modeling technique, inputting actual shell thicknesses, should demonstrate more thickness margin.
3. AmerGen will perform a 3D finite element analysis of the Oyster Creek drywell using modern methods. This analysis will be completed prior to entering the period of extended operation.

31

Ab!

[don li~l uIompy Reactor Cavity Liner Leakage Subcommittee Issue # 3:

Leakage through the reactor cavity liner should be eliminated.

Response

AmerGen will perform an engineering study prior to the period of extended operation to investigate cost effective replacement or repair options to eliminate Reactor Cavity Liner leakage.

32

Future Monitoring Programs Subcommittee Issue # 4:

The monitoring of drywell shell thickness should be more aggressive in the short term.

Response

The next slide shows the breadth and frequency of monitoring activities associated with the drywell shell. These activities include inspections to monitor the condition of the drywell shell so that any additional corrosion would be detected before the existing margin was eliminated.

33

Summary of Drywell Monitoring Activities During Refueling Outages ýMOF@05,

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Drywell Monitoring Activities Performed Refueling Outage Date During Refueling Outages 12006 1 20081 2010 1 2012 1 2014 122016 1 2018 1 2020 ý 2022 12024 1 2026 1 2028 Verification of Elimination of Water Leakage Into Sand Bed Region i) Cavity Liner - Apply Tape & Strippabie Yea Yes Yes Yes Yes Yea Yes Yes Yeo YQu Yea Yea Coating

2) Cavity Drain - Confirm Drain Is Clear Yeo you Yea Yea Yes Yes Yea Yes Y Yea yo You Yea
3) Cavity Drain - Monitor Flow Rate Daily Daily Dally Daily Daily Dally Daily Daily Daily Daily Daily Daily
4) Sand Bod Drains - Confirm No Water Daily Daily Daily Daily Daily Daily Daily Doily IDaly Daily Daly Dally Upper Drywell Shell Monitoring
1) UT Inspection% - Upper Drywail Transition 2 Areas 2 Areas 2 Areas 2 Areas Ifcorrosion is greater than the Upper Drywall locations, UTs will be Areas Inside Drywall @ 713'- continued at same frequency as the Upper Drywall 13 Locations
2) uT Inspections - Upper Drywall 13 Locations inside Drywall @ 87'5", W0.10", 100% 100% 100% 100% 1100%% 100%

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3) UT Inspections - Drywall Transition Areas 2 Areas 2 Areas 2 Areas 2 Areas If corrosion is greater than the Upper Drywall locations, UTa will be Inside Drywall @ 23',G" continued at same frequency as the Upper Drywall 13 Locations sand BedRegion Shell Monitoring
1) UT Inspections - Sand Bed 19 Locations 100% 100% Subsequent UT Inspection frequency will be established as appropriate, not to Inside Drywall @ 11 '.3" exceed a 10-year interval
2) VT Inspection of Sand Bed External Epoxy All 10 At Least At Least 10 in At Least At Least 10 in Coating and Shell to Floor Caulk Seal BaoBay3Bays 3 Bays 10 yra 3 Bays 3 Bays 10 yrs 2 2
3) UT.Inspections-Sand Bed 108 External 10 10 Bay 1 2 Bays 2 2 2... 2 s 2 2 Locally Thinned Locations Boys _ B__Bays 13 Bays Boy....s_ Bays - Bay Boys Bays
4) VT Inspection of Drywall Shell In Trench 100% 100% 100% VT Inspections will continue each outage if trenches are not restored.

Locations Inside Drywall

5) UT Inspection of Drywall Shell in Trench 826 028 628 LT inspections will continue each outage if trench@@ are not restored, Locations Inaide Drywall . .. . .. Points .. Points . Points UTisetoswllcniu.ahouaei.rnhs.r.e.etrd
6) Inspoctlon for Water in Trenches Yes Yes Yes If water is not observed In trenches for 2 consecutive outages, trenches will be restored and no further inspections will be required, General Monitoring . .. . . . .. . . . . . .. . . .
1) Structures Monitoring -Visual Inspection of yes Yes Yes Yes Yes Yes Yes Ye Yos Yes yeu Ye Concrete Floor, Trough & Shell Inside Drywall
2) Structures Monitoring - Visual Inspection of yes yes yes yes Yea Yoo Gump ees
3) Appendix J Test - Pressure Test and Perform Teat Within Ton Years Visual Inspection of Accessible Int. and Ext, Test Test of Previous Test Shell Surfaces
4) Drywall Service Level 1 Coating Inspection Yes Yes Yes Yes Yes Yes Inside Drywall .. _
5) Structures Monitoring - Visual Inspection of Moisture Barrier between Drywall Shell and 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100%

Concrete Curb Inside Drywall 34

Interior Surface of the Embedded Drywell Shell Subcommittee Issue # 5:

The trenches in the drywell floor should not be restored to the design configuration until sufficient monitoring is completed to verify corrective actions to eliminate water on the interior drywell shell have been effective.

Background:

The water source has been identified and corrective actions have been implemented.

Corrosion of steel embedded in concrete is mitigated by the high pH of the water and by the passive, protective film on the steel surface.

35

LOWER DRYWELL-SANDBED, TRENCH & SUMP

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Interior Surface of the AMI

[be or CruLmpy Embedded Drywell shell Response to Issue # 5:

The trenches in the drywell interior floor

  • Inspect during refueling outages for water.
  • Visual/UT exams of shell within trenches.
  • After confirming in 2 consecutive refueling outages there is no water in the trenches, restore the trenches to their original design condition.

37

License Renewal Application Summary 38

Description of Oyster Creek An [xel. Con i !-lny

  • Located in Lacey Township, Ocean County, New Jersey

, Barnegat Bay is Ultimate Heat Sink

  • GE BWR 2 with Mark I Containment
  • Licensed thermal power 1930 MWth
  • Design electrical rating 650 MWe
  • Interim Spent Fuel Storage established onsite

- Internal events: 1.1 E-05/year

- LERF: 5.8E-07/year 39

Current Plant Status e Operating license expires April 9, 2009

  • Operating in 21st cycle

° Transitioned to 24 month cycles in 1991

  • Completed 21st refueling outage in November 2006
  • Regulatory Oversight Program (ROP) status 40

License Renewal Methodology

" LRA submitted July 22, 2005

" NEI 95-10 Rev. 6 Standard Format

  • AmerGen prepared a reconciliation document comparing the Oyster Creek LRA to NUREGs 1800 and 1801 Rev, 1 .

41

An IFxe:lon* Co n-ipa ny Aging Management Programs

- 18 existing

- 14 existing requiring enhancements

- 18 new (10 associated with Forked River Combustion Turbines)

  • 7 Plant specific programs

- 2 existing

- 2 existing requiring enhancements 3 new (1 associated with Forked River Combustion Turbines) 42

Commitment Management Ani x,,*,C,,Iny

  • 65 commitments are listed in Appendix A of the application.

0 A commitment tracking number has been issued for these license renewal commitments

  • An associated action containing the details was issued for each of the commitments 0 Each implementing procedure is annotated to provide linkage to and preserve the details of the commitment
  • Process controlled by the commitment management procedure 43

Status of Program Implementation

  • 257 new and 111 enhanced implementation activities identified

- 13% completed in 2006 refueling outage

-19% in 2008 refueling outage scope

- 68% to be performed on-line 44

Summary

  • Aging Management Programs are established to ensure safe operation for period of extended operation

° License renewal commitments are tracked and will be implemented as expected

  • On track for completing activities prior to entering period of extended operation 45
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