IR 05000213/1987002

Insp Rept 50-213/87-02 on 861218-870209.No Violations Noted. Major Areas Inspected:Plant Operations,Radiation Protection, Fire Protection,Security Maint,Surveillance Testing,Licensee Events,Open Insp Findings & TMI Action Plan Items

ML20212B769
Person / Time
Site:	Haddam Neck File:Connecticut Yankee Atomic Power Co icon.png
Issue date:	02/13/1987
From:	Mccabe E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20212B696	List: IR 05000213/1987002 ML20212B689
References
50-213-87-02, 50-213-87-2, NUDOCS 8703030640
Download: ML20212B769 (16)

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U.S. NUCLEAR REGULATORY COMMISSION

REGION I

Report N /87-02 Docket N License N DPR-61 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: December 18, 1986 through February 9, 1987-Inspectors: Stephen M. Pindale, Resident Inspector Paul D. Swetland, Senior Resident Inspector A. A. Asars, Resident Inspector E. L. Conner, Project Engineer Approved by: Che b 2/3/87 E. C. McCabe, Chief, Reactor Projects Section 3B Date Summary:

Areas Inspected: This was a routine safety inspection (229 hours0.00265 days <br />0.0636 hours <br />3.786376e-4 weeks <br />8.71345e-5 months <br />) conducted by resident and region-based inspectors. Areas reviewed included: plant operations, radiation protection, fire protection, security, maintenance, surveillance testing, licensee events, open inspection findings, IE Bulletins and Information Notices, and TMI Action Plan Item Results: The inspection identified acceptable performance. Sixteen NRC open items were closed, no new unresolved issues were identified and no violations were cite [

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1. - S ummary o f Faci l i ty Acti vi ti e s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Operational Safety Verifications..................................... .

1 = Observation of Maintenance and Surveillance Testing.................. 1 3.1 Charging Pump Lube Oil Cooler Test.............................. 2 Followup on Previous Inspection Findings............................. 3 4.1 Missing Cable Vault Penetration Fire Barriers................... '3 4.2 Removal of Control Room Smoke Detectors......................... 3 4.3 Degraded Fire Doors............................................. 3

. 4.4. Inadequate Emergency Diesel Generator Retest.................... 4 4.5 Incorrect Processing of Field Changes........................... 4 4.6 Operating Procedures Not Implemented at' System Turnover......... 5 4. 7 Main Steam Isolation Valve Stroke Test Failure.................. 5 4.8 -Channel Checks'and Inadequate Core Cooling Instrument Limits.... 6 4.9 Administrative Control of Maintenance Activities................ 6 Followup on IE Bulletins and Information Notices..................... 7 5.1 Reactor Trip Breaker Failures - IEB 83-01....................... 7 5.2 Feedwater Line B rea k - IEN 86-106. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 5.3 Seismic Interaction of the Incore Flux Mapping System-IEN 85-4 . Followup on Events Occurring During the Inspection................... 8 6.1 Licensee Event Reports.......................................... 8 6.2 Core Deluge Loss of ' Coolant Accident Design Inadequacy. . . . . . . . . . 9

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6.3 Unmonitored Security Access Point............................... 11 6.4 Reactor Coolant System Brittle Fracture Relief Valve Stuck Ope ' Followup on TMI Action Plan Items.................................... 12

I.C.1 - Emergency Operating Procedures Revision................. 12

7.2 II.B.1.3 - Procedures for Reactor C601 ant System Vents.......... 13 7.3 II.K.3.5 - Reactor Coolant Pump Trip Criteria................... 13 7.4 II.K.3.10 & 12 - Anticipatory Trip on Turbine Trip.............. 13 Review of Periodic and Special Reports............................... 14 Ex i t I n te rv i ews . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

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DETAILS Summary of Facility Activities At the beginning of the inspection period the plant was holding power at 16%

pending short-term resolution of a design inadequacy in the Residual Heat Re-moval'(RHR) System, identified on December 12, 198 On December 19, the plant shut down to perform a special flow test on the RHR system to verify the adequacy of the proposed problem resolution. Following successful com-pletion of the test on December 20, the plant achieved criticality on December 2 Full power was reached on December 25,-and continued through the end of the inspection perio . Operational Safety Verifications 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 acknowledged.

Operator awareness and response to these conditions were reviewed. Control 4~

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 checke 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, 1 cgs and records were reviewed to determine if entries were properly made and communicated equipment status / deficiencies. These records included operatt ] logs, turnover sheets, tagout and jumper logs, process computer printouts, and Plant Information Reports. The inspector observed selected aspects of plant security including access control, physical barriers, and personnel monitoring. No abnormal conditions were identifie . Observation of Maintenance and Surveillance Testing The inspector observed various maintenance and problem investigation activi-ties for compliance with requirements and applicable codes and standards, QA/QC involvement, safety tags, equipment alignment and use of jumpers, per-sonnel qualifications, radiological controls, fire protection, retest, and reportabilit Also, the inspector witnessed selected surveillance tests to determine whether pruperly approved procedures were in use, test instrumenta-

' ion was properly calibrated and used, technical specifications were satisfied,

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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:

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Auxiliary Feed Pump Monthly Functional Test (SUR 5.1-13)

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Residual Heat Removal (RHR) and Charging Systems Leakage Inspection (SUR 5.1-20)

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Inspection of Main Steam Header and Feedwater Lines (SUR 5.1-24)

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RHR Flow Test to Determine FCV-796 Collar Dimensions (SPL 10.7-273)

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Charging Pump Lube Oil Cooling System Tests (SPL 10.7-266)

Investigate / Repair Pin-hole Leak in Charging System Recirculation Line

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(Work Order Numbers CY-87-893, 913, 926, 927, 929, 940, 958)

3.1 The recently completed probabilistic risk assessment for the Haddam Neck plant highlighted the reliability of charging pump auxiliaries as an area for improvement. Normal charging pump cooling is supplied by the non-safety grade component cooling water (CCW) system. Upon failure of CCW, a fan powered from motor control center (MCC-5) blows air through a cooler to maintain normal lube oil temperature. CCW is normally avail-able during routine charging pump operation and surveillance. Because the operability of the back-up fan cooler system was not verified, the system reliability for risk assessment was adversely affected. The lic-ensee conducted a surveillance test on May 4, 1986 to verify the oper-ability of the auxiliary lube oil cooling system for the charging pump This test was conducted in accordance with procedure SPL 10.7-266, Func-tional Test of the Charging Pump Lube Oil Fan Coolers, and was completed satisfactorily for both the A and B charging pumps. The inspector re-viewed the test procedure and results to verify the acceptability of the test results. No discrepancies were identified. In order to validate the continued reliability of charging pump auxiliaries, the licensee plans to incorporate procedure SPL 10.7-266 into a routine refueling in-terval charging pump surveillance. This test has been incorporated in the draft Standard Technical Specification submittal which should be implemented in 198 SPL 10.7-266 has been entered on the shutdown work-list for the July 1987 refueling outag During inspector review of the charging pump fan cooler subsystem, it was noted that the fan power supplies were not properly depicted on plant drawings. The inspector brought this discrepancy to the licensee's at-tention on January 14, 1987. It was determined that several components had been previously terminated in cubicles 7FHL and 8FHR without imple-menting design control n:easures to update the plant drawings. The lic-ensee documented this discrepancy on nonconformance report (NCR)87-035 on February 4,1987. It was determined that the charging pump cooler fans did not overload MCC-5 and drawing change request (DCR-CY-P-9-87) was

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' implemented to revise plan't drawing Inaccuracies in plant drawings

have been previously identified by the licensee as an area for improve- "

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ment. A significant project was completed in 1979-81 to upgrade plant

_ electrical drawings, and there is an ongoing project to verify P&ID

. drawings scheduled for completion in December 1987. The licensee stated

that corrective action for NCR 87-035 will determine whether the charging

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-pump fan cooler discrepancy represents a generic weakness not addressed by these upgrade programs. The accuracy of plant drawings is a previous

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NRC unresolved item which will be followed under the routine NRC inspec-

. tion program (213/84-26-01). ,

l Followup on Previous Inspection Findings

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During the course of the inspection, nine NRC open items were reviewe The i

inspector found licensee actions with regard-to these areas to be sufficient

to close these items. Details follow

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4.1 (Closed) Violation (213/84-14-01) Penetrations in the cable vault ceil-

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• ing/ auxiliary feedwater room floor were not properly sealed against fire The licensee promptly installed temporary fire seals and subsequently

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replaced them with permanent foam seals in accordance with procedure CMP

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8.5-143, Installation, Repair, and Inspection of Fire Barrier Penetration Seals. Procedure CMP 8.5-143 was revised to require that all fire bar-

! rier penetrations be sealed rather than just those in Technical Specifi-

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cation required barriers. In addition, the list of TS barriers in CMP 8.5-143 was amended to include the cable vault ceiling / auxiliary feed-water room floor. The inspector verified the implementation of these i

changes in Revision 1 to. procedure CMP 8.5-14 Inspections subsequent

to this occurrence have identified no further instances of missing fire

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, barrier penetration seals. This item is close '

' 4. 2 (Closed) Violation (213/85-15-01) A Technical Specification (TS) change was not initiated to allow the site approved removal of control room

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smoke detectors. Upon identification, the removal work order was re-

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scinded and a TS change was requested and' approved by NRC in Amendment 81 to the operating license dated August 18, 1986. The licensee also i improved the fire protection review process for modifications by empha-

sizing TS evaluations in procedure NE0 5.12, Performance of Fire Protec-

! tion Reviews, and project engineer on-the-job training. The inspector j reviewed revision 1 to NE0 5.12 and Corrective Action Request CY-85-06,

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' and interviewed selected engineers to verify the implementation of these actions. No further deficiencies were identified with regard to this ite L 4.3 (Closed) Unresolved Item (213/85-16-02) This item relates to the pos-

, sible degradation of the fire rating of 18 of the 20 doors listed in TS

! due to security hardware modifications, attachment of caution signs to y the doors using screws, lack of positive latching and/or more than ac-ceptable gaps between the laminated door leaves or between the door and j the floor. On September 13, 1985, the licensee issued Control Routing i

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(CR) 85-1185 committing to: 1) review the operability of all TS doors within 7 days; 2) take action to correct the gap problems with fire doors 1, 8, 9, 10, 11, 12 and 14 within 30 days; and 3) resolve the remaining issues concerning signs, small holes, etc. within 90 days. The inspector reviewed the closeout documentation for CR 85-1185 and inspected the fire door The repairs and modifications to the seven doors were found as documented in an internal memo dated September 13, 1985. Warning signs to keep each fire door closed and to prevent unauthorized modifications of any fire door have been properly installed on the doors. The inspec-tor had no further question .4 (Closed) Violation (213/86-01-02) The retest plan for tne Emergency Diesel Generator air system was incomplet (It was subsequently com-pleted and satisfactorily retested was accomplished.) The licensee has emphasized the importance of adequate and comprehensive test plans for maintenance and modification packages through various plant meetings and briefings. The Engineering Department follows Engineering Department Instructions (EDIs) which provide guidance on how to formulate test plan These EDIs are currently being revised to develop more comprehensive test plans. The implementation of the EDI revisions will be reviewed during the upcoming refueling outage. This item is close .5 (Closed) Violation (213/86-01-03) The licensee failed to document the significance determination for three Design Change Notices (DCNs) and did not initiate Plant Design Change Request (PDCR) revisions based on the positive determinations of significance for four DCNs. The licensee responded to this violation in a letter dated May 12, 1986 which stated that the cause was the responsible engineer's confusion over the purpose for the significance determination. Each of the seven DCNs were reviewed by PORC and determined to be insignificant; therefore a PDCR revision was not necessar To preclude further omission of the significance determination, all on-site engineers received retraining on the import-ance of correctly completing DCN form The inspector reviewed all PDCRs which have been initiated since May, 1986 to verify that significance determinations are being performed and documented correctly. Since that time there have been eight DCNs. All but one included an adequate sig-nificance determination and the corresponding documentation. DCN C-522-86 to PDCR 856, Appendix R Interim Remote Shutdown Instrumentation, did not have a significance determination documented on the DCN form. How-ever, this discrepancy was identified during the Engineering Supervisor's review of the PDC The PDCR contains a note which states that DCN C-522-86 was determined to be insignifican This DCN was initiated for instrument cabinet floor bolt relocation due to the interference of floor rebar. Since this omission of the significance determination was iden-tified, corrected and documented in the PDCR package, this item will be closed. Proper control and documentation of field changes will be fol-lowed during routine NRC inspection of modification activitie .

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4.6 (Closed) Violation (213/86-03-02) This violation involved the failure to implement normal operating procedure N0P 2.19-5, Steam Generator Wet Lay-Up - Recirculation System Setup and Storage, prior to turnover of PDCR 786 on February 7, 1986. As of April 1, 1986, NOP 2.19-5 had not been approved and PDCR 786 was being reevaluated to address leakage past the main feedwater system check valves located inside containment. The inspector confirmed that NOP 2.19-5, Original, was PORC approved and issued April 9, 1986. On November 15, 1986, this procedure was revised for minor corrections. Licensee corrective actions to assure procedures are implemented prior to system turnover are described in paragraph of this report. Since the procedure revision was the issue in the violation, this item is closed. The remaining questions, regarding the leckage past the main feedwater system check valves, will be reviewed during routine inspection of design change control activitie .7 (Closed) Unresolved Item (213/86-16-01) NRC review of main steam isola-tion valve (MSIV) air closure system modifications identified concerns regarding quality classification of system parts, turnover discrepancies and appropriate inservice testing (IST) of the MSIVs. On July 15, 1986, the licensee submitted a Licensee Event Report (86-29) which described the initial surveillance /IST test failure and the licensee's immediate corrective actions. Subsequently, other NRC inspection findings were addressed by Controlled Routing 86-1369. With regard to maintenance of component classification within the quality boundaries, the licensee reemphasized to maintenance technicians the need for segregated storage of quality parts for reinstallation during modification installation The inspector also verified that the quality assurance department review of completed work orders (as required by administrative control procedure (ACP) 1.2-5.1, PMMS Trouble Reporting System and Automated Work Order, and QAD Instruction 11) must verify the correct classification of new parts installed by a modification work order. These measures provide assurance and accountability for maintenance of the integrity of system quality classificatio The inspector also determined that gauges in-stalled on safety-related systems are classified Category 1, unless specifically addressed by a quality assurance boundary (MEPL) evaluatio Therefore, gauges installed or replaced in Category 1 systems must be procured or upgraded to safety grade requirements. This satisfies NRC concerns in this area. For the omission of nitrogen bank operating pro-cedure revisions prior to system turnover, the licensee modified proce-dure ACP 1.2-3.1, Preparation, Review, and Disposition of Plant Design Change Requests (PDCRs) to increase the timeliness and significance of PDCR reviews concerning procedural changes. The inspector verified the implementation of these improvements in steps 6.2.2.1 and 6.6.2 of re-vision 19 to ACP 1.2-3.1. No further problems were identified. Regard-ing MSIV testing, two surveillance tests are currently required to verify operability of the MSIVs. One test forces the MSIVs to close using the non-seismically mounted air operating system. The second test allows the valve to partially close by equalizing air pressure on the operating piston, allowing valve spring pressure to partially close the valv Licensee evaluation of valve specifications and main steam flow charac-

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teristics concluded that this second test meets the intent of IST fail-safe testing because any r.ain steam flow rate greater than 20 percent i will assist spring pressure to assure HSIV closure without air pressur Steam flows less than 20% may not assure MSIV closure without air assist-ance; however, this flow rate is bounded by the main steam line break accident analysis and will not exceed auxiliary feedwater flow rates, allowing controlled plant cooldown to residual heat removal system entry i conditions. Therefore the MSIV non-closure concern documented in NRC l IE Information Notice 85-84 is not applicable to Haddam Neck. This in- '

spector reviewed the licensee's internal evaluation on this issue. No

) further discrepancies were identifie .8 (Closed) Unresolved Item (213/86-27-07) The licensee was to revisa the guidance and documentation of qualitative channel checks and implement Administrative Technical Specifications (ATS) to assure interim oper-ability of Inadequate Core Cooling (ICC) instrumentation until formal Technical Specification (TS) changes are complete. The inspector re-viewed Normal Operating Procedure (NOP) 2.2-2, Operation at Powe N0P 2.2-2 was revised to define a channel check, and provide guidance on the performance of channel checks. Additionally, the procedure revision formally instructs the operator to perform the TS required channel check On January 31, 1987, an ATS was issued to address operability and testing requirements for ICC instrumentation. The licensee plans to incorporate the addition of formal ICC instrumentation TSs as a part of their con-version to standard TSs in late 1987. The inspector noted that the ATS for ICC deviates from the NRC guidance specified in Generic Letter N , NUREG - 0737 Technical Specifications. These deviations will be reviewed by NRC Licensing during their review of the standard TS submit-ta In the interim, the licensee plans to use the ATS to assure con-tinued operability of the system. The inspector had no further questions i at this time.

l 4.9 (Closed) Unresolved Item (213/86-30-02) The licensee was to develop a mechanism by which administrative control over maintenance activities l can be improved. Inadequate control of maintenance resulted in a plant trip on November 30, 1986 when Instrument and Control (I&C) technicians shorted out the power supply for the feedwater control system (FWCS).

Licensee Event Report (LER) 86-44 addressed this event. The stated cor-rective action was to develop a new I&C procedure concerning pre-work guidelines for I&C repair work requests received during off-normal work-ing hours. During normal working hours, I&C Department supervision co-ordinates the pre-work actions and interfaces with the shift supervisor to address the potential negative impact of the repair work on related systems or components. Additionally, daily interdepartmental planning meetings serve to supplement the I&C supervisor's task. In the interim, for any calls received during off-normal working hours, an I&C supervisor provides the necessary coordination efforts and instructions to the operations shift supervisor /I&C technician (s). The new I&C procedure includes a job briefing and sign-off with the Operations shift supervisor to insure that the operating shift has a complete understanding of the

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nature of the work, and that undesirable interaction with other plant systems or components is identified and minimized. The inspector also contacted the Maintenance Department in regard to this item. It was stated that whenever safety-related work is requested and performed during off-normal working hours, maintenance supervision normally reports to the site to aid in the work order initiation and repair work processe The implementation of the new I&C procedure will be reviewed under the routine inspection program. This item is close . Followup on IE Bulletins (IEBs) and Information Notices (ins)

5.1 IEB 83-01 - Failure of Reactor Trip Breakers (RTBs) to Open (Also Generic Letter 83-28, SALEM-ATWS Item 4.2 and 4.5.1)

This Bulletin concerns previous RTB failures and licensee actions re-garding maintenance and testing of RTBs required to prevent these prob-1 ems. The licensee had implemented appropriate maintenance and post-

maintenance testing which separately tests the undervoltage and shunt trip However, due to the inability to perform on-line RTB testing, the licensee was unable to verify the effectiveness of these preventive measures on the undervoltage (UV) trip devices after extended periods of breaker inactivity. The shunt trip devices normally trip the RTBs which are monitored on the post-trip computer printout. The lack of as-found UV trip test data was evaluated by NRC Licensing in response to NRC Generic Letter 83-28. On October 18, 1985, the licensee submitted additional information to NRC regarding RTB reliability. In particular, the licensee stated that RTB control power is derived from the same 125 VDC source which supplies the control rod stationary gripper coil Consequently, upon loss of power to the active shunt trip coil, control rod holding power would also be lost, causing the control rods to drop regardless of the RTB function. Although the response time of this ad-ditional trip mode is uncertain, it does provide back-up assurance that the plant will trip whenever the shunt and undervoltage trip devices are called upon to actuate. The inspector verified the control power scheme for the RTBs on plant drawings 16103-32112 sheet 33 and 16103-31092 sheets 1-5. No inadequacies were identified. The results of NRC:NRR review of RTB reliability and testing will be documented under GL 83-28 item 4.5.2. Action on this Bulletin is close .2 IN 86-106 - Feedwater Line Break This IE Notice alerted licensees of a potentially generic problem with feedwater system pipe thinning and other related problems. The licensee responded promptly to an NRC survey regarding the problem with respect to Steam, Feedwater and Condensate systems. The licensee currently maintains a Secondary Side Wall Thickness Program (SSWTP). The criteria for selection of the inspection points are based upon failure experience and engineering judgemen Several portions of secondary system piping have been replaced as a result of pipe wall thinning when the pipe wall thickness approached / reached the minimum wall thicknes In response

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to IN 86-106, the licensee concluded that their SSWTP has been effective to date, however, they plan to enhance the scope of the inspections to provide a more comprehensive program. This includes a 100 percent base line inspection of feedwater system piping. The corporate support group plans to evaluate specific, qualitative criteria that should be consi-dered in the selection of which arecs to be inspected. NRC evaluation of the survey data and licensee program upgrades will be reviewed during a subsequent inspectio .3 IN 85-45 - Potential Seismic Interaction Involving the In-Core Flux Mapping System The subject notice identifies concerns involving interactions between the non-safety related portions of the movable flux mapping system and the tubing seal table during a seismic event. The potential interactions may exist because portions of the flux mapping system that have not been seismically analyzed are located directly above the in-core instrumenta-tion tubing seal table. On June 19, 1985, the licensee processed a Nuclear Operations Assignment (NOA) 8354 requesting an analysis of this problem at Haddam Neck. The issue was closed out by an internal memo, dated September 9, 1985. The analysis concluded that the problem as described in Information Notice 85-45 has no applicability at this plan The inspector reviewed drawings and pictures and discussed the system arrangement with the licensee staff. At Haddam Neck, the thimble guide tubes enter a 6 foot diameter pipe a few feet below the seal table. This pipe, called the in-core sump tube, is covered by a steel plate. This pipe encases the tubes around the bend to the bottom of the core. The remaining mechanisms (drive motors, isolation valves, interconnecting devices, etc.) are offset in another area, not directly above the seal table as in some other plant designs. The seal table is adjacent to a wall and surrounded by floor gratings a few feet below the top of the tabl Therefore, the seismic design concerns of IN 85-45 are not ap-plicable to Haddam Nec During NRC review of this issue, the inspector found no documentation on this issue ir Nuclear Records. Only after questioning plant personnel was the internal correspondence located in non permanent storage. The inspector referred this observation to licensee management for evaluation and corrective action. The issue of appropriate filing / storage of plant records will continue to receive inspector attention on a routine basi . 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 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

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had been met, that appropriate correctiva action had been taken, and that the continued operation of the facility was conducted within Technical Specification Limit * 86-24 Spurious Turbine Load Runback

• 86-25 Reactor Trip During Nuclear Instrumentation Troubleshooting

• 86-26 Low Flow Trip Caused by Foreign Material in Relays

• 86-27 Reactor Trips Due to Heater Drain Pump Flow Problems 86-28 Inoperable Switchgear Halon Fire Protection System (Detailed in NRC Inspection Report 50-213/86-17)

• 86-29 Main Steam Isolation Valve Stroke Test Failure

• 86-30 Spurious Turbine Load Runback 86-44 Automatic Reactor Trip Due to Maintenance Error (Detailed in NRC Inspection Report 50-213/86-30)

86-45 Turbine Sprinkler System Disabled to Perform Appendix R Modifications 86-46 Failure of Overpressurization System Relief Valve Following Reactor Coolant System Pressure Spike (Detailed in paragraph 6.4 of this report)

86-47 Mode 2 Operation Outside Safety Analysis Assumptions (Detailed in NRC Inspection Report 50-213/86-30)

86-48 Medium Break LOCA Analysis Reveals Non-Conservative Results (Detailed in NRC Insoection Report 50-213/86-30 and paragraph 6.2 of this report)

• Events detailed in NRC Inspection Report 50-213/86-1 .2 On December 12, 1986, with the plant at approximately 16 percent power, the licensee identified a potential Residual Heat Removal (RHR) system design inadequacy. Sufficient core cooling flow could not be assured during the recirculation phase of a postulated intermediate break size loss of coolant accident (LOCA) in the Core Deluge system. The Emergency Core Cooling portion of the RHR system supply piping shares a common line with the Core Deluge [ low pressure safety injection (LPSI)] syste Consequently, a LOCA in the LPSI piping could dump emergency cooling recirculation flow out the break such that adequate cooling water would not reach the reactor in the recirculation mode. The licensee made the appropriate notifications to the state, local and NRC officials on December 1 The design inadequacy was discovered during an engineering

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effort to support Emergency Core Coeling System (ECCS) modifications needed to correct a previously identified small break LOCA response vulneabilit The licensee's proposed short-term fix for this postu-lated LOCA was to throttle the air-operated RHR flow control valve (RH-FCV-796) to limit RHR flow to the break so that adequate RHR flow could be directed to the core through the charging /high pressure safety injec-tion (HPSI) system flowpaths. RH-FCV-796 is located between the critical break location and the upstream RHR cross connect path to the HPS! and Charging systems. The proposed short-tehn resolution would establish a plant configuration which provides assurance that adequate, ECCS flow will be maintained through the LPSI path during'the ' injection phase of a LOCA while also assuring the viabilityLof the recirculatica phase for the LPSI break locatio /, i

Following meetings and conversations with the NRC, the licensee decided to shut down and perform a special flow test to demonstrate the adequacy of the proposed short-term fi Special Maintenance' Procedure SPL 10.7-273, RHR Flow Test to Determine FCV-796 Collar Dimensions, was re-viewed and accepted by the Plant Operations Review Committee (PORC) on December 18, 1986. A controlled plant shutdown from 16 pelcent power was initiated on December 19, 1986, and the unit was maintained in Mode 4 (Hot Shutdown) for the duration of the test. SPL 10.7-273 was per-formed on December 20, 1986. RH-FCV-796 was blocked in a throttled position for which the measured flow met the associated acceptance cri-teria. Two locking collars were installed (one on each side) on the horizontally mounted valve stem. Proper installation of the collars precludes valve motion. The inspector verified the proper installation of the collars on RH-FCV-796, and that valve novement was restricte Since the valve is horizontally mounted and the collars are labelled and locked to their respective sides, it is unlikely that their insta11stion wculd be reversed. Applicable procedurcs were reviewed to assure that they reflected th( hardware changes.. 'Tuporary procedure changes (TPCs)

were atta:hed to revise th9 text, however, the associated valve lineup sections were not change This concern was brought to the Mteensee's attention. The necessary revisions will bo included when the TPCs are incorporated in procedure revision TheplantTecht.icalSpecifications(TS)inplace'atthetime'cfbheevent required that RH-FCV-796 be left in the open pnsition with the afr' supply isolated when the reactor is critical and the reactor coolant systed (RCS) temperature is greater than 350 degrees Since the proposed short-term fix holds RH-FCV-796 in a throttled position, it was deter-mined that a license amendment request was appropriate. On December 17, 1986 (and supplemented on December 19, 1986), the licensee sdmitted an emergency license amendment request to NPC to permit opnation with RH-FCV-796 blocked in a throttled position. The NRC granted a temporary I waiver of compliance from TS 3.6 from December 22 until December 24, when the Emergency License Amendment was issued. Criticality was achieved on December 23 and full power was reached on December 25, 1986. The

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licensee is developing an action plan for ECCS modific4tions to address i

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both small'and medium break LOC 4 deficiencie The adequacy of this long-term cor ective action plan will be reviewed during a subsequent NRC inspectio During the special flow test, the inspector identified a discrepancy with a valve position lineup spec 1fied in the test procedure. The RHR heat exchanger air-operated bypass valve, RH-FCV-602, is used to bypass the RHR heat exchangers and RH-FCV-796 during the normal shutdown cooling mode of RHR system operation. RH-FCV-602 is normally blocked closed with the air supply isolated during routine operation to insure that all the ECCS flow goes through the heat exchanger The flow sensing element used in the special test is located on the common piping downstream of RH-FCV-602 and RH-FCV-736. Therefore, any flow through RH-FCV-602 during the test was also registered on the flow indicator. After RH-FCV-796 was adjusted for the required flow rate (15001200 gpm), the inspector questioned whether RH-FCV-60? was locally verified to be fully close RH-FCV-602 indicated closed on the main control board, however, the local verification of actual position found the valve not fully closed (ap-proximately 3/16" of the 4" total stem travel). After noting that the air supply to the valve was not isolated as it is during normal operation, the licensee isolated the air supply to RH-FCV-60 The valve went fully closed and the flowrate through RH-FCV-796, as measured at the downstream sensing element, decreased by approximately 500 gpm. This placed the resulting flowrate outside the specified acceptance criterion of 1500 1 200 gp The licensee removed the collars from RH-FCV-796, and re-adjusted the flow through RH-FCV-796 to 1583 gpm. Collars were then recut und installed on the valve, and the flow was verified to remain

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at 1583 gpm when the new collars were installed. Operators also noted that the collar used to block RH-FCV-602 was too small to maintain the valve in the fully clnsed position. The licensee fabricated and in-stalled a new collar for RH-FCV-602 following the test. The inspector

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had no further questions at this tim .3 On January 10, 1987, the licensee reported a 14 minute loss of security effectiveness to the NRC. The event involved an unmonitored access point between a protected area and a vital area. Upon discovery, the licensee implemented immediate compensatory actions. The cause of the event was the failure of a security officer to properly secure the access poin The individual was reassigned to training in security program duties and responsibilities, anc' the rest of the guard force was appraised of this incident. The licensee made the appropriate notifications. This failure to control access violated NRC requirements. However, since the viola-tion did not constitute a serious concern and was promptly identified, reported and corrected by the licensee, no further action is require Further licensee review of this event indicated that the one-hour report could have been made more promptly. The security organization uses a single procedure to classify and prepare both one-hour and 24-hour security event reports. This event was initially believed to be a 24-hour report, but later determined to be a one-hour report. The 24-hour reporting process includes additional, time consuming steps. To address i

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'. this concern, the licensee revised the Security Event Notification pro-cedure to ensure that both the one-hour and 24-hour event reports are

. c" processed fast.enough to meet the one-hour criteria. The inspector  :

ver,1fied the' completion of these corrective actions, and had no further

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question ~

6.4 On December 4,-1986, with the hlant' operating in ~ the hot shutdown mode

/ for maintenance, one of two ~ low pressure over pressurization (LPOP) i trains was isolated wheniits LPOP relief valve stuck cpen following an  !

inadvertent reactor coolant system (RCS). pressure spike. LER 86-46 was  !

- submitted on January 7,1987. The report stated that the relief valve reclosed upon mechanical agitation and the system was returned to service -

until the valve can be disassembled the next time the.RCS is depressur-

, ized. The inspector questioned whether the cause of the valve sticking ,

open could also prevent the valve from opening correctly. The licensee  ;

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- stated that the relief valve had opened properly on this' pressure transi-  :

y ent and that subsequent discussions with the valve manufacturer had con-

firmed that valve agitation would not close a wide open relief valve.

[ Rather, the isolation of the upstream block valve probably allowed pres-sure to decay below the blowdown _setpoint about the time the valve was

agitated. Since the licensee does not test and adjust blowdown setpoint

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ring settings on the LPOP reliefs and.there is a previous history of

excessive blowdown on these valves, the licensee concluded that (1) the safety significant function of this valve remains operable and (2) the valve must be disassembled, inspected and tested for.both lift pressure

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and blowdown. The licensee is also upgrading the control of safety system relief valve maintenance to assure the establishment and control of blowdown ring settings. On January 23, 1987, the licensee revised LER 86-46' to. clarify the probable cause of the relief valve failure and

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the planned corrective action. Relief valve testing and maintenance will be reviewed under the routine NRC inspection program.

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. . TMI Action Plan Followup s

+ I.C.I - Emergency Operating Procedures Revision The licensee was to revise plant emergency operating procedures (EOPs)

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L to conform with NRC approved symptom-oriented emergency response guide-lines. By letter dated August 19, 1986, NRC approved the licensee's

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Procedures Generation Package which outlined the methods for procedure l

development, verification and validation. On August 30, 1986, the lic-ensee formally implemented new emergency operating procedures upon com-

-pletion of operator training and final procedure validation, which in-t-

cluded the use of the E0Ps by all operators in the plant specific simu-lator. The inspector reviewed these procedures during simulator familiar-

ization in November 1986. Except as noted in paragraph 7.2 below no i discrepancies were identified. Further NRC technical evaluation of plant E0Ps will be conducted during a subsequent inspection. This item is

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closed.

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7.2 II.8.1.3 - Procedures for Reactor Coolant Sys' tem Vents Installation of the reactor coolant system (RCS) vent system required .

.the implementation of operating procedures which conform to the generic 1 emergency response guidelines as amended by the plant specific safety

evaluation report. Procedures FR-1.3,_and FS-C.3, Response to Inadequate

' Core Cooling, were reviewed. The inspector'found the-ERGS to be correctly

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implemented except that certain procedure. attachments _used to calculate-

venting duration time had not been distributed with procedure FR-I- An existing abnormal operating procedure (AOP) 3.2-22, RCS. Venting of Non-Condensable Gases contained similar attachments from.which the ap-I propriate venting time can be calculated. A0P 3.2-22 preceded the lic-ensee's implementation of symptom-oriented procedures, but had not yet been cancelled. The inspector brought this discrepancy to the licensee's n attention. E0P FR-I.3 was amended to include the appropriate Attachments  ;

and.AOP 3.2.22 will be cancelled. The inspector reviewed the licensee's

' previous E0P validation to confirm that FR-I-3 had been properly vali-dated including the. vent time calculation. The inspector had no further

[ questions in this are t

[ II.K.3.5'- Reactor Coolant Pump Trip Criteria i The licensee was to propose for NRC approval appropriate criteria for manually tripping the reactor coolant pumps (RCPs) following a loss of

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coolant accident -(LOCA). By letter dated December 20, 1984, the licen-see stated that its latest small break LOCA analysis shows the RCP trip-ping should not be necessary. NRC licensing has not completed their

. review of this new LOCA analysis. The inspector noted, however, that L

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the licensee's new emergency operating procedures contain manual RCP trip- -

criteria based on satisfactory operation of safety. injection (one high pressure safety injection or charging pump) and a reactor-coolant system i' pressure less than 1150 psig (1380 psig for adverse containment condi-tions). Additionally, RCPs are tripped in respon'se to a loss of second- -

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ary heat sink-event. These criteria are generally consistent with other

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reactor plants of similar size and design. The inspector informed NRC Licensing of the RCP trip criteria presently in use and notified the F

licensee thet this item would remain open pending appropriate NRC approval of the new LOCA analysis and RCP trip criteria, as necessar .4 II.K.3.10 & 12 - Anticipatory Trip on Turbine Trip i

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Both these items concern reactor protection system (RPS) modifications for anticipatory reactor trip on a main turbine trip.

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The Haddam Neck design has always had such a trip in place and no modifications or set-point changes were deemed necessar This position was confirmed by NRC letter dated November 30, 1981. Consequently, item II.K.3.10 will be closed. The inspector noted that the turbine trip operability surveil-

L lance requirements are not presently in plant Technical Specifications

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(TSs) but have been included in the draft standard TSs which are expected to be implemented in 1987. Item II.K.3.12 will remain open pending com-pletion of the standard TS implementatio . Review of Periodic and Special Reports Upon receipt, periodic and special reports submitted pursuant to Technical Specification 6.9 were reviewed. This review verified that the reported in- *

formation was valid and included the NRC required data; that test results and supporting infonnation were consistent with design predictions and performance specifications; and that planned corrective actions were adequate.for resolu-tion of the problem. The inspector also ascertained whether any reported information should be classified as an abnormal occurrence. The following periodic reports were reviewed:

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Monthly Operating' Report, plant operations from November 1-30, 1986

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Monthly Operating Report, plant operations from December 1-31, 1986' ,

9. Exit Interview During this inspection, meetings were held with plant management to discuss the findings. No proprietary information related to this inspection was identifie . - - - _ . . , . _ _- __. -. _ . . . - . , . . - - .