IR 05000213/1986030
| ML20212C005 | |
| Person / Time | |
|---|---|
| Site: | Haddam Neck File:Connecticut Yankee Atomic Power Co icon.png |
| Issue date: | 12/18/1986 |
| From: | Mccabe E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20212B882 | List: |
| References | |
| 50-213-86-30, IEB-86-003, IEB-86-3, NUDOCS 8612290364 | |
| Download: ML20212C005 (11) | |
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l U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Report N /86-30 DCS Nos. 50-213/86-10-16 50-213/86-11-08 Docket N /86-11-30 50-213/86-12-07 license N DPR-61 50-213/86-12-08 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 cunducted: November 18 through December 17, 1986 Inspectors: Stephen M. Pindale, Resident Inspector Paul D. Swetland, Senior Resident Inspector E. L. Conner, Project Engineer Approved by: OA bOM- 12ls el#6 E. C. McCabe, Chief, Reactor Projects Section 3B, Date Summary:
Areas Inspected: This was a routine resident inspection (158 hours0.00183 days <br />0.0439 hours <br />2.612434e-4 weeks <br />6.0119e-5 months <br />) of plant operations, raaTation protection, physical security, fire protection, maintenance, open items, IE Bulletins and licensee event Results: Inspector review identified generally acceptable performance. Five NRC open inspection findings were closed. Unresolved items were identified regarding adequacy of maintenance controls (Detail 6.2) and plant operation outside a safety analysis flow rate assumption (Detail 6.3). A potential inadequacy was identified by the licensee in'the ability of the residual heat removal system to provide core cooling in the event of a low pressure safety injection system line break (Detail
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8612290364 861219 PDR 0 ADOCK 05000213 PDR
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k TABLE OF CONTENTS Page 1. Summary of Facility Activities....................................... . 1 2. Review of Plant Operations........................................... 1 2.1 Plant Operations Review Committee............................... 1 3. Observation of Maintenance Activities. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 4. Followup on Previous Inspection Findings............................. 2 4.1 Procedures for Radioactive Material Transportation.............. 2 4.2 Corrective Action for Licensee Event Report Deficiencies........ 2 4.3 Triennial Fire Protection Audits................................ 2 4.4 Control of General Training Exams. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 4.5 Inservice Testing Acceptance Criteria........................... 3 5. IE Bulletin 86-03, Emergency Core Cooling Pump Recirculation Flow Isolation............................................................ 4 6. Followup on Events Occurring During the Inspection................... 4 6.1 Licensee Event Reports.......................................... 4 6.2 Plant Trip due to Maintenance Error............................. 5 6.3 Mode 2 Operation Outside Current Safety Analysis................ 7 7. Potential RHR Inadequacy............................................. 8 8. Unresolved Items.......................... ......... ................ 9 9. Exit Interviews...................................................... 9 i
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DETAILS Summary of Facility Activities The plant operated at full power from November 18-30, 1986, when an automatic trip occurred due to steam generator feedwater control problems. Post-trip identified equipment failures resulted in a partial plant cooldown for repairs from December 1- The plant operated at low power briefly on December Further secondary system equipment failures were identified and the plant remained shutdown until December 11. After startup, power was held at about 16% on December 12 upon licensee identification of an inadequacy that could
, affect the ability to use the residual heat removal (RHR) system in the re-circulation mode after a small break loss of coolant acciden . Review of Plant Operations The inspector observed operation during tours of the following plant areas:
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Control Room --
Securf+y Building
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Primary Auxiliary Building --
Fence ine (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
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Containment Building 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 inspecte Compliance with Radiation Work Permits and use of personnel monitoring devices were checke Plant housekeeping was observed, including control and storage of flammable material and other potential safety hazards. The inspector also examined the condition of various fire protection systems. During plant tours, logs and records were reviewed to determine if entries were properly made and communi-cated equipment status / deficiencies. These records included operating logs, turnover sheets, tagout and jumper logs, process computer printouts, and Plant Information Reports. The inspector observed selected aspects of plant secur-ity including access control, physical barriers, and personnel monitorin No unacceptable conditions were identifie .1. Plant Operations Review Committee (PORC)
The resident inspector attended a Plant Operations Review Committee (PORC) meeting on December 9. Requirements for attendance were me The agenda included pre-approval review of Plant Design Change Request PDCR 86-858, Moisture Separator Reheater (MSR) Deflector Plate Modifi-cations. The change involved removal of existing MSR baffle plates which were found to be deformed / dislodged following the November 30, 1986
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plant tri The meeting was characterized by frank discussions and questioning of the proposed temporary change. Consideration was given to the bases of the current MSR design and the potential consequences of the proposed modification. The inspector had no further comment . Observation of Maintenance Activities The inspector observed various maintenance and problem investigation activi-ties for corgliance with requirements and applicable codes and standards, Q4/QC involvement, safety tags, equipment alignment and use of jumpers, per-sonnel qualifications, radiological controls, fire protection, retest, and reportability. The following activities were reviewed:
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Work Order No. CY-86-12054, Packing Adjustment for Valve RC-M0V-546
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Work Order No. CY-86-12120, Cut Out and Replacerent of Valve DH-CV-546
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Work Order No. CY-86-12151, Packing Replacement for Valve RC-MOV-546 Findings are detailed in paragraph 6.2 of this repor . Followup on Previous Inspection Findings During the course of the inspection, five NRC open items were reviewed and closed. Details follow:
4.1 (Closed) Followup Item (213/85-09-05): The licensee was to approve and implement new quality control procedures for the radioactive material transpo tation program. On March 25, 1986, the licensee approved cor-porate procedure NE0 6.07, Quality Assurance and Quality Control in Station Radioactive Material Processing, Classification, Packaging and Transportation. This procedure is implemented by incorporation of the procedural elements in site quality control procedures 1.2-2.9, 1.2-1 and 1.2-13.7. These procedures have been used for radioactive material shipments since July 1986. No discrepancies have been identifie .2 (Closed) Followup Item (213/85-13-01): The inspector was to review the effectiveness of licensee corrective actions to improve the content and timeliness of Licensee Event Reports (LERs). LER quality and consistency has improved as a result of licensee attentio No further late LERs have been identified. The licensee implemented procedure ADM 1.1-150, Assignment of Responsibility and Tracking of Licensee Event Report Pre-paration, on December 1, 1986. This procedure expands and formalizes the commitments made for the previous inspection findin .3 (Closed) Unresolved Item (213/85-16-01): The licensee was to resolve the independence of fire protection audits conducted by parent utility engi-neers pursuant to Technical Specification (TS) 6.5. Amendment 83 to the Haddam Neck operating licensee changed TS 6.5 to specifically require a triennial fire protection audit by a contractor outside the utility.
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The inspector reviewed the findings of the first such audit conducted at the site September 2-25, 1986. These findings are documented in Audit Report A25006 dated October 27, 1986. The scope and content of the audit were found to be adequate and the findings and observations reviewed were vali Licensee corrective actions regarding these areas will be re-viewed during routine NRC inspectio .4 (Closed) Followup Item (213/85-25-03): Following a July 1985 General Employee Training (GET) examination incident, the licensee was to imple-ment revised test controls to preclude such events. On November 24, 1986, an NRC inspector attended a training session prior to badging. A suf-ficient number of proctors to monitor the exam were present and different exams were given to adjacent examinees. Written and oral instructions were provided concerning exam conduct. These items conformed with Nuc-lear Training Manual (NTM) Chapter 5.06, Control Guide for Exams. The inspector had no further questions in this are .5 (Closed) Followup Item (213/86-01-04): NRC observation of a January 1986 local leak rate test identified deficiencies including lack of prompt action for test failures and the use of only Inservice Inspection (ISI)
acceptance criteria for the surveillance test, while other acceptance criteria exist in Technical Specification limiting conditions for opera-tion (LCOs). The licensee was to improve the method and timeliness by which the ISI Group investigates failed test data, and the ISI Group was to review surveillance procedures to identify those which satisfy both ISI and LC0 requirements. Procedures satisfying both ISI and LC0 re-quirements were to be revised to clarify the separate acceptance criteria such that test reviewers can easily discern when equipment operability limits have been exceeded. The inspector reviewed various ISI surveil-lance procedures. Approximately 75 percent of the ISI procedures have
'been revised and approve Review of the updated ISI procedures noted specific and independent acceptance criteria blocks for ISI and LC0 re-quirements, with the associated immediate action requirements and re-sponsibilities identifie The procedures that have not been reviewed and revised contain only ISI acceptance criteria blocks and may or may not contain LCO requirements. Instructions for those procedures specify that test results exceeding ISI acceptance criteria are to be reported to ISI immediately and that ISI is responsible for any necessary correc-tive action. ISI will take the appropriate action in accordance with SUR 5.7-15, Individual Containment Penetration Test Calculation and Docu-mentation and, as an interim measure, will also review the results for equipment operability and LCO anomalies. Additionally, ISI has been instructed that calls received during off-normal working hours which meet the ISI immeolate notification requirements, are to be treated similarl The remaining procedure updates are ongoing and will be performed as they become due for their biennial procedure review. The program is expected to be completed by December 1987. IFI 213/86-01-04 is closed and the final implementation of ISI procedure changes will be reviewed under the routine inspection progra .
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5. Followup on IE Bulletins (IEBs)
5.1 Licensec action on the following IE Bulletin was reviewed for forwarding to appropriate management, licensee review for applicability, response timeliness, response appropriateness, response accuracy, corrective action commitments, and corrective action completio Failure of Emergency Cooling (ECCS) Pumps Due to Single Failure of Recirculation Line Isolation Valves (ICB 86-03)
The bulletin asked licensees to report to NRC whether or not the poten-tk1 for failure of ECCS pumps due to a minimum flow recirculation line valve failure exists; and to document, if necessary, the justification for continued operation and/or short-term modifications. The licensee's response, dated November 8,1986, stated that this potential does rot exist at Haddam Neck because the recirculation line isolation valve is required to be blocked open during plant operating modes requiring ECC The inspector verified the implementation of this technical specification requirement in operating procedures NOP 2.12-1, ECCS Lineups, and SUR 5.1-4, Hot Operational Tes The licensee also indicated that modifica-tions planned to alleviate another single failure problem in this system would also adequately address the Bulletin concern. NRC verification of the adequacy of these changes will be performed during NRC Licensing eview of the projected modifications. The licensee's response was not submitted under oath or af firmation as requested by the Bulletin. The inspector informed the utility licensing staff of this discrepancy on December 9, 1986. The licensee committed to review and correct the omission. The inspector had no further question . 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 had been met, that appropriate corrective action had been taken, and that the continued operation of the facility was conducted within Technical Specification Limit Operator Surveillance Missed Inoperable Lock on Safety Injec-tion Valve (Detailed in NRC Region I Inspection Report 50-213/
86-27)
86-43 Failure of the Wide Range Stack Radiation Monitor
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6.2 Plant Trip Due to Inadequate Control of Maintenance On November 30, 1986, the plant automatically tripped from 100 percent power following the inadvertent closure of the #3 feed regulating valve (FRV) which caused low level in #3 steam generator (SG) coincident with a steam flow / feed flow mismatch. The feed system tr nsient and subse-quent trip were caused when Instrument and Control I ,,artment (I&C)
technicians repairing a loose connection in the #3 feedwater control system (FWCS) shorted out the 10 volt DC power supply in that syste The #3 FRV had been placed in manual control at the main control board because of the FWCS problems. Upon loss of the FWCS control power, the
- 3 FRV failed closed, initiating the event. Plant systems responded normally immediately following the trip and the licensee made the appro-priate notifications to the state, local and NRC officials. During sub-sequent trip recovery actions, the licensee identified several other component / system problerrs including increased reactor coolant system leakage through a loop isolation valve packing and main turbine system problem The licensee determined that the technicians performing the FWCS repair intended to de-energize the drawer in which they were working, but this important step was not accomplished. The inspector noted a lack of pro-cedural/ equipment control employed with this job. The work order for the job (CY-86-12052) was assigned to the I&C technicians without equip-ment control prerequisites or procedures referenced. Since no equipment control requirements were specified, the Shift Supervisor did not ensure that the equipment was in the correct configuration prior to commencement of the work. These concerns were discussed with licensee management on December 8, 1986. The licensee recognized that the technicians' failure to de energize the control drawer before soldering was a significant maintenance error. However, they stated that performance of this and similar jobs is within the capabilities and qualifications of their per-sonnel. The licensee recognized the need for more specific and formal equipment controls and committed to develop a mechanism by which admini-strative control over maintenance activities can be improved in the future. The schedule for implementation of these actions will be in-cluded in the Licensee Fvent Report (LER) associated with this even The LER will be reviewed during a subsequent inspection. This item is unresolved (213/86-30-02) pending LER review and further assessment of the adequacy of the licensee's control over maintenanc During the recovery from the automatic reactor trip on November 30, 1986, plant operators initiated flow restoration in reactor coolant system (RCS) loops 1 and The reactor coolant pumps (RCPs) in these loops automatically trip off following any plant trip and must be manually restarted. During RCS flow restoration, a leak in the loop 1 cold leg isolation valve (CLIV) packing and the associated valve stem leak-off line developed. Before an RCP is started, the normally open, back-seated CLIV must be closed to preclude a cold water addition to the reactor when the F.CP starts. When the loop 1 CLIV was closed, plant operators noted
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a marked increase in the dCS leak rate. Additionally, increasing air-borne activity levels were observed on containment atmosphere monitor The licensee estimated the RCS leak rate to be about 20 gallons per minute (gpm). After the loop 1 RCP was started, operators opened the CLIV, and the RCS leak rate decreased to approximately 2 gpm. A subse-quent licensee inspection inside containment identified a steam leak from the body of the 1/2 inch check valve on the RCS loop 1 CLIV stem leak-off lin Licensee management review of the event concluded that an unusual event had existed during the period (approximately 10 minutes)
in which the RCS leak rate had exceeded 10 gpm. This Notification of Unusual Event was made at approximately 11:00 p.m. on November 30, 198 Appropriate state, local and NRC officials were notified. A plant cool-down was initiated on December 1, 1986 to replace the failed check valve and reoair the packing leak in the CLI The unit was maintained in Mode 4 (Hot Shutdown at about 210 F) through-out the maintenance. Work Orders CY-86-12054, 12120 and 12151 were issued to replace the leaking check valve (DH-CV-546) and to repack the loop 1 CLIV (RC-MOV-546). Upon removal of DH-CV-546, it was identified that the valve installed was carbon steel while the design specification requires a stainless steel valv Nonconformance Report (NCR)86-459 was initiated to address this discrepancy and to require that DH-CV-546 be replaced with a stainless steel valv The valve stem leak-off system is a non-safety-related low pressure drain system. Similar check valves (32) on other primary system valve stem leak off lines connect to the same discharge header. All of these 1/2" check valves were found to be carbon steel material. The licensee con-cluded that no further action for these valves would be required at this time. NCR No. 461 was initiated to address these remaining valves. The use-as-is disposition of NCR 461 was based upon: 1) the performance of visual inspections of all 32 check valves with no visual defects (cracks, boric acid deposits, steam leaks) evident; 2) the licensee determination that the check valves are non-safety related; and 3) if the check valves were to fail (coincident with substantial valve stem packing leaks), the RCS leakage would be contained within the containment building. Also, plant Technical Specifications place limits on both identified and un-identified RCS leak rates. The expected leak rates are n il within the detection capabilities of plant instrumentatio The licensee's preliminary evaluation of the failure mode of the 1/2 inch carbon steel check valve was a combination of boric acid corrosion and flow induced body erosio The licensee has undertaken a metallurgical analysis of the valve; the results will determine the final failure mode evaluatio Several attempts were made to adjust the loop 1 CLIV packing to stop the leakage. Because the leakage had decreased only slightly, the licensee decided to replace the packing. This repair reduced the leakage to a
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negligible value. On December 4, 1986, loop 1 CLIV. maintenance was com-plete and plant heatup began. The plant achieved criticality on December
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On December 6, 1986, during power ascension following the' shutdown, the i
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plant was manually shutdown from 25% power to investigate excessive vibration associated with one of the four moisture separator reheater (MSR) units. Licensee investigation revealed that the baffle plates-in-two MSRs were cracked and those in the remaining two MSRs were ben l'
The need for a 2-4 day shutdown for repairs was promptly reported to state, local and NRC officials on December 7, 1986. The MSRs are located in the crossover piping between the high pressure turbine exhaust;and .
the low pressure turbine inlets. They remove excess moisture and provide '
steam to the low pressure turbines. The baffle plates are lucated on the inlet side of the MSRs and direct the high pressure turbine exhaust steam to the first stage of the reheating process. The baffle plates minimize MSR internal flow turbulence. The licensee's preliminary
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evaluation determined that the MSR baffle plate failures were caused by a rigid baffle plate assembly design in combination with thermal expan-sion stresses. Another potential contribution to the failures was fluid leakage froia behind the baffle plate.which may have caused a pressure differential across the plate upon a turbine trip. The licensee decided to remove the damaged baffle plates rather than replace them. This is a temporary fix. The llSR supplier (Southwestern Engineering Co.) repre-sentative on site was consulted concerning~the licensee's proposed modi-fication. A permanent modification is to be implemented during the 1987 outag Plant Design Change Request (PDCR) N0.86-858, MSR Deflector Plate Modifications, was reviewed by the Plant Operations Review Commit-tee (PORC) on December 9, 1986, and subsequently approved on December 10, 1986. The PDCR required that functional characteristics of the modification be verified via collection of post-modification performance data and comparison to pre-modification performance dat Other main turbine system equipment failures were identified following the November 30, 1986 trip, including blown-out low pressure turbine rupture disks and the failure of the low pressure steam dump system actuation pressure switch. These items were repaired prior to plant start-up. Further licensee causal analysis for these problems was in-itiated under Plant Information Reports86-209, 210 and 216. These re-ports will be considered for future review under the routine inspection program. Upon completion of the MSR repairs, plant start-up resumed on December 10, 198 .3 Mode 2 Operation Outside Safety Analysis Assumptions On December 8,1986, the licensee identified that the reactor had been operated in Mode 2 (reactor critical, less than 5 percent power) for about 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> with three out of four reactor coolant pumps (RCPs) run-ning, a condition outside the assumptions of the present safety analyse ;
With the secondary plant shutdown for maintenance, the licensee main- '
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(: 8 H .tained the reactor critical but below the power range to preclude the generation of radioactive waste caused by borating to a 3 percent shut-down margin condition (Mode 3). In order to reduce the heat input to
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the reactor coolant system during the shutdown, operators secured the reacto. coolant pump (RCP) in loop 1 at about 10:00 p.m. on December 7, 198 Normally plant safety analyses assume three or four RCPs are operating in Mode 2. However, an inadequate three-loop flow condition identified by the licensee has invalidated the present three-loop safety analyses and the licensee had committed to NRC (Licensee Event Report 86-34) not to operate the plant in Modes 1 and 2 with only three loops operating until the safety analyses were revised. As of December 7, 1986, those analyses had not been completed and therefore the operation of three RCPs on December 7-8 did not provide the minimum reactor coolant flow assumed in the present analyses. Upon licensee identification of this problem by reactor engineering, the fourth RCP was started at about 10:00 a.m. on December 8,~1986. The licensee reported to NRC the plant operation outside the design basis at 2:15 p.m. December 8. The licensee determined that the errant plant operation was not prevented because the licensee commitment to restrict operation in this mode was not adequately implemented. Procedure changes had been implemented to restrict three-loop operation in Mode 1, however no restriction was applied to Mode 2 operation. Further, operating procedures did not clearly define a three-loop operating condition for Mode 2, such that operators did not consider the plant to be in three-loop operation. These problems were corrected by procedure changes on December 8, 1986. The inspector re-viewed the changes incorporated by Temporary Procedure Changes86-548,
.549, 550, and 551 to verify that continued conformance with the safety analysis assumptions would be maintained. No discrepancies were identi-fied. The licensee is evaluating the safety significance of the un-analyzed three-loop operation in conjunction with the reanalysis of all three-loop operating conditions. This item remains unresolved pending completion of this evaluation and submittal of an LER for this event
(UNR 213/86-30-01).
7. Potential RHR Inadequacy On December 11, with the plant at about 15% power for chemistry control during routine power escalation, the licensee concluded that a postulated loss of piping integrity could jeopardize the ability to provide core cooling on the residual heat removal (RHR) system in the sump recirculation mode. A hold at the existing power was imposed by the licensee to avoid unnecessary plant transients pending further review. The NRC was notified. A conference call was held by the licensee and the NRC on December 1 The postulated loss of primary system integrity was a break in the 4" diameter piping between low pressure safety injection (LPSI) motor operated stop-check valves M0V-871A or MOV-871B and the asscciated entry points to the primary system on the reactor vessel (RV) head. Downstream of each of these valves, the piping branches into two lines, each of which goes to its own fitting on the RV hea The inlet piping for MOV-871A and MOV-871B branches from a i
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single line which branches from a common pipe for LPSI flow to MOV-871A and MOV-8718 and for normal RHR flow to the primary coolant loop 2 cold leg. The postulated LPSI break was hypothesized to be accompanied by inability or failure to shut M0V-871A and/or MOV-8718. That could result in all RHR flow being diverted out the postulated break point with no RHR flow into the R The redundancy in emergency core cooling provided by having both high pressure safety injection (HPSI) and LPSI was stated to prevent the LPSI pipe failure from preventing core cooling until RHR operation was require During the December 11 conference call, the NRC (NRR) concurred with mainten-ance of the current power pending further evaluation. The licensee held power at the existing level (about 15%) for the remainder of the report perio The licensee identified their short-term fix. RHR air-operated valve RH-FCV-796 is upstream of the common RHR and LPSI piping. It is presently blocked open during operation in accordance with the Technical Specifications. Up-stream of RHR-FCV-796 is a connection path to the HPSI and charging system The proposed licensee short-term fix for the postulated break is to throttle RH-FCV-796 to assure enough RHR flow to cool the core would be channeled to the charging flow path. The NRC identified additional information to be pro-vided by the licensee. A meeting was held on December 15 in the NRR offices in Bethesda, Maryland to discuss this issu At the December 15 meeting, the licensee provided his basis for the proposed short-term fix of throttling RH-FCV-796. (The long-term fix is a design change that alters the piping / valve configurations.) Specific flow testing or further analysis was committed to be accomplished to demonstrate adequate core cooling flow with RH-FCV-796 throttled. A license amendment request authorizing such throttling during operation was identified as appropriat Procedure modifications and operator training were identified as necessar Thi licensee subsequently decided to shut down for flow testing. Region-based inspector attendance at Plant Operations Review Committee (PORC) and Nuclear Review Board (NRB) meetings on December 17 noted addressal of these matters, and identified no safety inadequacies. Flow testing, Technical Specification compliance during subsequent evolutions, and adequacy of procedure revisions and training will be reviewed incident to routine inspectio . Unresolved Items Unresolved items are matters about which more information is required in order to determine whether they are acceptable items or violations. Unresolved items identified during this inspection are discussed in Paragraphs 6.2 and . Exit Interview
, During this inspection, meetings were held with plant management to discuss the findings. No proprietary information related to this inspection was identified.
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