ML20198P560
| ML20198P560 | |
| Person / Time | |
|---|---|
| Site: | 05000000, Oyster Creek |
| Issue date: | 05/31/1983 |
| From: | MPR ASSOCIATES, INC. |
| To: | |
| Shared Package | |
| ML20151H203 | List:
|
| References | |
| FOIA-86-26 NUDOCS 8606060337 | |
| Download: ML20198P560 (54) | |
Text
__ _ ___
w yPR A;50CIATES. INC.
b (k6 RESPONSES TO A REQUEST FOR INFORMATION FROM THE FRANKLIN RESEARCH CENTER CONCERN!tlG THE OYSTER CREEK t!UCLEAR GENERATING STATION MARK I CONTAINMENT LONG-TERM PROGRAF 4 PLANT-UtlIOUE ANALYSIS REPORTS 3
-.y.,.
t-O......d=u.c. id./(L B J w
Prepared for:
General Public Utilities Parsippany, New Jersey May 1983 8606060337 860319 PDR FOIA PATTER 5086-26 PDR 1050 CoNNecTecut AVENut. N W.
WasNINotoN. D.C. 20036 202 659 2320 A /10 o
M'7R AccoctATE2. INC.
4 I
r TABLE OF CONTENTS 4
a
1.0 INTRODUCTION
1 2.0 RESPONSES TO REQUEST FOR INFORMATION
3.0 REFERENCES
i 1
4.0 APPENDIX A Franklin Research Center Request for Information (TER-C5506-319) i 4
I I
I I
t i
I i
1
}
1 1
l l
4 4
i 1
l i
4
- i....-......__._
1
1.0 INTRODUCTION
This document provides responses to a request for more information about the Oyster Creek Nuclear Generating Station Mark I Containment Long-Term Program Reports submitted to the U.S. Nuclear Regulatory Commission (NRC) in August 1982 (References 3.2 and 3.3).
This request was pre-pared by the Franklin Research Center as a contractor to the NRC assigned to review the plant-unique analysis reports of the Mark I Program (Reference 3.4).
A copy of the Franklin request, as transmitted to GPU Nuclear, is contained in Appendix A of this document.
O e
9 g,
l 2.0 RESPONSES TO REQUEST FOR INFORMATION J'
i This section contains the responses for each I
the Franklin requfsf for information of the 21 items included in I
t i
e i
Request:
Item 1:
Provide a summary of the analysis with regard to the vacuum breaker valves; indicate whether they are considered Class 2 components as required 6y the criteria (Reference 3.1).
Response
The vacuum breaker valves were analyzed in accordance with ASME Class 2 rules as required by NED0-24583-1 (Reference 3.1).
The stresses in the valve at the most limiting locations were computed for all required Mark I loads and load combinations.
To ensure operability, the valves were required to meet the Level 8 stress limits, also in accordance with NEDO-24583-1.
The calculated stress in the most limiting load combination [N + DBA(CO)
+ EQ(0)] was 7.3 ksi which is well below the Level B allowable of 21.0 ksi for the ASTM A216 Grade WCB material of the valve body.
Analysis of vacuum breaker performance under accident conditions is being performed by GPUN using the general methodology which GE has separately submitted to the NRC (Reference 3.6).
Based on a preliminary analysis, it appears that the Oyster Creek valves will satisfy the acceptance criteria contained in the GE reference with no modifications.
2-2 A
'i Request:
Item 2:
Provide a summary of the analysis with regard to the modified safety relief valve piping supports designated as 51, S2, S3, and SS.
Respons e;.---
Reactions were computed for SRV line supports S1, 52, S3, and S5 for all required loads and load combinations specified in the Oyster Creek Plant-Unique Analysis Report on torus attached piping (Reference 3.3).
These supports 4rc located as shown in Figure 1.
The limiting load combinations for these supports are listed in Table 2 using the nomenclature defined in Table 1.
Calculated limiting loads on these supports are greater than the original design loads.
These supports are being inspected during the current refueling outage to determine the as-built configuration. Based on this information, the connections will be rechecked to confirm that they meet the criteria, or an appropriate design modification will be made.
0 2-3 h
,m
~
-v+
- ------~-.,~-
a w. a., r..
RILIEF VALVES 24-!MCM MIM STEAM PIPE 8-15CM j
l j.
SR'#BEA 51 1
PIPE HANGER l
8.!NC N
g HANSER MSV-H4 J
ECTRC"ATIC i
RELIEF YALYE N!NED EER CVS s
)
8"IN R3GID IWi:ER 54 y
HAMCER M5v-H5 SNUBBER 53 SNUBBER 52 HINOFD 14-IN;M
'A vatt; 9 EREAGR$
IEll0WS RIGID $UPPORT 55 M 4-lhcx o
I 12-!xcx N HWER N
WATER LEYEL' IM TCRUS F EAElRATIC't TCRUS o'
RICI') SUPPORT
's PM5 HEAD TEE SUPPCRTS SLIDING SUPPORT FIGURE I ARRAfJGEMEi1T OFSOUTH HEADER SA,FETY RELIEF VALVE DISCHARGE PIPING
TABLE 1 MARK ! CONTAthw!NT Pa000AM LOADINGS STATIC LOADS Piping Deadweight s
Piping Internal Pressure P
Piping Thermal Espanston TH Main Steats Header Otsplacement Load L5N Torus Static Otsplacement Lead (Note 1)
LTS OYMMIC LOADS EQ(0)
Operating Basis Earthquake Load EQ(5)
Safe Shutdown Earthquake Load Torus Spectral Load Due to SRV - 3 Valves SAV(h0C) 06A(PS)
Torus Spectral Load Oue to Pool Swell Torus Spectral Load Due to Condensation oscillation 08A(CO)
IBA(CO)
Torus Spectral Load Oue to Pre chug Torus Spectral Load Ove to SRY (18A conditions) -
3RV(18A) 3 Valves 5AV(03A)
Torus Spectral Lead Due to SRY - 1 Valve 58A(PTCH)
Torus Spectral Load Due to Post-chug 3RY(t)
Time History Load Oue to SRV Valve Olscharge Time History Load"Due to Pool 5= ell lepact PSIMP(t)
P580(t)
Time History Load Oue to Pool 5.e11 Buttle Drag Condensation aset11ation and Pre-chug (IBA(CO)) Submerged COBO Structures Load (Note 2)
ERVBUS ERY Air Bubble Orsg Post-chug Submerged Structures Load (Note 2)
PCGB0 LOBE Torus Anchor Motion Due to CBE Torus Anchor Motion Due to 5!E L55E Torus Anchor Motion Due to Pcol Swell LTP5 Torus Anchor Motion Ove to Condensatiin Oscillation LTCO Torus Anchor Motion Due to SRV(IBA)
LTSRY Torus Anchor Kotion Due to Pre-chug LTPRE Torus Anchor Motion Due to Post-chug LTP5T NOTES:
)
- 1. Includes static displacement of ring girder and vent header penetration due to deadweight of torus snell.
2.Includesbothbubbledragandfluid-structureinteraction(ISI).
w-
}
TABLE 2 LOAD ComINATIONS FOR PIPING SUPPORT ANALYSIS LOAD CASE LOAD ComINATION I
N + TH + LSH + LTS + SRV(NOC) + EQ(S) + LTSRV + LSSE 11 N + TH + LSH + LTS + DBA(PS) + PSBD + SRV(DBA) + EQ(S) +
LTPS + LTSRY + LSSE III N + TH + LSH + LTS + DSA(CO) + COBD + EQ(0) + LTCO + LOBE lY & Y (Not evaluated since loads lower than above combinations)
S I
e
,m--e
,,-9 y
y w---
yr-wp
- u-w-
+-w w-g--
Request:
Item 3:
Provide a summary of the analysis with regard to Class 1 piping connections which connect the safety relief valve to the main steam piping in the drywell region.
Response: - - -
The connections to the main steam ' lines were analyzed using Class 2 rules in accordance with Paragraph NB-3630(d)(2) of Section III of the ASME Code (Reference 3.7), which permits Class 2 rules to be used provided certain criteria are met.
The criteria are satisfied for the SRV piping adjacent to the main steam line. Accordingly, Class 2 analysis per Subsection NC-3650 of Reference 3.7 was performed on this run of piping and the sweepolet connection.
The most limiting load combinations and stresses for these connections and the calculated results are listed below:
CALCULATED ALLOWABLC LOAD CASE STRESS (ksi)
STRESS (ksi) la [SRV + EQ (0) ]
20.8 21.0 lb [SRV + EQ (S) ]
21.8 31 5 III [0BAC0 + EQ (0) ]
32.0 42.0 V [PSTCHG + SRV + EQ (S) ]
33.5 31.5 i
As can be seen, all calculated stresses except one are within the allowable values. For Load Case V, the limits are exceeded by about 6%
which is considered within the conservatism of the piping model as oiscussed in the response to NRC Question G2.
2-4 w
g 9
g
_m
.m y
--e.
Request:
Item 4:
Provide justification for determining the load combinations indicated in Table 6.0-1 (Reference 3.2) to be the limiting load combinations.
Response: --
Table 5-1 of the Plant-Unique Analysis Application Guide (PUAAG),
Reference 3.1, identifies 27 different load combinations to be considered in the structural evaluation of Mark I Program Class MC components and internal structures.
These combinations are bounded by the six load combinations identified in Table 6.0-1 of the Oyster Creek Plant-Unique Analysis (Reference 3.2), based on the following rationale:
1.
Service Level A and Service Level B acceptance criteria are identi-cal for ASME Class MC (containment) components analyzed to the design-by-analysis rules of the ASME Code Section III, Subsection NE (Reference 3.7), which is the structural acceptance criteria for the Mark I Containment Long-Term Program.
2.
A combination of events results in a more severe stress state than any subset of the specified event combination.
That is, the margi-nal effect of adding an additional event is to make the stress more severe.
This assumption is valid because each of the events (e.g.,
IBA,SRY,EQ) considered in the PUAAG combinations is characterized primarily by a large dynamic response in the structure which varies from a positive to a negative extreme.
Lesser static loads are also present.
In the component evaluations, the dynamic responses from separate events are combined on a worst-case basis to create a maximum total dynamic response.
Because of the dominance of these dynamic effects and the conservative method of their summation, adding more events to an event combination will increase the response.
2-5
3.
The safe shutdown earthquake load, EQ(S), results in stresses more severe than the operating basis earthquake load, EQ(0).
The safe shutdown earthquake is a higher load than the operating basis earthquake.
Since the earthquake loads produce responses in both a positive and negative sense, the earthquake stresses always add to the worst-case severity of a stress state.
Therefore, considering the safe shutdown earthquake in a load combination is more severe than considering the operating basis earthquake.
4.
The safety / relief valve (SRV) discharge loads mechanistically cannot occur during DBA condensation oscillation and chugging. An SRV discharge event cannot occur because there is insufficient pressure in the primary reactor system during these phases of the DBA to produce a discharge event into the torus.
Accordingly, combination 27 in the PUAAG need not necessarily include the SRV discharge loads.
Based on these points, it is a straightforward exercise to show that all of the 27 load combinations in the PUAAG can be bounded by the six combinations identified in Table 6.0-1 of the Oyster Creek PUA.
2-6 l
Request:
Item 5:
Indicate whether each of the safety relief valve discharge lines has been analyzed as required by the criteria (Reference 3.1).
Also, provide justification for not considering all the lines.
Response
There are two safety relief valve ' discharge lines at Oyster Creek, designated the north and south headers, respectively.
The south header was analyzed for all loads and load combinations listed in the criteria.
Since the north header is almost identical in arrangement to the south header, scoping analysis were performed on the north header to confirm similar response to Mark I loads.
These analyses showed that for base excitation loads and SRV discharge loads the north header limiting stresses were less than the south header stresses.
Since the north header was found to be less limiting and only has 2 discharge valves (versus 3 in the south header) the south header was concluded to be more limiting and therefore was fully analyzed.
It should be noted that the wetwell and vent line runs and supports of both lines are mirror images of each other and thus the analysis results for the south header apply equally to the north header except the north header would have lower SRV stresses (since it has only 2 valves).
1 l
2-7
Request:
I Item 6:
With reference to Table 1 of Appendix B (see Appendix A),
indicate whether all loads have been considered in the analysis and/or provide justification if any load has been negl ected.
Response
1.
Torus Shell and Torus Support System All loads indicated in the appropriate columns of the Table were considered in the analysis of these structures.
2.
Main Vents, Vent Header, and Downcomer With' regard to the analyses of the main vents, vent header and downcomers, all of the loads indicated in the appropriate columns of the Table were used in the analysi, with the following minor exceptions:
In the evaluation of the main vents, there were no froth impingement loads used in the analyses.
This was justified because there were found to be no froth impingement loads on the vent system or on other structures which are structurally coupled with the vent system (e.g., the SRV piping), based on the load definition methodology covered in NUREG-0661 (Refer-ence 3.4).
In the evaluation of the downcomers, there were no T-quencher jet loads used in the analyses.
This was justified because there were found to be no T-quencher jet loads on the down-comers, based on the load definition methodology covered in NUREG-0661 (Reference 3.4).
The only structures which were i
2-8 hs
found to have T-quencher jet loads were the vent header support columns, and these loads had no significant effect on the downcomers.
3.
Other. Wetwell Interior Structures All loads indicated in the appropriate columns of the Table were considered in the analysis of these structures.
4.
Torus Attached Piping All loads listed in the Table were considered in the analysis of the torus attached piping systems.
For completeness, the loads from the Table applicable to torus attached piping, have been listed in the attached Table I with the specific piping system or piping component where the loading applies.
2-9 o
. - - - _. - - - _ -. ~,. _. - - - - -. - - - -
I' TABLE 1 Torus Attached P'iping Load Systems and Components (From Franklin R'eview)
Where Load Applies
- 1. Containment Pressure and Temperature All 3.4 Impact and Drag on Other Structures SRV, Demin, Spray Header 3.5 Froth Impingement SRV, Demin, Spray Header 3.6 Pool Fallback SRV, Demin, Spray Header 3.7 LOCA Jet SRV, Demin, Strainer 3.8 LOCA Bubble Drag SRV, Demin, Strainer 4.2 CO on Submerged Structures SRV, Demin, Strainer 5.2 Chug or Submerged Structures SRV, Demin, Strainer 6.1 Discharge Line Clearing SRV 6.4 Jet Loads S RV, Suction Strainer, Demin 6.5 Air Bubble Drag SRV, Suction Strainer, Demin 6.6 Thrust Loads on T-Ouencher SRV 6.7 S/RVDL Environmental Temperature SRV NOTE:
- 1. The abbreviations are as follows:
S/RVDL and quencher SRV Suction Strainer - Core spray suction strainer (3 total)
Demin Domineralizer relief valve discharge line Spray Header - Torus containment spray header 4
i 9
Request:
Item 7:
Indicate, in detail, how the vent system modal mass and stiffness terms were synthesized into the explicit torus shell model to derive the coupled torus / vent system model.
Response:.__-
The component mode synthesis method is used to develop the coupled torus / vent system model.
This method is discussed in Section 14 of the NASTRAN Theoretical Manual (Reference 3.8).
For this case, the details of the procedure are as follows.
First, an explicit 180 (1/20) beam model of the vent system is con-structed with a pinned-fixed boundary condition at the base of the vent header support columns.
The general attributes of this model are discussed in Section 5.2 of the PUA report (Reference 3.2).
Mode shapes, frequencies, and modal support reactions of the vent system are then calculated with this model.
Since the vent header columns transfer only axial force between the vent system and torus, and the columns lie in the symmetry plane of the torus metered joint for the 90 (1/40) torus model, it is possible to treat the vent system characteristics as a substructure to the torus model, by using one-half of the vent system modal properties in the coupled model.
Although the vent system will contain non-synnetric modes with respect to the miter, the vent header support columns will ' transfer only vertical or symnetric forces between the two systems.
Specifically, the vent system modal mass, modal stiffness, and modal 0
support reaction terms from the 18 (1/20) beam model are divided by two to create 135 generalized vent system degrees-of-freedom.
These degrees-of-freedom are added to the torus physical model coupled through the vent system support attachment points.
With this model, 2-10
hydrostatically distributed dynamic pressure loads on the torus shell produce a generalized displacement response for each of the generalized vent system modes which can be expanded to create a total response in the physical ve,nt system modes.
The accuracy of this method has been verified by comparing the displace-ments of several vent system degrees-of-freedom for a hydrostatically distributed static pressure on the torus shell calculated with this method to the results obtained for the same load using compatibility equations obtained from uncoupled torus and uncoupled vent system static model s.
2-11 m
e Request:
Item 8:
Provide a sumary of the analysis with regard to the torus for safety relief valve loads on the ring girders.
Response
This analysis will be documented in a supplemental report of the Oyster Creek Park I Containment Long-Term' Program Plant-Unique Analysis to be provided shortly.
2-12
Request:
Item 9:
Provide a summary of the buckling analysis of the torus.
Response
The torus Ts~ analyzed for buckling by evaluating the structure in accordance with the rules of ASME Code Section III, Subsection NE paragraph NE-3133 (Reference 3.2).
Two separate evaluations were performed. Maximum compressive circumferential membrane stress was evaluated to the rules of paragraph NE-3133.3 for cylinders under external pressure. Also, maximum axial compressive membrane stress was evaluated to the rules of paragraph NE-3133.6 for cylinders under axial compression.
The allowable compressive circumferential membrane stress was calculated for the lower half of a typical 180 (1/20) segment of the shell considering the mid-bay saddle as a stiffening ring per the rules of paragraph NE-3133.5 of the Code.
The lower half of the shell was judged to be limiting since the significant compressive membrane stresses occur in this area.
The effect of the shell hoop straps in reducing shell circumferential membrane stress was also considered.
The allowable axial compressive stress was calculated without consideration of the straps since they do not augment the shell axial load capacity.
The resulting allowable compressive circumferential membrane stresses between straps are -13.9 ksi for service limit A/B and -16.7 ksi for service limit C.
The allowable axial compressive stresses are -3.8 ksi for service limit A/B and -4.6 ksi for service limit C.
Limiting compressive membrane stresses were calculated for the Mark I Program load combinations in the following way.
2-13
_ _. = -.... -... - -..
0 1.
Using the coupled finite element model of a 9 (1/40) segment of the torus described in Section 5.0 of the PUA report (Reference 3.2), shell elements most likely to have the largest compressive membrane stresses were identified by Jtxamining the static deadweight of water load case.
2.
Combined compressive membrane stresses were determined for j
these selected shell elements from static and dynamic analyses with this coupled model. Minimum torus uniform internal pressures were assumed for these load combinations since this pressure produces tensile membrane stresses which tend to reduce the combined results.
For each dynamic load except Pool Swell and SRY, the maximum compressive membrane stresses were conservatively assumed to be equal to the maximum membrane stress intensities.
For Pool Swell and SRV, the maximum membrane stress com'ponents were used directly from the time of maximum membrane stress intensity.
The limiting compressive circumferential membrane stresses were calculated to be -11.2 ksi for service limit A/B and -12.1 ksi for service limit C. The limiting axial compressive stresses were calculated to be -1.8 ksi for service limit A/B and -2.1 ksi for service limit C.
The limiting load combinations were the Pool Swell load combinations 18 and 25 (Reference 3.1) for service limits A/B and C, respectively.
Accordingly, the torus meets the Mark I Containment Long-Term Program buckling acceptance criteria.
2-14 y-----.
Request:
0 Item 10: Provide and justify the reasons for not considering a 180 segment of the torus including columns, saddles, seismic restraints, and sway braces in order to determine the effects of seismic and other nonsymmetric loads. Confirm whether the everall behavior has been considered for calculating the fundamental frequency of 19 Hz given in Section 4.6.2.1 (Reference 3.2)
Response
The effects of seismic and other nonsymmetric loads were calculated accounting for the overall response of the torus with all its supports and braces.
This was accomplished using a hand calculation of a single degree of freedom model of the torus to determine the lateral natural frequency of the torus and the reactions at all supports and braces.
The reactions to the nonsymmetric dynamic loads were calculated using equivalent static analysis methods which conservatively accounted for dynamic amplification effects.
The dynamic amplification multipliers for the nonsymmetric loads were calculated as follows:
1.
Chugging loads - The nonsymmetric prechugging shell load was conservatively assumed to be sinusoidal and coincident with the fundamental structural resonance; the dynamic amplification multiplier was calculated on this basis.
The multiplier would be considerably smaller if a realistic time history analysic were performed.
2.
Seismic loads - The seismic analyses were performed using the methods employed in the original plant design; this is in conformance with the analysis guidelines of the Mark I long-Term Progran.
The seismic ground motion specified for Oyster Creek was applied to the torus lateral natural frequency to 2-15
determine the dynamic amplification multiplier.
To be conservative, the torus natural frequency was calculated assuming all the torus water moves with the structure.
Actually, only a fraction of the water moves laterally with 1he structure; therefore, the natural frequency would really be higher and the dynamic response to the seismic ground motion would really be lower.
3.
Safety relief (SRV) loads - The nonsymmetric SRV shell load was conservatively assumed to have a dominant bubble frequency which exactly coincides with the torus structural lateral resonance frequency; the dynamic amplification multiplier was calculated on this basis.
The reactions at torus supports and braces were calculated using these dynamic amplification multipliers.
These reactions were then applied to j
the detailed finite element model of the torus in the form of forces on supports and braces and "g" loads on the torus and water.
In this manner, stresses in the shell and torus connections due to the lateral component of nonsymmetric loads were obtained.
In addition, the pressure distribution on the shell in the torus bay with the highest pressures was applied to the finite element model of the torus for each of these load cases and the stresses from this " symmetrical" load were added to the stresses from the nonsymmetrical load.
The 19 Hz natural frequency referred to in Section 4.6.2.1 of Reference 3.2 is the natural frequency which responds the most to the oscillating SRV pressure load on the lower half of the torus.
This frequency was i
not used for the evaluation of the nonsymmetric SRV loads.
As noted above, the response of the torus due to the lateral effect of the nonsymmetric SRV load was calculated assuming that the SRV dominant bubble frequency coincides exactly with the torus structural lateral resonance frequency.
2-16 e-e r
--n.
e
--~,-
In sumary, the approach used to account for lateral loads due to nonsymetric loads used conservative methods and the resulting stresses were calculated in detail using the finite element model of the torus.
66 l
l i
i l
1 i
2-17
I s'
l b
0 reasons for not considering a 180 t
ten in order to determine the effec s
~ ~'
Asymmetric loads.
nonsymmetric loads were determined
'~
00 of this which considered the full 36 f the the major structural elements o del, along with appropriate stiffnesses der the drywell and where the vent hea Drus.
l and the synchronous chugging net latera
- loads evaluated for the vent system.
valuated as static equivalent loads.
ig the model solution was obtained us n l
ent sary to construct a computer finite e em The solution nt of the vent system.
forces ation model included the reaction d
Rons along the vent line, vent header, an The reaction based on " worst bay" results.
in the downcomer/ vent header intersections d vent rle static model of the downcomer an d finite were then applied to the detaile s
system to calculate the resulting stresse.
l 2-18
y wtth regard to the nozzles
^
ifety relief valve piptng-of the fatigue psis the results Oyster 3 supplemental report of the is to be Egram Plant-Unique Analys 2-19 j
Request:
Item 13:
Indicate how the gussets at the vent line/drywell intersection were modeled in order to account for their meridional stiff-nesses in the axisymmetric model.
Response:-
Special features were incorporated into the gusset elements of the axi-symetric model of the vent line/drywell intersection, to account for the gussets not being a true axisymmetric structure.
In the meridional direction, a very low value of modulus of elasticity (1.0 psi) was used, to simulate the virtually zero stiffness of the gussets in this direc-tion.
The value of 1.0 psi was arbitrarily chosen as a small percentage 6
of the true modulus of the material (about 28x10 psi).
i 2-20
}
Request:
Item 14:
Indicate how the closed form solution was used to calculate the response spectra for the steady-state condensation oscil-lation and chugging loads, and indicate the reference used.
Response
The condensation oscillation (CO) and the chugging loads were defined in the torus analysis by harmonic components (gain and phase) in the freq-uency domain.
These loads are periodic at 1 second and persist from 30 seconds up to 15 minutes depending on the specific transient under eval-uation. The response of the torus to these loads will reach a steady-state in these time frames.
The response spectra calculated for these loads should be one that reflects the steady-state response. Applica-i tion of traditional time integration methods for calculation of response spectra for steady-state periodic time histories can produce errors in the spectrum, if special care is not given to selection of the duration over which the time history is integrated (particularly for systems with low damping) and the time step selected.
In addition, the transient characteristic inherent to the time integration methodology can produce errors in steady-state response spectrum.
Since, however, the C0 and chugging loads and the responses to these loads are defined in terms of harmonic components, and the response of a single degree of freedom (SDOF) oscillator in the frequency domain is well known, Fourier 1
analysis techniques can be used to obtain directly the steady-state response spectrum.
The procedure used is as follows:
1.
The complex frequency response function for the SDOF oscillator tuned to each frequency at which the response spectrum is to be computed (and using the appropriate damping factor) is multiplied by each of the complex harmonic components of the load.
2-21
2.
The resulting response components are then summed as a Fourier series to produce a relative response time history.
The peak response in this time history is then recorded for each SDOF frequency.
Thus, the relative response spectrum is produced.
3.
To obtain the absolute response spectrum, the input time history is summed with each SDOF relative response time history and then the peak response is recorded for each SD0F frequency.
This absolute response spectrum was used in the analyses of torus attachments.
This procedure is bound on the principles describes in a number of texts on the theory of vibration, such as " Theory of Vibration With Applica-tions", William T. Thomson, Prentice-Hall, Inc.,1972.
2-22
Request:
Item G1:
Indicate whether condensation oscillation or chugging loads had been used in the limiting load combinations for load cases 14, 15, 20 and 27 in Table 6.0-1 (Reference 3.3).
Response
For each of load cases 14,15, 20 and 27 in Table 6.0-1, separate parametric combinations considering first the condensation oscillation loads and then the chugging loads were prepared.
The parametric combination which resulted in the worst stress was then used as the final result for that combination. For cases 20 and 27 involving the DBA, the condensation oscillation combination usually was the worst case. For cases 14 and 15 involving SBA/IBA, no such general statement can be made.
2-23 4
.r.-
,.-.y..--
---.,r-rm%....m r*--,
-v-
Request:
Item G2:
Provide more specific information on the conservatism used as the basis for accepting the overstresses at various locations in the torus, the vent system, and the piping systems.
Response
1.
Torus and Support System No overstresses were found in these structures.
2.
Yent System With regard to the vent system, there was one location, the vent line/ vent header intersection, where the calculated stresses slightly excee 'ed the allowable values.
The maximum amount by which the allowable values were ' exceeded was seven percent.
However, the conservatisms in the analytical approach are sufficient to offset this small amount by which the calculated stresses exceed the allowable values.
The conservative features of the analysis are described below:
Vent system responses to dynamic loads from diverse sources (e.g., LOCA, SRV, earthquake) were combined in a worst-case manner in the analyses.
That is, the individual responses to these loads were combined with a time phasing relationship which resulted in the most severe stress (i.e., absolute sum of each stress).
No other combination of the responses could result in an actual stress which exceeded the calculated values.
Since there are an infinite number of ways that the dynamic responses could combine, it would be reasonable to accept the stress associated with a certain probability of non-exceedance as representing a realistic worst-case stress.
Generic studies performed by the Mark I Program have 2-24
shown that SRSS summation of these independent dynamic loads is justified and this approach has been proposed to the NRC.
Use of SRSS summation would significantly reduce the limiting Str. esses.
Maximum stress intensities in the vent line/ vent header intersection due to internal pressure and due to beam load effects were added absolutely in the analyses.
This approach was necessitated by the form of the unit stress analysis results which were obtained as a part of the Mark I Program generic effort.
This approach is conservative because in effect it assumes that the maximum stresses due to pressure and due to beam loads occur in the same location, and that the principal stresses associated with these two sources are similarly oriented such that a direct addition is appropriate.
This conservatism was evaluated by applying the stress analysis method used for Oyster Creek to another plant for which explicit finite element results were also available.
It was found that the method substantially overpredicted actual stress intensity when both internal pressure and beam reaction loads were present.
Both of the sources of conservatisms described above are applicable to each load case for which the calculated stresses exceeded the allowable values.
3.
Torus Attached Piping Table 2 lists all locations where the criteria are exceeded in the torus attached piping.
The exceedance varies from 1% on the j
containment spray piping to the maximum exceedance of 9.5% on the SRV discharge piping.
The principal conservatisms in the Oyster Creek piping analysis which justify that this is acceptable include the following:
2-25 1
All dynamic responses were combined with an absolute sum, rather than an SRSS combination method. The NRC has recently accepted that independent Mark I dynamic loads (i.e., CO, SRV, EQ) can be summed SRSS.
Using this method would significantly reduce the calculated response for many systems.
All response spectrum dynamic loads were peak-broadened t10%.
Some systems have multiple response peaks and the broadened spectrum significantly increases the response on these systems.
Scoping analyses of a typical piping system showed that the response spectrum method used provides significantly higher pipe stress results (30" or more) than time history analyses.
2-26 yr m-r w,
,y w
b-wm
s TABLE 2 NRC Report Section Piping System Location Exception 6.3 Containment Spray Mid-span of torus Stress for load a nj..J e s,t Return containnent spray Case II exceeds Piping header (*ocation B the 36,000 psi in Figure 6.3-1) allowable stress by less than 14.
6.5 Core Spray suc' tion Header-nozzle tee Stress for load Header (Location D in Case II exceeds Figure 6.5-1) the 36,000 psi allowable stress by 6.16.
Header branch tee Stress for load (Location E in Case II exceeds Figure 6.5-1) the 36,000 psi allowable by 7.84.
2 6.6 SRV Discharge First cibow in Stress for load Piping Soutn drywell adjacent Case II exceeds to vent line the 36,000 psi (Location S in allowable by Figure 6.6-1).
6.11.
2 Sparger arm inside Stress for load torus (Location A Case II exceeds in rigure 6.6-1).
the 36,000 psi allowable bv 7.51 and for load Case V exceeds the 27,000 psi allowable by 9.24.
6.6 SRV Discharge Branch connection Stress for load Piping Soutn at steam line Case V exceeds' Header
' Location D in the 31,500 psi Figure 6.6-1).
allowable by 7.3%.
6.7 Torus Pressure Mid-5"1% of run Stress for load Transducer Case III exceeds the 36,000 psi allowable stress by 84.
Oxygen Analyzer Mid-span of run Stress for load Case III exceeds tne 36,000 psi allowable stress by 84.
Drywell Pressure Mid-span of. run Stress for load Case Transducer III exceeds the 36,000 psi allowable streds by 154.
'T
~
REOUCER 6-INCH B R A tl C H T E E 14-INCH IT!1 NCH REDUCitJGTEE g
t
=
4 -Itt C H GATE VALVE 4-INCH Cb C-Iff C H UU l
gn V A CUU!.t R E t. l E F P EllE T R A T IO tl RitJ G C IR D E R SUPPORT Y
(T YP) gy yy O
(c) un
/
VACUUPA RELIEF TORUS PEtJETRATIOff COttT Al it. EtlT SPR AY D SCHARGE T E TEST RETURf1 TORUS pet;ETR ATICr4 l
FJGURE 6.3-I LIMITING STRESS LOCATIONS CONTAINMENT SPRAY AND TEST RETURN PIPING AT VACUUM BREAKER G
..p W.
NORTH
....C _, s 8 2 *ess C=
^
.};
.e-. s t
...C..
s 2*asiCm ph l e 2-sacee
/vr i
es022tC
(
e 6-ahCoe f
ga.hCM 3 8 2-sssCM i
N m
2 0
- 6= C "
24
- piC H
@)
eno!!st S G-s Ca
.,OlltC c.g. CH 2 e c..=cm e 2 *** C a D
c' f
k
~
~
....C.,
t 2 -sn t n jiO saamcw s enANCHI 82*wCn 8 2.skC n FIGURE 6.5-1 L'IMITING STRESS LOC ATIONS CORE SPRAY SUCTION HEADER AND BRANCH PIPING 9
9 e
e
=
ntLite
' 4 eth A18 24-!NCH FAIN STEAM PIPE 8-t:.CH
,a 5NUBBE3 51 N
PIPE HANOER 8-!NCH
, N HANGER HSV-H4
' N, g[
ELECTRO *ATIC N.,
,[-
HINGED BELLOWS RELIEF WALVE :
RIGID HA'iOER 54 8-INCH
~~
y HANGER HSV-HS T
StrJ8EER 53 SNUSEER 52 HINOED 14-110
'A cate:M sa[AKERS bel. LOWS RIGID SUPPORT 55 M 4-::.cn t
o.
12-lhCH I
lt L1' 1 0';
C
.-q TORUS AIGID SUPPCRT,
j
's n
i RAMSHEAD TEE SUPPORTS N
SLID!?iG $Upr0RT FIGURE 6.6-1 LIMITING OTRESS LOCATIONS SOUTH HEADER SAFETY RELIEF. VALVE DISCHARGE PIPING e
e
'O q
+
.. ~ - -
,r-,
Request:
Item G3:
Confirm whether the hanger on the reactor building-to-torus vacuum relief piping which failed to meet the criteria (Reference 3.1) as indicated in Section 6.1 (Reference 3.3)
.har been modified.
Item G4:
Confirm whether the two supports for the core spray test run piping which failed to meet the criteria as indicated in Section 6.4 (Reference 3.3) have been modified or replaced.
Item G5:
Confirm whether the one support for the demineralizer relief valve discharge piping which failed to meet the criteria as indicated in Section 6.2 (Reference 3.3) has been modified.
Item G6:
Confirm whether the torus containment spray header supports have been replaced and whether the one support on the loop at Assembly G has been modified or replaced as indicated in Section 6.3 (Reference 3.3).
Response
Work is underway to design and fabricate new or replacement piping supports for the systems listed above. When installed, each support will satisfy the criteria given in NE00-24583-1 (Reference 3.1).
GPUN plans to have these supports installed prior to the start of Cycle 11.
4 2-27
Request:
Item G7: Confirm whether the provisions indicated in the footnote on Page 58 of ASME Code Subsection NE-3221.5 (Reference 3.7) have been applied for fatigue evaluation in Section 7.0 (Reference 1:2 ). -
Response
The footnote on Page 58 of ASME Code Subsection NE-3221.5 requires that consideration be given to the superposition of fatigue cycles of various origins which produce a total stress range greater than the individual cycles.
This requirement was incorporated in the fatigue analyses.
Specifically, when two or more cycles occurred simultaneously, stress intensity ranges for each were separately determined and added to conservatively estimate the total range for the combined event. When cycles occurred sequentially, checks were made to ensure the correct overall stress range was utilized, per the example given in the footnote on Page 58 of ASME Code Subsection HE-3221.5.
In the example of the ASME Code, the combination of 1000 positive-biased cycles with 10,000 negative-biased cycles is shown.
It was found for Oyster Creek that the stress cycles of greatest influence (earthquake, SRV, and LOCA CO or chugging) were not biased like the example in the ASME Code.
Accordingly, it was not necessary to make special corrections to the individual cycle counts.
2-28 1
3.0 REFERENCES
3.1 General Electric Company. Mark I Containment Program Structural Acceptance Criteria Plant-Unique Analysis Application Guide. NED0-24583-1, October 1979.
3.2 MPR Associates, Inc., Oyster Creek Nuclear Generating Station Mark I Containment Long-Term Program Plant-Unique Analysis Report Suppression Chamber and Vent System. MPR-733, August 1982.
3.3 MPR Associates, Inc. Oyster Creek Nuclear Generation Station __
Mark I Containment Long-Term Program Plant-Unique Analysis Report Torus Attached Piping. MPR-734, August 1982.
l 3.4 U. S. Nuclear Regulatory Commission.
Safety Evaluation Report, Mark I Containment Long-Term Program Resolution of Generic Technical Activity A-7.
NUREG-0661, July 1980.
3.5 General Electric Campany. Mark I Containment Program Load Definition Report. NED0-21888, Revision 2, November 1981.
3.6 General Electric Company.
Letter MFN-159-82 to the U. S.
Nuclear Regulatory Commission, October 28, 1982.
l 3.7 American Society of Mechanical Engineers. Boiler and Pressure Vessel Code Section III Nuclear Power Plant Components Division 1.
1977 Edition with Addenda through Summer 1977.
3.8 The MacNeal-Schwendler Corporation.
The NASTRAN Theoretical Manual.
December 1972.
-v-
e.h._
_4
._e 4.
.n.
2 m.i'.-4 A
h 4
5 e
. 4.0 APPENDIX A, FRANKLIN RESEARCH CENTER REQUEST FOR INFORMATION
' (TER-C5506-319) j i
k e n-i l
I i
i
'4 J
f i
I e
r e
1 l
4 4
f
)
4 f
=
i j
t
~~
TER-C5506-319 D
'h.
-(
REQUEST FOR INFORMATION TORUS, VENT SYSTEM, AND PIPING SYSTEMS Item 1:
Provide a summary of the analysis with regard to the vacuum breaker valves; indicate' whether they are considered-Class *2. components as required by the criteria [1].
Item 2:
Provide a summary of the analysis with regard to. th'e" modified safety relief valve piping supports designated as S1, S2, S3, and SS.
-k Item 3:
Provide a summary of the analysis with regard to Class'l piping connections which connect the safety relief valve to the main steam piping in the drywell region.
~
~
Item 4:
Provide justification for determining the lo,ad combination's indicated in Table 6.0-1 [2] to be the limiting load combinations.
Item 5:
Indicate whether each of the safety relief valve discharge lines has been analy:ed as required by the criteria [1].
Also, provide justification for not considering all the lines.
Item 6:
With reference to Table 1 of Appendix B, indicate whether all loads have been considered in the analysis and/or provide justification if e..
any load has been neglected.
Item 7:
Indicate, in detail, how the vent system modal mass and stiffness terms were synthesi:cd into the explicit torus shell model to scrive the coupled torus / vent system model.
Item 8:
Provide a summary of the analysis with regard to the torus for safety relief valve loads on the ring girders.
Item 9:
Provide a sum =ary of the buckling analysis of the torus.
Item 10: Provide and justify the reasons for not considering a 180* segment of the torus including column', saddles, seismic restraints, and sway s
braces in order to determine the effects of seismic and other nonsymmetric loads.
Confirm whether the overall behavior has been considered for calculating the fundamental frequency of 19 9: given in Section 4.6.2.1 (2).
Item 11: Provide and justify the reasons for not considering a 180' segment 'of the vent system in order to determine the effects of seismic and other nonsymmetric loads.
e I
e
.e M
-- -----------l---------------
TER-C5506-319 Item 12: Provide a sum: nary of the analysis v.ith rega,,rd to the nozzles in the I
vent system for the safety relief valve piping penetrations.
- Also, provide the results of the fatigue evaluation.
1 l
Item 13: Indicate, how the gussets at the vent lin'e /drywell intersection were modeled in order to account for their meridional-stiffnesses in the axisymmetric model.
Item 14: Indicate how the closed form solution was used to calculate the response spectra for the steady-state condensation. oscillation and chugging loads, and indicate the refefence usedT
~
~'
s i
on E
l l
i 6
-(
2 A
~
bhbli FrankJin Research Center i
A o.m
.t 9:o reene;o _
)-. -
TER,-C5506-319 l
l l
GENERAL Item Gl:
Indicate whether condensation oscillation or chugging loads had been
\\
used....in the limiting load combinations for load 'as's le.,
15, 20, c
e and 27 in Table 6.0-1 [2].
J' j
_t Item G2:
Provide more specific information on the conservatism used as the basis for accepting the overstresses at various loc ~ations in the torus, the vent system, and the piping systems.
/ /,
i Item G3:
Confirm whether the hanger on the rea'ctor build'ing-to tor 5s vacuum
~
relief piping which f ailed to meet the criteria [1] as indicated in
- Section 6.1 [2] has been modified.
ff s.
Item G4 :
Confirm whether the two supports for the core spray test run piping i
which failed to meet the criteria as; indicated in,Section,.6.4 [3) have been modifi:d or replaced.
S /'., -
~
Item GS:
Confirm whether the one support for the demineralizer relief valve discharge piping which failed to meet Section 6.2 [3] has been modified.
the criteria as indicated in g,e
.e, e f,
)
Item G6:
Confirm whether the torus containment spray header supports have been replaced and whether the one support on the loop at assembly G has been modified or replaced as indicated in Section 6.3 3
[3).
.. //s Item G7:
Confirm whether the provisions indicated in the footnote on page 58 1
of AS.ME Code Subsection NE-3221.5 have been applied for fatigue evaluation in Section 7.0 (2).
j(;-
4 e
e e
9 s
4 e
l
~.
4
~ ~ ~ ~ ~
~ ~ ~ ~ ~
' ~ '
' ~
e s..,,...,._ ;,, y.
A beu n clih2 Frinihn insutus Assignment No....
20 n and Rtc2 Snecu. Phds.. Pa. 19103 (215) 448 1000
- 3 "O"
' l'
'. '.. : *. 7 Plant Nam o
. O.='..-
f Tcble 1. Structural Loading (frorn Reference.~
I I
Other we r Inte nc-Structures Structur e
a o
3g b
EE=
o n
o d.'
5 D
e:
j k-y h
$b Loads
'S S
?
e 5
5"U 1
e e
{
E a
a= az=
10 O'
'2 d
E f
$ 8 :'
- 1. Containment Pressuro and Temperaturo X
X X
X.
X X
X X
- 2. Vent System Thrust Loacs X
X X'
I
- 3. Peo! Swell 3.1 Tcrus Net Venical Loads X
X 3.2 Torus Shell Pressure Histories X
X 3.3 Vent Systomimpact and Drag X
X X
3.4 Im;:act and Drag on Other Structures 3.5 Froth lmpingemont X
X X
X X
X X
X l
3.6 Pcc! Fallback 3.7 LCCA Jot X
X X i 3'.6 'LCCA ButOlo Drao '
X j
- 4. Condensation Oscillation X
X 4.1 Tcrus Shell Lcacs X
X 4.2 Lead on Su mergcc Structures 4.3 LateralLeads on Downcomers X
X 4.4 Vent System Lcacs X
X
- 5. Chugging X
X 5.1 Torus She!! Leads X
X 5.2 Leads on Submarged Structures 5.3 Lateral Loads on Downcemers y
y 5.4 Vent System Leads X
X C. T.Cuenchor Leads X
X 6.1 Dischargo Lino Cicating.
~
6.2 Torus Shell Pressures X
X X
6.4 Jet Leads on Sucmcrged Structures X
X X
6.5 Air 8u0010 Orag 6.6 Thrust Loads on T-Ouencher Arms X
X X
6.7 S/RVOL EnvironmentalTemperaturo X
- 7. Ramshead Loads x
7.1 Olschargo Lino C! caring 7.2 Torus Shell Pressures X
7.4 Jet Loads on Submerged Structurcs 7.5. Alt Subtle Drag
~
7.6 S/RVOL EnvironmentalTemperature E
Lords required by NUREG-C661l 4)
O h
N'.t app!!cablo.
TER-C5 50 6-319
\\
1
(,
REFERENCES, 1.
" Mark I"C6ntainment Program Structural Acceptance Criteria Plant Unique Analysis Application Gaide" i
-8 General Electric Co., San Jose, CA
. October 1979 2.
Oyster Creek Nuclear Generating Station Plant Unique Analysis Report, Suppression ' Chamber add Vent 'Sysicm, Mark I Containment Long-Term Program MPR-733 j
i e
General Public Utilities Nuclear August 1982 3.
Oyster Creek Nuclear Generating Station Plant Unique Analysis Report, TorusAttachedPiping,MarkICoNtainment
~
Long-Term Program HPR-734 General Public Utilities Nuclear August 1982 4.
" Safety Evaluation Report, Mark I Containment Long-Term Program
' J.esolution of Generic Technical Activity A-7" Of fice of Nuclear Reactor Regulation July 1980 5.
HEDO-21888 Revision 2
" Mark I Containment Program Load Definition Report" General Electric Co., San Jose, CA November 1981 e
ea e
6 e
t
+1 I
i g
_ liDDEoaqaaxtrrramud-- -- ------
SSINS No.:
6820 OMB No.:
3150-0096 Expiration Date:
12/31/84 IEB 83-02 0'i!TED STATES NUCLEAR REGULATORY COMMISSION OFFICE OF INSPECTION AND ENFORCEMENT.
WASHINGTON, D.C.
20555 March 4,1983 IE BULLETIN NO. 83-02:
STRESS CORROSION CRACKING IN LARGE-DIAMETER STAINLESS STEEL RECIRCULATION SYSTEM PINING AT BWR PLANTS Addressees:
Those licensees of operating boiling water reactors (BWRs) identified in Table 1 for action.
All other licensees and holders of construction permits (cps) for information only.
Purpose:
IE Bulletin 83-02 is issued to further inform all licensees and CP holders about the recent generic pipe cracking problems involving BWR plants and to require actions of those licensees listed in Table 1.
Descriotion of Circumstances:
As a result of the extensive intergranular stress corrosion cracking (IGSCC) found at Nine Mile Point Unit 1, the NRC issued IE Bulletin 82-03, Revision 1 for action to nine BWR plants scheduled for refueling outages in late 1982 and early 1983.
Inspections pursuant to IEB 82-03, Revision 1, and NUREG-0313, 1
Revision 1, have shown cracking of the main recirculation system piping in five of seven plants examined to date. Table 2 presents a summary of affected plants based on information available to date.
IEB 82-03 Rev.1 discusses the l
IGSCC problems experienced at Nine Mile Point Unit 1.
A brief description of the cracking prcblems at Browns Ferry Unit 2, Monticello and Hatch Unit 1 is presented below.
At Browns Ferry Unit 2, the inservice inspection (ISI) was extended to include the welds joining the jet pump piping sweepolets to the manifold of both A and B loops.
Unacceptable indications were found in the heat-affected zone of the manifold in the loops A and B sweepolet-to-manifold joint nearest the end caps.
All of the indications were interpreted to be cracks near the inside surface and were determined by UT to be about ik inches long (roughly parallel to the weld),
j and of about 20 percent depth through-wall.
As a result of further design analysis, review of shop fabrication records, and supporting in-situ metallography and ferrite determinations, the licensee established that the affected weld was solution heat treated and, therefore, not subject to the IGSCC.
The licensee believes the cracking cay be due to fatigue from flow-induced vibration.
At this tir.e the licensee is trying to resolve the problem.
1 '{}
bfllS.
f L
IES S3-02 March 4, 1983 Page 2 of 6 At M:nticello, IGSCC was confirmed in one end-cap-to pipe weld of the 22-inch-diameter distribution header (manifold) and at five welds in the jet pump inlet piping sr.fe-ends which are 12 inches in diameter and are made of schedule E0 stainless steel.
The cracks initiated on the inside surface in heat affected zones (HAZs) of the welds.
Some cracks were oriented axially and some circum-ferentially.
They varied fro:a k inch to 1 inch in length.
Someasialcracks in the recirculation inlet risers were found to be through-wall during subsequent.
repair activities and hydrotesting, although ultrasonic examination previously performed on these welds did not reflect this condition.
At Hatch Unit 1, multiple linear indications characteristic of the IGSCC found at Monticello were identified at seven welds in the large-diameter recirculation and associated residual heat removal (RHR) piping.
The affected welds were located as follows:
All four 22-inch-diameter manifold end-caps, one 22-inch-diameter branch connection (sweepolet-to manifold) of the recirculation piping, one elbow-to pipe weld in the 20-inch RHR piping, and one pipe-to pipe weld in the 24-inch diameter RHR piping.
The location and orientation of the indications were very similar to those found at Monticello.
The length of the indications ranged up to inch in the axial directio1 and l\\-inch in the circemferential direction.
Based on UT ceasurements, the depth of axial compenant of the crack indications were found to have essentially penetrated through the wall in three of the four end-cap welds repaired to date.
The discovery of extensive IGSCC in the large-diameter recirculation piping at Nine Mile Point Unit 1 (fiMP 1) after a decade of acceptable service has resulted in increased concern about the effectiveness of UT methodology used in the inservice inspection of stainless steel BWR pipe welds, particularly in large-diameter piping.
Therefore, the goal of Item 1 of IEB 82-03, Revision 1 was to obtain reassurance of the capability of UT inspection systems, techniques, and operators to detect significant IGSCC problems in the nine BWR plants that were performing ISI during fall / winter outages.
The performance test protocol as stated in Item 1 of IEB 82-03, Revision 1 required the licensee and/or ISI agencies to demonstrate their capability to detect IGSCC in large-diameter recirculation system piping before resuming power operation. Within this context, Electric Power Research Institute's NDE (EPRI-NDE) Center arranged to have five i
i reasonably characterized, service-induced cracked pipe samples from the NMP 1 plant available at Eattelle Columbus Laboratories (BCL) for industry performance i
capability demonstrations (PCDs).
All nine plants have now satisfied the demonstration phase of IEB 82-03, Revision 1.
By letter dated January 28, 1983, EPRI provided each licensee a su.7.ary of all teams performances, based on composite results from the five samples, plus a key to identify their ISI team's achievement.
The PC] results at BCL have shown that excellent performance can be achieved by well trained and experienced personnel with appropriate procedures and evaluation methods.
However, personnel from a relatively few licensee /ISI organizations achtend this level of competence during the first qualification attempt.
The overall results revealed a high failure rate which requirt.d retesting of the licensee /ISI organization teams.
Several interrelated factors contributed to this rate of failure:
IE3 83-02 March 4, 1983 Page 3 of 6 1.
UT procedures essentially meeting only the minimum requirements of the ASME Section XI code were ineffective.
2.
UT procedures lacked specific detailed guidance on UT systems and motheds proven capable of detecting IGSCC in thick-walled piping. -
3.
Some UT operators were inexperienced in evaluating signal patterns of reflectors in thick-walled, large-diameter piping.
Thus, some cracks were missed, or were called geometry effects; seme geometry effects were falsely called cracks.
4.
Many UT operators, inexperienced about the nature of IGSCC in large-diameter piping, did not establish finite metal path calculaticns during scanning; this resulted in falsely identified conditions.
ln view of the collective results at BCL, a continuation of the PCD program appears necessary.
Accordingly, the EPRI-NDE Center has arranged to have a series of service-induced cracked specimens available for this purpose at their facility about March 14, 1983.
The NRC recognizes that the prescribed actions of this bulletin exceed present plant ISI surveillance requirements under ASME Code Section XI rules.
- However, in view of the apparently generic pipe cracking experience and results of the UT demonstration trials, the NRC believes such an augmented ISI plan is necessary
?.o reasonably assure the integrity of the recirculation system for continued operations.
These actions are intended to apply only to the currently scheduled refueling outage for those plants listed in Table 1.
Any licensee who finds these actions will significantly impact the duratir i of the refueling outage may request relief by written request to the apprcpriate MC regional office.
Such requests must address (1) the impact on the length of the outage, (2) proposed alternative actions, and (3) technical basis for continuing operation.
Actions to Be Taken by Licensees of BWR Facilities Identified in Table 1:
1.
Before resuming power cperations following this scheduled or extended outage, the licensee is requested to demonstrate the effectiveness of the detection capability of the UT methodology planned to be used to examine welds in recircirculation system piping.
It is intended that the demonstrations be performed at the EPRI-NDE Center on service-induced cracked pipe samples made available for this purpose.
Each licensee should assure that the demonstration is valid for the weldnents of the recirculation system piping of their plant.
Arrangements should be made to facilitate NRC witnessing of these tests.
The demonstration tests will employ the following criteria.
a.
Ultrasonic Testino System:
To ensure that the field UT system will respond in the same way as the demonstrated system, the same procedures, standards, make and model of the UT instrument, and transducers to be utilized in the plant ISI are to be used in the IGSCC detection capability ccmonstration.
(
March 4, 1933 Page 4 of 6 4
b.
Personnel Performina Ocmonstration:
UT personnel teams drawn from the licensce/ISI contractor who will be actually supervising, performing examinations, recording data, and evaluating indications at the plant site will participate in the performance demonstratien tests.
All i
members of the teams must participate directly in the UT scanning, data recording, and evaluation of the test samples.; To ensure i
completion of testing within the time constraints below, the team should be limited to six persons.
For subsequent plant inspections, the personnel / equipment requirements noted below will apply.
c.
Pipe Samoles:
The total number of pipe samples selected should constitute an equivalent of 120 inches of weld for the demonstration 4
tests.
d.
Acceptable Criteria:
Eighty percent of the total number of preselected 4
cracks in the sample control group must be called correctly to i
constitute an acceptable test.
Excessive false call rates may result in an unacceptable performance rating.
j e.
Demonstration Time Limit: ALARA radiation dose considerations place constraints upon the time spent in field inservice inspection of a weld.
Therefore, a time limit of six hours, not including equipment calibration time, will be imposed for the examination and data I
recording.
Completion of data evaluation and preparation of final results of individual licensee /ISI contractors'should take no longer than one additional working day.
1 i
f.
Review of UT Procedures:
The specific procedure (s) to be used by the licensee /ISI contractor (s) for plant inservice inspection is to be 4
made available for review as part of the demonstration activity.
It j
is expected that the UT procedure and equipment system will have been validated to be capable of detecting IGSCC by the licensee /ISI con-j tractor before initiating the scheduled demonstration activities.
l NOTE:
Some of the licensees listed in Table 1 have completed efforts l
to validate the UT detection capability to be used to perform plant inspections in accordance with the requirements of Action Item I of IEB 82-03, Revision 1.
These licensees need not repeat this effort in accordance with Action Item 1 of this bulletin provided that:
the j
previous validated inspection group performs the new plant examination i
using identical UT procedures, standards, make and model of UT instrument, and the same make and model transducers that were used to i
complete the previous validation effort. In addition, the UT personnel employed in the new examination must be the same; or those having appropriate training (documented) in IG5CC inspection using cracked i
thick-wall pipe specimens, and are under direct supervision of the Level II/III UT operators who successfully complete the performance demonstration tests.
l l
i
IEB 83-02 fiarch 4,1983 Page 5 of 6 2.
Before resuming power operations licensees are to augment their ISI programs to include an ultrasonic examination of the following minimum number of recirculation system welds:"
a.
Ten welds in recirculation piping of 20-inch diameter, or larger.
b.
Ten welds of the jet pumps inlet riser piping and associated safe-ends.
c.
Two sweepolet-to-header (manifold) welds of jet pump risers nearest the end caps, if applicable to the design.
If flaws indicative of cracking are found in the above examination, additional inspection is to be conducted in accordance with IWB 2430 of ASME Code Section XI.
3.
Before resuming power operations following the outage, the licensee is to report the results of the Item 2 insp?ction and any corrective actions (in the event cracking is identified).
This report should also include the susceptibility matrix used as a basis for welds selected for examination (e.g. stress rule index, carbon content, high stress location, repair history) and their values for each weld examined.
4 The tiRC has an on going program to evaluate possible additional longer-term requirements relative to the IGSCC problem in the BWR recirculation system piping.
The fiRC may need additional information as part of this program.
Therefore, licensees are requested to retain the records and cata develcped pursuant to the inspections performed in accordance with Item 2.
5.
The written report required by Item 3 shall be submitted to the appropriate Regional Administrator under oath or affirmation under provisions of Section 182a, Atomic Energy Act of 1954, as amended.
The original copy of the cover letter and a ccpy of the reports shall be transmitted to the U.S.
?!uclear Regulatory Commission, Document Control Desk, Washington, D.C. 20555 for reproduction and distribution.
This request for information was approved by the Of fice of Management and Budget under clearance number 3150-0096 which expires 12/31/84.
Comments on burden and duplication should be directed to the Office of fianagement and Budget, i
Reports fianagement, Room 3208, liew Executive Office Building, Washington, D. C. 20503.
1
^5ince Big Rock Point and Lacrosse do not have jet pumps, the licensees of these plants should provide an equivalent sampling of the recirculation piping system based on the plant design.
l IEB E3-02 March 4, 1983 Page 5 of 6 Although ne specific request or require.?ent is intended, the following information wculd help tne NRC evaluate the cost of implementing this bulletin:
Staff time to perform requested demonstration.
Staff tir.e to prepare written responses.
The occupational radiation exposure experienced.
If you have any questions regarding this matter, please contact the Regional Administrator of the appropriate NRC Regional Office or one of the technical contacts listed below.
- ~C Q
Officeof{p/ Young,0, Richard C. D ector spection and Enforcement Technical
Contact:
William J. Collins, IE 492-7275 Warren Hazelton, NRR 492-8075 Attachments:
1.
Table 1 2.
Tacle 2 3.
List of Recently Issued IE Bulletins I
I
Attachcent 1 IES 83-02 March 4, 1983 Table 1 BWR Plants Scheduled to be in the Next Refueling Mode or Extended Outage After January 31, 1983 LICENSEE PLANT RELOAD DATE Philadelphia Electric Co.
Peach Bottom Unit 3 February 1983 Vermont Yankee Nuclear Power Vermont Yankee March 1983 Company Tennessee Valley Authority Brosns Ferry Unit 1 March 1983 Nebraska Public Pcwer District Cooper April 1983 Georgia Power Co.
Hatch Unit 2 April 1983 Consumers Power Co.
Big Rock Point May 1983 Power Authority of the State FitzPatrick May 1983 of New York Commenwealth Edison Co.
Quad Cities Unit 2 August 1983 Tennessee Valley Authority Browns Ferry Unit 3 September 1983 Carolina Power & Light Co.
Brunswick Unit 2 September 1983 Dairyland Power Corp.
Lacrosse October 1983 Philadelphia Electric Co.
Peach Bottom Unit 2 October 1983 l
Commenwealth Edison Co.
Dresden Unit 3 October 1983 Bosten Edison Co.
Pilgrim Unit 1 January 1984 i
IEB 83-02 c.
March 4, 1983 L
TABLE 2-CRACK INDICATIC:NS IN BWR RECIRCULATED SYSTEM PIPING I
PLANT PIPE SIZE WELD LOCATION HOW DETECTED NM? 1*
28" Dia.
Pipe to safe ends Initial crack-visual l
Visual leakage 28" Dia.
Pipe to Pipe UT 28" Dia.
Pipe to pump casing Visual - UT F
2 Monticello 12" Dia.
Riser to Safe End Leakage (weepage) 12" Dia.
Riser to Safe End Weepage - UT 12" Dia.
Riser to Safe End Weepage - UT 12" Dia.
Riser Elbow to Pipe UT 22" Dia.
Elbow to Pipe Leakage (weepage)
During Hydrotest-visual
)
Hatch 20" Dia.
Elbow to Pipe (RHR)
UT i
- l 22" Dia.
22" Dia.
24" Dia.
Pipe to Pipe (RHR)
UT 22" Dia.
12" Riser Sweepolet to Manifold UT Browns Ferry 22" Dia.
12" Riser Sweepolet i
12" Riser Sweepolet to Manifold UT Brunswick 28" Dia.
Elbow to Pipe UT j
12" Dia.
Riser to Safe End Leakage (weepage) l 12" Dia.
Riser to Safe End Leakage (weepage)
Dresden 2 28" Dia.
12" Dia.
Riser Pipe to Elbow UT l
Footnotes:
Cracks were found in 90% of welds examined
{
Ger.erally, there were indications of more than one axial or circumferential j
aligned crack in each affected weld.
i t
i i
t
larch 4, 1983 l
LIST OF RECENTLY ISSUED IE SULLETINS Sulletin Date of No.
Subiect Issue Issued to 83-01 Failure of Reactor Trip 02/25/83 Af1PWRfacilities Breakers (Westinghouse C3-50) holding an OL and to Open on Automatic Trip other power reactor Signal facilities for information 82-04 Deficiencies in Primary Con-12/03/82 All power reactor i
tainment Electrical Pene-facilities holding j
tration Assemblies an OL or CP l
82-03 Stress Corrosion Cracking in 10/28/82 Operating BWRs in Rev. 1 Thick-Wall large-Diameter Table 1 for action Stainless Steel, Recircula-and other OLs and cps tion System Piping at BWR for information j
Plants 82-03 Stress Corrosion Cracking in 10/14/82 Operating BWRs in Thick-Wall Large-Diameter, Table'1 for action i
Stainless Steel, Recircula-and other OLs and cps -
1 tion System Piping at BWR for information j
Plants i
i 82-01 Alteration of Radiographs of 08/18/82 All power reactor Rev 1, Welds in Piping Subassemblies facilities with
]
Supp 1 an OL or CP 82-02 Degradation of Threaded 06/02/82 All PWR facilities Fasteners in the Reactor Coolant with an OL for j
Pressure Boundary of PWR plants action and all other OLs or cps
]
for information i
82-01 Alteration of Radiographs of 05/07/82 All power reactor Rev. 1 Welds in Piping Subassemblies facilities with an OL or CP 82-01 Alteration of Radiographs of 03/31/82 The Table 1 Welds in Piping Subassemblies facilities for j
action and to all i
others for j
information j
81-02 Failure of Gate Type Valves 08/18/81 All poser reactor Supplement to Close against Differential facilities with an 1
Pressure OL or CP OL = Cterating License i
CP = Construction Permit 4
ea y
\\ aSINS NO.:
6820 IEB 82-03 UNITED STATES NUCLEAR REGULATORY COMMISSION OFFICE OF INSPECTION AND ENFORCEMENT WASHINGTON, D.C.
20555
~
October 14, 1982 IE BULLETIN NO. 82-03:
STRESS CORROSION CRACKING IN THICK-WALL',
LARGE-DIAMETER, STAINLESS STEEL, RECIRCULATION SYSTEM PIPING AT BWR PLANTS Addressees:
Those licensees of operating boiling water reactors (BWRs) identified in Table 1 for action.
All other licensees and holders of construction permits (cps) for information only.
Purpose:
~ This bulletin is to notify all licensees and CP halders about a matter that may have a high degree of safety significance, and to require specific actions as set forth below for those licensees listed in Table 1.
Specifically, this matter involves the degradation in the recirculation system piping in the reactor coolant pressure boundary (RCPB) that was found at the Nine Mile Point Unit 1 Nuclear Generating Station.
This information was described in consider-able detail in Information Notice 82-39, dated September 21, 1982.
Action by the affected licensees identified in Table 1 is required to (1) provide a reasonable level of assurance that inspections which are currently being performed or scheduled are sufficient to detect cracking in BWR thick wall i
recirculation piping welds and (2) to assist the NRC in determining the generic -
4
~
significance of the piping degradation found at Nine Mile Point.
The affected l'icensees are those owners whose' plants are currently in.or scheduled to be in a refueling mode or extended outage through January 31, 1983.
This bulletin is provided to all other licensees and holders of construction permits for information only at this time.
Licensees not listed in Table 1 will be notified by January 15, 1983 as to the scope and extent of any required actions.
Description of Circumstances:
During a primary system hydrotest in March 1982 at Nine Mile Point Unit 1 (NMP-1), leakage was visually detected at two of the ten furnace-sensitized, recirculation system safe-ends.
Further visual inspection revealed three pinhole indications and a single -inch-long axial indication, all of which were located in the heat-affected zone of the welds where the safe-end joined the pipe.
About nine months before the leak, these safe-ends were ultrasonic-ally (UT) inspected; at that time, the inspection did not disclose any report-able indications.
Subsequent to the leak, the UT procedure was modified; UT A/ /73 SM M M L,w
s,EB 82-03 October 14, 1982 Page 2 of 5 Table 1 Plants Currently in or Scheduled to be in a Refueling Mode or Extended Outage Througn January 31, 1983 LICE'NSEE PLANT (S)
Northern States Power Company Monticello Nuclear Generating Station Tennessee Valley Authority Browns Ferry Unit 2 Nuclear Generating Station Commonwealth Edison Company Quad Cities Unit 1 Nuclear Generating Station Dresden Unit 2 Nuclear Generating Station Northeast Utilities Millstone Unit 1 Nuclear Generating Station Georgia Powec Compa'ny Hatch Unit 1 Nuclear Generating Station '^
Carolina Power & Light Company Brunswick Unit 1 Nuclear Generating,/'
Station
- Jersey Central Power & Light Company Oyster Creek Nuclear Generating Station Iowa Electric Light & Power Company Duane Arnold Nuclear Generating Station
- To be performed during the November 1982 refueling outage, not 'the current outage.
O 4
0 5
0
i
. l.
l' 4EB 82-03 w
Oct.ober 14, 1982
'Page 3 of 5 l
I i
examination of the two a'ffected safe-ends and one other safe-end confirmed the presence of indications of intermittent cracking around.the pipe's inside diameter (ID).
Additional examinations revealed cracking in heat affected zones of recirculation pump discharge welds.
Dye penetrant' examination con-firmed these crack indications.
The UT examinations were extended to other 4
welds in the five. loops of the recirculation system.
The results of these j
j examinations disclosed ID cracking in a large number of the welds examined.
i i
Two boat samples removed from the area of the through-wall cracks in one.
}
safe-end were sent for evaluation -- one to General Electric Co. and the other to Battelle Laboratories.
- In addition, a boat sample from the cradk. region of the elbow weld was evaluated by Sylvester Associates, consultants to the l
1 licensee.
The results of these metallurgical evaluations concluded that the degradation resulted from intergranular stress corrosion cracking (IGSCC) in l
j the sensitized region of the weld's heat affected zones.
5 r
i Based on the fact that NMP-1 has furnace-sensitized safe-ends, the licensee i
j decided to replace all 10 recirculation system safe-ends without further j
investigation beychd that described above.
Based on recirculation system j
findings, the licensee decided to also replace all recirculation system piping j
'while the facility was shut down for safe-end replacement.
~
On September 16, 1982, a meeting was held between General Electric, BWR l
licensees, and NRC staff to review past IGSCC experiences and, the general implications of NMP-1 IGSCC degradation in main recirculation piping welds.
The staff had the benefit of the metallurg'ical evaluation of the NMP-1 event j
and an update'of the general IGSCC experiences relative to all operating BWR g
)
plants.
i l
j On September 27, 1982, a meeting was held between BWR licensees and the NRC j
staff to discuss the extent and results 'of examining welds'in the recirculation system for all BWR licensees with plants currently in or scheduled to be in a
[
refueling mde or extended outage through January 31,3 1983.
As a result of this meeting, the NRC staff has determined that additional information is needed to assess the effectiveness of the UT methods employed or planned to be used and to determine whether such piping should be designated " service-sensitive" in accordance with NUREG-0313, Rev.1, issued by NRC letter dated i
February 26, 1931.
I i
To provide a reasonable level of assurance that inspections which are currently i
being performed er scheduled are sufficient to detect cracking in thick-wall, recirculation system piping welds and to assist the NRC in further evaluating this issue, the affected licensees (identified in Table 1) are requested to i
take the following actions.
1 j
Actions to be Taken by Licensees of BWR Facilities Identified in Table 1:
l i
1.
Before resuming power operations following the current refueling or extended outage, the licensee is to' demonstrate the effectiveness of i
i 1
i i_,_ _
.l
a
- =.
(.EB 82-03 l
October 14, 1982 i
Page 4 of 5 i
i the detection capability of the ultrasonic methodology used or planned to be used to examine welds in recirculation system piping.
This demonstra-ti.on shall be made on representative service-induced cracked pipe samples.
j Arrangements should be made to allow NRC to witness this demonstration.
j This demonstration shall employ those procedures and standards,-the same type of equipment (same transducer size, frequencies and calibration-standards), and representative UT personnel from the inservice inspection j
(ISI) organization utilized or to be utilized in the examinations at the plant site.*
2.
Before resuming power operations following the current refueling or extended outage, the licensee is to provide a listing of results of recirculation system piping inspections.
3.
Before resuming power operations following the current refueling or extended outage, the licensee (if the inspections indicate the presence i
of cracks) is to describe the corrective actions taken and ieport these in accordance with the appropriate regulations.
4.
To assist NRC's further evaluation of this issue, the following shall be submitted by December 1, 1982:
j a.
A description of the sampling plan used or to be used during this i
outage for UT examinations of recirculation system piping welds
^ anc the bases for the plan.
The description should:
(1)
Provide an isometric drawing of the recirculation system piping l
showing all the welds, and the number of welds and their loca-4 tion that have been examined or will be examined.
(2)
Identify criteria for weld sample selection (e.g., stress rule i
index, carbon content, high stress location, and their values for each weld examined).
I (3) Describe piping material (s), including material type, diameter, and wall thickness.
l (4)
Estimate the occupational r,adiation exposure incurred or expected j
and briefly summarize measures taken to maintain individual and l
collective exposures as low as reasonably achievable.
r i
i i
i
- We understand that Electric Power Research Institute (EPRI) has arranged to I
have samples from the Nine Mile Point Unit 1 plant available for industry
}
demonstrations of UT methodology.
The samples have been taken to Battelle, j
Memorial Institute in Columbus, Ohio for characterization and subsequent use.
i f
a 4-
~
\\..EB E o
t -
Octet Page b.
A summary description of the UT p'ocedures and calibrat r
used or to be employed in the examination at the licens site.
This description should include the scanning'ser evaluation sensitivity and the recording criteria.-
c.
A summary of the results of any previous inspection of tion system piping welds which used the validated exami
~
odology as discussed in Action Item 1 above.
d.
An evaluation of the crack-detection capability of ults odology used or planned to be used to examine recircult piping welds.
This evaluation should result from condt demonstration ' required in Action Item 1 above, and shot comparison of the service-induced pipe crack sample to actually examined in the licensee's plant in terms of ;
thickness and diameter, weld geometry, and materials.
5.
The written reports required by Items 2,'3, and 4 shall be :
the appropriate Regional Administrator under oath or affirmt provisions of Section 182a, Atomic Energy Act of 1954, as at original copy of the cover letters and a copy of the report transmitted to the U.S. Nuclear Regulatory Commission, Docur Desk, Washington, D.C. 20555 for reproduction and distribut;
~
This request for information does not requiie Office of Managemer approval since the number of plants asked to provide the infcrma-to nine reactor plants.
Although no specific request or requirement is intended, the fol' tion would help the NRC evaluate the cost of implementing this bi o
Staff time to perform requested demonstration
~
o, Staff time to prepare written responses
~
If you have any questions regarding this matter, please contact Administrator of the NRC Regional Office or one of the technical listed below.
- g.
. };
,j /l p
+
.. = ywar 2 meu f
Office of Inspec,ng, Dire Richard C. DeY u tion and
~....
Technical
Contact:
William J. Collins, IE
' e" 492-7275 l
j Warren Hazelton, NRR 492-8075 e
5
_. ~..
o
\\-..ttachment 0
IEB 82-03 October 14, 1982 LIST OF RECENTLY ISSUED IE BULLETINS i
Bulletin j
Date of No.
Subiect Issue Issued to 82-01 Alteration of Radiographs of 08/18/82 All power reactor Rev 1, Welds in Piping Subassemblies facilities with an OL or CP Supp 1 82-02 Degradation of Threaded 06/02/82 All PWR facilitis Fasteners in the Reactor Coo,lant.
with an OL for' Pressure Boundary of PWR plants action and all other OLs or cps for information 82-01 Alteration of Radiographs of 05/07/82 All power reacto-Rev. 1 Welds in Piping Subassemblies facilities with an OL or CP 82-01
' Alteration of Radiographs of 03/31/82 The Table 1 Welds in Piping Subassemblies-facilities for action and to al others for information
~
81-02 Failure of Cate Type Valves 08/18/81 All power reacto Supplement to Close against Differential facilities with 1
Pressure OL or CP 81-03 Flow Blockage of Cooling Water 04/10/81 All power reacto To Safety System Components by facilities with CORBICULA SP. (ASIATIC CLAM)'
OL or CP and MYTILUS SP. (MUSSEL) 81-02 Failure of Gate Type Valves 04/09/81 All power reacto to Close Against Differential facilities with Pressure OL or CP 81-01 Surveillance of Mechanical 03/04/81 Specific power r Rev. 1 Snubbers facilities with f
02/13/81 To all specified 80-17 Failure of Control Rods Supp. 5 to Insert During a Scram e
with an OL & All at a BWR BWRs with a CP i -
OL = Operating License CP = Construction Permit g---
y -. _
Qgs Oc,,'o, o
f UNITED STATES
!?
e %
NUCLEAR REGULATORY COMMISSION 3,
i wasmucrou. o. c. 2osss OCT 141983 u
Docket Nos. 50-155, 219,'220, 237, 245, 254, 259, 260, 263, 271, 277 278, 298, 321, 325, 331, 333, 366, 373 and 387 MEMORANDUM FOR:
Darrell G. Eisenhut, Director Division of Licensing FROM:
Frank J. Miraglia, Assistant Director for Safety Assessment Division of Licensing
SUBJECT:
MEETING WITH SENIOR MANAGEMENT OF BWR LICENSED REACTORS TO DISCUSS FUTURE INSPECTIONS FOR IGSCC Dates and Times:
October 21, 1983 9:00 am - 12:00 noon 1:00 pm - 3:00 pm -additional plant specific discussions if required.
Location:
Room P-118 Bethesda, Maryland
Purpose:
To'present the NRC position regarding BWR IGSCC to senior industry representatives and to afford BWR licensees the opportunity to discuss. their future plans developed in response to IGLCC'cancerns.
Agenda:
The Agenda is enclosed.
Participants:
NRC REQUESTED PARTICIPANTS H. Denton, E. Case, E. Jordan, R. Vollmer, D. Eisenhut, W. Johnston, F. Miraglia, G. Lainas, T. Novak, G. Holahan, D. Vassallo, D. Crutchfield, J. Stolz 1
BWR Licensees Senior management representatives for the utilities identified i_n Enclosure 1.
, l,.
Frank J. Miraglia, Assistant Director for Safety Assessment Division of Licensing cc:
Regional Administrators R. DeYoung, IE V. Stello, DEDR0GR
'(3ff J. Fouchard, PA r
Contact:
olinski-3
. hy 1 ? / a ' L 3
)
i ENCLOSURE 1 BWR UTILITY ATTENDEES 1.
Carolina Power and Light Company Brunswick 1 50-325 2.
Commonwealth Edison Company Dresden 2 50-237 Quad Cities 1 50-254 LaSalle 1 50-373 3.
Consumers Power Company Big Rock Point 1 50-155 4.
Georgia Power Company Hatch 1 50-321 Hatch 2 50-366 5.
Iowa Electric Light & Power Company Duane Arnold 50-331 6.
Jersey Central Power & Light Company Oyster Creek 50-219 7.
Niagara Mohawk Power Corporation Nine Mile Point 1 50-220 8.
Nebraska Public Power District Cooper Station 50-298 9.
Northeast Nuclear Energy Millstone 1 50-245
- 10. Northern States Power Company Monticello 50-263 11.
Philadelphia Electric Company Peach Bottom 2 50-277 Peach Bottom 3 50-278 12.
Power Authority of the State of New York FitzPatrick 50-333 13.
Tennessee Valley Authority Browns Ferry 1 50-259 Browns Ferry 2 50-260 14.
Vermont Yankee Nuclear Power Vermont Yankee 50-271 15.
Pennsylvania Power and Light i
Susquehanna 1 50-387 1
se.
e AGENDA Meeting with Senior Management of UWRs Regarding IGSCC t
Opening Remarks (NRC)
Meeting Objectives NRC position regarding BWR IGSCC (scope of inspections, Current Status schedule, repair criteria) n long term considerations Discussion Issues for Each Licensee (about 10 minutes average, per licensee)
Degree of inspection to date Schedule for next extended shutdown or refueling outage Plans to conduct future IGSCC inspections and scope of Availability of qualified inspectors, qualification of inspections inspectors Repair Criteria Compensatory measures, as applicable The licensee should be prepared to make a presentation which addresses staff concerns contained in the agenda and to present GUIDANCE:
other information deemed relevant to the issues generated in response to the NRR presentation.
The conference room will accommodate one or two representativ from each of the invited licensees to be seated at the ARRANGEMENTS:
Other senior licensee officials will be conference table. seated in the rows immediately behind each princip speaker.
1 s
- f,
ATTACHMENT A -
SUMMARY
OF INSPECTION RESULTS AND SCHEDULES FOR NEXT INSPECTION EXTENT OF INSPECTION INSPECTION RESULTS 3
c INSPECTION
(% OF NO. OF WELOS INSPECTED)
(NO. OF CRACKED WELDS)
NEXT SIZING PLANTS QUALITY 1 RECIRC.
RHR RECIRC.
RllR REMEDIES OUTAGE CONCERNS 4 REMARKS Monticello A
100%, 106/106 78%, 18/23 6
0 Will replace 1/84 No recirt.
All std overlay
~
Browns A
27%, 25/91 28%, 9/32 2
0 Moisture sen-6/84 Yes Not IGSCC Ferry 2 sitive tapes Maybe fatigue Quad Cities 1 A
'8%, 9/110 20%, 9/44 0
0 None 3/84 N/A Dresdsn 2 A
47%, 47/101 10%, 4/40 10 0
7 overlay 12/83 yes 0.2" overlay repaired.
(Mid-cycle) on 7 riser H water welds.
cbemistry
. Millstone 1 M2 11%, 11/100 0%, 0/46 0
0 None 7/84 N/A Hatch 1 A'
47%,47/100 100%, 11/11 5
2 6 overlay 2/84 Yes Mostly axial repaired.
(unscheduled) cracks.
1-acoustic device.
Brunswick 1 M
25%, 29/115 75%, 3/4 3
0 All overlay 3/85 No All axial repaired.
cracks.
steel.
1 i
j i
a 1
O'
/
5
- a..
EXTENT OF INSPECTION INSPECTION RESULTS 3
s INSPECTION
(% OF NO. OF WELDS INSPECTED)
(NO. OF CRACKED WELOS)
NEXT SIZING PLANTS QUALITY 1 RECIRC.
RHR RECIRC.
RHR REMEDIES OUTAGE CONCERNS 4 REMARKS Oyster Creek A
39%, 31/80 0
0 None 4/85 A/A Duane Arnold A
42%, 49/117 40%, 2/5 0
0 None 10/84 N/A Peach A
91%, 77/85 92%, 35/38 10 5
All overlay 2/85 No Moisture Battom 3 repaired.
tape on all Moisture tapes repaired &
Vermont A
66%, 58/88 7%, 2/30 33 1
22 overlay 6/84 Yes Mini overlay Yankte repaired.
Moisture tape on 7 unin-spected welds.
browns A
100%, 91/91 100%, 32/32 33 14 Overlay re-2/85 Yes Mini-overlay Fcrry 1 paired some (still in outage)
Corp r A
100%, 108/108 100%, 7/7 20 0
13 overlay 10/84 Yes 4
repaired Hatch 2 A
94%, 97/103 100%, 11/11 36 3
27 overlay 1/84 Yes repaired.
Plan to replace i
I 4
e
k 3
EXTENT OF INSPECTION INSPECTION RESULTS s
c INSPECTION
(% OF NO. OF WELDS INSPECTED)
(NO. Of CRACKED WELDS)
NEXT SIZING PLANTS QUALITY 1 RECIRC.
RilR RECIRC.
RilR REMEDIES OUTAGE CONCERNS 4 REMARKS Big Rock lA 20%, 11/59 0
0 N/A 10/84 No Point Fitzpatrick Aa 47%, 49/106 45%, 5/11 1
0 None 3/85 Yes Peach A
100%, 85/85 100%, 38/38 18 7
18 overlay 3/84 No Bottom 2 repaired (still in outage) IllSI (16 welds) 1 Inspection Quality:
A-adequate, M-marginal.
2 Post inspection qualification test, passed the test after the second try.
3 Inspection personnel qualified under IEB-82-03 thru grandfathering.
4 Sizing concerns:
Yes - having unrepaired weld or mini-overlay.
No - cracked welds have been repaired by full strength overlay.
s Number of welds based on last available' information.
6 Outage time based on current s'taff information.
s
- b q
- ea aseg o,
UNITED STATES
-[i.
qff },
NUCLEAR REGULATORY COMMISSION g %, g/fl e
W ASHINGTON, D. C. 20555 o,
NOV 0 $ I Docket Nos. 50-115, 219, 220, 237, 245, 254, 259, 260, 263, 271, 277, 278, 298, 321, 325, 331, 333, 366, 373 and 387 MEMORANDUM FOR: Gary M. Holahan, Chief Operating Reactors Assessment Branch Division of Licensing FROM:
John A. Zwolinski, Section Leader Operating Reactors Assessment Branch 0 51sion of Licensing
SUBJECT:
MEETING MINUTES REGARDING POSSIBLE NRC ACTIONS CONCERNING NUCLEAR PLANTS PREVIOUSLY INSPECTED UNDER IE BULLETINS 82-03 AND 83-02 BWR IGSCC - OCTOBER 21, 1983 On October 21, 1983, the staff met with senior representatives of 15 BWR licensees. The meeting notice and list of meeting participants is enclosed (Enclosure 1). A list of meeting attendees is also enclosed (Enclosure 2).
The Summary of Inspection, hesults and Schedules for Next Inspection provided to the meeting attendees is included as Enclosure 3.
The staff presented opening remarks, stating that a final decision or series of decisions had not been made as yet; however, a number of recommendations have been prepared regarding the direction the staff is proposing to take regarding BUR IGSCC.
It was noted that in concert with industry, the staff has been pursuing solutions via the establishment of a Pipe Crack Study Group under the umbrella of the Piping Review Committee established by the EDO. DE and RES.have numerous professionals working to resolve the issues found regarding BWR IGSCC.
The staff presented a general overview of the program and preliminary conclusions.
Factors considered by the staff included:
1.
Quality of Bulletin Inspections UT capability demonstration results EPRI Round-Robin test results Field experiences 2.
Extent of Inspections 3.
Results of Bulletin Inspection severity and extensiveness of cracking 4
Remedial Measures 5.
UT detection and sizing limitations 6.
Date of next scheduled outage Ap/77
-13 !u! W3 Gy 1
9 NOV 0 3 ES3 Gary M. Holaban These factors are the principle basis for the preliminary staff position generated and presented as follows.
The staff position regarding BWR IGSCC is that a re-inspection program be initiated for piping systems operating above 200'F, with a piping diameter 4" or greater, and out to the second isolation valve of the primary coolant pressure boundary.
The general bases foe the above are found in safety consideration and isolatable portions, the coolant' makeup capability, field experiences on cracking suscept-ibility and laboratory test data. The program has evolved into five major parts:
Sampling Scheme Examiner Qualifications Evaluation and Repair Criteria Leak Detection Leakage Limits Yor Plant Shutdown The Sampling Scheme developed includes the following:
inspection of 20% of each pipe size of' unmitigated welds not previously inspected (minimum 4 welds) previously inspected welds (minimum 2 welds) all unrepaired cracked welds overlay repaired welds original crack length greater than 20% of the circumference sample inspection logic to follow IEB 83-02 The bases for the aforementioned points is found in ALARA considenations, results of Bulletin inspections and availability of examiner resotrces.
The Examiner Qualifications and Field Performance should conform to the
~
following:
UT Examiners (Levels 2 and 3)
Demonstration of performance capability and guidelines found in IEB 83-02
,u.
N0y 0 3 383 Gary M. Holahan UT Operators (Levels 1, 2 or 3)
Demonstration of field performance capability Viewing CRT display for evaluation Plant operation is permitted with cracked welds only for the time period that the cracks are evaluated to not exceed 2/3* of the limits for depth and length provided in ASME Code Secetion XI, Paragraph IWB-3640. Crack growth analyses must include any additional stress imposed on the weld by other weld repair operations, and each analysis must be approved by the NRC, Leak detection is highly focused following very closely with the criteria used for the five plants ordered to be shutdown. Specifically:
Leak detection systems shall be similar to the guidelines contained in RG 1.45 Leakage measurement instruments at least one operable instrument at each sump fix inoperable instruments within one day monitor sump level every four hou,rs or less visual examination for leakage during each plant outage when deinerted The staff recommended that leakage limits should be established for plant shut down. For a two gpm increase in unidentifiable leakage in 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, and/or five gpm total in unidentified leakage, plant shutdown should be initiated.
Overall replacement in lieu of repair was presented as the more desirable approach to be taken by licensees. Further, enclosure 3 was discussed and three plants were identifed as possibly requiring inspection as soon as practicable. They are Brunswick 1, Millstone 1 and Vennont Yankee. The enclosure does contain part of the basis / rationale for determining adequacy for the various plants.
Each licensee was then given an opportunity to conrnent. Their succinct remarks are presented below.
Oyster Creek Supports staff position
'*This criterion allows for an uncertainty of up to 100% in crack depth sizing for reported cracks up to 25% of wall thickness.
NOV 0 3 EE3 Gary M. Holahan 4-Nine Mile Point 1 has replaced recirculation piping core spray and emergency condenser supply line contain susceptible stainless steel and materials have been ordered to replace these lines - no commitment as yet.
Cooper Did 100% inspection Intend to replace all recirculation, CS and RWCU piping at next outage Millstone 1 Believe they have performed quite well on inspections conducted at date No comment on staff position Desired to make a presentation in the afternoon Vermont Yankee Support staff position Headed toward pipe replacement in 1985 Fitzpatrick No difficulty with presentation Intend to do additional IHSI, if efforts in January 1984 are successful Very low exposure rate plant Big Rock Point ho position Seeks a meeting with staff Monticello Replacing recirculation piping No problem with staff position Seven month outage to replace pipe Hatch 1,2 Hatch 2 to replace Hatch 1 may replace pipe Some concern regarding criteria Brunswick 1 Wanted to stbdy staff position Sought to meet with staff in afternoon Susquehanna Nn problens with staff position Planning to do IHSI
'TVA Supported and endorsed staff position g-,
,n r -
/
NOV 0 3 543 Gary M. Holahan '
Duane Arnold No problems with staff position Considerin,g IHSI Commonwealth No problems with staff position In conclusion, industry seemed to support our effort and direction taken.
The meeting adjorned with additional meetings to take place regarding the Peach Bottom Unit 2 IHSI concerns and plant specific meetings scheduled to be conducted with Millstone, Brunswick, and Vermont Yankee. As a result of these meetings, the staff will make a decision on expedited inspectinns of these plants.
/'}
v~
John. Zwolinski, Section Leader Operating Reactors Assessment Branch Division of Licensing
Enclosures:
1.
Meeting Notice & List of Participants 2.
Meeting Attendees 3.
Summary of Inspection Results and Schedules for Next Inspection cc w/ enclosure:
See next page i
I l
E. AJ 'c_ Lo s o R t-l
~
a nec,
u
- p
'o, UNITED STATES
['
}
NUCLEAR REGULATORY COMMISSION s.
E WASHING TON. D. C. 20$55
, % P/'.:I OCT 141983 Decket Nos. 50-155, 219, 220, 237. 245, 254, 259, 260, 263, 271, 277 278, 298, 321, 325, 331, 333, 366, 373 and 387 MEMORANDUM FOR:
Darrell G. Eisenhut, Director Division of L1 censing FROM:
Frank J. Miraglia, Assistant Director for Safety Assessment Division of Licensing
SUBJECT:
MEETING WITH SENIOR MANAGEMENT OF BWR LICENSED REACTORS TO DISCUSS FUTURE INSPECTIONS FOR IGSCC Dates and Times:
October 21, 1983 9:00 am - 12:00 noon 1:00 pm - 3:00 pm -additional plant specific discussions if required.
Location:
Room P.118 Bethesda, Maryland
Purpose:
To present the NRC position regarding BWR IGSCC to senior industry representatives and to afford BWR licensees the opportunity to discuss their future plans developed in response to IGSCC concerns.
Agenda:
The Agenda is enclosed.
Participants:
NRC RE0 VESTED PARTICIPANTS H. Denton, E. Case, E. Jordan, R. Vol'lmer, D. Eisenhut, W. Johnston, F. Miraglia, G. Lainas, T. Novak, G. Holahan, D. Vassallo, D. Crutchfield, J. Stolz BWR Licensees Senior management representatives for the utilities identified in Enclosure 1.
Frank J. Miraglia, Assistart Director for Safety Assessment Division of Licensing cc: Regional Administrators R. DeYoung, IE V. Stello, DEDROGR J. Fouchard, PA l
lO['#
)
Contact:
J. Zwolinski
- M!@d*N.ui~
ENCLO5URE 1 BWR UTILITY ATTENDEES 1.
Carolina Power and Light Company Brunswick 1 50-325 2.
Commonwealth Edison Company Dresden 2 50-237 Quad Cities 1 50-254 LaSalle 1 50-373 3.
Consumers Power Company Big Rock Point I
~
50-155 4.
Georgia Power Company Hatch 1 50-321 Hatch 2 50-366 5.
Iowa Electric Light & Power Company Duane Arnold 50-331 6.
Jersey Central Power & Light Company Oyster Creek 50-219 7.
Niagara Mohawk Power Corporation Nine Mile Point 1 50-220 8.
Nebraska Public Power District Cooper Station 50-298 9.
Northeast Nuclear Energy Millstone 1 50-245
- 10. Northern States Power Company Monticello 50-2o3'
- 11. Philadelphia Electric Company Peach Bottom 2 50-2'7 Peach Bottom 3 50-278
- 12. Power Authority of the State of New York FitzPatrick 50-333
- 13. Tennecsee Valley Authority Browns Ferry 1 50-259 Brewrs Ferry 2 50-260
~
14 Vermont Yankee Nuclear Power Vermont Yankee 50-271 1$. Pennsylvania Power and Light Susquehanna 1 50-387
1 I
. -ey. 9 gne,.
f;;Wk
}..
kE '. O
~^
. ' n ).
?
=
./ q.1 AGENDA
't 1
.y e Meeting with Senior 14anagement of BWRs Regarding ISSCC -
Opening Remarks (NRC) yt
_ z g. $.
Meeting Objectives Current Status NRC position regarding BWR IGSCC (scope of inspections, schedule, repeir criteria)
Long tem considerations Discussion Issues for Each Licensee (about 10 minutes average, per licensee)
Degree of inspection to date Schedule for next extended shutdown or refueling. outage Plans to conduct future IGSCC inspections and scope 'of inspections Availability of qualified inspectors, qualification of inspectors Repair Criteria s
l'
- i Compensatory measures, as applicable
!$, Ifl.j9f.}j.kn E(q
- s. <,
3 r,, u. e %..
GUIDANCE: The licensee should be prepared to make a prtsentat19n whighl s
addresses staff concerns contained in the agenda and 'to present other infomation deemed relevant to the issues generated j@P response to the NRR presentation.
.,n.
- " f.... d. V.j-
. c.t n
ARRANGEMENTS: The conference room will accommodate one or two. representatives
.. W N.-
from each of the invited licensees to be seate0 at the'puiin conference table.
Other senior licensee officials will p.
seated in the rows imediately behind each principle speaker.
., I.
, J '.
f, 3 e HQ,1 y%,
- .'...*.G.
-^
y.
r s
t N..
. ~h:
y c'
.l 4
e S
6 1
P N CLO S ORE Z.
MEETING WITH SENIOR MANAGEMENT OF BWR LICENSED REACTORS TO DISCUSS, FUTURE INSPECITONS FOR IGSCC OCTOBER 21, 1983 NAME ORGANIZATION TELEPHONE NO.
Robert C. Arnold GPU Nuclear (201) 263-6290 R. W. Keaton GPU Nuclear 201) '90 914A J. S. Chardos GPU Nuclear 201) 299-2287 C. V. Mangan Niagra Mohawk 315) 622-2155 Jay M. Pflant Nebr. Public Power Dist.
(402) 563-5325 Larry P. Kohles Nebr. Public Power Dist.
(402) 563-5381 W. G. Counsil Northeast Utilities (203) 666-6911 E. A. DeBarba Northeast Utilities (203) 666-6911 J. S. Kemper Phil. Electric (215)841-4502 E. C. Kistner Phil. Electric (215)841-4510 Andrew C. Kadak Vemont Yankee (617) 872-8100 Warren P. Murphy Vemont Yankee (802) 257-5271 Robert A. Burns New York Power Auth.
(914) 681-6275 Corbin A. McNeill New York Power Auth.
(315) 342-3840 Russell B. Dewitt Consumers Power (517) 788-1217 David J. Vandewalle Consumers Power (517) 788-1636 Joseph C. Danke EPRI (415)855-2071 Karl Stahlkopf EPRI (415)855-2073 Ed Kiss GE - San Jose (408) 925-6586 Dick Gridley GE - San Jose (408) 925-3732 David Musolf Northern States Power (612) 330-6764 Mike Anderson Northern States Power (612) 330-5542 Albert W. Zeuthen Long Island Lighting (516) 733-4487 George F. Head Georgia Power Company (404) 526-7893 Harvey Nix Georgia Power Company (404 526-7828 Al Bishop Carolina Power & Light Co.
(919 457-9521 Pat Howe Carolina Power & Light Co.
(919 457-9521 Robert J. Shov11n PA. Power & Light Co.
(215) 770-7536 Cornelius T. Coddington PA. Power & Light Co.
(215)770-7853 J. P. Ourrs USNRC 488-1282 Robin Galer GE - Licensing (408) 925-3747 Stu Savage NUS 258-2561 Drew Holland GPUN (201)299-2213 J. A. Gray, Jr.
NYPA (914) 681-6289 2
T. Dougherty NYPA (914)681-6281 A. R. Herdt USNRC - Region II 242-5585 Thomas Keefe Newport News Industrial (804)380-2244 R. W. Klecker NRC-DE R. J. Bosnak NRC-DE A. Taboada NRC-RES D. Sancic NYPA (914)681-6284 P. C. Riccardella Struc. Integrity Assoc.
(408) 978-8200 Marcello Galliani ENEL-Italy 8509-2578 Mohamad Behravesh EPRI NDE Center (704) 597-6170 David Crowley GE (408) 925-1147
NAME ORGANIZATION TELEPHONE NO.
Kathleen H. Shea Lowenstein, Newman 202)862-8400 David Wilson Iowa Elec. Light & Power 319) 398-4689 Ted Lambert
_LMT 408) 980-9333 B. L. Siegel OL/NRC Helen Nicolaras NRC/NRR
.)
W. R. Greenaway NUS (412 /8e-1080
)
Dick Clark NRC - Licensing (301 492-7162 G. M. Gordon GE (408 925-6421
{
J. P. Clark GE (408)925-6772 R. L. Perch NRR/DL/LD2 492-7235 L. S. Gifford GE (301) 654-0011 D. L. Pomeroy Scandpower Inc.
(301) 652-0883 J. O. Berga EPRI (202)872-9222 J. E. McEwen, Jr.
Tech. Services Indus.
(703) 759-7559 Ron Gamble Impell Corp.
(301) 654-2771 G. W. Rivenbark NRC/DL (301) 492-7136
- 5. Hou NRC/NRR/MEB (301) 492-8438 G. E. Gears NRC/DL (301) 492-8362 T. D. Myers Myers & Assoc.
(703)734-9327 R. Bala Ebasco Sarvices (212) 839-3233 Ken Herring NRC/0PE (212) 634 3302 J. R. Fair NRC/IE (301)492-7357 Robert S. Senseney NRC/0IP (301)492-9711 Paul H. Leach NRC/0RB#2 (301) 492-4952 Vernon Rooney NRC/0RB#2 (301) 492 8286 William Travers NRC/EDO Richard Emch NRC/0RB#5 (301) 492-7218 Robert Gilbert NRC/ ORB #5 (301) 492-7128 James J. Lombardo
.NRC/DL (301) 492-7167 John Pendlebury GE (301)654-0011 Marshall Grotenhuis NRC/ ORB #1 (301) 492-7367 William F. Kane NRC/EDO (301) 492-4354 Mohan C. Thadani NRC/NRR/DL (301)492-7380 P. S. Brown Delmarva Power (302) 429-3113 Jim Green TVA (615) 751-6911 L. M. Mills TVA (615) 751-2778 R. W. McGaughy Iowa Electric (319) 398-8154 R. F. Salmon Iowa Electric (319) 398-4574 K. V. Harrington Iowa Electric (313) 39B 4129 i
B. Rybak Commonwealth Edison (312) 294-3961 P. R. Matthews NRC/NRR/ DST (301) 492-4963 Rich Stark NRC/NRR (301) 492-8207 D. Crutchfield NHC/NRR/DL (301) 492-7403 D. Vassallo NRC/NRR/DL (301) 492-8053 J. Stolz NRC/NRR/DL (301) 492-8961 F. Miraglia NRC/NRR/DL (301) 492-7492 G. Lainas NRC/NRR/DL (301) 492-7817 i
A. Dromerick NRC/IE/DEPER (301) 492-4784 B. D. Liaw NRC/NRR/DE (301) 492 4360 t
s' 3-NAME ORGANIZATION TELEPHONE NO.
W. V. Johnston NRC/NRR/DE (301)492-7331 T. Speis NRC/NRR/ DST (301) 492-7517 J. Zwolinski NRC/NRR/DL (301 492-8543 D. Eisenhut NRC/NRR/DL (301 4532-76/2 R. Vollmer NRC/NRR/DL (301 492-7207 H. Denton NRC/NRR 301) 492-7691 Warren S. Hazelton NRC/NRR/DE 301)492-8075 Jere M. Ballentine Boston Edison 617) 424-3889 T. E. Spinn TVA 751-7865 John Raulston TVA 632 3063 R. W. Olson TVA 75173337 Mike Gothard TVA 615) 751-4982 Gary Pizl TVA (615)751-4691 Luther E. Willertz PA. Power & Light (115) 770-7745 Ray Hanford Carolina Power & Light (919) 362-2372 John Titrington Carolina Power & Light (919) 457 9521 J. A. Edwards Georgia Power Co.
(404) 52677011 Mike Belford Southern Company Serv.
(205) 877-7406 Pavlatte Tremblay SECY/NRC (202)634-1433 Bob Newlin NJtC/0PA (301)492-7998 Jim Shea NRC (301) 492-7231 L. J. Sobon NUTECH (408) 629-9800 G. M. Holahan NRC/NRR (301) 492-7415 M. Fairtile NRC/NRR (301) 492-9828
)
9
-e e
~
-vv'-
~
- ' ' " ^ ' ' ' * ' * -
~
h. N CLo s o RE 3 AITACllHENI A -
SUMMARY
Of INSPICIION RESULTS AND SClllDULES FOR NEXI INSPECTION I
EXIENT OF INSPECTION INSPECTION RESULTS a
s i
INSPl:CTION
(% OF NO. OF WELOS INSPECTEG)
(NO. OF CRACKED WLLDS)
NEXT SIZING PLAN 3 QilAl I TY' ItTClRC.
liflit RECIRC.
RilR RENEDIES OUIAGE CONCERNS 4 REMARKS Monticello A
100%, 106/106 78%, 18/23 6
0 Will replace 1/84 No recirc. All std overlay 8rowns A
27%, 25/91 28%, 9/32 2
0 Moisture sen-6/84 Yes Not IGSCC sitive tapes Maybe -
Ferry 2 4
~
fatigue i
Qu3d Cities 1 A
8%, 9/110 20%, 9/44 0
0 None 3/84 N/A 47%, 47/101 10%, 4/40 10 0
7 overlay 12/83 yes 0.2" overlay Dresalen 2 A
repaired.
(Mid-cycle) on 7 riser 11 water welds.
c$emistry Y
Millstone 1 M2 11%, 11/100 0%, 0/46 0
0 None 7/84 N/A Hztch 1 A
4 3, 47/100 100%, 11/11 5
2 6 overlay 2/84 Yes Mostly xial repaired.
(unscheduled) cracks.
1-acoustic i
device.
Brunswick i H
25%, 29/115 75%, 3/4 3
0 All overlay 3/85 No All axial repaired.
cracks.
]
e k
. EX1ENT OF INSPECTION INSPEC110N RESULIS s
4 3
INSPECTION
(% OF NO. Of WELDS INSPECTED)
(NO. Of CRACKED WELDS)
NEXT SIZING PLANTS QUALITY' RECTRC.
RilR RECTRC.
HilR REME01ES OUTAGE CONCERNS 4 REMARKS Oyster Creek A
39%, 31/80 0
0 None 4/85
/A Duane Arnold A
42%, 49/117 40%, 2/5 0
0 None 10/84 N/A Peach A
91%, 77/85 92%, 35/38 10 5
All overlay 2/85 No Moisture Bottom 3
{
repaired.
tape on all Moisture tapes repaired &
lilSI yninspected welds.
A+
66%, 58/88 7%, 2/30 33 1
22 overlay 6/84 Yes Mini-overlay Vermont Yankee repaired.
Hoisture tape on 7 unin-spected welds.
33 14 Overlay re-2/85 Yes Mini-ovkrlay Browns A
100%, 91/91 100%, 32/32 Ferry 1 paired some (still in outage)
Ccoper A
100%, 108/108 100%, 7/7 20 0
13 overlay 10/84 Yes repaired llatch 2 A
94%, 97/103 100%, 11/11 36 3
27 overlay 1/84 Yes repaired.
Plan to replace 4
i t
h EXTENT OF INSPLCil0N INSPECTION RESULTS s
a INSPECTION
(% OF NO. OF WELOS INSPEC1ED)
(NO. Of CRACKED WELDS)
NEXT SIZING PtANTS
()UAl.l TY 8 kTCTRC.
filTR R RIRC.
RilR REMEDIES OUTAGE CONCERNS 4 REMARKS Big Rnck A
20%, 11/59 0
0 N/A 10/84 No Point fitzpatrick A8 47%, 49/106 45%, S/11 1
0 None 3/85 Yes Peach A
100%, 85/85 100%, 38/38 18 7
18 overlay 3/84 No Bottom 2 repaired i
(still in outage) IHSI (16 welds) 4 8 Inspection Quality: A-adequate, M-marginal.
2 Post inspection qualification test, passed the test after the second try.
I 3 Inspection personnel qualified under IE8-82-03 thru grdndfathering.
4 Sizing concerns: Yes - having unrepaired weld or mini-overlay.
No - cracked welds h. ave been repaired by full strength overlay.
6 Number of welds based on last available information.
8 Outage time based on current staff information.
e I
l.
9 l
EXTENT OF INSPECTION INSPECTION RESULTS s
a i
INSPECTION
(% of NO. OF WELDS INSPECit0)
(NO. Of CRACKID WELDS)
NEXT SIZING l
PIANIS QtlAtlIY8 liECIRC.
RIijt RECIRC.
RilR REMEDIES OUTAGE CONCERNS 4 RENARKS Big Rock A
20%, 11/59 0
0 N/A 10/84 No Point i
fitzpatrick A3 47%, 49/106 45%, S/11 1
0 None 3/85 Yes Peach A
100%, 85/85 100%, 38/38 18 7
18 overlay 3/84 No Bottom 2 repaired (still in
~
i' outage) IHSI (16 welds) 3 Inspection Quality: A-adequate, M-marginal.
2 Post inspection qualification test, passed the test. af ter the second try.
3 Inspection personnel qualified under IE8-82-03 thru grdndfathering.
4 Sizing concerns: Yes - having unrepaired weld or mini-overlay.
No - cracked welds have'been repaired by full strength overlay.
L Ntadier of welds based on last available information.
G Outage time based on current staff information.
s 4
. _ _..