IR 05000338/1993011
| ML20035E927 | |
| Person / Time | |
|---|---|
| Site: | North Anna  |
| Issue date: | 04/08/1993 |
| From: | Blake J, Economos N, Samson Lee NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20035E918 | List: |
| References | |
| 50-338-93-11, 50-339-93-11, NUDOCS 9304200080 | |
| Download: ML20035E927 (17) | |
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%g UN11ED STATES
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NUCLEAR REGULATORY COMMISslON
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101 MARIETTA STREET, N.W.
- ATLANTA, GEORGI A 30323 o
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Report Nos.:
50-338/93-11 and 50-339/93-11 Licensee:
Virginia Electric and Power Company Glen Allen, VA 23060
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Docket Nos.: 50-338 and 50-339 License Nos.:
NPF-4 and NPF-7 Facility Name:
North Anna 1 and 2 Inspection Conducted: March 8-12, 1993 Inspectors:
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<3 N.'EFonom6s F
JrateAigned
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S'. S' Lee P
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9/l/93 Approved by:
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J/J. Bl#Re, Chief
'Date Signed l
!)a rials Process Section f ineering Branch Division of Reactor Safety SUMMARY
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Scope:
This routine, announced inspection was conducted in order to observe certain steam generator replacement project (SGRP), activities in Unit 1, including:
post-weld heat treatment, review of radiographs, cleanliness inspections of primary and secondary boundary spaces, system hydrostatic testing, monoball sliding restraint damage, preservice inspection of new welds and repair of main feedwater pump defective welds.
Information contained in this report includes input from S. S. Lee on temporary assignment while SGRP is in progress. His input covers the time period between February 26, 1993, until March 29, 1993.
Results:
All welding and testing activities involving primary and secondary systems were completed in a safe and satisfactory manner. System hydrostatic testing on the secondary side, began on the 12th of March 1993, and was completed soon afterwards satisfactorily. As such, the inspectors have determined that the steam generator replacement project of North Anna Unit 1, was completed without significant problems.
Good planning, training, communications and 9304200080 930409 PDR ADOCK 05000338 G
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cooperation between contractors and the licensee played a big role towards l
this end. QA/QC organizations were proactive in their areas of responsibility.
In these areas the licensee showed significant strength.
Three concerns were brought to the licensee's attention, these were:
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Radiographic film quality did not meet the licensee's standards
thus radiographs required reshooting which caused unnecessary project delays.
A more restrictive procedure would have prevented
these difficulties.
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A lack of attention to details, during the planning and/or design stage, resulted in primary loop weld surface contour condition
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which precluded full examination of new welds and adjacent base metal. This condition resulted in a submittal to NRR for code i
rel ief.
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Removal of protective coating material (paint) drippings from the
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OD surfaces of the primary loop was not given the priority and attention required to remove it at the time it was discovered.
Within the areas inspected violations or deviations were not t
identified.
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REPORT DETAILS j
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Persons Contacted i
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l Licensee Employees
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R. Bayer, Engineering Supervisor, SGRP l
R. Carroll, Jr., Administrative Services Supervisor j
- G. Clark, Manager, QA
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D. Dodson, Corporate Level III, Examiner
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- M. Gettler, Project Manager, SGRP J
- D. Heacock, Superintendent Engineering G. Jones, Quality Control SGRP
- G. Kane, Station Manager
- P. Kemp, Supervisor - Licensing
- J. Leberstein, Staff Engineer - Licensing
- J. O'Hanlon, Vice President - Nuclear Operations
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- P. Quales, Supervisor QA
- B. Shriver, Acting Assistant Station Manager
- J. Smith, Manager QA
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L. Spain, Materials Engineer SGRP
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R. Stack, level III UT Examiner
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J. Stall, Acting Assistant Station Manager
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E. Throckmorton, Supervisor ISI/NDE Licensing H. Travis, Supervisor, NDE Other licensee employees contacted during this inspection included technical support, QA and administrative personnel.
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Other organizations Bechtel Group Inc. (Bechtel)
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l L. Bennet, Welding Engineer l
R. Miller, Project Manager
l B. Reilly, Asst. Project Manager
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T. Sarma, Project QA Manager
J. Seccon, Welding Coordinator J. Senecal, Welding / Mechanical QC Engineer NRC Resident Inspectors
- D. Taylor, Resident Inspector
- Attended Exit Meeting i
i 2.
Preservice Inspections (PSI), (IP73053/73755)
Primary Loop Piping Welds i
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As stated above, the primary loop piping had been severed and rewelded at the steam generator nozzles.
Section XI (83S83), of the ASME Code requires a PSI of these welds to establish a baseline for subsequent inservice inspections (ISI). Because subsequent ISI of these welds will be based on ultrasonic testing (UT), the PSI is based on UT.
On March I, 1993, the inspectors observed the UT of the S/G "B" hot leg welds. The UT was performed by two of the licensee's Level III UT examiners to assure data accuracy and verification.
l UT had been performed, by the licensee's contractor a few days earlier,
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from four directions including the nozzle side and the pipe side to provide the Code-required volume coverage for the primary loop piping welds. At the time, the inspectors observed that the UT examination from the nozzle side produced significant non-relevant signals form geometric condition that may mask UT signals for relevant indications during future ISI. The UT had been performed with dual 45' longitudinal wave transducers focussed near the ID. The nozzle material was forged and the pipe elbow material was cast.
The licensee's, Level IIIs confirmed the presence of UT signals from geometric conditions using the 45' longitudinal wave transducers and examining from the nozzle side. Then, the NDE Level IIIs used a 60*
shear wave transducer and repeated the examination of the weld from the nozzle side. The shear wave signal from geometric conditions was reduced from that obtained using the 45* longitudinal wave transducer.
This indicated that the shear wave examination might be useful in discriminating geometric conditions.
The shear wave examination was performed for the Loop "B" hot leg and cross-over leg for future reference in case a shear wave examination is needed in evaluating ISI signals. Based on echo-dynamics of the UT signals observed from geometric effects, the licensee's NDE Level IIIs concluded that geometric indicators would not hinder future ISI examinations.
Section XI of the ASME Code and Code Case N-460 (Alternative Examination Coverage
.....), require examination of greater than 90 percent of the specified volume, which is the bottom 1/3 of the weld for the applicable Code edition (1983 Edition Summer 1983 Addenda). The licensee indicated that the OD profile of the new welds had limited the UT examination to approximately 80 percent of the specified volume for four out of the six new loop piping welds.
In view of this difficulty, the licensee was preparing a Code relief request for NRC review. The inspectors found that the licensee had shown apparent weakness in his failure to provide adequate accessibility for ISI examinations of the new primary loop piping welds. The OD profile of the new welds should have been designed and contoured with a geometry which would facility preservice/ inservice volumetric (ultrasonic) examinations of the code-required volume.
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o Feedwater and Mainsteam Welds Feedwater and mainsteam line welds require preservice volumetric examinations by Section XI of the ASME Code. These examinations are done using qualified ultrasonic procedures and personnel as required by the above mentioned code.
Inspection procedures and results for the
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subject welds were discussed with cognizant licensee personnel including those at the corporate office. During these discussions the inspectors addressed the matter pertaining to the time during which these examinations were to be performed, which is usually after postweld heat treatment is completed. However, in the case of the subject welds, it
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appeared that the licensee had elected to perform PSI, before final post weld heat treatment.
The inspectors questioned the correctness of this practice and the licensee responded by issuing Deviation Report N-93545
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and procedures to re-examine the subject welds. On March 12, 1993, the licensee provided the inspectors with a copy of a table from DCP 90-13-1 Appendix 4-21, page 4 of 4 entitled, Field Inspection of Welds. This table showed that the subject welds were scheduled to undergo baseline examination after postweld heat treatment.
By review of the information in this table, it appeared to the inspectors that the licensee's NDE group had not followed DPC requirements and had performed the baseline examination out of sequence; suggesting that there was validity to the finding.
Following the close of this inspection, the licensee provided the inspectors with new information (addenda 19'/0 to 1969 B31.7), which
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stated that the required NDE/ baseline could be performed either before or after postweld heat treatment.
By this new information, the inspectors ascertained that the licensee had met DCP and code
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requirements in this matter.
Within the areas inspected, violations or deviations were not identified.
Relief Request for limited Baseline Inspection of Primary Nozzle to Pipe o
WeldsSection XI of the ASME Code specifies the volume of weld and adjacent
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base metal material for examination.
Further, by Code Case N-460, the Code accepts a reduction in the volume examined provided that reduction is less than 10% of the required volume.
If the Code-required examination is not fully achieved, 10 CFR 50.55a(q) requires licensees to submit a relief request for NRC approval.
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l In the case of reactor coolant loop welds, the licensee had scanned the
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required volume of weld and base metal in four directions as required by l
the Code. A certain percentage of the specified volume was covered by
l each UT scan and documented. However, in order to determine the actual i
volume covered by the baseline examination, the licensee calculated the percent volume covered by each of the four scans and determined the average and used that figure as the percent of the volume of weld covered by the examination. An example of this approach is shown below:
Licensees's Scan Percentage of Designation No.
Volume Coverage
'2'
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'5'
100
'7' (same for '8')
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Then, the licensee calculated the average as
(83 + 100 + 90) / 3 = 91 In this manner, the licensee was able to show that 91 percent of the specified examination volume had been covered even though three of the four scans did not achieve their objectives. By this method, the licensee determined that the Code requirements had been met and did not plan to submit a relief request for this particular weld.
Because the inspectors disagreed with this method of calculation, they contacted NRR i
and discussed the licensee's use of average values in determining the
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extent of volume coverage.
NRR was of the view that a calculated
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average would be inappropriate and that the percentage of volume
coverage should be evaluated on a scan by scan basis. This position was related to the licensee who is considering this information in preparing the pending relief requests.
This item was identified as inspector followup item, (IFI),
50-338/93-11-01, Method of Calculating the Reduction in Examination Coverage, to permit tracking of this Code relief resolution.
o Review of PSI Ultrasonic Data (IP73055)
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Records of ultrasonic examinations performed on the new welds to satisfy Section XI preservice requirements were reviewed for completeness and accuracy. The applicable Code has been identified in previous i
paragraphs of this report. Welds selected for this review were as follows-
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Weld #
Location DWG #
% Coverage per l
Scan Direction l
W-29 Loop "C" Cold Leg 31"-RC-8-250lR-Q1
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W-4A Loop "A" Hot Leg 29"-RC-1-250lR-Q1
- 2-100, #5-70, #7&3-75 W-5A Loop "A" Cold Leg 31"-RC-2-250lR-Q1
- 2-91, #5-94, #7&B-80 W-16A Loop "B" Hot Leg 29"-RC-4-250lR-Q1
- 2-100, #5-62, #7&8-90
W-17 Loop "B" Cold Leg 31"-RC-5-250lR-Q1
- 2-62; #5-100; #7&8-90 W-28A Loop "C" Hot Leg 29"-RC-7-2501R-Q1
- 2-78; #5-100; #7&8-90
65-W Main Steam Pipe to 32"-SHP-2-601-Q2 100%
Pipe
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52-W Main Steam Pipe to 32"-SHP-3-601-Q2 100%
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Pipe
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Except for the problem concerning the method used to calculate
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percentage of volume examined, these records appeared to be in i
order.
Within the areas inspected violations or deviations were not identified.
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3.
Post-Weld Heat Treatment (PWHT) of Girth Weld (IP 55050)
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On February 26, 1993, the inspectors observed the installation of PWHT l
equipment on the B steam generator girth weld. The PWHT was to be
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performed for the girth weld and the feedwater nozzle-to-elbow weld
simultaneously.
A total of 61 thermocouples, including four on the inside diameter (ID)
l of the steam generator and eight on the feedwater nozzle, were to be
used.
PWHT was to be performed locally using electric resistance
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heating pads attached to the outside diameter (OD) of the steam i
generator shell.
Electric heaters covered about a 10-foot wide band of
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the steam generator shell. The ID and OD surfaces of the steam i
generator shell were insulated.
l A band around the steam generator covering 24 inches about the
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centerline of the feedwater nozzle and 2 inches below the girth weld was to be soaked at a PWHT temperature of 1125 25*F for 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and 45
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minutes.
This would maintain a uniform temperature region above the i
feedwater nozzle and the steam generator transition cone.
Heat up and l
l cool down would be at a rate less than 100*F/ hour when above 600*F. The temperature, soak time, heating and cooling rate, and region of PWHT l
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coverage were based on the requirements of Section III of the ASME Code.
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l Even though the allowable PWHT temperature in Section III of the ASME
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Code for the steam generator shell materials was between 1100*F and 1250*F, the licensee imposed a more restrictive upper limit of 1175*F to minimize the potential for excessive heating of the material.
Following completion of PWHT of the S/G "B" girth weld and feedwater nozzle weld the inspectors reviewed the PWHT temperature data provided by the licensee's subcontractor, Cooperheat. The inspectors also reviewed the PWHT temperature strip chart records for completeness, clarity, and accuracy. The data indicated that the soaking temperature was above the Code minimum of Il00*F.
Because the temperature at a thermocouple on the 10 was relatively low, heaters were energized to maintain the temperature of this ID thermocouple above 1100*F. This resulted in some other thermocouple exceeding Il50*F during soaking time, with one thermocouple reaching Il88'F.
Because the temperature exceeded ll75'F, which was the upper limit established by the licensee, an engineering evaluation would be performed.
(See the licensee's Nonconformance Report (NRC) No 0065).
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On March 5,1993, the inspectors observed the PWHT of S/G "A" girth weld
and feedwater nozzle.
The inspectors noted that the soaking temperature was above the Code minimum at 1100*F, with the exception of one thermocouple, which reached ll61*F.
On March 7,1993, the inspectors observed the PWHT of S/G "C" girth
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weld and feedwater nozzle. The inspectors noted that the soaking temperature was the Code minimum of Il00*F, with the exception of one
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thermocouple which reached ll63*F.
The temperature at one ID
thermocouple, was at 1090*F for a brief period of time during soaking.
As a result, the licensee increased the time period at soak to ensure that the cumulative soak time at above 1100*F would meet the Code requirements.
(See NCR no. 0071).
o Summary Table of PWHT for Welds Reviewed:
The inspectors reviewed a sample of PWHT records, Field Welding Checklists (WR-5), and QC Inspection records of completed welds.
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following is a summary table of PWHT soak time and temperatures for selected feedwater, mainsteam and S/G girth welds-
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Weld No.
Drawino No.
Size Soak Time Temperature
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FW59 FSK-M-Il5 R/0 3/4"x 16" I hr.
1280*F FW17A FSK-M-ll5 R/0 Nozzle 2 hr. 55 min.
Il40*F to ELL
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FW60 FSK-M-ll5 R/0 3/4"x 16" I hr.
1205'F FW55 FSK-M-Il5 R/0 16"x.844" 1.5 hr.
1280*F FW56 FSK-M-126 R/0 16"x.844" 1.5 hr.
1280*F FW57 FSK-M-Il5 R/0 16"x.844" 1.5 hr 1280*F FW42Cl FSK-M-Il6 R/0 16"x.844" I hr. 10 min.
1280*F J
FW43Cl FSK-M-Il6 R/0 16"x.844" I hr. 15 min.
1280*F j
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Drawina No.
Size Soak Time Temperature Feedwater l
FW44 FSK-M-116 R/0 16"x.844" I hr.
1280*F
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FW45 FSK-M-ll6 R/0 16"x.844" I hr. 15 min.
1280*F l
FW17A FSK-M-ll6 R/0 16"x.844" I hr.
1280*F FW62 FSK-M-Il4 R/0 Socket 3/4" I hr.
1280*F
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Main Steam, S/G "B" FW65W FSK-M-064 R/0 32"x 3.68" I hr. 15 min.
Il75'F
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Girth Weld S/G "B" FW2 FGK-M-043 R/I 170.32"x 2 hr. 55 min.
Il75'F 3.68" i
Within the areas inspected violations or deviations were not identified.
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4.
Review of Final Radiographs (IP57090)
l The inspectors reviewed radiographs and associated reader sheets for selected welds in the Main Steam and Feedwater systems and girth weld in i
S/G "C".
The radiographs were shot in accordance with procedure RT-
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ASME, Rev.3, which referenced ASME Code Section III, 1986 Edition as the
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applicable Code. The radiographs and associated records were reviewed
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to ascertain whether radiographic and film quality were satisfactory and whether evaluation and disposition of rejectable indications were
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consistent with Code requirements. Welds selected for this review were as follows:
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FW-43Cl FSK-M-Il6 16"x 0.844" Elbow to Pipe FW-42C2 FSK-M-ll6 16"x 0.844" Elbow to Elbow
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FW-44 FSK-M-116 16"X 0.844" Elbow to Pipe
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FW-17A FSK-M-116 16"x 0.844" Elbow to Pipe FW-41C1 FSK-M-116 16"x 0.844" Elbow to Pipe Main Steam FW-17A FSK-M-115 32" x 1%"
Nozzle to Elbow FW-70W FSK-M-063 32" x 1%"
Pipe to Pipe FW-52W FSK-M-065 32" x 1%"
Pipe to Pipe S/G "C" airth Weld FW-3 FSK-M-044 135.5"x 4" Upper to Lower Shell
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Within these areas, the inspectors noted that film quality, with regards i
to development, lacked consistency, in that roller marks fror the automatic developer and artifacts were observed on several films. Also,
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it was noted that, inaccurate information regarding type and location of
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indications had been recorded on the reader sheets for weld FW17A.
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Although the presence of film artifacts and developer roller marks on
the film did not necessarily render the film rejectable by Code, the
licensee's Level III examiners persistently rejected radiographs for lack of acceptable quality and requested reshooting of several welds including S/G "C" girth weld. Although film quality was a continuing problem on this project, the licensee's persistence on high film and i
radiographic quality i.e. sensitivity, showed significant strength in this area.
Within these areas violations and deviations were not identified.
5.
Hydrostatic Pressure Testing (IP70362)
o Secondary Side
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Section XI of the ASME Code requires a hydrostatic pressure test after a repair or replacement. The applicable code wasSection XI,1983 Edition and Summer 1983 Addenda. On March 6, 1993, and March 10, 1993, the
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inspectors discussed with the licensee plans for hydrostatic tests. The licensee indicated that hydrostatic pressure tests for the secondary side of the steam generator and the primary loop side would be performed i
in accordance with Section XI.
L On March 10, 1993, the inspectors accompanied the licensee on a system i
walkdown in preparation for the hydrostatic test. The licensee
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identified locations of applicable valves and gages in the main steam i
valve house that would be used in this test.
The inspectors also examined three temporary pumps that would be used in the hydro. The
inspectors reviewed the applicable procedure D-NAT-90-13-1-1 and found it to be in order.
i The licensee would fill the secondary side of S/G "B", using the primary grade (PG) water pump and vent through the valve on top of the main steam line (1-MS-42) according to procedure 1-0P-33.2.
Then, the steam
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generator would be pressurized through the auxiliary feedwater system (1-FW-271) using a hydrolazing pump.
During the test hold time, the hydrostatic pressure would be maintained by a smaller variable speed pump. The main pressure gage would be a gage added to a steam generator level instrument line near a level transmitter (1-FW-LT-1484).
The main pressure gage would be at a level about one foot above the
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tubesheet.
A backup pressure gage would be located on the main steam line at 1-MS-240. The pressure could be manually released through a valve on one of the main steam lines in the main steam valve house.
Pressure relief protection would be provided by a relief valve located on the pump.
Similar procedures were available for the A and C steam generators. The licensee had originally intended to perform the secondary side hydrostatic test at less than the ASME Code requirement
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because the NRC had granted certain relief for the licensee's 10-year ISI program. However, the Authorized Nuclear Inservice Inspector (ANII)
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found it inappropriate to apply a code relief intended for a 10-year ISI program, to the SGRP.
In addition, the inspectors found no basis for i
relief from the hydrostatic test requirements after the repair because i
the test was apparently not impractical.
Following internal discussions, the licensee decided to perform the secondary hydrostatic l
test as required by the applicable code.
The secondary side hydrostatic pressure test would be performed at 1.25 times the lowest pressure relief valve set point which would give a
hydrostatic test pressure of 1356 psi.
Because the system would be
insulated, the hydrostatic pressure hold time would be 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The
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test would be performed at 70*F above S/G metal temperature this parameter was in response to fracture toughness considerations for the
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re-used old steam dome.
To ensure that this temperature would be
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achieved, the PG water would be heated to 120*F.
l o Observation of Hydro, S/G "B" Secondary Side
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On March 12, 1993, the inspectors observed the pre-job briefing and the secondary side hydrostatic pressure test of the B steam generator.
The metal temperature of the steam generator measured at the hand hole was about 95*F after filling the steam generator.
During pressurization, a packing leak was detected in a newly installed blowdown valve (1-BD-11),
at about 1000 psi and required tightening. The pressure at the 4-hour hold was stable at about 1380 psi.
The inspectors observed the Code
"VT-2" visual examination after the 4-hour hold. No leakage was
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identified by the licensee.
However, the licensee identified condensation in the channel head, which was more evident on the hot leg i
side of the S/G.
O Primary Side
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For the primary hydrostatic pressure test, the licensee would perform the test as a part of reactor start up, according to procedure 1-PT-171.2.
After the fuel is loaded and the reactor vessel head tensioned, the licensee would heat up the primary side by running the reactor coolant pumps.
The hydrostatic test would be performed in Mode 3 at above 500*F. The temperature was selected based on fracture toughness considerations for the reactor vessel. The primary hydrostatic pressure test would be performed at 1.02 times the operating pressure which would give a hydrostatic test pressure of 2279 psi. The test pressure would be achieved by using the pressurizer heaters.
Because the system would be insulated, the hydrostatic pressure hold time would be 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.
In summary, the inspectors found that the licensee had demonstrated i
above average strength in planning the hydrostatic pressure test. The i
I licensee had considered the leak tightness of various valves at the l
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hydrostatic test boundary. When applicable, the licensee had filled beyond the test boundary to leak-tight isolation valves to prevent valve leak-by during hydrostatic test. The hydrostatic pressure test was
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completed without any unusual events.
Within the areas inspected violations or deviations were not identified.
l 6.
Facility Modifications (IP37700)
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o Cleaning of Steam Generator Channel Head Bechtel Work Plan and Inspection Record (WP&IR) No. WR-06.02. 00-13,
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" Removal of Tubesheet Protection.
Bowl Protection, and Debris Dams from S/G's A, B, C," describes the procedures to clean the channel head area after all work had been completed inside the channel head.
On March 4, 1993, the inspectors observed cleaning out of the S/G "B" i
channel head on the cold leg side and, S/G "C" channel head on the hot
leg side. The tubesheet protective cover had been held in place by
attachment plugs inserted into some tubes. After removal of these plugs l
and the tubesheet protective cover, the tubes where plugs had been, were
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l swiped with isopropyl alcohol. After the removal of protective covers
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from the channel head interior, the inside surfaces were also swiped
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with isopropyl alcohol to remove tape residues.
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The inspectors noted that the isopropyl alcohol carried a Bechtel Consumable Material Evaluation (CME) color code that required this
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l substance to be removed after use on stainless steel and Inconel I
materials.
In the case of North Anna 1, new tubes were fabricated from Inconel; the tubesheet was clad with Inconel; the divider plate was
fabricated from Inconel; and the channel head was clad with stainless
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steel.
In discussing the acceptability of using isopropyl alcohol on the aforementioned material, the licensee produced the specific CME for isopropyl alcohol which permitted its use inside the channel head.
i However, the inspectors noted that the specific CME did not permit the substance to be left as-is after use. But the specific CME did not provide cleaning procedures and/or requirements either. The licensee j
indicated that the large volume of water used in the subsequent hydrostatic pressure test would clean any residual substance from the channel head surfaces and therefore there were no grounds for concern.
On March 10, 1993, the licensee provided the inspectors with a copy of Bechtel Construction Change Request (CCR) No. M-006. dated November 12, 1992, documenting that the licensee had evaluated the application of isopropyl alcohol for cleaning the steam generator. The CCR permitted the use of isopropyl alcohol as a cleaning solvent for the primary side of the new steam generators. As indicated in the CCR, the licensee's Specification for Repaired Steam Generators (NAP-0001) had approved the use of isopropyl alcohol for cleaning the new steam generator. The CCR t
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stated that a water rinse after using isopropyl alcohol would not be necessary if wiping was performed with a white lint-free cloth. The i
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licensee indicated that the channel head was cleaned according to this CCR and would not require rinsing of the isopropyl alcohol from the cleaned surfaces.
l Within the areas inspected violations or deviations were not identified.
o Removal of Protective Cover Over Tube Bundle The tube bundle had been protected with a protective cover sheet-metal structure design called a " bee hive".
Between the " bee-hive" and the
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top of the tubes was a protective sheet of fabric material. After work inside the steam dome was completed, the " bee-hive" had to be removed.
On March 8, 1993, the inspectors observed the mock-up training for removing the " bee-hive." The work required that the sheet-metal " bee-hive" be cut into small pieces with an electric shear and any metal
shavings would be collected and disposed of in designated containers.
On March 9, 1993, the inspectors observed the cutting and removal of the l
" bee-hive" from the B steam generator.
The structure was cut into small l
pieces about a foot wide spanning a quarter of the " bee-hive" or less.
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Cutting started circumferentially from the center of the " bee-hive" and progressed outward towards the wrapper. Cut pieces were removed from the steam dome through the manway. After most of the " bee-hive" had been removed, a worker cut the remainder by laying on cushions placed on the tube bundle. The fabric cover below the " bee-hive" was then
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removed. The personnel access holes on the steam generator wrapper were welded closed, in preparation for cleanliness inspection and hydrostatic
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testing.
l Foreign Object Search and Retrieval (FOSAR) Inside Primary Piping
The primary loop was severed at the steam generator nozzles to permit the removal of the old steam generators. The piping was cut by
machining without any debris dam installed inside the pipe. Therefore, a small amount of machining chips from pipe severance was deposited l
inside the primary piping.
Earlier the licensee had performed F0SAR
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mock-up training to ensure that the machining primary piping welds had been completed.
On March 1, 1993, the inspectors observed the FOSAR of "A" loop cross-over piping. A video camera mounted on a sled was pushed inside the pipe through the steam generator manway.
The cross-over leg descends from the steam generator and forms a loop in the loop room about 15 feet below. The FOSAR camera found that small amounts of machining chips had collected at the bottom of the loop.
Subsequently, a vacuum hose, about 2 inches in diameter, was inserted into the pipe and maneuvered to the location of the chips where they were removed and cleanliness restored.
The F0SAR was completed successfully and the camera images were recorded on videotape.
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FOSAR of the primary piping, i.e, hotleg and cross-over leg,- for all y
three steam generators has since been completed.
o F0SAR, on Steam Generator Tubesheet
After the protective cover over the tube bundle had been removed and the personnel access hole covers welded, F0SAR was to be performed to
retrieve debris on the tubesheet.
The F0SAR was to be performed in the following areas:
the annulus between the steam generator shell and the
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tube bundle; the blowdown lane between the hot and cold legs of the tube l
bundle; and within the tube bundle between the tubes.
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On March 9,1993, the inspectors observed the F0SAR trial for the "B"
steam generator tubesheet annulus area. A video camera was mounted on a
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small cart which was controlled remotely. A semicircular strip of sheet
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metal (shovel), was mounted in front of the cart to drag objects for retrieval. An electro-magnet was also mounted on this device to retrieve magnetic objects. The cart was placed onto the tubesheet
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annulus area through the hand hole.
The cart travelled through the
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entire annulus area without encountering obstructions. Minor items of debris were located and retrieved from the annulus area.
The inspectors also examined the video probe that would be used to
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perform F0SAR between tubes from the tube lane. The probe would be pushed into the tube rows manually to examine the tubesheet area around all the tubes. A guide tube would be inserted through the hand hole to guide the probe. However, because of space restrictions between tubes, foreign objects found could not be retrieved. This video probe would i
also be used to inspect the blowdown lane.
Following the close of this inspection, the licensee completed F0SAR on the tubesheet for the "B" steam generator.
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i o Dripped Coating Material on Primary Pipe OD Surfaces
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l The licensee applied an encapsulant coating to the old steam generators j
to minimize the potential for loose contamination during their removal.
As discussed in Inspection Report No. 93-09, the licensee inadvertently dripped unqualified coating on the A, B, and C loop primary piping OD surfaces when applying the encapsulant.
The licensee issued NCR No. 0028 on January 28, 1993, to describe corrective actions for removing the drips of coating from the primary piping. On February 27, 1993, the licensee closed out the NCR stating that the dripped coating material had been removed from the OD surfaces of the subject piping.
On March 1, 1993, the inspectors examined the primary piping and found dripped coating material as follows:
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Location Dripped Coatina
"B" cross-over leg 1-inch long and %-inch wide streak on
side of pipe
"C" hot leg 1 square inch on top of pipe near loop j
isolation valve
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"C" hot leg Spots on underside of pipe
"C" cross-over leg Incomplete cleaning with visible remnants f
of the coating material The inspectors notified the licensee of the continued presence of the subject coating material on the primary loop surfaces.
Following discussion, the licensee initiated new NCRs (Nos. 0060 and 0074), to
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describe further corrective actions for removing the remaining coating
material.
l The inspectors found that the licensee showed an apparent weakness in implementing adequate corrective measures for removing this unqualified coating material from the primary piping in a timely manner. The inspectors had many discussions with the licensee relative to this matter and were told that this material would be removed sometime before the plant is turned over to the station. The inspectors will continue
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to monitor this matter and will document the outcome in the report of i
the next scheduled inspection.
t o Restriction on Movement of Valve Handle Bar On March 4,1993, the inspectors learned through informal discussions with craft, that the handle bar on a newly installed "A" loop drain i
valve could not be turned because of interference with an adjacent spring can support.
The inspectors verified the information provided and discussed the matter with the licensee who indicated that these type of problems would be detected and corrected during walkdowns.
On March 8, 1993, the licensee showed the inspectors the severed ends of
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the valve handle bars which had been cut from the "A" and "C" loop drain i
valves to remove the interference with supports. The licensee indicated that similar actions would be taken for loop drain valve (s) when installing supports.
o Monoball Sliding Restraints Damage on Feedwater Piping The feedwater line was supported at various places inside and outside containment by so-called monoball sliding restraints (MSR) which would permit horizontal pipe movement but would not permit vertical pipe movement. However, the horizontal pipe movement was limited to the
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amount predicted in the piping analysis.
As discussed in Inspection
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Reports 93-08 and 93-09, the inspectors found the feedwater pipe had
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pushed against two of the MSR outside containment in the mechanical
equipment room.
On March 5,1993, the inspectors examined the two damaged MSRs after they had been disassembled. The bronze casing of the MSR had several
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long cracks on the top end near the pipe.
The sliding plate surface,
containing graphite inserts, appeared to be in good condition. The
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licensee removed the load bearing shafts from the MSR to conduct a i
liquid penetrant test (PT) for cracks. The welds on the pipe support
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saddle would also be examined by magnetic particle testing (MT). The licensee indicated that there was no apparent pipe movement when the MSR were disassembled indicating that the damaged MSR did not overly
restrict pipe movement and would not introduce significant stresses in
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the pipe.
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The licensee indicated that the damaged MSR would be replaced with others of a different design. The new MSRs will consist of a sliding
plate without limitations on horizontal pipe movement and will not limit pipe up lifts. The inspectors indicated that the licensee should l
consider measuring the horizontal pipe movement at the locations of the
damaged MSRs during plant start up to verify that the pipe movement is l
within the piping analysis. The inspectors have kept NRR informed and
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will continue to evaluate the licensee's efforts in subsequent inspections.
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Within the areas inspected violations or deviations were not identified.
7.
Maintenance (IP62702)
I o Defective welds on Main Fr:edwater Pump Discharge Nozzle (Unit 1)
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In Inspection Report 93-09, the inspectors discussed the detection of cracks in the welds between the discharge side of the main feed pump and the adjoining reducing elbow.
Because Unit 2 has a similar configuration, the inspectors issued a followup item in order to monitor
the licensee's corrective actions on Unit I and to review results of a I
metallurgical investigation in order to ascertain whether Unit 2 can continue to operate safely with cracks in the subject welds. During the present inspection period, the inspectors ascertained that the licensee removed / cut a ring from the "C" pump nozzle weld, at about 7/8 inches, on the nozzle side and about If inches on the elbow side, in order to preserve the weld for metallurgical examination.
On March 3, 1993, the inspectors observed the metallurgical examination at the licensee's Innsbrook Technical Support Center.
The licensee investigated the location of the 2%-inch circumferential indication and found no cracking at this location. However, the licensee found a weld repair at the counter bore region with about a 1/2-inch long slag inclusion. The licensee attributed the rest of the 2%-inch long indication to the apparent sharp profile of the counter bore.
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The licensee also considered the apparent cracking into the "B" pump
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nozzle. The weld was removed by machining and the machined surface was acid etched for remaining weld material following machining. After all l
the weld material was removed, the licensee performed PT on the pump
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nozzle surface and found no evidence of crack indications. Thus, any
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axial cracking that was present did not propagate into the pump nozzle.
Through discussion and by observation, the inspectors ascertained that the licensee decided to remove the original weld material and replace
the reducing elbows with erosion / corrosion resistant chrome-moly steel elbows. The replacement elbows on the discharge side of each of the i
pumps were buttered with inconel, prepped and rewelded using a machine
gas tungsten arc (GTAW), procedure. The cutting and welding was
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performed by PCI, the company that rewelded the reactor
<olant piping.
l The licensee's preliminary assessment of the cracking problem was that the axial cracks were the result of the original weld fabrication where
a wrong weld procedure was used.
Because the feedwater pumps in Unit 2 had similar welds, the licensee is performing an engineering fracture
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mechanics evaluation to determine structural integrity. The licensee's contractors are performing Charpy impacts and tension testing to
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determine the fracture toughness of the original weld and base l
materi al s.
The fracture mechanics analysis will be based on Unit 2 loads assuming the presence of a through-wall flaw.
i After completion of this inspection, the inspectors were informed, on March 29, 1992, that preliminary analysis indicated that the Unit 2 feedwater pumps have adequate structural integrity for continued safe
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operation. A preliminary fracture mechanics analysis was performed by the licensee based on lower-bound materials properties and upper-bound
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pump nozzle loads.
The results indicated that structural integrity is l
l maintained with a postulated through-wall flaw of about 4 inches in
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length.
The licensee is evaluating options to replace the Unit 2 l
feedwater pump outlet nozzle elbows during the upcoming fall scheduled I
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refueling outage.
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l The quality and depth of this investigation reflects the licensee's
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significant strength in this area and concern for safe plant operation.
Within the areas inspected violations or deviations were not identified.
l 8.
Exit Interview l
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The inspection scope and results were summarized on March 12, 1993, with those persons indicated in paragraph 1.
The inspector described the areas inspected and discussed in detail the inspection results. One inspector followup item was identified and its listed below.
Proprietary information is not contained in this report. Dissenting comments were not received from the licensee.
IFI 50-338/93-11-01 Method of Calculating the Reduction in Examination Coverage, paragraph 2.
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