IR 05000313/1986036

Insp Repts 50-313/86-36 & 50-368/86-36 on 861020-1120.No Violations or Deviations Noted.Major Areas Inspected:Reactor Coolant Pump Insps,High Pressure Injection Nozzle Repair & Steam Generator Tube Surveillance

ML20212E451
Person / Time
Site:	Arkansas Nuclear
Issue date:	12/19/1986
From:	Gilbert L, Hunnicutt D, Ireland R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20212E430	List: IR 05000313/1986036 ML20212E423
References
50-313-86-36, 50-368-86-36, IEIN-86-019, IEIN-86-19, NUDOCS 8701050329
Download: ML20212E451 (8)

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APPENDIX U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

NRC Inspection Report: 50-313/86-36 Licen~ses: DPR-51 50-368/86-36 NPF-6 Dockets: 50-313 50-368

' Licensee: Arkansas Power & Light Company (AP&L)

P. O. Box 551 Little Rock, Arkansas 72203 Facility Name: Arkansas Nuclear One (ANO), Units 1 and 2 Inspection At: Russellville, Arkansas Inspection Conducted: October 20 through November 20, 1986 Inspectors:L. p / />l//f/f5 01 GjJtiert, Reactor Inspector, Engineering D6te'

Section, Reactor Safety Branch

$- by /A//9 8 p D. M. Hunnicutt, Chief, 0;ieration Section Dste '

Reactor Safety Branch Approved: [. f/ /a//9//4, R. E. Ireland, Chief ~ Enginebring Section

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, Date V Reactor Safety Branch Inspection Summary Inspection Conducted October 20 through November 20, 1986 (Report 50-313/86-36; 50-368/86-36)

Areas Inspected: Routine, unannounced inspection of licensee's reactor coolant pump inspections, high pressure injection nozzle repair, and steam generator tube surveillanc Results: Within the three areas inspected, no violations or deviations were identifie {j1050329861223 O ADOCK 05000313 PDR

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DETAILS

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. ,* Persons Contacted

• J. -M. Levine, Director, Site Nuclear Operations

+#*E. C. Ewing, General Manager, Plant Support

1. • A. B. McGregor, Engineering Services Supervisor

• D. K. Crabtree, Steam Generator Cocrdinator

1. • D. B. Lomax, Plant Licensing Supervisor

+#*P. Campbell, Plant Licensing Engineer

• L. W. Humphey, General Manager, Nuclear Quality

1. • D. G. Horton, QA Superintendent

1. • J. L. Taylor, Brown, QC Superintendent J. McWilliams, Maintenance manager A. M. Armstrong, Maintenance Coordinator -

R. Reamey, Welding Engineer

1. D. Bennett, Mechanical Engineer

1. F. Snow, Babcock & Wilcox

• Attended ex't interview on October 23, 198 # Attended exit interview on November 4,198 + Attended exit interview on November 20, 198 . Reactor Coolant Pump Inspection IE Information Notice No. 86-19 Followup (Reactor Coolant Pump Shaft Shaf t Failure at Crystal River)

The NRC inspector reviewed Special Work Plan 1409.080, Revision 1 to verify that the ultrasonic examination and stiffness test on all reactor coolant pump shafts in Unit I had been performed as committed to in AP&L letter to NRR dated September 15, 1986. Records were reviewed which confirmed that the ultrasonic examination and stiffness test had been performed on the four shaft Inservice Inspection The NRC inspector reviewed the visual inspection report for inspecting the internal pressure boundary surface of the pump casing for reactor coolant pump " A". The inspection procedure used was Procedure ISI 350,-Revision 20, and the report indicated that no recordable conditions exist. The NRC inspector selectively reviewed the radiographs and the radiography report for the inservice inspection volumetric examination of the pump casing welds for the "A" reactor coolant pump. The radiography report identified a slag line indication that measured 5.66 inches in length between radiographic location markers C26 and D26. The radiographic film containing the slag line indication was included in the radiographs reviewed by the

- NRC inspector. In addition to the inservice radiographs, the i

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inspector reviewed preservice inspection radiographs of the area identified by the inservice inspection to contain 5.66 inches of

. slag using the Hughes radiographic enhancement equipment. By using the enhancement technique, the slag could be seen in the preservice inspection radiographs that was identified in the inservice inspection radiographs. The depth of the slag was determined to be 1.5 inches below the outer surface using the double exposure (parallax) technique because the ultrasonic techniques did not yield any reliable results for locating the slag dept The NRC inspector reviewed the "B" reactor coolant pump preservice inspection radiograph identified by the licensee as having a 1.5-inch slag indication, after enhancing selected preservice inspection radiographs for the "B" reactor coolant pump. The licensee also enhanced selected preservice inspection radiographs for "C" and "D" reactor coolant pumps and reported that no slag indications were eviden ,

The licensee has performed an evaluation of the inservice inspection subsurface indication in "A" reactor coolant pump and the enhanced preservice inspection indication in "B" reactor coolant pump that exceeds the allowable planar indications acceptance standard of the ASME B&PV Code, 1980 Edition and Addenda through Winter 1981. The preliminary fracture mechanics analysis and reanalysis of pump case stresses indicated that the pump casings for "A" and "B" reactor coolant pumps would be acceptable for continued service with the identified flaw The licensee has submitted a relief request to NRP for relief from performing additional examinations on other reactor coolant pumps during this outage as required by paragraph IWB-2430 of the ASME B&PV Cod No violations or deviations were identified 3. High Pressure Injection (HPI) Nozzle Inspection and Repair General Discussion

, Inservice Inspection (ISI)'was scheduled to be performed on the "A" HPI nozzle (MK #46-208-3) during the current refueling outage at Unit 1. When the mirror insulation was removed to permit radiographic examination (RT) of the thermal sleeve in the "A" HPI nozzle, severe corrosion was observed on the lower surface of the

' nozzl Inspection indicated that corrosion damage had occurred in an area about 2 to 3~inchas wide (about 60 to 90 degrees around the circumference) and about 10 inches along the bottom portion of the carbon steel surface of the HPI nozzle. The corrosion damage extended downward along the HPI nozzle and onto the cold leg pipin The corrosion on the cold leg piping extended for about 6 inches down

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the side of the piping. The corrosion damaged area on the cold leg

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piping was blend ground and no welding repairs were required. lne

"A" HPI nozzle is ferritic steel (ASTM, A-105, grade 2). The HPI nozzle is clad on the inside nozzle with stainless steel. This HPI

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nozzle had been modified in early 1982 when a new safe end and thermal sleeve were installed in accordance with approved procedures (reference: FCA04-3753-02).

Repair preparations consisted of blend grinding the corrosion damaged surface area to remove all traces of corrosion products. The area was dye penetrant (PT) tested to verify that all unsound carbon steel and corrosion products 'Id been remove A chart showing the blend ground area configuration prior to start of weld repair and also showing the repair area after weld repair had been completed was prepared. This chart was required to accurately record (map) the repair area and to facilitate analytical calculations. The calculations will be used to determine the structural integrity of the nozzle repair and to justify scheduled plant operations subsequent to completion of repairs and testing of the HPI nozzl The maximum depth of grinding on the HPI nozzle was about 1/2 inc Approximately 1/4 inch of carbon steel remained between the stainless steel cladding on the HPI nozzle inside diameter (ID) and the area of deepest grinding. No repairs or welding were performed on the inconel or stainless steel portions of the HPI piping or HPI nozzl Weld repairs were completed using qualified inconel (NiCr-3) weld electrodes, a qualified NDE Level III examiner, qualified welders, approved procedures, and QA overview by licensee QA personnel; applicable ASME B&PV Code requirements were me b. Preparation for Repair to the HPI Nozzle Subsequent to discovery of the corrosion damaged area on the "A" HPI nozzle, the contractor prepared plastic negatives and pnsitives of the corrosion damaged area prior to the start of repairs. The plastic negatives and positives accurately defined the area, depth of damage, and position and dimensions of the damaged area. Using this information, a mockup HPI nozzle was ground down to the dimensions and configuration of the ground out area on the installed "A" HPI nozzle. This mockup HPI nozzle was repaired using the relative position of the installed HPI nozzle, qualified welders, qualified weld electrodes and equipment, qualified NDE Level III examiner, contractor and licensee QA personnel, approved procedures, and applicable ASME B&PV Code requirements. The personnel performed the repair on the mockup HPI nozzle while wearing an.i-C clothing and respiratory protection (masks), adhering to approved procedures and applicable ASME B&PV Code requirements. Anticipated precautions related to work space and simulated radiation exposure and airborne contamination conditions were included in the successful repair to

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'the mockup HPI nozzl Satisfactory repair of'the mock'up HPI nozzle 3 under these conditions assured that repair of:the . installed "A" HPI 1: nozzle could be completed according to approved procedures and

related criteria. -The same personnel and procedures were_ utilized to

complete;the repair on the "A" HPI nozzle. No unusual problems or conditions were identified during the repair of the installed "A" HPI-nozzl ' Nozzle' Repair Discussion

_ Nozzle repair considerations and requirements are listed below:

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Nozzle / piping wall thickness measurements were made prior to and subsequent to repairs.

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Thermal sleeve tightness in the roll expanded area in the safe

, end bore was verified by RT both before and after welding on the t HPI nozzle.

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A minimum of 1/4. inch' thickness of base carbon steel remained on

.the 3-1/2. inch OD' straight portions of the "A" HPI' nozzle. The inconel buttering was not blend ground or repaired since no

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corrosion occurred on the incone The' repairs met applicable.ASME B&PV Code _Section XI, including e-IWA 4000, 1980 Edition including all addenda through Winter 1 198 ,

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The welding repairs and nondestructive examination (NDE) were

performed in accordance with ASME B&PV Code Section III, 1980 l Edition including all addenda through Winter 1981.

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A system pressure test must be performed in accordance with ASME'

[ B&PV Code Section III, subparagraph IWB 5210,-5222, 5230, ana

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Table IB-522-1. This is an open item pending NRC review of the

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test results (313/8636-01)

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All welding procedures were submitted to B&W HPD for review and p approval prior to their use in repair of this HPI. nozzl *

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All NDE procedures ~were submitted to,AP&L or B&W for review and

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approval prior to their use in verifying repair.of this HPI nozzl '

Applicable. documents used during various stages of HPI nozzle repair

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and repair verification were: '

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eeASME B&PV Code Sections II Part C, III, V, IX, and XI, 1980 Editions including all addenda through Winter 1981 i

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B&W Drawing 131996E-6, " Assay and Data for 2 1/2" Pressure Injection Nozzle".

B&W Drawing 1311998-4, "RC Piping List of Material".

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- FCA #04-3753-02, "HPI and HPI/MU Nozzle Repair". t

' Documentation Review The NRC inspector reviewed the following documentation related to repair and examination (testing) of HPI nozzle (MK #46-208-3):

General Procedure for Manual Gas Tungsten Arc Welding (GTAW),

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9-WP-200, Revision 1 Weld' Control Records, HPI-8601-060 and - 080

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- Welding Instruction Sheet, Identification: WIN 106-1, Revision'3.

, Welding Instruction Sheet, Identification: WIN 206-1, Revision 3.-

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Radiographic Examination of Weldments, RT Procedure 20.A.1, Revision 24- Design Change Package Approval Form (Form No. 1000.13D), Revision 10

- DCP #86-1116, dated November 1, 1986.-

The-following documents are a part of DCP #86-1116:

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ALARA Review Checklist - Category Ilior III (Form No. 1000.33B),

Revision 2, dated October 25, 198 Safety Or Environmental Determination Form (Form 202 F9, Revision March 7,1985).

DesignDocumentChecklist(Form 1032.01B, Revision 7).

Design control (Form 1032.01, Revision 7). Welding Material Release for weld filler metal. File No. 50-AN0#1 - P. O. #:

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087766-ED/087790-ED Welding Material Release, dated October 14, 1986 Certified Material Test Report from Inco Alloys International

_ ~ Certificate _of Welder Performance Qualification Test for welders with

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- Symbol Nos~. 9969 (dated October 8, 1986) and 0771 (dated October 8,

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Certification of chemical requirements for Penetrant

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Certification indicated that the materials met ASME B&PV Code,Section V, Article 6, Paragraph T-630, 1980 Edition, with Addenda through Summer 1981 and MIL-I-25135C, as amende Certification that nondestructive examination evaluaters, certified to ASNT-TC-1A recommendations, met requirements for Level II or III examine Repair / Replacement Program Implementation had previously been reviewed and were documented in NRC Inspection Reports 50-313/86-37; 50-368/86-37 (issued on December 1, 1986) paragraph 5 and 50-313/86-32; 50-368/86-32 (to be issued) subparagraphs 2.d.(2) and (3).

Inservice Inspection (ISI) reviews were conducted and documented in NRC Inspection Report 50-313/86-32;50-368/86-32(tobeissued)

subparagraph No violations or Deviations were identifie . Steam Generator Surveillance Review of Procedures The licensee issued Procedure 1022.015, Revision 0 for administrative control of the inservice inspection performed by Babcock & Wilcox on the steam generator tubes in Unit 1. The licensee's procedure implements the requirements of American Society of Mechanical Engineers Boiler and Pressure Vessel Code,Section XI,1980 Edition and Addenda through Winter 1981. The NRC inspector reviewed the following Babcock & Wilcox procedures:

ISI-406, Revision 8. "Inser ion, Calibration, Operation, and Removal of Eddy Current O' Tube Examination Equipment in Upper Head,"

151-418, Revision 2, " Technical Procedure for the Multifrequency Eddy Current Examination of 0TSG Tubing in 177 Steam Generators using the MIZ-18,"

ISI-460, Revision 13, " Technical Pr ture for the Evaluation of Eddy Current Data of Nuclear Grade Steam Generator Tubing,"

- ISI-467, Revision 3, " Technical Procedure for Evaluation of Eddy Current Data of Nuclear Grade Steam Generator Tubing for

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Intergranular Attack,"

ISI-469, Revision 1, " Technical Procedure for the Evaluation of Eddy Current Data of Roll Expansion Sleeved 0TSG Tubing,"

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The above procedures were prepared in-accordance with the ASME, Code,Section XI and approved by Babcock & Wilcox Level III nondestructive l

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examination personne ' . Review of Records The NRC: inspector reviewed the Eddy Current Examination results for steam generators "A" and "B." The examination reports reviewed.were signed by: Level II examiners that were certified for the Eddy Current Nondestructive Examination Metho The steam generator tubing surveillance required by Technical Specification 4.18.which consists of a general inspection (3 percent

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of the total tubes) and a special inspection in_the lane region and wedge region. The initial general inspection consisted of 470 tubes in each steam generato One defective tube was found in the general-inspection sample for the "A" steam generator; therefore, an additional 6 percent (940 tubes) sample size was required for SG "A."

Since one defective tube was found in the additional-6' percent sample, the general-inspection was required to be expanded to include an additional 12 percent (1880 tubes). sample. . The results of the-12 percent expanded inspection met the acceptance criteria of th Technical Specification, therefore, the sample size was not expanded further. No defective tubes were found in the "B" steam generator general inspection sampl l The special inspection required by the Technical Specification in the lane region and wedge region for intergranular attack was performed on 4950 tubes in "A" steam generator and 5045 tubes in "B" steam generator. Babcock & Wilcox identified only.two defective tubes in the A" steam generator and four defective tubes in the "B" steam-generator. The Technical Specification required that these defective tubes be plugge No expansion of. sample size was require No violations or deviations were identifie . Exit Interview The NRC inspectors met with the licensee representatives denoted in paragraph 1 and Mr. W. D. Johnson, NRC senior resident inspector, on October 23, November 4, and 20,1986, and summarized the scope and findings of the-inspection.