IR 05000369/1993012
| ML20057A180 | |
| Person / Time | |
|---|---|
| Site: | McGuire, Mcguire  |
| Issue date: | 09/02/1993 |
| From: | Blake J, Economos N, Kleinsorge W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20057A178 | List: |
| References | |
| 50-369-93-12, 50-370-93-12, NUDOCS 9309130156 | |
| Download: ML20057A180 (26) | |
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NUCLEAR REGULATORY COMMISSION
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UNITED STATES
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101 MARIETTA STREET, N W., SUlTE 29%
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Report Nos.: 50-369/93-12 and 50-370/93-12 j
Licensee: Duke Power Company
422 South Church Street Charlotte, NC 28242 i
i Docket Nos.:
50-369 and 50-370 License Nos.:
i facility Name: McGuire 1 and 2
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i Inspection Conducted: July 19-23, and August 2-6, 1993
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J. f. Blake, Chief Date Signed
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Materfals and ProcessSection I'ngineering Branch
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Division of Reactor Safety
SUMMARY Scope:
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This routine, announced inspection was conducted in the areas of Unit 2, ten year inservice inspection (ISI) of the reactor pressure vessel; eddy current (ET) examination of steam generators (SG); ultrasonic examination of feedwa-ter nozzles and related piping welds.
Modifications in progress where inspections were performed included chemical and volume control system (NV);
letdown orifice and associated pipe replacement; containment spray system i
(NS), 2B heat exchanger replacement; containment liner corrosion repair;
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erosion corrosion degraded pipe replacement.
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Results:
In the areas inspected, violations or deviations were not identified.
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i 9309130156 930902 PDR ADOCK 05000369 G
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REPORT DETAILS 1.
Persons Contacted J. Baumann, Supervisor Eddy Current Examination F. Bulgin, Technical Services, NDE Supervisor D. Cabe, Technical Support NDE, Reactor Vessel C. B. Cheezum, Manager, NDE General Services Department M. Davis, Civil Engineer, reacture Mechanics T. Foster, Mechanical, Sr. Engineer M. Geddie, Station Manager P. Guill, Regulatory Compliance Engineer
- R. Hall, Engineering Manage-G. Holbrooks, Engineer Containment Liner Repair M. Kunkel, Mechanical Engineer
- L. Lunka, Regulatory Compliance Engineer
- J.
McArdle, ISI Level III Examiner J. Mead, Systems Engineer, Heat Exchanger J. Parker, Component Engineer Erosion / Corrosion
- N. Pope, Instrument and Electronics Superintendent
- R. Sharpe, Regulatory Compliance Manager D. Silvers, Supervisor Mechanical Maintenance /ISI J. Watkins, Principal level III Eddy Current D. Whipp, Technical Specialist in Training D. Whitaker, Nuclear Services, in Training Materials D. White, Mechanical Engineering Other licensee employees contacted during this inspection included craftsmen, engineers, and technicians.
Other Organizations Babcock & Wilcox Nuclear Services Company (BWNS)
A. Richmond, Task leader Reactor Vessel Examiner H. Stoppelmann, Level III Examiner, Ultrasonics Hartford Steam Boiler Insurance Company
- R. Klein, Authorized Nuclear Inservice Inspector
- Attended exit interview Acronyms and initialisms used throughout this report are listed in the last paragraph.
2.
Inservice Inspection - (ISI)
This is the eighth (8th) refueling outage in the third period of the first 10 - year interval for Unit 2.
The inspector observed in-progress examinations, and reviewed procedures and records indicated below, to determine whether ISI examinations were being conducted in accordance with applicable procedures, regulatory requirements and licensee
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l commitments. The applicable code for examination activities was the American Society of Mechanical Engineers Boiler and Pressure Vessel (ASME B&PV) Code,Section XI 1980 edition with addenda through Winter 1980.
BWNS, was conducting the reactor vessel examination using the ARIS 11 manipulator.
The licensee's technical support group was in charge of the remaining ISI examinations including eddy-current (ET), examinations of Steam Generator tubes.
a.
Review of NDE Procedures (73052)
The inspector reviewed the procedures listed below to determine whether they were consistent with code requirements and regulatory commitments. The procedures were also reviewed in the areas of procedure approval, requirements for qualification of NDE personnel, visual acuity requirements and compilation of required records.
- Eddy Current Analysis Guidelines McGuire Nuclear Station E0C-8
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NDE-701 Rev. I Multifrequency Eddy Current Examination of I
S/G Tubing at McGuire
NDE-702 Rev. 0 Eddy Current Data Screening Production
NDE-703 Rev. 3 Evaluation of Eddy Current Data for S/G Tubing
NDE-704 Rev. 0 Evaluation of Eddy Current for Anti-Vibra-tion Locations and Denting on Westinghouse S/G(s).
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NDE-705 Rev. O Multifrequency Eddy Current Examination of
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Non-Ferrous Tubing I
NDE-706 Rev. 0 Evaluation of Eddy Current Data for Nonfer-rous Tubing
NDE-707 Rev. 1 Multifrequency Eddy Current Examination of Nonferrous Tubing using a motorized Rotary Coil
NDE-708 Rev. 1 Evaluation of Eddy Current Data for Nonfer-rous Tubing Using Motorized Rotating Pan-cake Coil (MRPC)
NDE-712 Rev. O Multifrequency Eddy Current Examination of Nonferrous Tubing Using a MRPC with the SM-15 Probe Head
NDE-B Rev. 18 Training, Qualification and Certification
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of NDE Personnel
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NDE-25 Rev. 15 Magnetic Particle Examination Procedure &
Technique (
e NDE-35 Rev. 14 Liquid Penetrant Examination
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e NDE-44 Rev. 9 Ultrasonic Examination of Bolts and Studs e
NDE-46 Rev. 4 UT Examination of Reactor Vessel Closure
Nuts for Preservice Inspection and ISI
NDE-600 Rev. 2 Ultrasonic Examination of similar metal piping welds in Wrought Austenitic and Ferritic Material
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NDE-620 Rev, 1 Ultrasonic Examination of Welds in Ferritic Pressure Vessels >2" in thickness
e NDE-630 Rev. 1 Ultrasonic Examination of Welds in Wrought
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Ferritic and Austenitic Pressure Vessels 2" i
thickness and Greater.
b.
Observation of Work Activities (IP73753)
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The inspector observed work activities, reviewed certirication records of NDE equipment and materials and, reviewed '1DE personnel
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qualifications for personnel, utilized for ISI examin tions observed. The observations and reviews conducted by the inspector
are documented below.
Work Observation Item Weld Exam Component Comments Type feedwater C05.021.052 2CF2FW13-12 UT/MT/RT N0Z. 2"D" UT Rejectable Indications See Below C05.021.050 2CF2FW13-1 MT/RT N0Z.2"A"
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to Elbow C05.021.054 2CF2FW15-1 MT/RT N0Z.2*B"
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to Elbow C05.021.056 2CF2FW-15-12 dT/RT N0Z.2"C"
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to Elbow i
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C05.021.677A 25M2DI-X MT Pipe to Pipe Clear Auxiliary Feedwater C05.011.021 2CA2FW52-13 MT Pipe to Pipe Clear l
C05.011.022 2CA2FW52-15 MT Pipe to Pipe Clear l
C05.011.024 2CA2FW52-22 MT Pipe to Pipe Clear
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C05.011.025 2CA2FW52-23 MT Pipe to Pipe Clear C05.011.026 2CA2FW52-24 MT Pipe to Pipe Clear
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CO2.021.009A 2SGC-06A-AFW MT Noz. to Ell Clear j
i Comments
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Feedwater. Elbow to Nozzle 2"D"-
This examination was perforned in response to concerns raised over the adequacy of the ultrasonic examination performed during the previous outage, see Report 93-04.
In summary the inspector of
.ecord had expressed concern over the evaluation of recordable indications as geomctric reflectors. The concern was because these reflectors were located in the inside surface of the pipe or in the l
root of the weld, in the same area where fatigue induced cracking has occurred in the past.
Because of this concern the licensee agreed to re-examine during this outage a nozzle using a_ technique capable of verifying these type cracks.
Examination of the Elbow to Nozzle 2"D" weld during the present refueling outage with shear and refracted longitudinal wave type transducers disclosed intermittent indications, in the aforementioned weld area. These were evaluated as having through wall dimensions that were code rejectable. An examination of the same weld in each of the othe-three steam generators, produced similar results. As a confirmatory alternate examination, the licensee radiographed all four nozzle welds using a radiographic technique with a sensitivity that exceeded code re-quirements.
The radiographs of all four nozzle welds showed no evidence of the code rejectable through wall indications. The condition observed was related to root geometry i.e. counterbore and/or mismatch which was acceptable per weld fabrication standards.
The inspector reviewed the subject radiographs and concurs with the licensee's interpretation of the indications in question.
Because, ultrasonic examination identified these indications, the inspector stated that they cannot be ignored and recommended that on future outages the licensee re-examine the subject welds to see what if any changes have occurred in the dimensions of these l
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j indications which is now baseline data. This matter will be l
revisited on future inspections as part of the overall ISI work effort.
Reactor Pressure Vessel (RPV) Ten (10) Year ISI Examination Examinat'an of the RPV was performed by BWNS using their automated reactor inspection system (ARIS) during the week of July 25, 1993.
This examination was performed at this time to satisfy the ten year examination requirement specified by Section XI of the ASME code.
The Reactor Vessel Examination Manual, approved by the licensee on July 20,1993, served as the controlling document for this activity.
This document contained administrative and the technical procedures
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listed below, examination requirements and the contractors position on RG 1.150 Rev.1.
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The following procedures were reviewed for adequacy and technical content.
ISI-132 Rev.9 Calibration of the Aris - II Mechanical Manipu-lator and Core Flood Nozzle Attachment 151-132 Rev.7-Aris II Operating Procedure 151-138 Rev.13 Aris II Ultrasonic Examination of Reactor Vessel and Associated Piping Using Accusonex 151-362 Identification and Layout of Welds and System Components The referenced accusonex system is used to provide data acquisition and imaging to collect and digitize ultrasonic data, record time and amplitude of indications greater than the present recording thresh-old.
The examination was performed with transducers in direct contact with the weld surface as opposed to the water path used in the past.
j This technique coupled with the use of digitized computerized method of data recording and analysis established a new baseline and a superior examination method. The following Table shows the beam angle, sound wave, the weld and its coverage during this examina-tion.
Nominal Application Weldina Volume And Dir.
Anale Of Examination O' Long Vessel welds nozzle 100% of total volume to shell welds
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45' Shear Vessel welds reactor 100% of weld from four coolant nozzle to directions 100% of T/2 from carbon steel pipe, both axial and circumf.
nozzle to shell from directions
nozzle box 60* Shear Vessel Welds i
45' Long Nozzle to safe-end 100% weld
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and safe-end to pipe weld (Austinitic)
core flood nozzle l
piping welds j
70* Long Nuclear surface nozzle 100% of weld volume to safe-end from the carbon steel side j
Low Angle Nozzle to shell from
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i L-Wave bore
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i Through a review of records and procedures the inspector ascertained
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the following.
Calibration was performed using blocks with side
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drilled holes; vessel weld examination extended i t from the fusion on both sides of the weld plus the weld near surface examination extended one inch into the base metal nozzle inside radius for one
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inch below the surface and pipe welds; % t from the base metal interface including the weld plus i " beyond the fusion line.
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In addition, the inspector reviewed the examination plan including
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volume coverage for each of the welds, calibration setups, equipment and personnel certifications.
i On the start of the second week of this inspection, the inspector met with the licensee to discuss the results of the examination and l
to obtain additional information on the indication / gouge in the cladding on the vessel wall located above the edge of the bottom
head weld, W-01.
A summary of the information obtained is as follows:
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Clad Vessel Surface Indication:
On or about July 28, 1993, during the remote visual examination of the vessel cladding surface with video equipment, the licensee /BWNS J
discovered an area of discoloration, later identified as a gouge, on
the clad surface above the edge of the bottom head weld (W-01).
Its position was located between 274* and 286* clockwise from the
"W"
axis of the vessel.
In order to obtain additional information and
to better characterize the nature of this indication, BWNS performed i
an ultrasonic examination, considered as a best effort basis. The inspection was performed using a 45* shear transducer and a full i
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node technique.
Calibration was performed using the response from
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the 2%T notch of the calibration block, measured at full node.
The
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response from the notch was 178% DAC. This level of sensitivity at
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full node provided sufficient confidence that a planar flaw extend-
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ing into the base metal beneath the cladding would be easily dis-
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cerned.
In addition, the indication was scanned with other trans-
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i ducers on the ARIS, including 0*, 45*, and 70*L-wave and 60* shear
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wave.
j The presence of the incore instrumentation nozzles limited manipula-j tor movement, such that scanning was performed with sound beams i
directed only from above the indication area towards the weld.
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Through discussions and document review the inspector ascertained
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that there was no detectable flaw in the location of the cladding l
indication.
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.j Physical Measurements:
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On or about August 2, 1993, BWNS obtained an impression of the l
subject gouge. Measurements from this impression revealed the gouge l
was approximately 4" deep, had a maximum width of approximately %"
and a length of approximately 11 inches.
Because the discoloration
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in the immediate area indicated that a small area of the alloy
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material (base metal), was now exposed to water, the licensee j
retained the services of Westinghouse to evaluate the extent of
corrosion penetration in the area. A review of the Westinghouse
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j report disclosed that with the present maximium depth of 0.25", the i
maximum calculated depth / penetration of the unclad area over 40-
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years would range from 0.335" to 0.423."
The Westinghouse report
recommended that the gouge be left in the as is condition as it i
posed no threat to the integrity of the vessel over the next 40 i
years.
On August 5, 1993, the licensee shared this information with NRR by telephone.
u Vessel Outer Diameter Indication:
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Results of the vessel examination revaaled that a code rejectable
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l planar flaw / indication had been identified on the vessel outer
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diameter surface. The indication was located in weld 2RPV-WOI which j
joins the bottom head to the transition ring.
Its position was located at approximately 130*, clockwise from the
"W" axis of the i
vessel. The indication is oriented transverse to the weld near the
root and, appears to penetrate the OD surface.
Its dimensions were approximately i " deep or about 8.8% through wall and has a length of about 2.4 inches.
It has an amplitude between 15% and 20% DAC.
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I The presence of incore instrumentation stubs limited the examination to a single direction circumferential scan.
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A review of baseline UT records showed 'that no recordable indica-tions had been recorded / identified for the weld.
The last examina-tion / baseline, on this weld had been performed in 1978 in accordance i
with Section XI 1974 Edition requirements. The examination was
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performed using the immersion technique.
Data was monitored but not
recorded on tape.
Indications 2: 20% DAC were investigated, those 2:
i 50% were recorded. The licensee's review of construction radio-graphs showed no evidence of the indication in question.
Similarly
the licensee's review of weld fabrication records failed to reveal evidence of repair or other activity that would provide an insight i
for the cause of this indication.
Presently the licensee is per-
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forming a fracture analysis to determine whether the vessel can be returned to service in the as is condition. On August 5, 1993 the licensee discussed this matter with staff members at NRR.
The
licensee agreed to provide the staff detail information regarding
their analysis including assumptions, calculations, and results by i
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the 16th of August 1993.
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Through discussions with Level III examiners, review of procedures l
and examination records the inspector has determined that the j
examination was performed by well qualified personnel in a conserva-
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tive manner using state of the art equipment.
The UT procedure used for the examination had sufficient sensitivity to provide reasonable
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assurance that the area of interest was adequately examined.
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3.
Plant Modifications (37700)
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Replacement of Containment Spray 28 Heat Exchanger, Unit 2
Extensive degradation of tubing in the original heat exchanger
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caused the licensee to replace this heat exchanger with a newly designed vertically mounted, two pass single shell type, built to
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Duke specification MCS-1201-06-00-0002.
The replacement was built to the requirements of ASME Code Section III Class 2, 1989 Edition
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and 1990 Addenda.
Tubing for the heat exchanger was identified as ASME Code Section III Class 3.
The heat exchanger was built by
Joseph Oats Corp., under purchase order number C-20164-M3. The new
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design has the containment spray water on the shell side and the raw lake watar running on the tube side.
This is directly opposite to the original design.
Design and operating parameters of the new
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heat exchanger are as follows:
Conditions Shell Tubing t
Refueling water Raw river water storage tank (Lake Norman)
Design Press. & Temp.
252 PSIG 135 PSIG\\
l 190*F 150*F 70*F Min.
40*F Min.
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Operating (Normal)
Press & Temp.
Flow Rates 3470 GPM 3800 GPM Dimensions 541" ID
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.035 Min. wall Titanium Penetrations I
Shell Inlet and
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Outlet nozzles 10" O x %" thick Tube Outlet Nozzles 18" O x%" thick
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Manway 20" O
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The new heat exchanger had been hydrostatically tested at 380 psig
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on the shell side and 205 psig on the tube side.
l At the time of this inspection the licensee had made the necessary
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pipe cuts and removed the interferences in preparation for the
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replacement activity. On the evening of July 19, 1993 the inspector j
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witnessed the removal of the old heat. exchanger by crane from the
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auxiliary building to a flatbed truck where it was secured and prepared for removal to a storage location. On the following
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evening July 20, 1993 the inspector witnessed the lift of the new heat exchanger from a flatbed truck to the auxiliary building. The
lift was performed by Duke per.onnel followie.g procedure TN/2/A/
9700/065.
This procedure provided line item sign offs for each main
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evolution of the removal of the old and installation of the new heat
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exchanger.
Vendor Radiograph Review:
The licensee's receipt inspection effort included a review of vendor
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d supplied radiographs. Through discussions with cognizant personnel, j
the inspector ascertained that the nozzle to shell welds for nozzles l
A and B, weld Nos. 141 and 157 included radiographs whose density and density variation did not meet minimum code requirements of 2.00 j
and - 15% + 30 % respectively. The subject nozzles were 24" in diam-
eter.
The welds were radiographed using 12 equal segments of film or intervals.
In weld No. 141 there were five intervals (1, 2, 6, 7
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and 12) which exhibited one or both conditions mentioned above.
In
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weld No.157 there were six (1, 5, 7,10,11 and 12) intervals where
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a small increment of the radiograph / weld failed to meet minimum code requirements.
Because vessel and weld geometry precluded reshooting
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the welds in question, the licansee performed a fracture mechanics analysis, file number MCC-1201.06-00-0005, to determine the adequacy
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i of the subject welds. The calculations assumed that each interval l
had a flaw 0.314 inches long or approximately 57.' of the weld. Using
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ASME Code Section XI, 1989 guidelines and the vendor's nozzle load report J-2514, the licensee concluded that the welds in question were acceptable in the as is condition.
The inspector reviewed the radiographs of the welds in question and concurred with the licensee's interpretation.
Through this review, the inspector noted that the area of interest or weld location, where code acceptability was in question, was clear of fabrication related indications whose interpretation could have been impacted by this condition. Therefore, it is safe to assume that weld quality in the area in question was satisfactory. Also, by taking this approach, the licensee has demonstrated significant engineering strength and conservatism in determining the acceptability of the welds in question.
By telephone on July 27, 1993 the inspector discussed with the
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licensee the code acceptability issue of these two welds.
The inspector's position was that following discussions with management, it was decided that the Region had no technical concerns over the adequacy of the subject welds and the methodolgy used to determine their adequacy.
However, the inspector suggested that the licensee take up the issue of code acceptability and the possible need for code relief with Headquarters /NRR, who is in a position to make a final decision on this matter. This matter was revisited during the i
exit interview because licensee management was a9parently unaware
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that construction code requirements had not been met on these nozzle I
welds. The licensee agreed to look further into this matter and pursue the code relief as necessary.
The inspector will follow-up this matter on a routine basis.
In terms of lessons learned, cognizant technical personnel agreed with the inspector's position that the subject radiographs along with all code required radiographs in this component, should have been reviewed in the vendor's shop at the time of construction when remedial action could have been taken with relative ease.
Through this discussion the inspector ascertained that the area of vendor inspections, during component fabrication, is currently under review.
Containment Spray (NS) Heat Exchanger-Operating History and Perfor-mance Units 1 and 2 l
The primary purpose of the NS system is to spray cool water into the containment atmosphere when appropriate in the event of a loss-of-coolant accident, thereby assuring that the containment pressure does not exceed its design pressure of 15 PSIG.
In the event of an accident, the NS system pumps pump pctentially radioactively contam-inated reactor coolant (NC) system water through the NS heat exchangers into the containment. The NS heat exchangers are cooled by nuclear service water (RN) (raw Lake Norman water). The only barrier, during an accident, between the potentially contaminated water and Lake Norman is the NS heat exchanger tube walls.
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As early as 1986 the licensee noted degrading thermal efficiency of the NS heat exchangers. The designer ran the raw RN water through the shell side of the NS heat exchangers and the NS water through
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the tube side of the NS heat exchanger.
Because there is no access to the shell side of the NS heat exchangers, mechanical cleaning of
any biofouling was precluded. The licensee was left with chemical cleaning. Repeated attempts to chemically clean the shell side of the heat exchangers, in the 1986 to 1988 time period, did not
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improve thermal efficiency.
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In May of 1988, the licensee received a calculation from MPR Associ-
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ates Inc. (MPR), of Washington DC indicating that a leak under the divider plate in the gasket area during performance testing could erroneously over-predict fouling resistance by a factor of 2.5, which could explain almost all the heat transfer degradation indi-i cated in the licensee's performance tests. The NS heat exchanger i
head gasket is a flat,. fiber, cut, one piece type. MPR recommended l
testing to confirm the potential divider plate gasket leak. July i
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1988 Thermister test data appeared to corroborate that the divider
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j plate gasket was permitting flow to bypass the tube bundles. MPR i
a provided stainless steel spring seals as replacement and the licens-
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i ce installed the seals in the time period between August and Novem-
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ber 1988.
Post installation testing, of the heat exchangers, with j
the spring seals in place, demonstrated near new heat transfer
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performance.
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In July and August 1988 Dowell Schlumberger (DS) participated in j
what was described as aggressive cleaning of the 2A and 28 NS heat i
exchangers.
The cleaning agents included significant quantities of l
sodium hypochlorite.
Licensee records indicate that DS did not
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strictly adhere to required amount of chemical additions.
The t
licensee indicated that sodium hypochlorite was used on all four NS i
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heat exchangers, however aggressive cleaning with significant
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quantities of sodium hypochlorite was only used on the Unit 2 heat
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Eddy Current (ET) examinations of the NS heat exchanger tubes
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conducted by Cramer & Lindell Engineering (C&L) November 1988 (lA
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and IB), October 1991 (IA and IB), and March 1993 (lA and IB) June
J 1987 (2A) and June 1988 (2B), resulted in one tube being plugged in
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the 2A heat exchanger. After the aggressive DS sodium hypochlorite cleanings of the 2A and 28 NS heat exchanger tube bundles of July-
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j August 1988, the January 1992 Unit 2 End of Cycle 7 Refueling Outage
(2EOC 7 RFO) ET examination indicated that both bundles were in poor l
condition due to OD (raw RN cooling water side) tunneling corrosion
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pits.
This was confirmed by metallurgical analysis of three tube samples removed from the 2B NS bundle. The ET examination indicat-ed that the pitting was in the early stages in the 2A NS bundle with 18 tubes exhibiting OD damage ET indications.
The pitting was
advanced in the 2B NS bundle, with 610 of 900 U-tubes exhibiting detectable pits, i
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The tubes in all the ET examinations were interrogated at 240 Khz i
and 100 vhz plus a support cancellation mix of the two frequencies.
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The instrument was calibrated such that a 1/16" diameter through hole in the calibration standard, would give a strip chart deflec-j tion of 25 divisions. The criteria for plugging a tube was five
strip chart divisions. This criteria was cooperatively established
by licensee representatives and C&L examination personnel. This criteria resulted in the plugging of two tubes in the 2A NS bundle
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and 144 tubes in the 28 NS bundle. The licensee decided in February 1992 that a predetermined number of tubes would be ET examined in
the mid-July to early August time frame in an attempt to quantify
the progression rates of the pits.
This work was to be done during
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a 72-hour Technical Specification window.
Heretofore, the licensee
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had ET examined 100% of the straight lengths of the tubes in each bundle (two straight lengths per U-tube).
This examination was
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conducted August 17-19, 1992, on 515 straight lengths of tubes, of
i the remaining 1512 unplugged straight lengths of tubes in the 28 NS i
bundle. The examination identified 42 tubes that met the plugging
,
criteria.
The plugging of these 42 tubes brought the total number j
i of plugged tubes in the 28 NS bundle to 186, or 20.7% of the bundle.
'
During 2E0C 8 RF0 July-September 1993, the licensee is in the
.
process of replacing the 2B NS heat exchanger.
i In May 1988, the licensee's Catawba station notified the McGuire station, of a condition found in the Catawba NS heat exchangers.
The tie rod spools (which maintain the vertical placement of the j
heat exchanger tube baffle plates) had severely deteriorated by
corrosion.
The movement of the tube baffle plates could increase i
the free span of the heat exchanger tubes such that vibration could
lead to tube failure.
Visual examination, during E0C 7 RF0 November
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1988, of the IA NS heat exchanger tube bundle, through the only
access port in all four NS heat exchangers, confirmed that this l
condition existed in the McGuire NS heat exchangers as well. The licensee conducted an evaluation and determined that the NS heat
exchangers were operable. This evaluation is documented in PIR l-
,
M91-0194 and calculation 1201.06-00-0003. The licensee's long term
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fix for this condition was to select six strategically located i
tubes, in each NS heat exchanger, which were free of Eddy Current (ET) indications.
Expand each of these tubes above and below each tube baffle plate, there by stabilizing the baffle plate positions.
Upon completion of the expansion operation, the six tubes in each of the remaining heat exchangers, were again ET examined and plugged as a precaution.
Babcock and Wilcox (B&W) performed the qualification testing and developed the parameters for the tube expansion process for the McGuire NS heat exchanges. The tube baffle plate stabiliza-tion was implemented by Minor Modification MGMM-3354.
The work was conducted on the 1A and IB heat exchangers during IEOC 8 RF0 January-March 1993 and 2A heat exchanger during 2EOC 8 RF0 July-September 1993.
The 2B NS heat exchanger is being replaced during 710C 8 RFO.
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2 To address the shell side raw water corrosion of carbon steel components in the NS heat exchangers (tie rods, baffle plates, support sleeves
...), the licensee has repaired / replaced the RN
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isolation valves (October 1987 to May 1990) to the NS beat exchangers and established a wet layup program (April-May 1992).
To evaluate the licensee actions related to the NS heat exchangers, i
and to assess the status of the remaining three original NS heat
,
exchangers, the inspectors interviewed licensee personnel, examined
documents and conducted walkdown inspections of the 2B replacement
NS heat exchanger to observe installation activities.
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Documents Reviewed ID Revision Subject
,
C&L Record of Eddy Current Inspection of Balance of Plant Heat Exchangers on Unit 1 of Duke l
Power Company's McGuire Nuclear Power Station
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Cowans ford, North Carolina October 1 through November 2, 1991 - Volume VII Containment Spray (NS) Heat Exchangers IA and IB C&L Record of Eddy Current Inspection of Balance of Plant Heat Exchangers on Unit 1 of Duke
Power Company's McGuire Nuclear Power Station j
Cowans Ford, North Carolina March 22, through April 9, 1993 (UIEOC8) - Valume V Containment Spray Heat Exchangers NS-1A and NS-1B
C&L Record of Eddy Current Inspection of Balance of Plant Heat Exchangers on Unit 2 of Duke
Power Company's McGuire Nuclear Power Station Cowans Ford, North Carolina January 20 through February 22, 1992 - Volume V Contain-
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ment Spray (NS) Heat Exchangers 2A and 28 C&L Record of Eddy Current Inspection of Contain-ment Spray Heat Exchanger NS 2B on Unit 2 of
]
Duke Power Company's McGuire Nuclear Power
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Station, Unit #2, Cowans ford, North Carolina August 17 through 19, 1992 i
DPC 4/23/92 Memo to file: McGuire Unit 2B Heat Exchanger
- Root Cause of Tube Pitting MN-208.38
DPC 3/11/92 Metallurgical Analysis Report: Type 304 SS
j tubing sections from the NS (containment i
spray) 2B heat exchanger
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C&L 30-84 7/12/93 Damage and Condition Report McGuire Unit 2,
July 12, 1993 for Containment Spray Heat Ex-J changer NS 2A
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Documents Reviewed f
ID Revision Subject B&W 3/26/93 McGuire Cont. Spray Hx Hydraulic Expansion 51-1218830-02 Qualification Report l
B&W 9/25/92 McGuire Hx Expansion Parameters 32-1212622-01
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DPC 2/8/93 Minor Modification:
Expand tubes in Contain-
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3354
- aent Spray Hxs lA, IB, & 2A to capture and stabilize the baffles as a substitute for the weakened tie rod sleeves.
DPC 2/3/93 USQ Evaluation for MM3354, Expand Tubes in NS MCC-1503.13-00-HXs lA, IB, and 2A
,
0409
,
i DPC 11/20/91 Problem Investigation Report:
Degraded Con-1-M91-0194 tainment Spray Heat Exchanger baffle plhte tie rod support sleeves
,
Calculation:
Inlet \\0utlet Plenum Divider 5/4/88 Plate Bypass and Effect on Thermal Perfor-mance MPR
Calculation:
Deflection of Closure Head with
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7/6/88 Test Pressure Loading MPR
Calculation: Maximum Stress and Fatigue Us-12/1/88 age for Divider Plate / Closure Head 5eal Dur-ing Thermal Performance Test MPR
Calculation: maximum Stress in Divider Plate 12/1/88 Closure Head Seal for LOCA Conditions DPC 7/22/88 Memorandum for N. A. Smith: Potential NMS Containment Spray Heat Exchanger 2B Partition Plate Gasket Bypass Flow Effects on GS-208.38 i
& GS-252.00
DPC 12/6/88 Memorandum to File: McGuire Nuclear Station Containment Spray (NS) Heat Exchanger Divider
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Plate Gasket / Thermistor Tests
DPC 4/11/89 Variation Notice: NS Heat Exchanger Gasket MEVN-1412 Replacement DPC 2/19/92 Containment Spray Heat Exchanger Corrective
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MP/0/A/7150/69 Maintenance
DPC 5/1/92 McGuire Final Safety Analysis Report Section 6.5 Containment Spray System
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The inspectors found the licensee's engineering practices sound and their engineering decisions deliberate and well thought out. The licensee was slow to identify the root cause of the degrading heat transfer properties of the NS heat exchangers. The delay in this area, resulted in aggressive cleaning practices applied to the 2A and 2B NS heat exchangers. The end result was some tube degradation in the 2A NS heat exchanger, and the replacement of the 28 NS heat exchanger.
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Figure 1 lists NS t 7t exchanger ET inspection data in columns in
chronological order. The replaced 2B NS heat exchanger data is shaded for emphasis. Note that the last ET examination and associ-l ated tube plugging of the 2B NS heat exchanger, brought the total number of tubes plugged, in that heat exchanger,. to 186, only six
tubes short of the licensee's plugging limit of 192. As can be
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clearly seen in the 1993 data (the last four columns) the degrada-tion in the 1A and IB NS heat exchangers is slight, with no tubes plugged due to degradation.
The degradation resulting from the aggressive cleaning practices employed on the 2A NS heat exchanger, has brought the total tubes plugged due to degradation to three.
The licensee has made the following significant modifications to equipment and changes to practices:
replacement of the divider plate gaskets-with spring seals; repair / replacement of heat exchang-er isolation valves, implementation of a wet layup program; suspen-sion of aggressive shell side cleaning practices; and continued ET examinations of the heat exchanger tubing, with particular emphasis I
on the 2A heat exchanger. With the modifications to equipment and changes to practices, that the licensee has made related to the NS heat exchangers, the NS heat exchangers should remain operable and available to assume their safety function when needed.
With in the areas examined no violations or deviations were identi-fied.
b.
Replacement of Letdown Orifices and Associeted Piping (Unit 2)
Letdown flow is controlled by a combination of two orifices and a control valve arranged in parallel flow paths. This arrangement provides for any combination of an orifice and the control valve to be used for making adjustments to the charging and letdown flow functions.
One of the two orifices (2NVFE 6200) is sized to pass the normal flow of 75 gpm while the other (2NVFE 6210) is sized to pass 45gpm. The licensee has determined that flow induced vibra-tion, attributed to the design of these orifices, has led to fatigue cracking of pipe welds, see Report 50-370/93-09 and Operability Evaluation /JC0 Notification, PIR #2-M93-0503, dated July 4, 1993.
To correct this problem and prevent its recurrence, the licensee is implementing this modification (NSM 22413).
The modification will replace both orifices with new redesigned replacements and i
associated piping.
The replacements are designed to eliminate l
cavitation and associated vibration which is the root cause for this
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failure. The new piping will have fewer joints, most of which will be full penetration welds rather that crack sensitive socket welds.
Each of the designed flow paths will have a thermal expansion loop,
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fabricated from properly sized, bent stainless steel piping.
By
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review of related technical documents, the inspectors ascertained that the subject modification will not change the function of the chemical and volume control system or the operational characteris-tics of the orifices, i.e., they will be placed in service by remote
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manual operation using their respective isolation valves as done
prior to the modification. The following documents were reviewed for content and technical adequacy:
MCC-1503.13-00-0434 Engineering Calculation Unreviewed
)
Safety Questions Evaluation
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i MCC-1223.04-00-0030 Code Acceptance Calculation for Let-down Orifice MCS-1206.00-02-0013 75 GPM and 45 GPM Orifices for NV system Design Conditions and Seismic Qualification Method
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Referenced Codes: ASME Section III, NC Class -2 (86) as applicable to design requirements, original constructions code of record is
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ASME Code Section III 1971 Edition; ASME Section XI (80W80).
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MCM-1210.06-0217 Engineering Drawing
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l DPS-1206.00-02-001 Rev. 7 Duke Procurement Specification i
Operating parameters of the letdown orifices were as follows:
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-l Desian Conditions Operatina Conditions l
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2485 psig 2185 psig Inlet
650*F 300 psig Outlet 290*F Work In Progress l
I At the time of this inspection, piping spools associated with the j
modification were being prefabricated on site. Accordingly the
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inspectors observed completed welds for workmanship and code accept-i ability. Material and welder identification was recorded for review of required certifications and qualifications. Welds, materials and
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I welders whose quality records were reviewed were as follows-
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I Completed Size Drawing No.
Welds 30, 31, 33 3"x 0.438" NV2FW-215 Rev. 10 35, 36, 39 l
40, 41, 48, 49 2*x 0.344" NV2FW-215 Rev. 10 52, 53, 57 2 x 0.436" NV2FW-216 Rev. 4 MATERIALS Piping Heat No.
Description / Heat No.
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2" (3 DXH L37998 Double Rad. 90* three dia. Radius Pipe bend 2" (3 DXH L36534 Double Rad. 90* three
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dia. Radius Pipe bend Stencil No.
F.W. DATA SHEET F 3009 L231-18 In addition to this review, the inspectors evaluated final radio-graphs to ascertain whether they meet code requirements and the licensee's procedure NDE - 10A Rev. 18.
WELD NO.
DRAWING NO.
COMMENTS 31, 33, 35 MCFI - 2NV-215 Acceptable - ASME 36, 39, 40 Code Section 111, Class B Through discussions with cognizant licensee personnel, document review, field inspections and evaluation of radiographs the inspec-tor determined that the licensee has directed sufficient engineering and technical resources to implement this modification in a satis-factory manner. This should provide reasonable assurance that the heretofore problems will be corrected which will improve system operability.
c.
Replacement of Piping Susceptible to Erosion Corrosion
l As on previous outages, the licensee is continuing to monitor the effects of erosion corrosion on certain balance of plant carbon
steel piping components.
In addition, to this effort, the licensee is pursuing their program of replacing carbon steel piping compo-nents which by analysis and industry experience have been shown to be subject to erosion corrosion attack. The replacement piping / components are made of stainless steel 304 type material which has significantly greater resistance to erosion corrosion than
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i carbon steel.
Through this approach, the licensee is planning to replace al the carbon steel piping from susceptible systems.
It is
expected that this program will diminish the number of components
requiring monitoring, while improving plant safety.
Piping replace-t
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ment was in process in the following areas.
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First Heat Extraction (HA)
l Pipe Size System location
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18" dia.
Main run from turbine extraction to the feedwater j
greater drop loops.
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12" dia.
Drop 2A3 feedwater heater; 2Al and 2A2 previously t
replaced.
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8" dia.
Loop in steam supply to first stage moisture separa-i
tor reheater.
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6" dia.
All remaining carbon steel in six inch diameter drops j
and the steam supply.
Second Heat Extraction
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20" dia.
Main run and remaining piping from turbine nozzle to the extraction check valve.
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18" x 14" Reducer Lateral pipe.
2" dia.
Scavenging steam from MSR to the extraction
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system, socket welded piping
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L 6" dia.
Feed reg bypass and heater vent system Piping systems HA & HB are non-QA, Duke Class
"G" classification and therefore are not safety related. Accordingly weld acceptabili-ty is based on visual examination by the craft foreman or his designee. Work on systems HA and HB was being performed in accor-dance with Work Requests 92045586 and 92045611 respectively.
Applicable minor modifications, #3550 and #3553 were issued to address 10 CFR 50.59 evaluation of unreviewed safety questions.
Similarly work on the CF system was being performed per work request #92045614 and minor modification 13557. The latter addressed 10 CFR 50.59 unreviewed safety question and evaluation. The CF system was identified as a QA - 4 class "F" classification.
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The inspector reviewed the above documents for technical content
completeness and accuracy. Work areas in the turbine building, were toured to observe completed and in process welds as available.
)
Randomly selected welds were inspected for appearance and workman-l ship quality which appeared to be satisfactory.
l I
4.
Eddy Current (El) Examination of Steam Generator Tubes, Unit 2 As reported in previous inspection reports 93-09,92-14 Unit 2 has
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experienced primary water stress corrosion cracking (PWSCC) in the rolled
"
tubesheet region. This phenomenon is responsible for removing many tubes l
from service. Other causes responsible for taking tubes out of service
!
include:
tube wear observed at the periphery in the preheater area of
!
the generator; anitvibration bar wear in the U-Bend area; stress corro-
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sion cracking in the freespan region in the cold leg side of the steam
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i generators; outside diameter stress corrosion cracking (0DSCC) which
originates at the tube support plates (TSP) generally in the hot leg side j
of the steam generator.
As in previous inspections, the licensee performed 100 percent bobbin l
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coil eddy current inspection of the cold leg tubes,100 percent rotating
pancake coil (MRPC) eddy current of the hot leg tubesheet,100 percent
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MRPC of the row 2 and 3 U-bends,100 percent MRPC of the Inconnel 600
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rolled plugs,100 percent MRPC of the kinetic sleeves, and MRPC in areas
>
of special interest.
l I
Data acquisition and analysis was being performed in accordance with l
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ll procedures identified earlier in this report.
Controlling documents / code l
by reference, included ASME Code Section XI (80W80), Regulatory Guide l
1.83 July 1975 and Code Case N-401, Digitized Data Collection for Eddy l
j Current Examination.
Data acquisition was being performed by licensee
'
personnel. Data analysis was conducted at the McGuire Nuclear Station.
Examinations were being performed with a multifrequency bobbin coil j
technique, utilizing the computerized MIZ-18 system.
<
Equipment used for data acquisition and analysis included Hewlett -
l Packard (HP), computers, Zetec's Eddynet acqui.sition modules and soft-l ware, HP hard disk and optical disk drive.
Probes used for the examina-
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tion included differential bobbin probes 0.610.0 and motorized rotating
)
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pancake multi-coil probes.
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i Tubing in each of the four steam generators were examined in the follow-
ing manner.
S/G "A" S/C "B" S/G "C" S/G "D"
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j Standard H/L C/L H/L C/L H/L C/L H/L C/L
Bobbin 4250 4397 4219 4390 4273 4407 4260 4416 l
MRPCU-Bend 253 260 282 322
[I MRPC H/L Tube 4250 4219 4273 4260 r-l l MRPC Plugs 277 277 284 284 242 264 240 258 i
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Data acquisition was observed on S/G "D" both cold and hot legs. On the
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I hot leg, MRPC examination of the tube sheet region was observed for tubes j
in column 46 rows 46-29.
In the cold leg, examination of tubes in the j
anti vibration bar region was observed. These tubes were located in
column 12, rows 103, 104, 107 and 108.
The inspector witnessed system J
calibration performed on the hot and cold legs of the subject generator.
l Results were recorded on disks A05D HTS at 16:35 and A03 DUB at 17:09 on j
July 20, 1993 respectively.
In addition, the in:pector observed shif t j
turnover which was performed in an orderly and satisfactory manner.
!
On August 1,1993 the inspector received the final list of tubes removed from service by plugging.
The plugs were made from inconel 690 material
j and were the rolled mechanical type.
Following is a tabulation of j
presently and previously plugged tubes.
j S/G "A" S/G "B" S/G "C" S/G "D" j
Tubes Plugged:
j Present Outage
48
49 j
Previous Outage 278 284 267 258
]
Totals 333 332 302 307
!
The inspector reviewed, personnel certifications recorus of sixteen ET l
examiners, five calibration standards and six MIS-18A RDAU Units.
All i
these appeared to be in order. By observation through discussions and i
document review the inspector has determined the ET of steam generator
tubes was performed by well trained personnel using state of the art
)
equipment and conservative guidelines. This effort provides reasonable j
assurance that all detectables flaws have been identified and evaluated.
j lubes with rejectable indications have been removed from service allowing
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the steam generators to be returned to service for continued operation.
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5.
Steel Containment Vessel (SCV) Degradation f
i l
As discussed in NRC Inspection Report Nos 50-369/91-23 and 50-369,370/92-
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l 03, this matter was discovered by the licensee, on July 27, 1989, while
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performing a preliminary inspection of the SCV prior to Integrated Leak j
Rate Testing (ILRT).
Licensee inspections identified SCV coating failure
and SCV corrosion in both units, inside the SCV on two elevations
,
j adjacent to cork forms for concrete floor slabs and outside of the SCV in
l the annulus area where the SCV intersects the concrete floor.
l l
Outside the SCV in the annulus area, the degraded areas were cleaned, the f
j concrete removed and corroded areas excavated and weld repaired where i
necessary to restore SCV wall thickness.
The weld repair areas were i
j Visually (VT), Magnetic Particle (MT), and Ultrasonically (UT) ex? mined.
s'
i Leak testing of the weld repair was postponed until the next ILRT.
The l
coating was renewed on the SCV, the concrete replaced, the coating on the l
floor renewed and the interface Lween 'he concrete floor and the SCV
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l was caulked. During this outage, 2E0C 8 Rt6, the licensee is removing
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the concrete in the areas where the SCV was we'd repaired, in preparation
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for leak testing during the up ccming ILRT.
Ths concrete will be replaced, recoated, and caulked after the ILRT. The concrete floor and SCV coating, along with the interf ace caulking, should prevent a recur-l
l rence of SRV deterioration in this area.
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i Inside the SCV, the licensee is in the process of removing tLe cork in
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the interface between the SCV and the end of the concrete floor slabs, at
the two elevations where coating degradation was identified. After the
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cork has been removed the coating is cleaned, inspected, repaired, and i
inspected. After the co'pletion of the coating repair the licensee is
installing a new seal between the SCV and the bottom of the concrete
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floor slabs. The new seal has a sizable continuous reservoir with
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i regularly spaced drains.
This new seal, when completed, should prevent a
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recurrence of the SRV deterioration in this area.
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To assess the licensee's actions to repair the SCV and prevent a recur-
rence of the degradation, the inspectors interviewed licensee personnel, I
i conducted a walkdown inspection, and reviewed procedures / documents i.nd l
selected quality records, as indicated below.
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The inspectors conducted a walkdown inspection of annulus area and two
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i elevations inside the SCV, where ac+i.ne work was in progress, observing l
cork removal, coating cleaning, coating application, and concrete removal j
activities.
These observations were compared with the applicable
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procedures.
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Procedures / Documents Reviewed ID Revision Title / Subject
MP/0/A/7650/103 12/10/90 Controlling Procedure for Pneumatic i
Testing of Steel Containment Vessel I
MP/0/A/7650/74 4/6/92 Service Level 1 Through IV Coating l
MP/0/A/7700/88 9/11/91 Containment Vessel Coating
LER 5/30/99 Corrosion Occurred on The Steel Contain-
.
50-370-90-16 ment Vessel Because of Design Deficiency
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Caused by Unanticipated Environmental
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Interaction
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LER 9/25/89 Abnormal Degradation of Steel Contain-
40-369-20-89-20 ment Vessels Due to Corrosion Caused By
j Standing Water in The Annulus Area Be-l
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cause of Unknown Reasons
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6/4/92 Memorandum: McGuire Nuclear Station l
Five Year Plan for Steel Containment
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Vessel (SCV) Cork Removal
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Calculation: Containment Review for 1131.00-00-0025 Corrosion (
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PIR 0-M90-0093 6/5/90 Problem Investigation Report: Contain-
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j ment Corrosion
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i The inspectors examined quality records related to the weld repair of the
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SCVs.
These records included: Detailed Process Control Sheets; Weld i
Process Control Sheets; Welders Performance Qualification Records; Welder Qualification Update Notices; Certifications ^f Nondestructive Examina-
tion Personnel; Eye Examination Reports for nondestructive examiners;
Receiving Inspection Reports for welding filler material; and Certified i
j Material Test Reports for welding filler material.
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s Welders' records examined:
V49 J52
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l Nondestructive examiner records examined:
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HCN Welding-II, MT-II, PT-II i
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JAP Welding-II, HT-II, PT-II
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RK Welding-II, MT-II, PT-II
Welding Filler Material Records Examined:
i E 8018, 3/32"x14", Ht. No. 88044 i
E 8018, 3/32"x14", Ht. No. 422K158)
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Weld repairs to the SCV were made by properly qualified and certified welders, with certified filler materials and examined by properly qualified and certified examiners.
When, the external coating and sealing of the SCV to concrete interface, and the internal SCV coating repairs, and installation of the concrete slab to SRV reservoir seal, are completed, those actions should prevent a recurrence of the SRV degradation.
Within the areas examined no violations or deviations were identified.
6.
Exit Interview The inspection scope and results were summarized on August 6, 1993, with those persons indicated in paragraph 1.
The inspectors described the areas inspected and discussed in detail the inspection results listed below. Although reviewed during this inspection, proprietary information is not contained in this report.
No dissenting comments were received from the licensee.
7.
Acronyms and Initialisms ARIS Automated Reactor Inspection System B&W Babcock and Wilcox BWNS Babcock & Wilcox Nuclear Services Company CF Condensate and Feedwater System C&L Cramer & Lindell Engineering DPC Duke Power Comapny DS Dowell Schlumberger E0C End of Cycle ET Eddy Current Testing HA Heat Extraction System HP Hewlett - Packard HX Heat Exchanger ID Inside Diameter ILR1 Integrated Leak Rate Testing ISI Inservice Inspection LER Licensee Event Report MT Magnetic Particle Testing MPR MPR Associates Inc.
MRPC Motorized Rotating Pancake Coil NC Reactor Coolant System NPF Nuclear Power Facility N/R Not Reported NRC Nuclear Regulatory Commission NRR NRC Office of Nuclear Reactor Regulation NS Containment Spray System NV Chemical and Volume Control System ODSCC Outside Diameter Stress Corrosion Cracking PIR Problem Investigation Report PWSCC Primary Water Stress Corrosion Cracking
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Rf0 Refueling Outage Rif Nuclear Service Water
RPV Reactor Pressure Vessel SCV Steel Containment Vessel
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S/G Steam Generators
TSP Tube Support Plates
UT Ultrasonic Testing VT Visual Examination
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._ __
.
<
25
,
CONTAINMENT SPRAY HEAT EXCHANGER EDDY CURRENT INSPECTION DATA FIGURE 1 HX ID 2A 2B 1A IB 2A 2B 2B 1A
2A Inspection Dates 6/87 6/88 10/1-11/5/91 1/20-2/22/92 8/17-3/22-4/9/93 6/93 IEOC 7 RF0 2EOC 7 RF0 19/93 1EOC 8 RF0 Previously Plugged Tubes
0
0
0 144
0
.01%
16.0%
0.6%
Tubes Sections Examined 1798 1800 1800 1800 1798 1800 515 478 467 1619 100%
100%
100%
100%
100%
100%
34.1%
26.5%
25.9%
90%
Severe Damage 40% and
0
17
856 505
16
over 0.1%
0.9%
0.9%
1.3%
48.1%
30.5%
1.9%
3.4%
1.7%
Moderate Darnage 20%-40%
20
3
28
12
21 1.2%
1.1%
0.2%
0.2%
1.4%
1.6%
0.3%
2.5%
0.9%
1.3%
Minor Damage
0
0
2
0
5 Less than 20%
0.1%
0.1%
0.1%
0.04%
0.3%
OD Damage Indications N/R N/R N/R N/R
870 N/R N/R N/R
1.0%
48.3%
1.2%
OD Damage 5 Divisions &
0
0
157
0
0 Greater 0.2%
8.7%-
'2.5%
OD Damage 1 to 4 Divi-N/R N/R N/R N/R
713 473 N/R N/R
sions 0.9%
39.6%
28.6%
1.2%
New Tubes Plugged
0
0
144
6*
6*
u*
0.1%
8.0%
2.5%
0.6%
0.6%
0.6%
l Total Tubes Plugged
0
0
144 186 6*
6*
9*
0.1%
0.2%
16.0%
20.7%-
0.6%
0.6%
0.9%
Includes the six tubes used to stabilize the baffle plates vertical position and plugged as a
precaution.
%
Percent of remaining unplugged tubes in bundle N/R Not Reported
.
.
.
.
.
.
_ -, -.
.._,
.. _ _,, - _ _. - _ ~ _. -.... _ _ _. -
.
_- -