IR 05000213/1986024

Insp Rept 50-213/86-24 on 860815-0930.No Violations Noted. Major Areas Inspected:Plant Operations,Radiation Protection, Physical Security,Fire Protection,Maint,Surveillance,Open Items,Ie Bulletins & Licensee Events

ML20211D465
Person / Time
Site:	Haddam Neck File:Connecticut Yankee Atomic Power Co icon.png
Issue date:	10/09/1986
From:	Mccabe E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20211D435	List: IR 05000213/1986024 ML20211D430
References
50-213-86-24, IEB-80-06, IEB-80-6, IEB-85-003, IEB-85-3, NUDOCS 8610220198
Download: ML20211D465 (12)

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U.S. NUCLEAR REGULATORY COMMISSION

REGION I

Report N /86-24 DCS NOS. 50-213/85-08-02 50-213/86-01-04 Docket N /86-07-08 50-213/86-07-23 License N DPR-61 50-213/86-08-06 50-213/86-08-30 Licensee: Connecticut Yankee Atomic Power Company P. O. Box 270 Hartford, CT 06101 Facility: Haddam Neck Plant, Haddam, Connecticut Inspection at: Haddam Neck Plant Inspection conducted: August 15 - September 30, 1986 Inspectors: Stephen M. Pindale, Resident Inspector Paul D. Swetland, Senior. Resident Inspector Approved by: bb to/9/Pd E. C. McCabe, Chief, Reactor Projects Section 3B Date Summary:

Areas Inspected: This was a routine resident inspection (137 hours0.00159 days <br />0.0381 hours <br />2.265212e-4 weeks <br />5.21285e-5 months <br />) of the fol-lowing areas: plant operations, radiation protection, physical security, fire pro-tection, maintenance, surveillance, open items, IE Bulletins and licensee event Results: Na violations were identified during the inspection. Ten NRC open in-spection findings were closed. One unresolved item was identified concerning the adequacy of the fire barrier between the control room and computer room (Detail 2.1),

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TABLE OF CONTENTS Page 1. Summary of Facility Activities....................................... 1 2. Review of Plant Operations........................................... 1 3. Observation of Maintenance and Surveillance Testing.................. 2 4. Followup on Previous Inspection Findings............................. 2 4.1 Main Steam Safety. Valve Setpoint Errors....................... . 2 4.2 Charging Pump Shaft Fracture....... ............................ 3 4.3 Unanalyzed Post-LOCA Release Paths.............................. 3 4.4 Double Valve Isolation During Maintenance....................... 4 4.5 Improper Nonconformance Dispositioning.......................... 4 ;

4.6 Instrument Technician Training in Technical Specifications...... 4 4.7 Reactor Protective System Channel Interaction................... 5 t 4.8 Power-0perated Relief Valve Retesting........................... 5 4.9 Wa te r Chemi s t ry Sampl e C hec k s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 4.10 Steam Generator Tube Testing and Repair......................... 6 5. Followup on IE Bu11etins.................... ........................ 7 6. Followup on Events Occurring During the Inspection................... 8 7. Review of Periodic and Special Reports............................... 9 8. Unresolved Items..................................................... 9 9. Exit Interview....................................................... 10 i

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DETAILS Summary of Facility Activities During the inspection, the plant operated at full power except for a manual plant trip on August 30, 1986. Operators tripped the plant after main feed-water (MFW) system problems resulted in rapidly increasing steam generator levels. The MFW transient (Report Detail 6.2) was caused by a failed open feedwater regulating valve (FRV). Power operation resumed on September 3, upon completion of FRV repair . Review of Plant Operations The inspector observed plant operation during regular tours of the following plant areas:

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Control Room --

Security Building

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Primary Auxiliary Building --

Fence Line (Protected Area)

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Vital Switchgear Room --

Yard Areas

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Diesel Generator Rooms --

Turbine Building

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Control Point --

Intake Structure and Pump Building Control room instruments were observed for correlation between channels and for conformance with Technical Specification requirements. The inspector ob-served various alarm conditions which had been received and acknowledge Operator awareness and response to these conditions were reviewed. Control room and shift manning were compared to regulatory requirements. Posting and control of radiation and high radiation areas was inspected. Compliance with Radiation Work Permits and use of appropriate personnel monitoring devices were checked. Plant housekeeping controls were observed, including control-and storage of flammable material and other potential safety hazards. The inspector also examined the condition of various fire protection system During plant tours, logs ar.d records were reviewed to determine if entries

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were properly made and communicated equipment status / deficiencie These records included operating logs, turnover sheets, tagout and jumper logs, i

process computer printouts, and Plant Information Reports. The inspector observed selected aspects of plant security including access control, physical

barriers, and personnel monitoring. The fol. lowing concern was identified.

2.1 On September 2,1986, the licensee notified NRC Licensing of problems encountered implementing Technical Specification (TS) Amendment 81 be-cause of deficiencies with the fire barrier between the control room and the computer room. The existence of a 1-hour fire barrier with attendant

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fire detection and suppression systems was specifically conditioned in the basis of TS Amendment 81, which approved the deletion of the existing computer room fire detection system. The licensee identified that the new computer room fire detection and suppression systems were not yet l ready for operation and that deficiencies existed in the certification I

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of the 1-hour fire barrier between the control room and the computer roo The inspector discussed these problems with NRC Licensing and licensee management.on September 3, 198 The inspector noted that both the new control room fire. detection /sup -

pression system and the old control / computer room fire detection system remained operable, however,-the computer room fire wall was not being

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controlled by the licensee as a TS fire barrie The licensee stated that they did not consider this wall to be a required fire barrier until it was identified as a basis for TS amendment 81. Since the quality of the computer room fire barriers were now in question, the licensee (the Acting Station Superintendent) committed to maintain the computer room fire detectors operable'and to implement a 1-hour roving fire patrol for that barrie These actions were found to be adequate pending further review of the bases for the computer room fire wall and TS Amendment 8 This item is resolved pending further NRC and licensee review (UNR 213/

86-24-01).

3. Observation of Maintenance and Surveillance Testing The inspector observed maintenance and problem investigation activities for compliance with requirements and. applicable codes and standards, QA/QC in-volvement, safety tags, equipment alignment and use of jumpers, personnel qualifications, radiological controls, fire protection, retest, and report-abilit Also, the inspector witnessed selected surveillance tests to deter-mine whether properly approved procedures were in use, test instrumentation was properly calibrated and used, technical specifications were satisfied, testing was performed by qualified personnel, procedure details were adequate, and test results satisfied acceptance criteria or were properly dispositione The following activities were reviewed:

PMP 9.1-16 Control Rod Alignment SUR 5.1-5 Periodic Check of Containment Trip Valves and Containment Recirculation Fan Dampers _

t No unacceptable conditions were identifie . Followup on Previous Inspection Findings l

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During the inspection, eleven NRC open items were reviewe The inspector found licensee actions on ten of these to be sufficient to close the item Final corrective actions on two potential ~unanalyzed release paths are schad-i uled for the refueling outage in July 1987, and will be reviewed upon comple-l tion of those actions. Details follow:

l 4.1 Main Steam Safety Valve Setpoint Errors l (Closed) Followup Items (213/84-32-01 and 85-25-02). The inspector re-I viewed the causal analysis and corrective actions resulting from the as-l found setpoint errors during testing of main steam safety valves (MSSVs).

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The licensee repaired / reset the out of specification MSSVs. In addition, surveillance test procedure 5.5-2 was revised to improve the accuracy of lift pressure readings. All 16 MSSVs were satisfactorily retested during the plant restart from refueling on May 5, 1986, but MS-SV-13 again failed to open at the limit of the air assist test motor pressur The licensee subsequently determined that the valve body dimensions on MS-SV-13 are different from the other HSSVs, requiring a different air assist motor baseplate thickness for the test. After proper remounting of the test motor on MS-SV-13, the valve functioned satisfactorily. The licensee stated that the MSSV test procedure 5.5-2 would be revised to address proper mounting of the test motor for each MSSV. The inspector had no further questions in this are .2 Charging Pump Shaft Fracture (Closed) Followup Item (213/85-07-02). The licensee was to determine the cause and final corrective action for the May 1985 failure of the

"A" charging pump shaf A second "A" charging pump failure occurred in July 198 After the second failure, licensee and manufacturer in-vestigation identified the failures as due to fatigue because of improper fit of components on the pump shaft and too loose an axial clearance on the thrust bearing. The "A" charging pump had been assembled in accord-ance with the manufacturer's guidelines. Revised fit-up and axial clear-ance tolerances were tentatively identified after the first failure, but no additional preventive maintenance was initiated. After the July 1986 failure, the pump shaft was replaced and the charging pump was reas-sembled using new guidelines. Pump retest was satisfactory. The in-spector noted that the "B" charging pump had been assembled using the manufacturer's old guidelines and may be subject to a similar failure mod The licensee stated that this fatigue failure manifests itself during early pump operation. As such, the continued operation of the N" pump af ter more than twice the operating hours of the "A" pump shows t'at the "B" pump tolerances are adequate to prevent this failure mod The licensee now performs periodic maintenance checks of the charging pu.ap thrust bearing clearance. The inspector had no further questions at this time. During the next assessment of licensee performance, the 1 year period between initial identification of this problem and its second occurrence will be considere .3 Unanalyzed Post-LOCA Release Paths (0 pen) Unresolved Item (213/85-13-02) The acceptability of certain un-analyzed post loss of coolant accident release paths was unresolved pending NRC review and licensee implementation of corrective action The licensee identified an additional potential release path in the reactor coolant system (RCS) drain piping. The drain header relief valve discharges outside containment and would be expected to lift upon con-tainment isolation actuation if the plant was using the alternate RCS letdown path through the drain header. An upstream motor-operated valve

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(DH-MOV-310) could be closed to terminate a release through this pat However, this valve could not be fully environmentally qualifie Con-sequently, the licensee has tagged "H-MOV-310 closed.during normal operation. The inspector-verified.the satisfactory implementation of this administrative control ~. The details of this new release path were documented in Revisions 1 and 2 to Licensee Event Report 50-213/85-1 In these reports, the licensee described additional planned corrective actions including rerouting of the piping relief paths inside containmen Based on the licensee's actions, the NRR-licensing project manager in-formed the inspector that NRC Licensing had concluded that the offsite dose calculation concerns were adequately addressed. This item remains open pending licensee implementation and NRC review of the proposed system modification .4 Double Valve Isolation During Maintenance (Closed) Followup Item (213/85-19-01). The licensee was to review and implement, as necessary, operator guidance on the use of double isolation boundaries during system maintenance. On January 15, 1986 an Operation Department Instruction (0DI-151) was issued explaining the need for two-valve protection and detailing the system operating criteria and radi-ation. exposure reduction circumstances for implementing two valve pro-tection. The inspector verified operator training in and knowledge of 001-151. No inadequacies were identifie .5 Improper Nonconformance Dispositioning (Closed) Followup Item (213/85-21-05). The licensee did not disposition a nonconformance report (NCR) in accordance with quality assurance pro-cedures. The individuals involved were counseled regarding the import-ance of compliance with all aspects of the quality assurance (QA) progra This event was also the subject of departmental training as a case study session. In addition, departmental supervision was called in for off-hour jobs to assure adequate and timely completion of QA documentatio Inspector review of sub quent work packages identified no further in-stances of inadequate WC.i processin .6 Instrument Technician Training in Technical Specifications (Closed) Followup Item (213/85-21-06). The licensee was to conduct training for instrumentation technicians with regard to Technical Speci-fication (TS) requirements. Instrumentation technicians had removed a reactor protection system channel from service without notifying opera-1 tors because they did not understand the safety and technical specifica-

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tien implications of their intended wor The licensee conducted initial TS training in December 1985. Subsequently, this training has been in-

! corporated in the formal Technical Training Program initiated in 1986.

The inspector reviewed the lesson plans for TS training and verified the

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adequacy of coverage and attendanc No inadequacies' ware identified.

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4.7 Reactor Protective System Channel Interaction (Closed) Followup Item (213/85-21-12). The NRC examined the high steam line flow (SLF) automatic reactor and turbine trip for generic implica-tions of reactor protection system (RPS) cht.nnel interaction. Special licensee procedure SPL 10.2-22 was developed to quantify the extent of the high SLF channel interactio Performance of SPL 10.2-22 indicated'

extensive interaction among the four SLF channels. Further licensee investigation revealed that the channel interaction occurred as a result of common routing of associated circuitry from all four channels. The licensee subsequently resolved the immediate SLF interaction concern by re-routing portions of the associated RPS cabling to provide physical separation of SLF circuit control and signal leads. However, complete physical separation of the high SLF portion of the RPS does not exist at the channel level. Following the cable re-route, SPL 10.2-22 was used-to verify the adequacy of the change. The test results demonstrated negligible channel interactio Licensee review of other RPS channels showed that they also do not pro-vide complete physical separation.among redundant channels. However, the licensee has not experienced similar interaction in the other RPS channel The SLF channel interaction caused problems during routino surveillance test The potential consequences were conservative in that they would have caused a trip to occur sooner during a transient. But they also represented potential unnecessary challenges to safety systems. Appro-priate action has been taken to correct the problems encountered. This item is therefore close The licensee performs pressurizer pressure and level channel checks every six weeks. During these tests, no channel interaction has been apparen However, lack of physical separation of all RPS channels remains a potential system weakness. The licensee plans to intearate RPS channel interaction and separatial concerns into existing project assignment 83-113, RPS Upgrade, which will modify or replace the RPS to improve system capability. Implementation of the RPS system upgrade will be followed under the NRC's Integrated Safety Assessment Progra .8 Power-Operated Relief Valve Retesting (Closed) Followup Item (213/85-21-14). The licensee did not implement system retest requirements for the power-operated relief valves in ac-cordance with quality assurance (QA) procedures. QA procedure 1.2-5.1, Trouble Reporting and Automated Work Orders, has since been revised to clarify requirements for retesting work performed for implementation of design change In addition, new procedures governing implementation of design changes require separate review of~ work orders prior to testing and system turnover. Plant engineers received training on these proce-

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dures in September 1985. Inspector review of plant design changes im-plemented during the January - April 1986 refueling outage identified no further instances of poor test control and documentatio .9 Water Chemistry Sample Checks (Closed) Followup Item (213/85-24-01) An evaluation was to be made fol-lowing completion of chemical analyses of water samples by the licensee and Brookhaven National Laboratory (BNL). During NRC Region I-Inspectien 50-213/85-24, service water,- steam generator blowdown, and reactor cool-ant were sampled and analyzed by the licensee. Duplicate samples were sent to the BNL for an independent check of these analyses. A statis-tical evaluation was not made for most of the analyses because the analysis uncertainties were not availabl The sample results are tabu-lated below:

Split Sample Comparison Sample Source Chemical Parameter BNL Value CY Value Results in parts per billion (ppb)

Service Water chloride 9 iron 100 480 copper 502 540 S.G. Blowdown hydrazine 4 2 ammonia 535 +/- 10 450 +/- 7 Results in parts per million (ppm)

Reactor Coolant boron 102 102 The iron and copper differences were attributed to insufficient acid in the BNL sample causing hydrolyzation. The ammonia difference is sus-pected to be caused by sampling errors. The inspector-had no further questions in this are Further addressal of this matter will be accomp-lished, as' appropriate, during "outine NRC specialist inspectio .10 Steam Generator Tube Testing and Repair (Closed) Followup Item (213/86-01-05). The inspector was to review the completion of steam generator (SG) eddy current testing (ECT) and tube repairs following the 1986 refueling outage. The inspector verified the completion of ECTs on all SGs and the subsequent plugging of tubes with greater than 50 per. cent through-wall indications. One tube (37-73) was not plugged as required and was satisfactorily dispositioned as docu-

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mented in NRC Region I Inspection Report 50-213/86-06. That tube was subsequently plugged during a SG repair outage in July 1986. Four tubes in SG #4 were not inspected due to obstructions with the test apparatu On April 15, 1986, the licensee requested a change to Technical Specifi-cation (TS) 4.10 which would. exempt these tubes from inspection during this cycle. NRC Licensing determined that the safety effect of the un-inspected tubes was minimal based on the satisfactory history of ECT data for tubes in that SG location. Based on the completion of SG tube re-pairs and interim assessment of the. safety implications of the licensee's April 15, 1986 amendment request, no unacceptable conditions have been identified. Subsequent SG tube concerns are discussed in NRC Region I Inspection Report 50-213/86-20. Follow-up actions in this area are tracked'by NRC Licensing under action control No. 6126 . Followup on IE Bulletins (IEBs)

5.1 Licer=ee action on the following IE Bulletins was reviewed for forwarding to appropriate management and licensee review for applicability; response timeliness, appropriateness, and accuracy; and the adequacy of corrective action commitments and implementatio IEB 80-06, Engineered Safety Features (ESF) Reset Controls IEB 80-06 involved the verification that all ESF components remain-in the accideat mode upon reset of the actuation signal. NRC review of licensee implementation of bulletin commitments was documented in NRC Region I Inspection Report 50-213/84-32. Six components were identified as requiring modification to meet the IEB 80-06 specified reset criteria. By letter dated January 24, 1985 the licensee com-mitted to make those modifications during the 1986 refueling outag These modifications to the containment air recirculation dampers, the containment sump pump discharge valve and the containment air sampling system suction valve were completed in April 1986. The inspector reviewed plant design change package PDCR 86-811, Con-tainment Isolation Circuit Hodifications, and the post-modification test SUR 5.1-5, Periodic Check of Containment Trip Valves and Con-tainment Recirculation Fan Dampers, to verify satisfactory imple-mentation of the final bulletin commitments. No discrepancies were identified. NRC followup action on IEB 80-06 has been close IEB 85-03, Motor-0perated Valve Common Mode Failures By letter dated June 11, 1986, Northeast Utilities provided their bulletin response. That response describes implementation of a program to ensure that switch settings on the specified safety-related motor-operated valves are selected, set and maintained cor-rectly to accommodate the maximum differential pressures expected during normal and abnormal events within the design basis. Sched-uled completion dates were provide _- .- -_ . ___ .-

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The inspector found the licensee's response timely in that the pro-

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gram for implementation was submitted within the extension period requested on May 14, 1986. Discussions were held with corporate

and site personnel regarding their selection of motor-operated 4 valves covered by the bulletin, the three vendors being considered to supply test equipment, and~the order of testing (Millstone-1 in May, 1987 with Haddam Neck, Millstone-3 and Millstone-2 following).

No problems wi.th the. licensee's program were identified. Adequacy of the licensee's proposed actions will be reviewed at a later dat . Followup on Events Occurring During the Inspection

! 6.1 Licensee Event Reports (LERs)

The following LERs were reviewed for clarity, accuracy of the description of cause, and adequacy of corrective action. The inspector determined

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whether further information was required and whether there were generic implications. The' inspector also verified that the reporting require-ments of 10 CFR 50.73 and Station Administrative and Operating Procedures had been met, that appropriate corrective action had been taken, and that the continued operation of the facility was conducted within Technical Specification Limit Setpoint Drift of Main Steam Safety Valves, Revision 2 (Detailed in paragraph 4.1 of this report)

86-37 Containment Isolation Valves for Safety Injection Recirculation Lines (Detailed in NRC Region I Inspection Report 50-213/86-20)

86-38 Axial Offset Monitor Out of Calibration (Detailed in NRC Region I Inspection Report 50-213/86-20)

86-39 Personnel Overexposure (Detailed in NRC Region I Inspection Report 50-213/86-22)

1 86-41 Manual Reactor Trip Caused by Failed Open Feedwater Regulating i

Valve (FRV) (Detailed below)

6.2 Manual Reactor Trip Caused by a Failed Open FRV (LER 86-41)

On August 30, 1986, the plant was manually tripped from 100% power due to a failure of the #1 feedwater regulating valve (FRV). The control room operators received and acknowledged main feedwater (MFW) system low suction and low discharge pressure alarms. There was an automatic trip and immediate restart of one MFW pump. The operators noted a rapidly

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increasing water level (beyond 80% wide range) in the #1 steam generator (SG) and promptly tripped the reactor and turbine. Plant systems re-sponded normally following the trip. Licensee post-trip investigations revealed that the FRV stem to plug weld on the #1 FRV had failed, allow-i ing the plug assembly to drop to its full-open position. This caused

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full FW flow into the #1 SG.- At the time of the transient, maintenance personnel were repairing a leaking MFW isolation motor-operated valve upstream of the #1 FR The licensee's review verified that the FRV failure was independent of this maintenance activit The FRV stem is threaded into the plug and they are welded togethe The licensee's evaluation of the failure indicated-that the stem to plug weld failed around its mini. mum section (throat). Lack of fusion (20-25%)

was identified in the weld throat area. The licensee believes the root cause of the failure was either (or both) manufacturing defects in the weld or in-service fatigue caused by torsional stresses induced by flow through orifice rings around the plug. The' licensee inspected the con-dition of the remaining three FRVs. Liquid penetrant inspections indi-cated that there were no other cracks.in the stem to plug welds and no significant orifice ring misalignment was identified. The failed stem and plug assembly was replaced with a spare assembly from the onsite warehouse. The replacement stem to plug weld had a substantially larger throat than the failed assembly. A liquid penetrant test was performed on the replacement assembly prior to installation and no defects were observe The failed stem and plug assembly was shipped to the manufacturer (Fisher)

for metallurgical analysis to verify the root cause of the failure. The licensee also plans to determine the reason for the larger weld in the replacement assembly. Additionally, future purchase requisitions for these assemblies will require performance of liquid penetrant tests at the factor The inspector had no further questions in'this are . Review of Periodic and Special Reports

.Upon receipt, periodic and special reports submitted pursuant to Technical Specification 6.9 were reviewed. This review examined whether the reported information was valid and included the NRC required data; whether test results and supporting information were consistent with design predictions and per-formance specifications; and whether planned corrective actions were adequate for resolution of the problem. Also, the inspector ascertained whether any reported information should be classified as an abnormal occurrence. The following periodic repor+s were reviewed:

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Monthly Operating Reports 86-07 & 08; plant operations from July 1 - August 31, 1986 I

No unacceptable conditions were identified.

i Unresolved Items

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Unresolved items are matters about which more information is required in order to determine whether they are acceptable items or violations. One unresolved

, item was identified during this inspection (Detail 2.1).

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10 Exit Interview During this inspection, meetings were held with plant management to discuss the finding No proprietary information related to this inspection was identified.

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