IR 05000344/1987024

Insp Rept 50-344/87-24 on 870524-0725.Violations Noted.Major Areas Inspected:Operational Safety Verification,Maint, Surveillance,Piping Support & Restraint Sys & Followup on Previously Identified Items

ML20237J113
Person / Time
Site:	Trojan File:Portland General Electric icon.png
Issue date:	07/10/1987
From:	Rebecca Barr, Mendonca M, Suh G NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V)
To:
Shared Package
ML20237J106	List: IR 05000344/1987024 ML20237J104 ML20237J110
References
50-344-87-24, NUDOCS 8708260012
Download: ML20237J113 (13)

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l l , U.S. NUCLEAR REGULATORY COMMISSION 1 REGION V  ! Report No. 50-344/87-24 Docket Wo. 50-344 License No. NPF-1 Licensee: Portland General Electric Company 121 S. W. Salmon Street Portland, Oregon 97204 L Facility Name: Trojan Inspection at: Rainier, Oregon Inspection conducted: May 24 - July 25, 1987

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Inspectors: A 7-M 7//* h ' R. C. Barr / Date Signed Senior Resident Inspector n G. Y. Suh

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Date Signed Resident Inspector

 ' Approved By:            7//# O 7 M. M. Mendonca, Chief          Date Signed Reactor Projects Section 1
 , Summary:

Inspection on May 24'- July 25, 1987 (Report 50-344/87-24) Areas Inspected: Routine inspection of operational safety verification, maintenance, surveillance, piping support and restraint systems, and follow-up on previously identified item Inspection procedures 30703, 61701, 61726, 62703, 70370, 71707, 71710, 71881, 92700, 92701 and 93702 were used as guidance during the conduct of the inspectio Results: Of the areas inspected, one violation involving failure te make a timely notification to the NRC of a reportable occurrence per 10 CFl! 50.72 was identified (paragraph 4).

8708260012B70Bdh PDR ADOCK 050 p G

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DETAILS Persons Contacted

  *C. A. Olmstead, Plant General Manager
  *R. P. Schmitt, Manager. Operations and Maintenance
  *D. W. Swan, Manager, Technical Services
  *J. K. Aldersebacs, Manager, Plant Modifications
  *J. D. Reid, Manager, Plant Services R. L. Russell, Operations Supervisor R. Budzeck, Assistant Operations Supervisor D. L. Bennett, Maintenance Supervisor R. A. Reinart, Instrument and Control Supervisor T. O. Meek, Radiation Protection Supervisor R. W. Ritschard, Security Supervisor T. Bushnell, Manager, Civil Engineering Branch M. Gandert, Supervising Engineer, Nuclear Plant Engineering C. H. Brown, Operations Branch Manager, Quality Assurance E

The inspectors also inte'Jviewed and talked with other licensee employees during the course of the inspection. These included shift supervisors, reactor and auxiliary operators, maintenance personnel, plant technicians and engineers, and quality assurance personne * Denotes those attending the exit intervie . Operational Safety Verification i During this inspection period, the inspectors observed and examined activities to verify the operational safety of the licensee's facilit The observations and examinations of those activities were conducted on a daily, weekly, or biweekly basi On a daily basis, the inspectors observed control room activities to verify the licensee's adherence to limiting ccnditions for operation as prescribed in the facility technical specifications. Logs, instrumentation, recorder traces, and other operational records were examined to obtain information on plant conditions, trends, and compliance with regulations. On occasions when a shift turnover was in progress, the turnover of information on plant status was observed to determine that all pertinent information was relayed to the oncoming shift personne During each week, the inspectors toured the accessible areas of the facility to observe the following items: General plant and equipment condition Maintenance requests and repair Fire hazards and fire fighting equipmen Ignition sources and flammable material contro Conduct of activities in accordance with the licensee's administrative controls and approved procedure Interiors of electrical and control panel Implementation of the licensee's physical security pla Radiation protection controls.

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, . 2- . Plant housekeeping and cleanlines ' Radioactive waste system Proper. storage of compressed gas bottle The licensee's equipment clearance control was examined weekly by the  l inspectors to determine that the licensee complied with technical specification limiting conditions for operation with respect to removal of l equipment from service. -Active clearances were spot-checked to ensure that their issuance was consistent with plant status and maintenance'  '

evolution During each week, the inspectors conversed with operators in the control room, and with other plant; personnel. The discussions centered on pertinent topics relating to general plant conditions, procedures, security, training, and other topics aligned with the work activities involve The inspectors examinej the licensee's nonconformance reports (NCR) to confirm that deficiencies were identified and tracked by the syste Identified _nonconformances were being tracked and followed to the completion of corrective actio Logs of jumpers, bypasses, caution, and test tags were examined by the inspectors. Implementation of radiation protection controls was verified by observing portions of area surveys being performed, when possible, and by examining radiation work permits currently in effect to see that prescribed clothing and instrumentation were available and use Radiation protection instruments were also examined to verify operability and calibration-statu Routine inspections of the licensee's physical security program were performed in the areas of access control, organization and staffing, and detection and assessment systems. The inspectors observed the access control measures used at the entrance to the protected area, verified the integrity of portions of the protected area barrier and vital area barriers and observed, in several instances, the implementation of compensatory measures upon breach of vital area barriers. Portions of the isolation zone were verified to be free of obstructions and the functioning of the central and secondary alarm stations, including the use of CCTV monitors, was observed. On a sampling basis, the inspectors verified that the required minimum number of armed guards and an individual authorized to direct security activities were on sit The inspectors verified the operability of selected engineered safety features. This was done by direct visual verification of the correct position of valves, availability of power, cooling water supply, system - integrity and general condition of equipment, as applicable. ESF systems verified operable during this inspection period included the Containment

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Spray System.

l No violations of NRC requirements or deviations were identified.

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3; Maintenance The inspectors observed portions of preventive maintenance being performed for the fire ~ pump diesel engine. The work was performed.under Maintenance Requests 87-4286 and 87-1842 which covered the. quarterly, semi-annual, and annual inspections specified in Maintenance Procedure MP-12-8. The inspectors observed portions of the annual inspection which included the inspection of the turbocharger, the measurement of the' turbocharge bearing clearance and work on the cooling system. The work was performed in.accordence with MP-12-8, and the current revision of the procedure was on hand. Required equipment tagouts were in place, and quality control

. coverage. required by the procedure was provide No. violations of NRC requirements or deviations were identifie . " Surveillance The surveillance testing of safety-related systems was witnessed by the-ins pectors'... Observations by the inspectors included verification that-proper procedures ~were used, test instrumentation was calibrated and that the system or component being tested was properly removed from service if required by the test procedure. Following completion of the surveillance tests.-the inspectors verified that the test results met the appropriate-
-acceptance criteria. Any necessary corrective maintenance was completed during the conduct of-the tests in accordance with approved maintenance request (s). Surveillance tests witnessed during this period included:

TPT-189, " Centrifugal Charging Pump Total Flow and Injection Flow Balance."

During this inspection period, the inspectors also reviewed and witnessed portions of the-licensee's surveillance test of loss of offsite power with and without the presence of a safety injection signal. The test is performed at least once per 18 months during shutdown and is controlled under Periodic Operating Test P0T-12-2 titled, " Emergency Diesel Performance, Loss of Off-site Power, Diesel Automatic Start, and Auxiliary Feedwater Valve Actuation." P0T-12-2 addresses several surveillance test requirements in the technical specifications (T.S.), including specific portions of T.S. 4.8.1. The inspectors reviewed P0T-12-2 and verified that the procedural test requirements were consistent with the indicated parts of T.S. 4.8.1.1.2. The inspectors witnessed portions of the test including various system lineups in preparation for the test and the automatic start of the west emergency diesel generator with a safety injection signal present. Upon manual initiation of a safety injection signal, the diesels started from ambient condition, energized the emergency busses, energized the auto-connected emergency loads through the load sequencer, and operated for longer than five minutes. The test also verified load shedding from the emergency busses upon simulation of a loss of offsite power. The inspectors verified the completion of a sample of ' the test prerequisites, the calibration of the performance monitor recorder, and that the appropriate revision of the test procedure was in l use by test personnel. The completed data sheets and test results were ! reviewed to verify that the appropriate acceptance criteria were me . _._-.__m_ . _ - - - _ _ _ - . _ - - - _ - _ - - _ - . - - - _ - . - - - - - - - - - - - - . - - -

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During the performance of P0T-12-2, a reactor trip signal was received at 9:02 p.m. on June 29, 1987, resulting in the open11g of reactor trip breakers RTA and RTB 'and bypass breaker BYB. The plant was in mode 5 with all control. rods fully inserted and with the rod-drive motor generator sets off. An inspector was present in the control room during this portion of the test. The licensee has initially determined the cause of the reactor trip signal to be the existence of general warnings on both solid state protection system trains. Train A had one 48 volt DC power supply breaker open. This general warning was not responded to by the operators even though the corresponding annunciator had apparently alarmed, and when they closed bypass breaker B as part of P0T-12-2, a general warning was achieved on Train B. General warnings on both trains resulted in a reactor trip signal. This event including the cause of the

. Train A 48 volt DC breaker being open is being investigated by the licensee as Event Report 87-12 This occurrence constitutes an actuation of the Reactor Protecticn System; and thus, 10 CFR 50.72 and the licensee's Nuclear Division Procedure NDP-600-3, titled " Event Reports," require that this occurrence be reported to the NRC within four hours. On June 30, 1987, the inspectors discussed the need to report this event with a licensee representative, and subsequently a report to the NRC was made at 7:05 p.m. on June 30, 1987. Failure to report an actuation of the RPS in accordance with 10 CFR 50.72 is considered a violation (87-24-01).

A review of records including the control room log, shift supervisor turnover checkoff lists, and P0T-12-2 documentation, appears to indicate that prior to this discussion with the inspectors, no written record was made of the receipt of a general warning reactor trip signal. Coincident with the report to the NRC, the event was logged in the control room log; a reactor shutdown / trip form and post-trip review form were completed; and Event Report 87-121 was initiate Although the actual safety significance of the reactor trip breakers opening was low given plant conditions at the time of occurrence, this event appears to indicate a need for increased awareness of the reporting requirements of NDP-600-3 and 10 CFR 50.72. As stated in NDP-600-3, events need to be reported to ensure that lessons learned from operating experience result in corrective actions to improve plant safety and reliability. This event indicates at least three areas where corrective actions and/or improvements need to be considere First, it appears based on the licensee's initial determination of the cause of the opening of the reactor trip breakers that Annunciator F(K13), Window A-2 labeled

" Protection System Train A Trouble," alarmed prior to the operators closing bypass breaker BYB, which resulted in a general warning reactor trip. According to the Annunciator Response Guide (ARG), Revision 12, the appropriate action is to determine and correct the cause. The ARG lists several potential causes, including loss of 48 volt DC power suppl Failure to properly respond to an annunciator alarm appears to have contributed to this event. Second, the cause of the 48 volt DC power supply breaker being open should be investigated to identify if improvements to the solid state protection system power supply are neede Third, it appears that the immediate diagnosis of the cause of the reactor

' trip signal was made more difficult because general warning on a solid state protection system is not displayed on the reactor trip status panel.

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discussed in recent inspection reports (e.g., 50-344/87-18 and 50-344/87-07). The required telephone notification reports per NDP-600-3 = were not made in a timely manner as described above. NDP-600-3 also requires that PGE Nuclear Division employees shall be alert for and report ~ t all abnormal events, which as defined includes this event. Although a time limit for initiation of an event report is not specified, Event Report 87-121 was initiated subsequent to a discussion with the inspectors. Administrative Order A0-3-7, titled " Post-Trip Review and Permission for Reactor Trip Recovery and Mode Changes," requires that a Reactor Shutdown / Trip form and Post-Trip Review form be initiated following a reactor trip. Although a time limit for initiation of these forms is not specified and " reactor trip" as defined in A0-3-7 could be interpreted to not include a general warning reactor trip, the need to initiate these forms was apparently not considered prior to a discussion with the inspectors. After the discussion, both forms were initiate . Piping Support and Restraint Systems I=L

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An inspection was performed to verify proper installation and operation of , pipe and component support and restraint systems in accordance with the Technical Specifications and licensee procedures. The inspectors also reviewed the licensee's program for the surveillance of pipe supports and , restraints and associated record The inspectors visually examined twenty dynamic and fixed piping supports on safety-related portions of the "A" and "C" main steam lines. The inspection verified that hydraulic fluid leaks, deterioration, corrosion, physical damage and deformation were not evident. The integrity of the support plates, extension rods, and connecting joints was also examine As discussed in paragraph 6, the licensee determined that the allowable anchorage capacities of the supports for the hydraulic snubbers on each of the main steam lines was exceeded by stated design loads. As part of its response, the licensee conducted an inspection of main steam line supports. A review of this inspection program was performed, including a review of NPE Civil Guide EG-010, dated June 7, 1987, which outlined the a fa pection procedure; a review of the inspector qualification files; and a review of the inspection record For a sampling of the supports, the inspectors independently verified the inspection result In addition, the inspector performed an as-built inspection of the following hanger supports for compliance with the civil drawings and code requirements: EBB-1-2-SS-88 and 92 on the main steam lines and EBB-3-1-SR-8 on a main feedwater line. The support configuration, weld type and size were as specified on the applicable drawing The licensee's inspection program resulted in twenty-two Nonconformance Reports (NCRs). Four NCRs were related to the hydraulic snubbers on each line (EBB-1-1-SS-81 and SS-86, EBB-1-2-SS-88 and SS-92) and identified the presence of cracks between the support baseplate and grout, and between the grout and supporting wall. The remaining NCRs dealt primarily with the identification of discrepancies between the as-found condition and design drawings. These discrepancies were dispositioned by performing calculations to determine if adequate design margin could be assured for

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the as-found condition. In those cases where adequate design margin was not assured, the determination was made to restore the design margin by modifying the supports. This process resulted in identifying the need to repair three supports during this outage period in addition to the seven supports which required modifications based on a review of tiic dynamic load analyses as discussed in paragraph 6. In addition, maintenance requests were prepared to make adjustments to various hangers and supports in the main steam support structure and turbine building. The significance of these inspection findings is discussed in paragraph The Technical Specifications set forth snubber surveillance requirements consisting of a visual inspection program, functional test program, and

service life monitoring program. The licensee's program is controlled by l

the following procedures: PET-7-2, " Hydraulic Snubber Visual Examination"; PET-9-7, " Hydraulic Snubber Functional Testing"; and PET-9-6, " Mechanical Pipe Snubber Visual Examination and Functional , Testing." A review of the test records for PET-9-6 verified that a visual ' inspection of an initial sample of 82 mechanical snubbers was performe One mechanical snubber failed the visual inspection, but was tested to be operable in functional testing. A 100% visual inspection of hydraulic snubbers was performed. Functional testing of mechanical snubbers ' revealed six failures which required and resulted in, for each failure, testing of an additional 10% of the snubber units of that type. The test records of functional testing, per PET-9-7, of hydraulic snubbers on the main steam lines were reviewed. Nonconformance reports were written, as appropriate, in response to test failures. Testing of reworked snubbers demonstrated that the Technical Specifications and procedural requirements for activation velocity, bleed rate, and drag force were met. The service life monitoring program for a sample of mechanical and hydraulic snubbers was reviewed. The inspection verified records were being maintained of the installation and maintenance records for these snubber No violations of NRC requirements or deviations were identiff a . Event Follow-Up "A" Accumulator Fill Line Failures On May 12, 1987, with the plant in Mode 6, the A accumulator fill line failed immediately upstream of the socket weld to the accumulator tank nozzle. At the time, the operators were in the process of transferring water from the A accumulator to the D accumulator using the accumulator fill line Upon receiving a report of water spraying inside conta.nment, the operators shut the valves on the fill lines of both accumulators in an attempt to isolate the leakage. The operators had earlier unsuccessfully attempted to transfer water using the accumulator sample lines.

l On May 23, 1987, with the plant in Mode 6, a second failure of the A accumulator fill line was experienced at the same location. The fill line piping had been replaced per MR 87-2922. A hydrostatic test per procedure SPT-87-054 had been performed. To decrease the volume of l water in the A accumulator following the test, the operators started transferring water from the A to D accumulators through the fill

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 . 7 lines. On receiving reports of loud noises in containment, the operators stopped the operation, investigated, and upon finding no apparent problems with either the A or D accumulator, the operators restarted the water transfer from A to D accumulators. Reports of l'  loud noises in containment were again received. The operation was stopped and then restarted. The fill line then failed, and reports of water in containment were received. An entry in the control room log the following day instructed the operators to not use the accumulator fill lines or the accumulator sample lines to transfer water between accumulators pending evaluation of the failures. At the time of the second failure, NCR 87-163 was still outstanding on the first failure of May 1 The noise reported in containment lasted on the order of 10 seconds

!. and resembled that of a jack hammer. The source of the reported noise in containment was determined to be caused by backflow through , a packless metal diaphragm (PMD) manual isolation valve in the fill line which is normally held open by the force of a spring on the disc assembly. Subsequent to the second failure, the licensee's immediate actions included investigating the effect of r2 verse flow through the PMD valve, which is designed for unidirectional flow; metallurgical examination of the second failure; inspections of the PMD valves and control valves on all four accumulator fill lines; and inspections of seismic supports on the fill lines. As part of its response to the accumulator fill line failures, the licensee performed nondestructive examination testing of the welds immediately adjacent to the four accumulator tanks for all lines and subsequently on selected pipe welds on the fill and sample lines. The inspectors witnessed liquid penetrant testing of several welds and verified that the QC inspectors were following the appropriate procedures: QCP 6, titled

 " Liquid Penetrant Inspection," and QCP 5, titled " Visual Examinations." Completed liquid penetrant testing reports were reviewed. Testing identified four surface indications, two on the B accumulator outlet line, one on the B accumulator fill line, and one on the D accumulator outlet line. These indications were removed by surface conditioning; and upon re-examination by liquid penetrant testing, the surfaces showed no indications. In response to NRC concerns, the licensee measured the wall thickness and performed calculations to verify that minimum allowable wall thickness remained after surface conditionin The licensee pursued the possibility of chattering and system pressure pulses caused by the manual PMD valves upon imposition of reverse flow and large pressure drops across the valve. Bechtel was asked to develop a dynamic analyses model to determine the magnitude of the forces on the line. This included modeling the fill line from the accumulator nozzle to the control valve to determine the forces imposed on the failure location. The licensee contacted the valve manufacturer and other utilities for information on experience with reverse flow through PMD valves. Subsequently, the licensee ran a bench test using a PMD valve on a one inch line to duplicate accumulator line conditions in an attempt to duplicate the chattering that was thought to have occurred. The bench test results showed chattering and onset of failure of the fill line at a flow rate

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greater than would be expected through the sample lines and less than would be expected through the fill lines. Inspection of a sampling of PMD valves and control valves on the accumulator fill and sample l lines showed no indication of chattering except for the A accumulato Results of the licensee's dynamic analysis of the accumulator fill l line were reviewed. A thermal hydraulic analysis model of the piping I between the A and D accumulators was developed, and computer analysis runs indicated that significant pressure pulses and forces were generated due to the closure of the PMD valve when subjected to back j flow conditions. Sensitivity analyses were performed to determine I the effect of PMD valve closure time, sequence of control valve operations, and fill line flow rate. The analyses results indicated that reverse flow through the PMD valve resulted in. fluid forces of sufficient magnitude to have caused the low cycle fatigue failures that were experienced. The analyses also indicated that calculated piping stress levels under normal conditions were well within the allowable value After the first failure of the fill line, MR 87-2922 was prepared , which provided for retrieving portions of the failed piping on both sides of the fracture for metallurgical examination, as well as the installation of replacement piping. The licensee's metallurgical examination of the failed portions from both failures was documented in report ASD 2806 87M, dated June 1, 1987. The examination concluded that both failures were a result of low cycle, high stress fatigue cracking. The examination revealed no metallurgical or chemistry related causes whicn contributed to the failure Examination of the heat affected zone's grain boundaries and microstructure did not show indication of excessive welding hea The two failures were determined to have the same failure mode based on an examination of the location of the cracks, crack progression, and fracture surfaces characteristic The inspectors verified both failed pipes met applicable material specifications. For the first failure, a review of the material test report verified that pipe was ASME A312, Type 304 material. For the second failure, the inspectors reviewed the applicable storeroom material issue sheet, receipt inspection report, purchase order package and material test certificate and verified the pipe was of ASME A312, Type 316 material. The design material specification requires either ASTM A312, Type 304 or Type 31 The licensee's evaluation included a review of other plant systems to determine susceptibility to failures from back flow through PMD { valves. All applications of these valves were reviewed, and about thirty instances were identified which had potential for back flow conditions. Although most had minimal expected flowrates of less i than 10 gpm, the licensee planned to prohibit back flow through these I valves until further evaluation was complet Based on the inspection described above and a review of the licensee's evaluation, it appears that the licensee has identified l l l _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ - _ - _ _

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the root cause, developed a technically strong explanation for the failure. occurrence and has taken actions to assure that similar -{ failures will not occur. . The licensee's evaluation as discussed- 1 above included dynamic analyses, metallurgical examinations and bench

  ' flow testing. Failure'_.to-obtain a deviation from Trojan operating procedures and failure to establish adequate controls using QC hold tags or' danger and caution tags as discussed in inspection report 87-18 will continue to be followed as open items 87-18-02 and 87-18-0 !

l Main Steam Line Support i Upon completion of functional testing of. hydraulic snubber EBB-1-1-SS-81 on main steam line "B", a visual inspection of the associated support identified separation between the grout and

  ' baseplate and the grout and bioshield wall. Nonconformance Report NCR 87-214 was written for the observed condition. Inspection.of the corresponding hydraulic snubber supports on the other three main-steam lines showed similar grout separation. As part of the evaluation of NCR 87-214, design load demands were compared to support capacities- Preliminary evaluations indicated that dynami .

loads for a turbine trip transient as indicated on the SS-81 pipe-support detail were two to three times greater than the support allowable anchorage capacities. ' Event Report 87-108 was initiated to

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evaluate the apparent design discrepanc The licensee's corrective actions included a design review of all supports designed by the group within the Architect-Engineer's organization that was responsible for SS-81; a review of the dynamic-load analyses for all safety-related supports; and field inspections of main steam line supports. For the main steam system, the review of the~ dynamic load analyses identified seven supports as needing modifications to restore desired design margins. Field inspections identified an additional three supports for modification. The modifications are being performed under Request for Design Change 86-001. The field inspections identified an additional thirteen supports which required minor adjustments to clamps, shim packs and hanger spring cans'. The results'of the field inspections were verified by the inspectors as discussed in paragraph 5. The review of support design and dynamic load calculations is being performed by NRR. A preliminary , review of the ' dynamic load calculations resulted in several concerns

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and a July 9,1987, letter to the licensee requesting information pursuant to 10 CFR 50.54 (f) to provide assurance that the original , design of piping and. supports in various safety-related systems, including the main steam system, meet the licensing design base The licensee responded in letters dated July 10 and July 15, 198 The resolution of these concerns, as well as operability concerns of the as-found condition of the main steam system will be addressed =in the evaluation of Event Report 87-108, and will be followed as an ! open item (50-344/87-24-02).

No violations of NRC requirements or deviations were identified.

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10 Steam and Feed System Pipe Wall Thinning (1986 Surry Event Follow-up) , As followup to the December 1986 Surry feedline rupture and planned 1987 ) Trojan outage activities, the inspectors examined the licensee's program i for determining wall thickness of piping subject to erosion / corrosio The inspectors concluded the licensee's program accomplished the j following: i I

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Identified piping experiencing accelerated wall thinning due to I erosion / corrosio Appropriately and correctly established repair and replacement criteria for piping experiencing accelerated wea Was maintained current with industry practices. Additionally, the licensee attended-the Surry event lessons learned symposium attended a training session on the EPRI CHEC Program, and is planning to implement the EPRI CHEC Progra 'The inspectors examined the licensee's response to INP0 SER's 1-87 and 6-87 and NRC ins 86-106, 86-106 Supplement 1 and 87-19. The licensee through various internal memorandums identified the need to examine piping with moderate flow velocity; however, these examinations were not included in the revised 1987 outage UT program to identify wall thinning. They were added when unexpected erosion was identified in the feedpump discharge piping. Additionally, the licensee identified safety related  ! components whose function could be compromised if a failure of the feed piping were to occur. This analysis will be conducted following the 1987 i outag ! The inspectors made the following observations while evaluating the licensee's program for determining wall thinning:

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In evaluating 1985 wall thinning data, the licensee, without documenting departure from accepted engineering practice, non-conservatively based wall thinning analysis on operating pressure vice design pressure. The licensee felt justified in their actions since the Code is generally conservativ In evaluating 1986 wall thinning data, the licensee failed to identify, due to an individual's oversight, a portion of the main steam system piping being less than minimum well thicknes The 1986 wall thinning data analysis of the 30" feedwater header was nonconservative because wall thickness values for 24" pipe vice 30" pipe were use l

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Plant Engineering Procedure (PEP) 30-9, Rev. O dated 6/26/86, l Secondary Piping Erosion / Corrosion Monitoring Program did not ! establish detailed criterit for establishing sample selectio In spite of these errors and potential deficiencies, the 1987 Outage program for determining wall thinning eventually identified sections of

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feedwater piping that were experiencing substantial unexpecte erosion / corrosion. The licensee has committed as a result of their findings during the 1987 outage, to take action to implement program enhancements such as upgrading PEP 30-9. Additionally, during the 1987 outage,.the licensee repaired or replaced all safety and non-safety piping and welds that were less than minimum wall thickness or projected to be less than minimum wall thickness prior to the 1988 outag Due to the licensee's thorough ultrasonic testing (UT) of feedwater piping after detecting unexpected erosion / corrosion at the feed pump discharge piping, sections of piping previously predicted by recent industry

'  criteria not to be vulnerable to accelerated erosion / corrosion were foun As a result of the licensee's. findings, further industry examination of erosion / corrosion effects on carbon steel piping is being pursued. NRR has the lead on the plant specific and generic aspects on this topi As part of the, inspection, the inspector observed in-process welding being performed on Weld No. P25884 of the "D" Feedwater lin The welding at
 'this joint, a pipe-to-elbow connection, was examined for welding
 ' technique, weld joint geometry, weld type and identification, correct   j filler material and proper filler metal control. The inspector also visually examined the completed weld. joints performed on several 90 elbows of the "A" and "C" feedwater lines. These were examined for size, shape, surface condition, arc strikes, weld spatter, and surface defect All weld activities were in compliance with applicable procedures and codes. The inspector noted that each section of pipe welded, or to be welded, was properly identified, which allowed the inspector to identify the purchase order (P0 No. 2245), and to review the applicable CMTR The inspector observed the storage of welding materials utilized in the welding operations. All filler material located in holding ovens and in opened containers were correctly identified. Each holding oven contained one classification of electrode, and were calibrated and operating within the required temperature rang No violations of NRC requirements or deviations were identfie . Quality Hotline On July 14, 1986, the Quality Hotline was implemented via Nuclear    j Department Procedure (NDP) 600-4. The PGE Quality Hotline was modeled after the Arizona Public Service Quality Hotline. The Quality Hotline, via direct phone access to the Vice President Nuclear, provides the   )

employee the opportunity to identify quality concerns to the highest ' levels of corporate management. Employee awareness of the Quality Hotline is achieved through General Employee Training and Quality liotline poster Dispositioning of employee concerns made via the hotline has been within the guidelines established in NDP-600-4. In all cases the employee quality concerns identified areas where clarification or improvements were warrante !

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The licensee attributes low usage of the Quality Hotline to increased employee utilization of the other quality reporting systems (Event Reports, Nonconformance Reports and Nonconforming Activity Reports) and effectively managing employee concerns at all supervisory and management level No violations of HRC requirements or deviations were identifie . Training of Contract Quality Control (OC) Personnal . The inspector examined the training records of the QC contract personnel employed by the licensee during the 1987 refueling outage. The training 1 records thoroughly documented the training received by the contract personnel. Training required for temporary QC personnel is delineated in Quality Control Procedure QCP-25, Revision 1. Contract personnel received the training required by procedure QCP-25, Revision 1. The training delineated in QCP-25 requires knowledge of various plant Administrative, Nuclear Department and Quality Control Procedures. In addition NRC fi Inspection Report No. 50-344/86-24 is part of required reading serving as lessons learned. Following completion of all QCP-25 requirements an examination is administered. If the minimum grade is not achieved, the temporary QC person receives retraining and is again examined. The inspectors noted only one examination was generated for each disciplin The readministered examination as a result of a failure was the same as the initial examination. The licensee committed to changing this practice for all future temporary QC personne No violations of NRC requirements or deviations were identifie . Exit Interview The inspectors met with the licensee representatives denoted in paragraph 1 on July 31, 1987, and sunmarized the scope and findings of the s inspection activitie , _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ .. }}