IR 05000416/1993019
| ML20058A252 | |
| Person / Time | |
|---|---|
| Site: | Grand Gulf  |
| Issue date: | 11/08/1993 |
| From: | Blake J, Crowley B NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20058A243 | List: |
| References | |
| 50-416-93-19, IEB-80-07, IEB-80-7, IEIN-93-079, IEIN-93-79, NUDOCS 9311300180 | |
| Download: ML20058A252 (17) | |
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UNITED STATES
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j NUCLEAR REGULATORY COMMISSION yi,
REGloN H
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'S 101 MARIETTA STREET, N.W., SUITE 2900
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o ATLANTA, GEORGIA 30323-0199
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Report Nos.:
50-416/93-19 Licensee:
Entergy Operations, Inc.
Jackson, MS 39205
Docket No.:
50-416 License No.: NPF-29
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Facility Name: Grand Gulf
Inspection Conducted: October 18-22, 1993 Inspectors:
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/ Crowley Date' Signed
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Approved by:
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.'Blake, Chief D' ate Signed
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Ma erials and Processes Section E gineering Branch Division of Reactor Safety
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SUMMARY Scope:
This routine, announced inspection was conducted on site in the areas of:
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(1) Inservice Inspection (ISI), (2) Flow Accelerated Corrosion (FAC), and (3)
review of actions for NRC Bulletin 80-07 (Inspection of Jet Pump Beams) and NRC Information Notice (IN) 93-79 (Core Shroud Cracking at Beltline' Region
Welds).
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Results:
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In the areas inspected, no violations or deviations were identified.
In the area of ISI, in general, a good ISI program was in place with good
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implementation.
NDE examinations were being conducted in a professional manner by qualified personnel in accordance with applicable procedures. A
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strong organization involving Nuclear Plant Engineering (NPE), Quality Programs (QP), and Performance and System Engineering (P&SE) was in place and l
functioning well. The overall organization for program documentation and issue, implementation, and documentation of results was good.
Neat and
orderly records were-being generated and maintained.
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9311300100 931116 PDR ADDCK 05000416 G
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Significant improvements were noted in the FAC program since the last inspection. An Engineering Standard, including detailed procedures, had been issued and implemented.
Engineering was deeply involved in the process and a knowledgeable Engineer, dedicated only to the FAC program, was in place and ensuring that the program was properly implemented. An aggressive inspection program for the current outage had been implemented to obtain data to further improve the program and predict future wear. An EPRI assessment had been completed and recommendations for program improvement were being implemented.
A susceptibility analysis for all plant systems, including small bore piping, was being performed.
There appeared to be a strong management commitment to a good FAC program.
It appears that when the EPRI Assessment is issued and findings are acted upon; the Susceptibility Analysis is completed and fully incorporated into the program; and current inspection results are fed into the CHECMATE Model to update the model; the licensee will have an excellent program.
Licensee actions relative to the current Jet Pump Beam problem and the plans for Core Shroud inspection during the next refueling outage (RF0 7) appear to be appropriat _
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i REPORT DETAILS 1.
Persons Contacted Licensee Employees B. Arasteh, Engineer - Erosion / Corrosion - HPE
- E. Burton, Technical Specialist - ISI
- J. Dimmette, Manager, Performance and System Engineering (P&SE)
- C. Hayes, Director, Quality Programs
- R. Hutchinson, Vice President - Nuclear Operations S. Lewis, ISI Technical Specialist - NPE S. Martin, Engineering Supervisor, Piping - NPE A. McCurdy, Contract Manager - Turbine
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- M. Meisner, Director, Nuclear Safety and Regulatory Affairs
- D. Pace, Grand Gulf Nuclear Station General Manager
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- C. Renfroe, Testing / Inspections Programs Supervisor
- R. Ruffin, Licensing Specialist
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Contractors U. S. Testing Company,-Inc.
R. Morrill, NDE Shift Supervisor J. Ruiz, Visual and Mechanical Supervisor Siemans Power Corporation C. Mead, Project Engineer Westinghouse ()f)
A. Clay, Quality Control L. Reeves, Level III Examiner Other licensee employees contacted during this inspection included engineers, QA/QC personnel, craft personnel, security force members, technicians, and administrative personnel.
NRC Employees
- F. Cantrell, Section Chief, Projects Section IB
- R. Bernhard, Senior Resident Inspector
- C. Hughey, Resident Inspector
- M. Sykes, Reactor Inspector Intern l
- Attended exit interview
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l Acronyms and initialisms used throughout this report are listed in the i
last paragraph.
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2.
Inservice Inspection (ISI)
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See NRC Inspection Report No. 50-416/92-13 for documentation of a previous inspection in this area.
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The inspector reviewed documents and records, and observed activities, as i
indicated below, to determine whether ISI was be hg conducted in accordance with applicable procedures, regulatory requirements, and licensee commitments. The applicable code for IS', is the American
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Society of Mechanical Engineers Boiler and Pressure Vessel (ASME B&PV)
Code,Section XI,1977 Edition with Addenda through Summer 1979 plus some portions of the 1980 Edition, Winter 1980 Addenda. The Safety Evaluation
Report (SER) for the first ten year ISI plan and relief request is dated July 22, 1986.
The most current relief request (I-00010, Revision 5) was
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granted by NRC letter dated May 23, 1993.
Grand Gulf is in the 2nd refueling outage (RF0) of the 3rd, 40-month period, of the 1st, ten-year ISI interval. There will be one more refueling outage (RF07, April 1995)
before the end of the interval.
Three licensee organizations have responsibilities for the ISI NDE program and its implementation. NPE has responsibility for documenting
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the program, submitting the program to the NRC for approval of relief request, and issuing the program to the plant for implementation. The i
Testing / Inspection Programs Section of the plant P&SE organization has the responsibility for implementing the ISI program and documentation of
code required Forms and Reports.
The licensee's QP organization is J
responsible for performing the nondestructive examinations. Contractors working for the Quality Programs organization furnish inspection examiners and supervisors.
For the current outage, U. S. Testing is
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performing the NDE examinations.
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ISI Program Review (73051)
The inspector reviewed the following documents relating to the ISI
program to determine whether relief requests had been approved by
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NRR, the services of an Authorized Nuclear Inservice Inspector
(ANII) had been procured, the plan had been reviewed by the ANII, j
the plan had been approved by the licensee and to assure that procedures and plans had been established (written, reviewed, i
approved and issued) to control and accomplish the following i
applicable activities: program organization including l
identification of commitments and regulatory requirements, preparing plans and schedules, and qualification, training, responsibilities, i
and duties of personnel responsible for ISI; repair and replacement l
program requirements; personnel qualification requirements; and guidance for identifying and processing relief requests.
Specification SERI-M-489.1, Revision 7, SERI Grand Gulf Nuclear
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Power Station Unit 1 Standard for the Ten-Year Inservice Inspection Plan j
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Specification SERI-M-489.2, Revision 2, Standard for the
Performance of ASME Section XI Examinations
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Specification SERI-M-489.0, Revision 0, SCNs 90/001, 91/001,
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and 91/002, ASME Section XI, Divisior. 1 Repairs and
Replacements
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Plant Operations Manual Procedure 01-S-07-10, Revision 9,
Preservice and Inservice Inspection f
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Performance and System Engineering Procedure 17-S-05-15, Revision 1, Inservice Inspection
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Plant Operations Manual Procedure 01-S-07-28, Revision 10, ASME Section XI Repair / Replacement Program Company Directive C2.801, Revision 0, NDE Certification
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QAP 2.48, Revision 4, Indoctrination and Training of QP
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Contractor Personnel
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QAP 2.54, Revision 7, GGNS NDE Level III Inspection Personnel
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Qualification / Certification
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QAP 2.56, Revision 8, GGNS NDE Level I and II Inspection
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Personnel Qualification / Certification
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QAP 2.57, Revision 1, GGNS SNT-TC-1A Visual Inspection i
Personnel Qualification / Certification
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QAP 5.10, Revision 28, Preparation, Revision, distribution, and control of Quality Assurance Procedures / Instructions / Manuals QAP-9.10, Revision 7, Administration of Nondestructive
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Examinations (NDE)
f QAP 9.52, Revision 6, Visual Acuity Exam and Examiner
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Certification QAP 9.70, Revision 4, Expendable Material Used in
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Nondestructive Examinations QAI-2.01, Revision 1, Advance Change 2 Quality programs f
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Certification / Qualification Tracking Program QAI-9.21, Revision 1, Manual Ultrasonic Weld / Wall Thickness
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Profile j
NOTE:
Most of the documents listed above were reviewed during the 92-13 inspection.
For documents previously reviewed, only changes since that inspection were reviewed.
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b.
Review of Procedures (73052)
The inspector reviewed the following NDE procedures to determine whether these procedures were consistent with regulatory
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requirements and licensee commitments. The procedures were reviewed in the areas of procedure approval, requirements for qualification i
of NDE personnel, compilation of required records, and division of responsibility between the licensee and contractor personnel.
In addition, the procedures were reviewed for technical adequacy and conformance with ASME, Sections V and XI, and other licensee commitments / requirements.
l QAI 9.13, Revision 5, Liquid Penetrant Examination, (PT)
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Solvent Removable (ASME,Section XI)
i QAI 9.14, Revision 4, Magnetic Particle Examination (MT) (Yoke
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Method) (ASME,Section XI)
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QAI 9.03, Revision 6, Manual Ultrasonic Examination of Similar
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And Dissimilar Metal Welds (Section XI)
NOTE:
These procedures were reviewed during the 92-13 inspection. Only changes since that inspection were
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reviewed.
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c.
Observation of Work and Work Activities (73053)
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The inspector observed work activities, reviewed NDE personnel qualification records, and reviewed certification records of NDE equipment / materials, as detailed below. The inspector verified:
compliance with applicable codes, availability of and compliance
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with approved NDE procedures, use of knowledgeable NDE personnel, and use of NDE personnel qualified to the proper level.
(1) Liquid Penetrant Examination (PT)
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The inspector observed the in-process PT examinations of weld
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1E51G001-28-11-1 on Drawing RI-11-4.
In addition, since no other ISI PT inspections were available to evaluate adequacy of this inspection method, the inspector observed inspection of the new welds listed below on Work Order (WO) 19910088-2. The inspections were performed by the same examiners who were performing the ISI examinations. The observations were
compared with the inspection attributes of the applicable procedure and code to verify the performance of acceptable examinations.
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l Examinations Observed i
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Welds -
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38379 FW-902, FW-903, FW-904 l
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38711 FW-902. FW-903, FW-904 (2) Magnetic Particle (MT)-Examination The inspector observed the in-process MT examinations of welds
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IG33G001-11-8-1, -2, -3, -4 and -5 on Drawing C0-8-2.
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observations were compared with the inspection attributes of
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the applicable procedure and the ASME B&PV Code to verify the
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performance of acceptable examinations.
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(3) Ultrasonic (UT) Examination l
The inspector observed the in-process UT examination of the welds listed below. The observations were compared with the
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inspection attributes of the applicable procedure and the ASME
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B&PV Code to verify the performance of acceptable examinations.
Examinations Observed ISO /DWG WELD
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RI-8-4 lE51G004-W17 l
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RI-11-4 1E51G001-16-11-1
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(4) Visual (VT) Examination
The inspector observed the in-prtcess VT examination of Pipe
Suport Q1G41G0llR09. The observations were compared with the
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inspection attributes of the applicable. procedure and the ASME 1'
BSPV Code.to verify the performance of acceptable examinations.
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Personnel Qualification / Certification The inspector reviewed personnel qualification documentation as indicated below for examiners who performed the examinations detailed in paragraphs (1), (2), (3), and (4) above. These personnel qualifications were reviewed in the following areas:
employer's name; person certified; activity qualified.to perform; current period of certification; signature of.
employer's designated representative; basis used for
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certification; and, annual visual acuity, color vision
examination, and periodic recertification.
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Examiner Records Reviewed Method Level Number PT II
MT II
UT II
VT II
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Equipment Certification Records The inspector reviewed the certification records for the equipment / material listed below to ensure the use of qualified
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equipment / materials.
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Eauipment/ Material Identification
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Penetrant Cleaner Batch 023H4
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Penetrant Batch 710G1 Penetrant Developer Batch 326G6 MT Powder Batch 91F053
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UT Couplant Batch 91165 i
UT Transducer Serial D0911 i
UT Transducer Serial D0912
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UT Transducer Serial D0902 UT Transducer Serial J23353 UT Instrument Serial 600038
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UT Instrument Serial 600042 In addition to observing the above inspections, in-process
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examination records for the inspections were reviewed.
l RESULTS In the areas inspected, no violations or deviations were identified.
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In general, a good ISI program was in place with good implementation.
NDE examinations were being conducted in a professional manner by
qualified personnel in accordance with applicable procedures. A strong organization involving NPE, QP, and P&SE was in place and functioning well. The overall organization for program documentation and issue,
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implementation, and documentation of results was good. Neat and orderly records were being generated and maintained.
3.
Flow Accelerated Corration (FAC) Program (49001)
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In this report, the terms Erosion / Corrosion (E/C) and FAC are
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interchangeable.
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F In response to Generic Letter (GL) 89-08, Erosion / Corrosion Pipe Wall Thinning, licensee's have implemented long term Erosion / Corrosion (E/C)
or FAC programs. The licensee's E/C program was inspected in_NRC
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Inspection Reports 50-416/90-22 and 50-416/92-13. During the inspection
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documented by Report 92-13, the licensee had just started to implement the EPRI CHECMATE modelling prognm for ranking components for inspection. During that inspection, the inspector noted a number of
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weaknesses, including the small number of inspection locations being monitored. However, the licensee was in the process of expanding and making improvements in the program. The purpose of the current inspection was to evaluate the status of the program and determine if an adequate program was in place. The following is a summary of the
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inspection activities and results:
a.
General Based on discussions with licensee personnel, review of the documents listed in paragraph b. below, and observation of the
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inspections listed in paragraph c. below, the following actions have been completed by the licensee:
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A full time individual in NPE has been assigned to the E/C program.
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A site specification has been developed and issued to define the program and site implementing procedures have been issued.
The program is based on EPRI Draft Document NSAC/202L, Recommendations for an Effective Flow-Accelerated Corrosion Program.
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ABB Impell was contracted to perform a susceptibility analysis for plant systems. This includes susceptibility analysis of small bore piping based on the guidelines of the EPRI Draft Document ASAC/202L. The Impell report has not yet been issued.
A Pass 1 CHECMATE analysis has been completed for 7 systems and
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the results used in the current outage for identifying some inspection locations.
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EPRI performed an assessment of the FAC program in August of 1993. Their report has not yet been issued, but preliminary I
results had been provided to the licensee. The results indicated a number of strengths and some recommendations for improvement. The recommendations that had immediate impact on the program were incorporated. After the final report is issued, the other recommendations will be evaluated to determine necessary program changes.
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For the current outage, the GGNS inspection plan includes approximately 159 inspection locations with 42 of these being
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in small bore piping. The selection of locations for inspection was based on the Pass 1 CHECMATE analysis, plant experience, industry experience, and engineering judgement.
The inspection results will be entered into the CHECMATE model t
to perform the Pass 2 analysis.
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In addition to the above completed actions, the NPE E/C Engineer i
identified the following additional program improvements planned:
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Evaluate the EPRI assessment and make improvements based on EPRI recommendations that have not been incorporated.
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Continue to improve the program based on the susceptibility analysis and the results from the current outage inspections.
b.
Review of Procedures The inspector reviewed the following documents which define the FAC program:
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Standard No. GGNS-MS-41, Revision 2, Standard For Monitoring
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Internal Erosion / Corrosion of Piping Components
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NPE Administrative Procedure No. 903, Revision 0, Review of
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Design Documents Which Potentially Impact Piping Integrity
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Programs
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c.
Observations and Reviews In addition to review of the above program, procedures, and plans,
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the inspector observed in-process activities and reviewed other aspects of the FAC program as detailed below:
In-process grid layout was observed for Grid #14, component
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identification N19-516.
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Preliminary results of the EPRI assessment was reviewed.
In order to determine the extent of previous problems with FAC
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in plant systems, the inspector reviewed, with the E/C Engineer, the history of through-wall leaks since 1988. These records had already been developed during the susceptible analysis and indicated a total of approximately 10 leaks due to E/C.
All but 1 of these leaks were in small bore piping. The
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one leak in large bore piping was the-recent through-wall flaw in an 8"X12" reducer near the condenser.
The inspector examined licensee's future plans for material
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replacements for FAC degraded piping, i.e., practices for replacing "like for like" or up-grading to better materials.
Based on discussions with licensee personnel, and as indicated in the program documents, the general policy will be to replace FAC degraded piping with CrMo material.
In some cases, it may be necessary to replace "like for like" to allow proper planning time for replacement with upgraded materials.
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As of October 21, 1993, inspection had been completed on
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approximately 50% of the 159 inspection locations and the preliminary evaluation completed for 41 of the inspection locations with the following results:
L e s s '.h a n 0. 87 X t
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Greater than t,
n Greater Than 0.875 X t
, but may be below by RF0 7 - 24 n
RESULTS No violations or deviations were identified.
Significant improvements were noted in the FAC program since the last inspection. An Engineering Standard had been issued and implemented.
Engineering was deeply involved in the process and a knowledgeable Engineer, dedicated only to the E/C program, was in place and ensuring that' the program was properly implemented. Detailed procedures were included in the Standard to implement the program. All affected organizations, Operations, Engineering, and Chemistry, were involved in the program. The EPRI CHECMATE Model had been implemented and the Pass 1 analysis completed. An aggressive inspection program for the current outage had been implemented to obtain data to further improve the program and predict future wear. An EPRI assessment had been completed and
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recommendations for program improvement were being implemented. A susceptibility analysis for all plant systems, including small bore
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piping, was being performed. There appeared to be a strong management-commitment to a good E/C program.
It appears that, when the EPRI Assessment is issued and findings are acted upon, the susceptibility analysis is completed and the results fully incorporated into the
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program, and current inspection results are fed into the CHECMATE Model to update the model, the licensee will have an excellent program.
4.
NRC Bulletin 80-07, BWR Jet Pump Assembly Failure (92701)
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After a plant trip on September 13, 1993, core flow anomalies were
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observed which were attributed to possible Jet Pump #10 malfunction.
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After plant shutdown, in-vessel visual examination revealed a displaced mixer on Jet Pump #10, with the nozzle and mixer assembly located upside
down-between Jet Pumps #8 and #9. The #10 Jet Pump Beam was assumed to have failed and could not be located (The search for the Beam was still i
in process at the conclusion of the inspection).
The remaining Jet Pump Beams were subsequently inspected. The inspector reviewed the current inspection results and discussed with licensee personnel the current problem and the previous Jet Pump Beam inspection history. The following summarizes the inspection activities:
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a.
Background NRC Bulletin 80-07, dated April 4,1980, identified problems with
failure of Jet Pump Beams in certain BWR plants due to Intergranular Stress Corrosion Cracking (IGSCC).
In response to the Bulletin and General Electric (GE) Service Information Letter (SIL) 330, the licensee has been VT and UT inspecting the Jet Pump Beams each outage in accordance with GE Procedure TP-508.642. GE has been
providing the inspection services.
i IGSCC cracking in the Inconel X-750 Jet Pump Beam material has been l
attributed to a susceptible microstructure (resulting from the heat i
treating process), tensile stresses (resulting from beam preload),
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and the environment (dissolved oxygen in the reactor coolant).
Mitigation alternatives include improved heat treatment, reduction of stresses by reducing the initial preload, and environmental changes such as hydrogen addition to the reactor coolant. At Grand Gulf, a reduced preload was used during initial Jet Pump Beam install atio n.
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Inspection History RF0 4 -
During this outage, UT indications were recorded in Beam
- 10 (8% Full Screen Height) (FSH), Beams #16, #17, and #21 (5% FSH). These indications were recorded even though below the minimum threshold for recording (20% FSH).
RF0 5 -
No indications were recorded.
It is not known whether no j
indications were noted or no indications above the j
recording level (20% FSH) were noted.
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For the current outage, Westinghouse (W) is providing the inspection services. After the failure of Jet Pump #10, the other 23 Beams were UT inspected.
Indications were noted in Beams #8 and #21. The licensee considers that the current inspection provided more reliable results than previous inspections based on the 'ollowing changes in the inspection technique:
A new improved transducer fixture was used. The fixture should ensure that desired UT sound angles are obtained.
Any indication, regardless of amplitude, was recorded and considered to be indicative of cracking (this is necessary for proper evaluation of IGSCC flaws).
Previous procedures had used a 20% FSH recording level and the current W procedure still had the 20% FSH recording level.
In the " Pitch Catch" (thru-transmission) any amplitude drop was evaluated.
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One-half inch 5.0 MHz transducers and a 4" water column were used.
Previous inspections used 2-1/4 MHz transducers with a 2" water column.
The transducer package was rotated 180 after the first inspection and and the inspection repeated. This provided a second inspection of each area of interest with a different set of transducers.
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c.
Review of Inspection Procedure and Inspection Data
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The inspector reviewed the applicable inspection procedure, BWRP -
3.0, Revision 0, Ultrasonic Examination of Jet Pump Beams for Grand Gulf Nuclear Station.
In addition, the inspector discussed the
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inspection technique with licensee and }{ personnel, observed the.
transducer fixture and the calibration standard.
The inspector also reviewed the following records-
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Inspection results for the 23 installed Beams and 3 replacement
Beams, including the Calibration Data Sheets.
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The Flaw Indication Data Sheets for Beams #8 and #21.
Certification records for the Level III examiner who performed
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the inspections.
Technioue
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The technique involved 4 transducers mounted on the inspection fixture, each sending sound into the beam at an angle near the 4 corners formed by the intersection of the Trunnions and the sides of J
the Beam.
Each transducer was operated in the Pulse-echo mode and l
then the pair of transducers on each side of the Beam was operated.
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in the " Pitch Catch" mode. As noted above, the fixture was then
.j rotated 180" and the inspection repeated.
j Calibration Standard
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The calibration standard was a full size Beam with a 0.100" deep
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notch machined in the threaded bore of the. beam (the expected crack j
origination area).
i Inspection Results No UT indications were recorded in any of the beams, except Beams #8 and #21.
For these Beams, inspection results (both Pulse-echo and
" Pitch Catch" modes) documented indications in the area of interest consistent with that expected for IGSCC.
Inspection in at least one direction on each beam produced indications greater than 100% FSH.
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At the conclusion of the inspection, the licensee had replaced Beams #8,
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i On October 26, licensee personnel provided (by telephone) the following i
updated information:
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The Beam for det Pump #10 has still not been located.
Beams #8 and #21 have been VT inspected and #21 is definitely
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cracked.
Beam #8 appears to be cracked, but scale in the-area of interest precludes 100% verification of cracking.
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In investigating the reasons for failure of the #10 Beam and cracking in Beams #8 and #21, when no indications were reported in
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RF0 5, the licensee has determined the following:
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Based on the known cracking mechanism and Fracture Analysis, it does not appear feasible that the cracks initiated and grew to failure in
one fuel cycle. Therefore, the most likely reason for the cracks not being identified during previous inspections is problems with the UT technique used. This question is still being investigated by the licensee.
Improvements in technique that were incorporated in the current-
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inspection and that should/will be incorporated in an improved procedure are:
No minimum amplitude level should be imposed for recording and evaluating UT indications.
For the UT " Pitch Catch" (thru-transmission) mode, a 2 db or greater drop in amplitude should be recorded and evaluated.
A 5 MHz transducer should be used.
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After the outage, one or both of Beams #8 and #21 will be metallurgically analyzed.
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The licensee is still evaluating this problem.
Further details relative to the Jet Pump problem are provided in the NRC Resident Inspector's
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Report 50-416/93-15.
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No violations or deviations were identified.
It appeared that the licensee was taking the appropriate actions to investigate causes of the Jet Pump Beam failure.
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NRC Information Notice (IN) 93-79 Core Shroud Cracking at Beltline Region l
Welds in Boiling Water Reactors (92701)
l This IN was issued in response to recent cracking identified in weld
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regions of the Core Support Shroud at Brunswick Unit 1 (a BWR-4 reactor).
Both axial and circumferential cracks have been identified with the majority of the cracks being locate in the weld heat affected zones.
In addition to the NRC IN, GE issued Revision 1 to Rapid Information Communication Services Information Letter (RICSIL) and Service Information Letter (SIL) 582, Revision 1 to update information on the-Core Support Shroud cracks and to provide recommendations to perform visual examination of accessible areas of the Shroud at all GE BWRs at the next refueling.
The inspector discussed the NRC IN and GE SILs with licensee personnel and determined that the following actions are planned:
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There are no plans to inspect the Shroud during the current outage (RF0 6).
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The licensee has allocated funding in 1994 to evaluate vessel internals to identify the potential for Stress Corrosion Cracking (SCC). The evaluation will include a full search for documented failure history and identification of specific GGNS materials.
Therefore, the inspection of the Shroud will be deferred until after this evaluation and the development of an inspection plan for the next outage (RF0 7).
The GGNS Shroud material is type 304L stainless steel. Based on GE
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SIL 582, Units with 304L material should be inspected after 8 or more years of power operation. GG's operating licensee was 8 years -
old in July, 1993.
The decision to defer the inspection until RF0 7 was based on Shroud
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materials being low carbon type, chemistry being maintained within BWR limits, and the age of the plant such that the shroud irradiation is below the threshold of Irradiation Assisted Stress Corrosion Cracking.
The licensee provided the inspector documentation indicating that GE agreed with deferral of the inspection until RF0 7 and that the 8 year time limit specified in the GE SIL was considered to be effective power years and not years since the issue of the Operating License.
No violations or deviations were identified. The licensee's proposed inspection schedule appeared to be appropriate.
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6.
Material Nonconformance Reports (MNCRs)
The inspector reviewed licensee actions for the following MNCRs:
l a.
MNCR 0258-93, UT Indications in the Low Pressure (LP) Turbine 3 Rotor Disk During UT inspection of the LP 3 Rotor Disk to meet GGNS License Condition # 2.c(26), a number of recordable UT indications were
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identified in the #4 Disk (generator end). The inspector reviewed with the licensee and their contractor (Siemens Power Corporation)
the inspection technique, the preliminary inspection results, and preliminary disposition of the results.
Approximately 150 small indications were found. The maximum indication radial depth was 9 mm, which includes 3 mm added for NDE uncertainty. Although with the technique used, the exact length of indication is not measured, the maximum length is the width of the inspection zone, which is 20 mm. Based on these conservative sizing criteria, fracture mechanics calculations were used to show that the disk has a remaining life of 151,000 operating hours.
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At the conclusion of the inspection, NPE was still evaluating the inspection results.
The inspection technique appeared to be adequate and personnel responsible for the inspection were very knowledgeable in the
technique used. The preliminary disposition of the results appeared to be reasonable.
b.
MNCR 0179-93, External Corrosion of SSW Spray Headers This MNCR documented thin wall SSW Basin piping in Cooling Tower Loops A and C.
Thinning was because of external corrosion caused by repeated wetting and drying of the pipe surface during normal plant operations.
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The inspector discussed resolution to this problem with the Engineer and reviewed the NPE disposition of the thinned piping, which
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includes replacement of the piping in RF0 7.
Although calculations
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show some locations will be slightly below minimum wall by RF0 7, the calculations were very conservative. Based on conservative calculations and the fact that any pipe failure would be a small _
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leak and not a catastrophic failure, which would have little affect on operation of the system, it appears the NPE disposition to replace the piping during the next RF0 is reasonable.
No violations or deviations were identified, e
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7.
Exit Interview The inspection scope and results were summarized on October 22, 1993, with those persons indicated in paragraph 1.
The inspector described the areas inspected and discussed in detail the inspection findings.
Propri-etary information is not contained in this report. Dissenting comments were not received from the licensee.
On October 26, 1993, licensee personnel (S. Lewis) provided (by telephone) updated information, as noted in paragraph 4.0 above, relative to the Jet Pump Beam problem.
8.
Acronyms ANII Authorized Nuclear Inservice Inspector ASME American Society of Mechanical Engineers B&PV Boiler and Pressure Vessel CrMo Chromium Molybdenum E/C Erosion / Corrosion EPRI Electric Power Research Institute FAC Flow Accelerated Corrosion GE Ceneral Electric Energy - Inspection Services GGNS Grand Gulf Nuclear Station GL Generic Letter IGSCC Intergranular Stress Corrosion Cracking IN NRC Information Notice ISI Inservice Inspection
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MNCR Material Nonconforming Report HT Magnetic Particle Examination NDE Nondestructive Examination
NPE Nuclear Plant Engineering NRC Nuclear Regulatory Commission NRR Nuclear Reactor Regulation P&SE Performance and System Engineering
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PT Liquid Penetrant Examination QA Quality Assurance QAI-Quality Assurance Instruction QAP Quality Assurance Procedure QC Quality Control QP Quality Programs RF0 Refueling Outage RICSIL Rapid Information Communication Service Information Letter i
RII NRC Region II
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R&R Repair and Replacement SCC Stress Corrosion Cracking SER Safety Evaluation Report
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SIL Service Information Letter t,n Nominal Pipe Wall Thickness o
UT Ultrasonic Examination VT Visual Examination W
Westinghouse WO Work Order
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