IR 05000327/1988028
| ML20207G959 | |
| Person / Time | |
|---|---|
| Site: | Sequoyah  |
| Issue date: | 07/25/1988 |
| From: | Jenison K, Long A NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20207G952 | List: |
| References | |
| 50-327-88-28, 50-328-88-28, NUDOCS 8808240303 | |
| Download: ML20207G959 (39) | |
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UNITED STATES g p240o9'g NUCLEAR REGULATORY COMMISSION !
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r.E000N It 101 MARIETTA STREET. +
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i Report Nos.: 50-327/88-28,50-328/88-28 !
Licensee: Tennessee Valley Authority .
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6N 38A Lookout Place 1101 Market Square Chattanooga, TN 37402-2801
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Doc.ket Nos. : 50-327 and 50-328 1.icense Nos.: OPR-77 and OPR-79 l
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Facility Name: Sequoyah Units 1 and 2 Inspection Conducted: May 5 - June 2, 1988 3 l Project Engineer: Q (1. L v 7/15/ff A. Long, Project"Engineer Date 5fgned Inspectors: P. Harmen, Shift Inspector G.HumphreyIftInspectorShift K. Ivey, Sh Inspector i
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> A.Longless,jectEngineer 0. Love Shift Inspector .
W. Poertner, Shift Inspector f W. Bearden, Shift Inspector I
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, C. Bassett, Radiation Specialist l
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Shift Manager Approval: 7/2 k88 ;
K/ Jenls Shift Manager Datt signed i N f. Bra >ch,ShiftMana(Wr A 7/AI M
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8008240303 000016 '
PDR ADOCK 0b000327 G PNV
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Summary Scope: This announced inspection involved onshift and onsite inspections by
. the NRC Restart Task Force. The majority of expended inspection
effort was in the areas of extended control room observation and operational saftty verification including operations performance
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system lineups, radiation protection andsafeguardsandhousekeeping
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inspections. OtherareasinspectedIncludedmaintenanceobservation, review of previous inspection findings, follow-up of events re i of licensee identified items, and review of inspector follow view u)
items. During this period there was extended control rooin and p' ant
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activity coverage by NRC inspectors and manager ,
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Results: One violation was identified:
j- [ 327,328/88-28-01: Failure to Follow Procedures (caragraph 9)
- Additional examples of a previous violation were identified:
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- 327,328/88-26-01: Failure to implement procedures associated with
- configurationcontrol(paragraphs 9and10).
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REPORT DETAILS ! Persons Contacted l l -.
Licensee Employees
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- J. LaPoint, Acting Site Director J. Anthony, Operations Group Supervisor T.Arney,QualityAssuranceManager
- R. Beecken Maintenance Superintende J.Bynum,AssistantManagerofNuclearPower
- Cooper: Licensing fupervisor H. Elkins, Instrument Maintenance Group Manager R. Fortenber , Technical Support Supervisor J. Hamilton uality Engineering Manager M. Harding,,L censing Group Manager G. Kirk C
- L. Martin,omplianceSupervisor SiteQualityManager R. Olson, Modifications J. Patrick, Operations Group Supervisor R. Pierce, Mechanical Maintenance Supervisor
- R. Prince, Radiological Control Superintendent
- R. Rogers, Plant Operations Review Staff M. Skarzinski, Electrical Maintenance Supervisor 5. Sliger, Manager of Projects
- 5. Smith, Plant Manager
- S.-Spenser, Compliance J. Sullivan, Plant Operations Review Staff Supervisor
- C, Whittemore, Licensing Engineer
- B. Willis, Operations and Engineering S o erintendent NRC Employees
- F. McCoy, Startup Manager
- K.- Jenison, Shift Manager
- M. Branch, Shift Manager ,
- C. Bassett, Radiation Specialist
- Attended Exit Interview on June 8
- Attended Exit Interview on May 20 l Sustained Control Room Observation (71715)
The inspectors observed control rocm activities and those plant activities directed from the control room on a continuous basis for tie entire period l
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of this repor The observation consisted of one shift inspector per shift supported by one shift manager per shift and other OSP management.
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2 Control Room Activities Including Conduct of Operations The inspectors reviewed control room activities and verified that operators were attentive and responsive to plant parameters and conditions; that operators remained in their designated areas and were attentive to pint operations, alarms and status; that operators employed communication, terminology and nomenclature that was clear and formal; and that operators performed a proper relief prior to being discharged from their watch standing dutie Control Room Manning The inspectors reviewed control room manning and determined that TS requirements were met and that a professional atmosphere was maintained in the control room. The inspectors found the noise level and working conditions to be acceptable and observed that radios or other non-job related material did not exist in the control roo The control room appeared to be clean, uncluttered, and well organized. Special controls were established to limit personnel in the control room inner area. Operator compliance with regulatory and TVA administrative guidelines were reviewed. No deficiencies were
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identifie Routine Plant Activities Conducted In or Near the Control Room The inspectors observed activities which require the attention and direction of control room personnel. The inspectors observed that necessary plant administrative and technical activities conducted in or near the control room were conducted in a manner which did not compromise the attentiveness of the operators at the controls. The licensee has established a Shift Operations Supervisor office in the control room area in which the bulk of the administrative activities, including the authorized issuance of keys, take place. In addition, the licensee has establishd H0, WR, SI, and modification matrix functions to release the licensed operators from the bulk of the technical activities that could impact the performance of their duties. These matrixed activities were transformed into the WCC which is located in the TSC spaces.
! d. Control Room Alarms and Operator Response to Alarms The inspectors observed that control room evaluations were performed l utilizing approved plant procedures and that control room alarms were responded to promptly with adequate attention by the operator to the
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alarm indications. Control room operators appeared to believe the
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alarm indications. None were identified by the inspectors that were j ignored by the operators.
The inspectors observed operator actions immediately following the
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reactor trips on May 19 and May 23 (See paragraph 9). The operators handled both situations in a calm manner and their actions i
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were effective in stabilizing the plan In addition, the shutdowns were performed without problem Fire Brigade The inspectors reviewed fia brigade manning and qualifications on a routine basis. Both manning and qualifications were found to meet TS requirement Shift Briefing / Shift Turnover and Relief The inspectors observed that U0s completed turnover checklists, conducted control panel and significant alarm walkdown reviews, and reviewed significant maintenance and surveillance activities prior to relief. The inspectors observed that sufficient information was transferred on plant status, operating status and/or events and abnormal system alignments to ensure the safe operation of the Uni The inspectors observed the ASOS relief and concluded that sufficient
'information appeared to be transferred on plant status, operating status and/or events, and on abnormal system alignments to ensure the safe operation of the Uni Shift briefings were conducted by the offgoing S0 Personnel assignments were made clear to oncoming operations personne Significant time and effort were expended discussing plant events, plant status, expected shift activities shift training, sionificant surveillance testing or maintenance ac.ivities, and unusual plant conditions, Shift Logs, Records, and Turnover Status Lists The inspectors reviewed SOS, U0, and STA logs and determined that the logs were completed in accordance with administrative requirement The inspectors ensured that entries were legible; errors were corrected, plant initialed status; and dated; significant logbook events operational entries and adeq/oruately unusualreflected parasaters were recorded; and entry into or exit from TS LCOs were recorded promptly. Turnover status checklists for R0s contained sufficient information and indicated plant status parameters, system alignments, and abnormalities. The following logs were reviewed:
Night Order Log System Status Log Configuration Control Log Key Log Temporary Alteration Log LC0 Log
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4 Control Room Recorder / Strip Charts and Log Sheets The inspector observed operators check, install, mark, file, and route for review, recorder strip charts in accordance with the established plant processes. Control room and plant equipment logsheets were found to be complete and legible; parameter limits were specified; and out-of-specification parameters were marked and reviewed during the approval proces . Management Activities TVA msnagement activities were reviewed on a daily basis by the NRC shift inspectors, shift managers, and Startup Manage Daily Control of Plant Activities (War Room Activities)
The licensee conducted a series of plant activities throughout each day to control plant routines. These activities were referred to by the licensee as War Room activities. War Room activities were observed by the shift manager on a daily basis and were found to be, an adequate method to involve upper level management in the
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day-to-day activities affecting the operation of the units, Observation of First Line Supervisor Activities Improvements in the area of first line supervisor activities have been identified. First line . supervisors appear to be more knowledgeable and involved in the day to day activities of the pian More first line supervisor involvement in the field has been observed, Management Response To Plant Activities and Events In general, management responsc to those plant activities and events that occurred during this inspection period was quick and effectiv . Site Quality Assurance Activities in Support of Operations During the inspection period the site QA staff performed audits, inspections, and reviews of the following:
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Temporary Alterations (Review of TACF log)
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Configuration Control (UHI, EGTS, ERCW, and Condensate Systems)
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sis Required for Mode Change (12 of the 15 required sis were reviewed, with one minor deficiency identified and corrected.)
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Surveillance Instruction Scheduling and Tracking
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Logkeeping (Including LC0 log)
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Operator Aids (94 items were observed; three deficiencies were identified and subsequently corrected.)
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These issues were reviewed by the inspector and found to be adequately resolved by the licensee. In addition, day to day involvement by the site QA staff in unit operations appeared to be adequat . Chronology of Unit 2 Plant Operations At the beginning of the the NRC Restart Task Force shift coverage, Unit 2 was in Cold Shutdown (Mode S) with three RCPs operating and the 2A-A RHR pump in service. The RCS was at 180 degrees F and 370 psig. Pressurizer level was at 26 inche All SGs were filled to the operating range, the condensate system was on long cycie recirculation, and there was a vacuum in the main condense On February 4,1988, the NRC approved entry into Mode 4/3 (Hot Shutdown /
Hot Standby). The plant was neated up using R'Ps and entered Mode 4 on February 6, 198 On February 10, 1988, RHR cooling was returned to service and the licensee suspended all non-essential testing and maintenance for about 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> This was done following a series of events which included generation of a reactor trip signal, inadvertent MSIV closures and feedwater isolations, and a loss of the VCT level due to maintenance activitie Prior to Mode 3 entry, a3 proximately nine personnel errors had occurre None of the events resulting from those personnel errors represented significant safety concerns of their own accord and col;ectively appeared to be ty3ical of what one would expect at a near term operating license plant go:ng through the same evolutio Unit 2 entered Mode 3 on February 27 and was maintained in mode 3 with four RCPs operating until April The RCS was maintained between 350 F/1600 psig and 546k F/ 2250 psi, A number of events occurred during this time period, including an inadvertent closure of all four MSIVs, exceeding TS surveillance limits for RCS leakage, and exceeding RCS cold leg accumulator boron concentratio In addition, two potential violations were identified involving charging pump and auxillary feedwater pump operability. Themajorityoftheseeventswerepersonnelrelatedand were responded to by the .icensee in an adequate manner. Within this time neriod, several equipment related events also occurre The most significant of these involved the operability of the reactor trip breakers, the RCS letdown orifice isolation valve, source range channel N-31, and a limitorque motor in the balance of plant feedwater syste The equipment related events were adequately resolved by the license On March 22, 1988, the NRC Commissioners voted to allow Unit 2 to restar On March 30, the NRC approved entry into Mode 2 (Startup). On March 31, prior to actually beginning dilution, the licensee determined that
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modifications would be required on one of the three pressurizer 1003
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seals, and the restart was delayed. During resolution of problems w th oressurizer loop seals, a tube leak was identified in the #3 steam generat;s.
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On April 7, Unit 2 began a cooldown from Mode 3 to Mode 5 to repair the SG
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tube leak and complete pressurizer loop seal modification On April 29, following completion of corrective actions associated with resolution of pressurizer loop seal and steam generator tube leakage problems, TVA met with OSP HQ personnel for a technical discussion of the SG tube repair process and the pressurizer safety valve and loop seal issu TVA actions were determined to be acceptable with respect to these inue Significant events which occurred during this inspection period are summarized below:
On May 5, Westinghouse notified TVA of an error in their calculations for fuel assembly grid straps. Thase calculations were used in accident analy as. This error was later determined by Westinghouse to pose no safety significance. This evaluation was reviewed by the inspector and found to be adquat On May 5, an incorrect pre-recorded telephone message was issued during a test of the radiological emergency personnel recall system, indicating that an actual alert was in progres On May 7, at 3:00 am, Unit 2 entered Mode On May 7, the recirculation flow path from the boron injection tank to the boric acid tanks was discovered to be blocked by boron crystallizatio On May 8, slightly contaminated water was sprayed from an open drain standpipe into the protective clothing storage are On May 9, the TVA TS interpretations book was found to have been returned to the control room prior to PORC approval of several of the individual interpretation On May 11, at 7:25 am, Unit 2 entered Mode On May 12, TVA was informed of an unreviewed safety issue involving 4 the potential for inadvertent operation of the cold over pressure protection system (COPS) during certain unanalyzed accident The licensee disabled the COPS until corrective action could be determined and implemented.
On May 12, NRC Hold Point 2 was released. Shutdown rods were fully withdrawn by 5:00 am, and RCS dilution commenced at approximately 6:30 am. At 10:10 pm, the licensee administratively declared Mode 2, I and control banks were withdrawn to Bank 0 at 150 steps. Dilution l towards criticality then commenced.
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On May 13, reactor criticality was achieved at 12:20 p The licensee received NRC permission to exceed 5% power and the plant entered Mode 1 at 6:23 pm. The reactor achieved 10% power at approximately 7:10 pm. The generator was synchronized and tied to the grid at 9:07 p On May 15, at 8:45 pm, NRC holdpoint #4 was released to allow operation above 30% powe On May 16, reactor power exceeded 30%.
On May 16, incore detector flux thimble A failed to retract after being inserted into the core due to blown fuse in the drive circuitr On May 17, leaking valves in the liquid waste treatment system caused the evacuation of the auxiliary building in response to high airborne activity concentrations. Some minor personnel contamination occurre The licensee adequately recovered from this even On May 18, contaminated water was spilled from the liquid waste treatr.ent heade On May 19, SG 1evel indicator 2-LI-3-97 was declared inoperable due to the identification of an unqualified splice in the circui On May 19, Unit 2 tripped from 73% aowe Pending resolution of several issues, the NRC reimposed Ho d Point #2 (permission to enter Mode 2). Hold Point issues included review of the trip report, and resolution of the non-EQ splice (reference violation 327, 328/88-28-01)
On May 20, the NRC reviewed the licensee's corrective actions to resolve the Hold Point issues identified above and released Hold Point # Withdrawal of shutdown banks began at 5:29 p On May 21, at 12:03 am, Unit 2 was taken critica Mode 1 was entered at 2:05 a The generator was synchronized and tied to the grid at 4:05 a On May 23, at 12:28 am, Unit 2 tripped from 70% power on low RCS flow on loop # On May 24, at 3:25 am, Unit 2 entered Mode On May 24, Unit 1 experienced a loss of decay heat removal capability l when the operating RHR pump lost suction and was tripped by the operators.
! On May 28, at 6:15 pm, NRC holdpoint #5 was released to allow operation above 75% power.
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On May 29, Unit 2 achieved 100% reactor power, producing approximately 1150 MW A detailed discussion of certain events which occurred during the period of the inspection is contained in paragraph . Operational Safety Verification (71707) Units 1 and 2 Plant Tours The inspectors observed control room operations; monitored conduct of testing evolutions; reviewed the shift logs, night' order book, clearance hold order book, configuration log, and TACF log, conducted discussions with control room operators; observed shift turnovers; and confirmed the operability of instrumentation. The inspectors verified the operability of selected emergency systems and verified compliance with TS LCOs. The inspectors verified that maintenance WRs had been submitted as required and that follow-up activities and prio:itization of work was accomplished by the license Tours of the diesel generator, auxiliary, control, and turbine buildings were conducted to observe plant equipment conditions, including potential fire hazards, fluid leaks, excessive vibrations, and plant housekeeping / cleanliness conditions. The inspectors entered the annulus on May 6 and noted that the insulation on some of the ventilation ductwork was in poor condition. The AS05 was notified of the condition. The inspectors later entered the upper containment for a containment tour and exited through the lower entryway, accompanied by operations, public safety, and health physics personnel. The Public Safety officers reviewed the areas for explosives, and the other personnel reviewed cleanliness and material condition On May 7, the inspectors entered the upper ice condenser for final inspectio On May 18, inspectors touring the auxiliary building noted various staging and work materials in the areas around the BIT, 2A RHR and CS heat exchanger room, CCS pump 1A-A, the CCPs, -
and the CCS heat exchanger. Licensee management was informed and the areas were adequately addresse The inspectors wt.1ked down accessible portions of the following safety-related systems on Unit 2 to verify operability and proper valve alignment:
Safety Injection System Pressurizer Loop Seal Drain Valves Containment Spray 125 V DC Vital Power No violations or deviations were identifie Safeguards Inspection
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In the course of the inspection activities, the inspectors included a review of the licensee's physical security program. The performance of various shifts of the security force was observed in the conduct of daily activities, including: protected and vital area access controls; searching of personnel and packages; escorting of visitors; badge issuance and retrieval; patrols; and compensatory post In addition, the inspectors observed protected and vital area barrier integrity. The inspectors verified interfaces between the security organization and both operations and maintenance. Specifically, the shift insaectors inspected security during the outage period and reviewed icensee security event report No violations or deviations were identified, c. Radiation Protection and Radiological Control Considerations The inspectors observed HP practices and verified the implementation of radiation protection control On a regular basis, RWPs were reviewed and specific work activities were monitored to ensure the activities were being conducted in accordance with aaplicable RWP Selected radiation protection instruments were verified operable and within calibration frequenc The following RWPs were reviewed:
88-0-91: Condensate DI Routine Maintenance 88-2-118: Calibrate RCS Flow Transmitters to Support TI-2
! 88-0-113: 669 Spent Resin Tank Valve Hallway 88-0-14: Calibration of Transmitters and Gages and Associated Work-All Areas Except Containment No violations or deviations were identified in the RWP revie On May 11, 1988, the shift inspector reviewed RWP-014, Calibration of Transmitters and Gages and Associated Work (all areas excluding containment) and noted that three workers were not documented as having pre-work briefings. This was identified as shift issue 4/11/88-1- A review of other RWPs by shift inspectors on all shifts did not indicate any additional problems with briefing documentatio The discrepancies were discussed with Radiological Control supervisory personnel who investigated the specific instanc It was found that one of the individuals was an HP conducting a survey. HPs conducting surveys were familiar with the area and excluded by procedure from the briefing requirement. The other two individuals were craft personnel. Radiological Control personnel stated the two individuals would be counseled. Because this appeared to be an isolated incident of low safety significance, and there was
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a lack of other examples, the inspector considered the licensee's actions adequat This issue is resolve The inspector reviewed the radiation protection aspects of the licensee's recovery actions taken as a result of leaking valve packing in the HUT valve gallery (See paragraph 9). At approximately 11:50 pm on May 16, an air sample taken in the Penetration Room of the Unit 2 Auxiliary Building on the 690 elevation showed an increase in particulate airborne activity of less than twenty-five percent (25%) of the Maximum Permissible Concentration limi As a result of this increase and because airborne radioactivity had ingressed the area in the aast via the floor drain and related piping in the Volume Control Tan ( Room, Radiological Control personnel posted the Penetration Room as an airborne radioactivity area and began preparing a Radiation Work Permit in case an evacuation of the Auxiliary Building was necessary. The RWP would be used to ensure that everyone inside the radiation control area was accounted for and track MPC-hours should that be necessar Following the isolation of leakage paths in the HUT valve gallery, HP personnel initiated an air sample in thct area at approximately 2:38 am on May 17. Results from the air sample showed no airborne activity in the are However, increased indications cn the continuous air monitors located on the 690 elevation caused operations and HP personnel to evacuate all personnel from the auxiliary building. The SOS also placed the Auxiliary Building Gas Treatment System in operation to aid in eliminating the apparent airborne proble Water from the leaking valves began to accumulate in the HUT valve gallery room and the area outside. HP technicians established a contamination zone around the area to control the spread of contamination and continued to take air samples. Maximum cor.tamination levels in the HUT valve gallery were measured and found to be 3000 disintegrations per minute per one hundred square centimeters (dpm/100 cm2). Wnile personnel were being evacuated from the auxilie.ry building, HP technicians completed posting the building as an air' corne radioact;vity area. At approximately 4:00 am, HP technicians were dispatched to all elevations of the auxiliary building to take air samples to determine the extent of the proble The results indicated that no airborne radioactivity was present and the CAMS also indicated that the airborne levels were decreasing to norma At approximately 5:36 a.m. the auxiliary building was released from airborne area controls and normal operations resume During this event some cases of clothira and personnel contaminations
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were reported. The inspector reviewed the contamination reports and the WBCs performed by the licensee as a result of the contaminations.
! All clothing and personnel were decontaminated according to the licensee's procedures and the WBC results indicated that no one received any detectable amounts of internal contamination.
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-No violations or deviations were identified in associat!an with the recovery from the even . Shift Surveillance Observations and Review (61726)
The inspectors observed / reviewed TS recuired surveillance testing and verified that testing was performed in accordance with adequate procedures; test instrumentation was calibrated; LCOs were met; test results met acceptance criteria requirements and were reviewed by personnel other than the individual directing the test; deficienciar were identified, as appropriate, and any deficiencios identified during the testing were properly reviewed and resolved by management personnel; and system restoration was adequate. For completed tests, the inspector verified that testing frequencies were met and tests were performed by qualified individual The following activities were observed / reviewed, with no deficiencies identified:
SI-14.2: Verification of Containment Integrity 50I-47.2: Turbine Overspeed Test SI-38: ShutdownMarginCalculation(Reviewedinconjunction with TI-33, Shutdown Margin Calculation)
SI-40.1: Centrifugal Charging Pump Casing and Discharge Piping Venting SI-78: Power Range Neutron Flux Channel Calibration by Heat Balance Comparison
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SI-79: Incore/Excore Power Range Neutron Flux Channel Calibration by Axial Imbalance Comparison SI-129.1: SafetyInjectionPumpCasingandDischargeVenting
SI-137.2: RCS Leakage Determination SI-166.6: hsting of Category "A" & "B" Valves after Maintenance or Release from a Hold Order SI-166.10: Accumulator / Injection Primary and Secondary Valve Integrity i SI-166.15: Containment Spray Check Valve Test Performed During Operation l SI-167: Containment Inspection
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During the inspection period, the following problems were identified in SI performance:
During the performance of SI-17, the EGTS initially failed to meet the test acceptance criterion because a Unit 1 breaker was out of service (See paragraph 9).
During(See trip paragraph 9).the performance of SI- 246, a personnel error cau
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8. Shift Maintenance Observations and Review (62703) Station maintenance activities of safety-related systems and compo-nents were observed / reviewed to ascertain that they were conducteC in accordance with approved procedures, regulatory guides, industry codes and standards, and in conformance with T The following items were considered during this review: LCOs were met while components or systems were removed from service; redundant components were operable; approvals were obtained prior to initiating the work; activities were accomplished using ap3 roved procedures and inspected as applicable; procedures used were acequate to control the activity; troubleshooting activities were controlled and the repair record accurately reflected what actually took place; functional testing and/or calibrations were components or systems to service;QC performed prior records were to returning maintained; activities were accomplished by qualified personnel; parts and materials used were properly certified; radiological controls were implemented; QC hold points were established v'.ere required and were observed; fire prevention controls were implemented; outside contractor activities were controlled in accordance with the approved QA program; and housekeeping was actively pursue No violations or deviations were identifie Temporary Alterations (TACFs)
The following TACFs were reviewed:
2-88-2010-68: Removal of jumpers for disabling COPS while above 350 degrees in RCS temperature 0-88-08-02: Installation of temporary connections to CST drains 0-2-500 and 0-2-501 to allow makeup water feed from a mobile vendor demineralizer No violations or deviations were identified, Work Requests The following work requests were reviewed:
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WR 8253109 - Calibrate level control on the #3 heater drain tank (2-LCV-6-106A).
WR B267052 - Disassemble and repair 1-FCV-74-02 WR 275181 - The inspectors reviewed licensee efforts in 3rogress to correct a plugged section of piping in the BIT to 3AT recirculation line. This work effort involved the removal of several feet of small bore piping which was found to be plugge A temporary hose, tubing and gear pump was installed to remove a second plug. The inssector determined that the piping welds and ASME classification were correct but that the TVA code class (TVA C) specified on the work order was incorrect. This was found to be the result of a drawing error Additionally the inspector determined that no post maintenance testing was specified in the work order. These issues did not impact the actual completed work in that the proper code class ,
pipe was actually installed and proper testing was actually accomplished in order to estab1'.;h operability pursuant to Technical Specifications. TVA initiated action to resolve tne paperwork deficiencie WR 8281655 - Calibration of COPS Pressure transmitter WR 8751228 - Stuck Incore Probe A WR B751206 - IRPI Deviat'on No violations or deviations were identifie d. Hold Orders The inspectors reviewed various H0s to verify compliance with AI-3, revision 38, Clearance Procedure, and that the H0s contained adequate information to properly isolate the affected p'>rtions of the system being tagged. Additionally, the inspectors verified that the required tags were installed on the affected equipmen The following H0s were reviewed:
Hold Order Equipment 2 - 88 - 345 SafetyInjectionPumps 2 - 88 - 417 2A - A Pressurizer Heaters 2 - 88 - 403 Valve 2-62-392A 2 - 88 - 429 PORVS (Closure for COPS Problem)
2 - 88 - 436 ERCW Pump M-B 1 - 88 - 760 CVCS The inspector noted that the clearance sheet for H0 2-88-417 did not include the time, dace, sheet number section, phone, Unit AS05 received the PMT requby,irement.datereceived,configuratIonlogentryverification,and The inspector reviewed 15 other hold orders and identified no similar deficiencie The inspector notified the ASOS
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on duty, wi.o corrected the missing item This is considered to be an administrative issue and is resolve No~ violations or deviations were identifie . Event Follow-up (93702, 62703)
On May 4, the pressurizer was drained to approximately 28% level in preparation for drawinct a bubble. On May 5 there was a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> delay to vent the reactor vesse' head again after determining that there was a gas bubbl A determination was made that the prior vent and sweep process was not performed adequately. The inspectors observed efforts in progress associated with the performance of S0I-68.1, Reactor Coolant System, which pertained to filling and venting the RCS. The S0I was accompanied by an instruction change to ensure that the pump run times did not exceed 30 seconds to avoid entrainment of gasses into the RC On May 5, the licensee advised NRC staff that they had received notification from Westinchouse of an error in assumptions used in the accident analysis for fue' assembly grid strap stiffness. A site specific recalculation with proaer grid strap stiffness parameters yielded loads of only 65% of the loading that could induce deformation and affect the analysi This conclusion was documented in a letter from Mr. J. R. Guthridge of Westinghouse to Mr. J. D. Robertson of TVA dated May 9, 198 FinaldocumentationanaQAverificationofthisanalysiswas reported complete by Westinghouse letter serial 88TVA-G-0034 dated May 13, 198 This letter reported that the grid loads during a combined LOCA/
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Seismic event were calculated to be less than 75% of the deformation loading value. This issue is resolve On May 5, containment spray suction check valve 72-507 failed the ASME Section XI test (required for Mode 4 entry) after a number of unsuccessful attempts 'and corrective actions. This leak test was performed per SI-166.15. The check valve successfully passed the SI on May 6, after having been reworked by maintenanc On M:y 5, during a planned test of the radiological emergency personnel recall system, a phone message was issued by mistake which indicated that an actual ALERT was in progress. This resulted from the wrong pre-programmed call button being pressed. Actions to correct the false alert were taken immediately. Some confusion resulted because by
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coincidence a small fire had simultaneously ignited in a container of insulation in the terbine building. When some of the emergency personnel called in to verify that the ALERT was not a drill, they were told that a fire was in progres On May 7, 1988 the licensee determined that a flow blockage existed in the recirculation line from the boron injection tank to the boric acid tan This was discovered vhen the licensee attempted to establish recirculation, and was believed to be the result of the 20,000 ppm boric acid in the system solidifying when flow was secured. The blockage was
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removed on May 10 by replacing several feet of 1" pising. This established operability of the Boron Injection Tank for hode 3 entr On May 11 at 12:45 am, two consecutive samples taken from the BIT were within acceptable boron concentration limits, and this was used to verify that the BIT was in service. After resolution of some problems with heat tracing, the system was restored to operabilit On May 8, dress-cut clothing was contaminated with liquid from a nearby open drain standpipe in '.he floor. Approximately 20,000 dpm was measured in the area. HP personnel contained the contamination and operations personnel initiated an evaluation of the source of the leakage. There was no evidence on any of the radiation monitors that any contamination was released from the area. Approximately one quart of contaminated water was sprayed ou On May 8, the NRC was informed that RCP #1 had a vibration of 12 mil After censulting Westinghouse, it was determined that this wts acceptable because the vibration had not increase On May 9, 1988, licensee staff members advised the startup manager that 19 TVA TS Interpretations had been put back into the TS interpretation book in the Control Room prior to approval by PORC. This was contrary to commitments made by the licensee at the Centrifugal Charging Pump enforcement conference on March 17, 1988. The plant manager was advised of the incident and stated that the una) proved interpretations would be removed from the control room immediately and that he would advise the restart staff of the cause of this incident once determined. Resolution of this concern was completed on May 9, 198 On May 10, problems were observed with pressurizer level instrument 2-LT-68-320 (not a post accident monitoring instrument) failing its channel chec The instrument was not within 5.5% of the level measured by the ad The bistable was placed in the tripped position, jacent two indicator which was acceptable for Mode 2 entry and power ascension pursuant to TS 3.3.1. The pressurizer level instrument reading was attributed to a slope change in the instrument tap due to damage induced by personnel traffic in the pressurizer cubicle. The licensee reestablished the zero reference point and rescaled the instrument to
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account for the reconfigured instrument tap prior to criticalit On May 10, one of +he containment sump level indicators was observed to read approximately 5.9%, while the others were reading 0%. SI-2 requires a deviation of less than or equal to 6% between channels while in Modes 1, 2, 3 and The indicator later returned to 0% after containment ventilation changes were mad The cause of the problem was determined to
! be temperature differences at the instrument's reference legs.
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On May 11, steam generator level instrument 2-LT-3-97 failed high. The bistable was placed in the tripped position for Mode 2 entry and power ascension pursuant to TS 3.3.1. The instrument was subsequently returned i to within specification without corrective actions being require The I
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licensee continued to observe the instrument reading for further evidence of malfunctionin On May 11, 1988 the licensee identificd missing PMT documentation (SI-166.6) for the ERCW auto supply valve to the 28-B EDG (2-f CV-67-67).
This ~ was identified as shift issue 3/12/88-2- The valve had been modified by modifications WP 001188-01.51-166.6 was a requirement of the W The work was completed on 3/5/88, the valve was declared operable on 3/7/88, and SI-166.6 was not performed until the error was discovered on 3/11/88. Investigation revealed that MI-10.43, M0 VATS Testing, was done on 3/5/88 which technically accomplished equivalent testing to SI-16 The modification arocedure AI-19 Part IV has been revised to include additional specifications and clarification on performance of recuired post modifications testing. This item was identified and correctec by the licensee. This issue is resolve On May 11,1988, the licensee identified traces of cesium in steam generator #3. Subsequent tritium testing results indicated slight t; aces of tritium above minimum detectable levels. The licensee concluded, based on the test analysis results and based on the fact that blowdown had not been initiated on steam generator #3, that the radionuclide indications were residual from the SG tube leak discovered April 6,1988, which had since been repaired (See Inspection Report 88-26). The licensee initiated monitoring for stearn generator tube leakage on a 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> basis in accordance with TVA's normal surveillance progra On May 11, ASME relief for MIC was received from NR It was determined that the licensee was in compliance with TS 3.4.10 per SER and lette This issue is resolve On May 12,1988, the NRC site staff was made aware that certain other Westinghouse plants had an unreviewed safety issue with respect to their low temperature overpressurization system. This system was similar to the cold overpresst,re protection system at Sequoyah. COPS is designed to automatically reset the lift setpoint of the PORVs when the RCS temperature is less than 350?F to protect the RCS from a 3ressure transient with the pressurizer solid. Westinghouse determinec that during a main steamline break or SG tube rupture that the RCS temperature could drop to below 350?F, and that a failure of a single TH0T channel would cause the PORVs to open. The uncontrolled opening of the PORVs during these events had not been analyzed with respect to DNB limits. Upon learning from the NRC of the unreviewed safety issue at the other Westinghouse plants, the licensee immediately placed the PORVs in the closed position to prevent their opening. They determined that the PORVs were not inoperable in this configuration, as the operators could open the valves by hand if necessary. Within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />, the licensee had installed a TACF which removed the COPS operation signal and returned the PORVs to the P-Auto position. The TACF included procedure changes to require the COPS tc, be returned to service prior to decreasing the RCS below 350? This itsue is considered to be satisfactorily resolve . .
An additional COPS issue had previously been identified by TVA on 2/27/8 During pisnt cooldown, the "Cold Over Pressurization Approaching Limit" alarm activated approximately 45 PSI higher than expected (NRC shift followup item 2/27/88-2-1). Work request 8281655 was issued and performed to calibrate the pressure transmitter. A second work request 8281656 was issued and performed to verify the alarm setpoint and actuation poin The inspector reviewed the completed work requests and asso::iated calibration and verificaticn procedure. Licensee action on this issue was satisfactory. This issue is resolve l On May 12, 1988, the licensee determined that the hydrogen recombiner system on Unit 2 was inoperable because a thermocouple in the containment temperature compensation f rcuit intermittently caused a high resistance in the circui The lictasee stated that the circuit was non-CSSC. The inspector reviewed design document SQN-DC-V-26.1, Combustible Gas Control Syste Paragraph 3.5.2 of the design document states that,
"Thermocouples shall be provided for convenience in testing and periodic check out of the recombiners." Additionally, the inspector reviewed 501-83.1, Containment Hydrogen Recombiner System. For a hypothetical i failure of the compensation circuit, the worst-case scenario would require the operator to start t.nother recombiner and would not affect the function of the recombiners. This is a more conservative situation. The licensee repaired the circuit prior to entering Mode 2 and declared the system o?erabl The ins tiat the licensee'pettor agreed that s operability call tne wascircuit should be non-CSSC of a conservative nature. and This issue is considered resolve '
On May 12, the licensee administrative 1y declared Mode 2 at 10:10 p Withdrawal of the control banks commenced, and was completed by 12:58 am on May 13, with Bank 0 at 150 step Oilation towards criticality commenced in the normal dilute mod At 7:15 am, dilution was shifted to the alternate dilute mode to decrease the waiting time required for boron concentrations to equaliz t i On May 13, at 9:15 am, the inspector informed the ASOS that rod H4 IRPI was indicating twelve steps different from the group demand indication.
l The IRPI are very sensitive to ambient temperature variations. The l
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licensee allowed the upper head area temperature to increase by turning off the CRDM coolers. This caused the H4 position indication to come back i within 12 steps of the other rods in the grou On May 13, at 10:13 am, the U0s attempted to achieve criticality by i pulling the control rods further out of the cor Prior to the rod l withdrawal, the reactor was approximately at the predicted criticality conditions of 957 ppm boron and 150 steps on Bank the cycle design
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calculations indicated that 400 pcm of reactivity worth was available on the inserted remainder of Bank D. However, when Bank D was withdrawn to 195 steps, the reactor was not critical. Bank D was then reinserted to 150 steps and further dHution was performed. Subsequently, with RCS boron concentration at ??i.' ppm, Bank 0 was again withdrawn, i
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On May 13, at 12:03 pm, Unit 2 achieved criticalit Initial critical conditions were 922 ppm boron and 174 steps on Bank The difference between the initial predicted critical conditions of 957 ppm /150 steps and the actual critical conditions was approximately 430 pcm. The 3redicted critical conditions were calculated by Westinghouse using a 2-d mensional core model. Westinghouse subsequently provided a refined calculation of critical conditions, based on a 3-dimensional core model, of 939 ppm and 174 steps on Bank D.
4-On May 12, at 6:23 pm, the unit entered into Mode 1 with the reactor at approximately 5% power, following NRC release of Hold Point #3. The reactor achieved 10% power at approximately 7:10 p On May 13 and 14, the unit received an intermittent alarm on high temperature in the pressurizer safety and PORV relief lines. The licensee determined that the discharge piping temperatures for two of the three safety relief valves and L r both PORVs were slightly above the alarm setpoint. Acoustic monitoring and PRT tank parameters, however, reflected no indication of valve leakage. The licensee attributed the alarm to pressurizer cubicle ambient temperature conditions and adjusted lower compartment cooler flow which cleared the alarm. This issue is considered resolve '
On May 14, TAVE RTO 2-TE-68-44E was observed to be indicating erroneousl The licensee declared the instrument inoperable and tripped all RPS ,
bistables associated with that instrument. Operation and mode change in this condition are allowed by TS 3.3.1. The problem was corrected and instrument 2-TE-68-44E was returned to service on May 1 '
On May 15, the licensee performed a flux mapping run with the movable ,
incore detectors to determine whether a quadrant power tilt of 7% observed '
on the excore power channels was real or was caused by a power range .
instrument problem. The tilt was confirmed to be a power range instrument calibration problem, attributed to the detectors having been moved slightly during the extended outage. The excore power channels were normalized to correct the proble l
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On May 16, incore flux detector A would not retract after being inserted for flux mapping which started on May 15. On May 18, the detector was i retracted after correcting a problem with the drive motor. A worn cable i wasamajorcontributortothedrivemotorproble Cable replacement for '
permanent repair of the system is currently in progres On May 16, the main turbine overspeed test was performed successfully, and
the turbine generator was retied to the grid.
On May 17, at 2:55 am, the auxiliary building was evacuated as a precautionary measure when airborne radioactivity was created by leaking ,
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valve packing in the holdup tank valve gallery. At approximately 2:00 am i on May 17, Unit 2 operations personnel attempted to ret e inventory in
- the VCT via the divert valve to HUT B in order to make allowances for a '
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Unit 2 dilutio However, the VCT level was not dropping as expected. A high level of 90% in the HUT B was suspected to be the problem. The U0 instructed an AVO to check the status of valve 2-62-951. Based on the indications available, the AVO reported back that it "appeared" to be ope He noted that a positive ve/ification could not be made due to the valve stem position indicator being missing as well as the reach rod being ben The latter would have hindered manual manipulation without a pipe wrenc The valve cage door was locked, which prevented the AVO from entering the valve gallery and verifying the position by looking at the valve itself. Because the level of HUT B was 90%, the AVO was requested to pump from HUT B to HUT A to help the letdown attempts. As the level in HUT B dropped, an initial level drop in the VCT was experienced, but then leveled off. At this point the U0 contacted the AVO for the second time to request another attempt to verify the position of valve 2-62-951. The AVO referred to the status board, which indicated that the valve was closed. Minutes later, operations made note of a leak from and around the HUT valve gallery. When the AVO returned to the valve gallery, the area had been roped off by HP personnel, and water was coming out from under the gallery cage door. With HP assistance, the AVO and HP technician climbed over the gallery wall and opened valve 2-62-951. Four to five valve bonnets were found to be leaking. After opening valve 2-62-951, the AVO terminated the transfer from HUT B to HUT A. Radiological control
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considerations associated with the recovery from this incident were reviewed b; NRC HP staff and considered adequate (See paragraph 7).
Failure to assure proper system lineup before beginning the flow transfer evolution was identified as a further example of violation 327, 328/88-26-01 (see parsgraph 10).
On May 18, a second contaminated water spill in the holdup tank valve gallery occurred during an evolution to pump evaporator distillates to the holdup tanks. Operations initiated a valve lineup manipulation for the BAEs and HUTS via a phoha request from the control room to the AVO. The AU0s believed the desired configuration had been achieved, based on the reflected status board lineup and a partial physical verification of some of the valve positions. At approximately 6:55 pm, the control room was i notified of a leak around the elevator at the 690 elevation, and the HUT valve gallery area. Header isolation valve 62-948 was shown as open on the waste water system status board, wW, in actuality it was shut. This isolated the evaporator distillate ramp discharge, overpressurizing the i line, and resulted in valve packir leaks along the line. No personnel i contamination was reported. The faliJre to maintain configuration control was identified as a further example of violation 327,328/88-26-01 (See paragraph 10).
On May 19, at 1:03 pm, SG #3 level indicator 2-LI-3-97 was declared inoperable because a butt splice on one conductor between the indicator
and the indicator junction box was determined to be environmentally unqualified. All bistables associated with the indicator were placed in l the tripped postion per action statement #7 in LC0 3.3.1. The NRC
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operations center was notified on the Emerger.y Notification System at 7:00 pm. The condition was initially discovered on May 15 during
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replacement of the level indicator under work request WR 8751208. While observing instrument maintenance personnel who were replacing the level indicator, the QC inspector noted 2 Raychem splices and a third uncualified insulated butt splice in the "LB" condulet connected to the incicator. This butt splice was at variance with drawing 47E235-45, Environmental Data, Enviro,nmental-Harsh Lower Compartment which implements M&AI-7, Cable Terminations, Splicing and Repairing of Damaged Cables. The transmitter connection was completed, but the WR was not closed out because a conduit fire seal required repacking. During interviews conducted by NRC inspectors, the QC inspector indicated that his understanding after leaving containment was that the WR would be replanned '
to correct the unqualified splice and repack the fire seal. Upon exiting containment, both the QC inspector and the IM personnel informed their respective supervisors of the problem. When the QC inspector returned to work on the evening of May 16, he discovered the replanned WR was completed; however, the unqualified splice had not been corrected and the level indicator had been returned to service. The QC inspector then initiated a WR which was reviewed and determined to require a CAQR. During investigation and evaluation of the CAQR it was found that:
Although the insulated butt splice was unacceptable on a 10 CFR 50.49 device i '
structIon.t may The have been allowable
"unqualified splice" wasduring the time of plant con-not documente The 2 Raychem splices in the "LB" condulet were thought to be undocumented (not on the splice list), but it was found that they were insu11ed under a modification package and omitted from the splice list due to an administrative erro Non-conforming equipment had been returned to service without an operabiltiy determination for the non-conforming conditio IM personnel, A QC inYbector and their supervisors were aware of the problem for a least 4 cays prior to the performance of an operability determination on the equipmen The procedural were violated. requirements SQM-2 requires of SQM-2} ate notification of the ShiftMaintenanc immed Technical Advisor if at any point during the WR process it is discovered that the p"lant configuration does not agree with the latest "As Constructed drawin Instrument maintenance personnel who conducted the maintenance were '
not familar with the environmental qualification requirements for splices on 10 CFR 50.49 device The unqualified insulated butt splice in the condulet was subsequently repaired under WR 273915 and the level indicator was returned to servic '
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Had procedures been followed properly, the level indicator would have been-declared inoperable on May 15,1988 and LC0 3.3.1 action statement #7 would have been followe This incident was related to the May 19, Unit 2 reactor trip which was caused by a steam / feed flow mismatch coincident with a low steam generator leve The steam generator level bistables had been placed in a tripped condition due to the unqualified splice and resulting operability determination on the level indicato The tripped bistables provided one half the logic necessary for the reactor trip (the reactor trip is discussed below). If the unqualified splice had been properly identified and corrected prior to May 19, the Unit 2 reactor trip would have been prevente Based on a review of the incident, multiple interviews with IP personnel, QC personnel, their supervisors, and management personnel, 'nspectors concluded that equipment had been returned to service sith rutstanding operability questions, training deficiencies in the requirt.ments for accceptable EQ splices existed, training deficiencies on the requirements for conduct of maintenance existed, and that first level supervision by both Instrument Maintenance and Quality Control departments failed to provide for proper procedural actio _
This is identified as Violation 50-327, 328/88-28-01, Failure to Follow Procedure On May 19, at 2:14 pm, Unit 2 tripped from aaproximately 72% powe The trip was initiated by a steam flow to feed flow mismatch, coincident with low steam generator level. At the time of the event, level channel 2-LI-3-97 on steam generator 3 was in the tripped condition while maintenance work was in progress on the level transmitter's cable splic The low (25%) steam generator level trip bistable is part of this channe The steam flow greater than feed flow condition occurred when a turbine load runback was initiated, creating a feed flow transien Prior to the event the following initial conditions existed:
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Control rods were in manual
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Main feedwater pump A was in automatic control
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Main feedwater pump B was in manual control
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Heater Drain Tanks A and B were operating
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Centrifugal charging pump 2A-A was inoperable for SI-4 AFW pump 28-8 was inoperable for SI-29 Steam generator level instrument 2-LT-3-97 was inoperable, with all bistables tripped At approximately 1:50 an SR0 and an IM began adjustments to the #3 HDT level controllers. The turbine building ASOS had been told by the Turbine Building AVO that the #3 HDT level was high as noted by visual observation of the sight glas It was also noted that the controller was set at zer Using WR 8253109, the SR0 and IM proceeded to troubleshoot the
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problem in an attempt to reduce the level in the heater drain tank. This was being done by a series of small incremental adjustments to the controller followed by checks of the sight glass level, HDT discharge valve position, and HDT pump suction pressure. After the third or fourth iteration, the SR0 noted the HDT pumps began to cavitate, and a subsequent trip of the pumps occurre Concurrently, in the control room, the 80P operator noted fluctuations in the No. 3 HDT discharge flow and subsequent perturbations in the No. 3 HDT pump amperage Also, the hotwell level was increasing and flow was oscillatin The operator notified the lead operator and the ASOS. At approximately 2:08 pm, both No. 3 HDT pumps tripped (motor trip out alarm received). The 80P operator immediately started a reduction in turbine load using the governor valve positioner at the rate of 3% per minut Recognizing a further reduction was required, the 80P went to valve sosition limiter control and continued to reduce power. The lead operator 1ad placed the rods in automatic, and the rods stepped in on Tave/ Tref mismatc It was noted that SG 1 level was dropping. The operator tous manual control of feedwater regulator valve 2-FCV-3-35 (loop 1) and went to full open to regain level. The operator also o regulator valve to 20% for additional feedwater flow.pened the dropped Level bypass to 21% in the #1 SG. The A feedwater pump speed automatically reduced to follow turbine load. However, 8 main feedwater pump continued in manual control causing feedwater flows to be high. The operator took manual control of SG 2, 3, and 4 feedwater regulator valves and closed down on the valves to reduce feedwater flow to these loo)s. Level in the SGs continued to increase to 60%, at which point t1e regulator valves automatically closed as designed. This resulted in a steam flow /feedwater flow mismatch. The combination of the SG #3 low level trip signal mentioned previously and the steam flow / feed flow mismatch signal initiated a reactor tri The 00 announced the reactor trip and entered emergency operating procedure E- The ASOS referenced the procedure and had the U0s verify the appropriate actions. Following the reactor trip, pressurizer pressure decreased to 1970 psig and pressurizer level decreased to approximately 10%. A letdown isolation occurred as a result of the low pressurizer level. The pressurizer pressure and level decrease was caused by cooling of the RCS; however, the RCS and pressurizer cooldown limits specified in TS were not exceeded (Margin to saturation was approximately 25 degrees F). Tave in loop 1 decreased to approximately 500 degrees F ind to 521 degrees F in the other three loops. Loop I was lower because the AFW turbine-driven pump was being su) plied from this loop. In addition to the reactor trip, the cooldown was increased because the A MFPT isolation was leaking and steam dump valve FCV-1-104 intermittently opening until TAVE reached the 541 degrees F steam dump interlock. The rod bottom light for shutdown bank "0" rod E-13 did not illuminate; however, the operator verified that the rod position indicator was at zero. It was determined that the rod bottom light ha. ournt out and that the rod was in the correct position. The light bulb was subsequently replaced. Other anomalies noted were:
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The steam dump valve 2-FCV-1-104 intermittently opened without demand after TAVE recovered above the 541?F interlock poin !
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The A main feedwater pump steam valves leaked through causing approximately 2000 RPM with the stop valves close Loop 1 feedwater regulator valve failed to respond in automati Hotwell level decreased following the trip such that it appeared that ,
the vacuum drag valve was slow or did not respond to the transien None of the above anomalies affected the recovery from the reactor tri Recovery of the trip was initiated using ES-0.1, Reactor Trip Response, Units 1 and The following conclusions were reached in the licensee trip evaluation:
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The reactor tripped as a result of steam flow /feedwater flow mismatch coincident with low SG 1evel in loop 3. Low levi was a result of an RPS bistable being in the tripped condition becat.se of EQ concern Steam flow /feedwater flow mismatch was caused by a SG 1evel transient induced by a manual balance-of plant runback as a result of No. 3 HDT level controller manipulations and subsequent loss of No. 3 HDT pum Operator performance during the transient demonstrated a thorough knowledge of system performance and the ability to react to and control plant transient Safety-related equipment required to mitigate the transient operated as designed. SSPS logic was completed with reactor trip breakers opening and subsequent rod insertion. A feedwater isolation occurred on reactor trip-and low Tav Letdown isolated at 17% pressurizer
- level. No PORVs or safety valves lifted. The available AFW pumps started. The main turbine tripped on the reactor tri Operators aware of theinNo. the3 Main HeaterControl Room Drain Tank (U0, level B0P,and control 505) were not ASOS,ler manipulation Consequently, the operator did not know why the condensate
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fluctuations were occurring. The SR0 and IM considered previous approval of generic WR on the heater / drain controller acceptable for allowing work on the controller. They attempted to notify the UO of ongoing work on the morning of the even Sight glass level did not indicate actual HDT #3 leve Controller
- manipulation caused 2-LCV-6-106A&B to throttle close This resulted in a loss of suction to the No. 3 HDT pump and a pump trip. The licensee suspects that the sight glass was partially blocked.
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Investigation of controller versus tank level problem was improper or
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insufficient. The assumption was made that sight glass was indicative of actual level and that the controller was
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malfunctionin However no problems were indicated by the control
, room operators on previous shifts with No. 3 HDT pump / valve fluctuation SQM-2 section 11.3 does not appear to pcavide adequate clarification to notify operations of work activities on generic WRs. The procedure does not clearly require that the operators be notified each time the generic WR is being used to perform wor The inspectors also concluaed that the reactor trip would not have occurred if the SG #3 low level bistable had not been in the triaped position. The EQ problem associated with the level transmitter autt splice was initially identified on May 15, 1988. The failure to promptly initiate a CAOR in a timely manner led to a delay in correcting the deficiency until May 19. This reactor trip was therefore avoidabl The following recommendations were approved by PORC after review of the trip report:
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Verify and clean the sight glass on the HDT #3 prior te Mode 1 (WR 8785248)
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Recalibrate controllers on the No. 3 HD (WRS2533109)
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Verify 2-LCV-6-106 A&B stroke from the controller Also, verify 2-LCV-6-105 A&B do the sam (WRB253109)
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, Troubleshoot the vacuum drag valve to the condenser (2-LCV-2-9) ,
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2A main feedwater pump governor valve requires repair as the valve is j leaking. (WRs 8751234 also 8751232 & B751233 on B pump)
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No.1 SG main feedwater regulator valve failed. Troubleshoot this i valv (WR 8751212)
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2-FCV-1-104 inadvertently opened - check the valve controllers. (WR 8237736)
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No. 3 HDT motor trip out light did not come on for the "B" pum Investigate and repair this proble Repair 2-LCV-3-97 with the prop)r EQ splic Includes CAQR disposition (DNE/H005).
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Review SQM-2 to determine if further clarification is recuired for use of generic WRs. Revise this procedure if required anc provide a
SQN dispatch to describe plant policy.
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Determine by interviewing operators and system engineers if any sight glass on feedwater heaters, hotwell, and No. 7 HDT have f
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indications of potential blockage which might result in false level '
indication (WR 8253109)
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Research in plant versus control room communication for operations, necessity and emergency usages. Consider dedicated phone line to each horsesho Implement a formalized troubleshooting procedure outlining the guidelines on types of troubleshooting allowed and when it is allowe "
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Review this event with Operations personne The inspectors determined that the implementation of above recommendations would P adequate to resolve this issu On May 19, during the performance of SI-14.2, a cap was found missing from the 734 air lock pressure indicator drain and LC0 3.6.1.1 was entered at 2:35 pm. PRO 2-88-151 was generated. The cap was later re) laced and the ,
LCO exited. Subsequent P0RS evaluation of the missing cap cetermined that the cap was not a containment integrity boundar .
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On May 21, at H20 am, with the unit at 39% power, a control rod urgent failure alart vnunciated. The problem was traced to a power cabinet associated witu ontrol Banks B and D, and Shutdown Bank B. By 4:18 am, the IMs had changed out the solid state cards in the power cabinet and the i alarm was cleare On May 21, during draining operations of the Unit 1 RCS for SG and CVCS work, a level drop of 12 inches was observed in the pressurizer. The draining was stopped and the licensee initiated an investigation of the cause. NRC review of the RCS level perturbation was identified as shift !
followup item 5/21/88 1-1 (See paragraph 12).
On May 22, EGTS Train A was dcciared inoperable at 4:42 pm as a result of failing to pass the acceptance criterion of SI-17, Containment Shield Building Emergency Gas Treatment System Flo The heaters would not i function because an indicated low flow condition existed. Therefore' the SI acceptance criterion was not met. On May 23, the licensee identified that the power brecker to the Unit 2 Train A EGTS was tagged out on a Unit I hold orde Once the breaker was closed the heaters came on and i the EGTS functioned properly. A reperformance of SI-17 was then initiated and successfully complete On May 23, at 12:28 am, with the unit at approximately 70% power, the reactor tripped on a low RCS Flow signal on Loop #4. Loop #4 channel 2 flow transmitter FT-68-71B was in the tripped condition to support RCS loop flow calibrations per SI-246.e, #4 RCS loop. With the unit above the P-8, 35% permissive, a momentary trip on channel 3 flow transmitter FT-68-710 occurred, thereby making up the 2 out of 3 reactor trip logi , .
Subsequent review of the flow calibration procedure with the IMs involved revealed that the IMs had deviated from the procedure steps while valving the 71B transmitter in and out. After valving the transmitter out to begin the calibration, SI-246 required depressurizing the sense lines via the test tee fitting However, contrary to this step, the IMs depressurized the sense lines via the high side drain' valve on the bottom of the transmitter. By this deviation in procedure, water drained from the high side drain line. All three of the loop #4 RCS flow transmitters (FT-68,71A, 718, and 710) share a common sense line on the high sid Consecuently, when the 718 transmitter high side isolation valve was openec as the last step of returning the transmitter to normal, a void in the high side drain line caused a pressure drop in the common high side sense line to FT-68-710 and subsequently actuated bistable FS-68-71 The licensee duplicated the actions performed by the IMs and verified that bistable FS-68-71D once again actuated. It was reasoned that Channel 1 i (71A) did not trip because it had been calibrated earlier by a different IM crew and was adjusted to read 100% flow; whereas channel 3 (71D) had The not yet been calibrated and was reading 93% flow.inwas thevalved common backhiinh side sens was apparently st enough to drop Channel 3 (710) to the 90% trip setpoin The icensee performed the remaining RCS loop flow instrument calibrations prior to going above P- The failure of the IMs to depressurize flow trar.smitter FT-68-718 as specified in $1-246 is a violation of TS 6.8.1 and is identified as a second example of Violation 327,328/88-28-0 On May 23, at 12:09 pm, Unit 1 experienced a loss of decay heat removal capability when the operating RHR pump lost suction and was tripped by the operators. At the t'me of the event, the RCS was partially drained in preparation for plugging SG row 1 tubes. RHR pump 18 was recirculating from the RCS hot leg, through the RHR heat exchanger, and back to cold legs #2 and #3. With negligible decay heat present, RCS temperature was controlled by intermittently cutting in the component cooling system to the RHR heat exchanger. The operations staff decided to align the second heat exchanger in parallel with the first to reduce the frequency of having to cut in the CC An AVO was dispatched to open up the RHR heat exchanger cross-connect valves 1-FCV-74-36 and 1-FCV-74-37. The AVO opened 1-FCV-74-36, then mistakenly opened 1-FCV-74-34 instead of 1-FCV-74-37. Opening 1-FCV-74-34 aligned the RHR pump dis::harge to the RWST, which caused the RCS inventory to be reduced to the point where air was introduced into the pump suctio After stopping the RHR pump, the unit operator had the AVO shut 1-FCV-74-34 and open 1-FCV-63-1, the RWSi suction to the RHR system. This rapidly refilled the RCS to above a minimum level. Operators began venting the 1-A RHR pump to restore shutdown cooling. At 1:38 am the venting was co.apleted and the 1A RHR pump was started, terminat'ng the even The ENS (red phone) notification was made at 3:37 a.m. in
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accordance with 10 CFR 50.72.b. fii.8. This is considered a further example of violation 327,328/88-26-01 on configuration contro On May 24, at 8:02 am, Unit 1 received a trip signal on source range instrument NI-32. The reactor trip breakers were open, so no actual trip occurred. The licensee beliefed the source range trip signal to be the result of welding, similar to trip signals which have previously occurre On May 25, at 7:50 pm, the licensee identified that the 8 boric acid tank had a boron concentration of 19,077 ppm. The BAT boron concentration is used to verify com)liance with TS requirements on the BIT. The operators immediately enterec the action statement for LCO 3.5.4. This LC0 requires the BIT to be between 20,000 and 22,500 ppm boron or be in Mode 3 and borated to cold conditions within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. The boric acid evaporator was used to raise the BAT and BIT boron concentration to within the BIT TS limits (20,023 ppm) and LC0 3.5.4 was exited at 10:21 pm. No notifications were made and no plant transients occurre On May 26, at 10:15 pm, aower was lost to the A Common Board, a non-safety related electrical boarc. The loss of power resulted while the alternate feeder breaker was being racked-in, inadvertently opening the normal
feeder breaker. Normal lighting in the control room and the turbine buf1 ding were lost for approximately 30 minutes. Emergency lighting systems functioned as expected and the operators responded adequately to the even . Resolution of Dreviously Identified Mode Change Items
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The inspectors verified adequate licensee resolution of the following items which had been previously identified in Inspection Report 88-26 as requiring resolution prior to specified Mode changes:
j UpperHeadInjectionSystemOperability As a result of UHI level indication system problems docu'inted in Inspection Report 327,328/88-26, demonstration of full UHI operability was required prior to 1900 psi in Mode Prior to entry into Mode 3 the licensee repaired the packing leaks
that had allowed the A train UHI level switch reference legs to drain down, and recalibrated the switches to verify proper operation. The licensee also backfilled the sense lines to ensure that no blockage of the sense lines was present. The inspectors and the licensee
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monitored the UHI hydraulic system during this inspection period and no further loss of hydraulic pressure has been note '
As a result of this event the licensee instituted controls to ensure that the UHI system and at:endant instrumentation remained operationa These included:
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1) A systems engineer will accompany AU0s or instrument maintenance personnel whenever drain, sample, isolation or instrument valves are manipulated in the UHI system. Each of the recent events coincided with work perfo med by those groups. Having a systems engineer observing future work provides some assurance that the manipulations will be performed properl ) Procedural changes will be implemented t' require routine reference leg f'ils and work procedures will be changed to require fills following maintenance on panel valves and drain line ) Hydraulic accumulator pressure readings will be added to the unit operators shift log to assure that the pressures on the hydraulic accumulators are not being slowly depressurize Previously, this pressure was not monitored; therefore the licensee was not sure that the reduction in hydraulic pressure was due to a switch actuation rather than a slow lea The licensee corrective actions appeared to adequately resolve the issu b. RCS RTO Post Maintenance Testing Licensee justification for not reperforming SI-488 as a post maintenance 68-0065 was test after replacement identified of wide as Shift followup rang item 4 /24/88-1-1e RCS and was hot leg RTO resolved prior to entering Mode 3 (See paragraph 12).
c. Loose Parts Analysis of Missing SG Tube Plug The insaector reviewed the TVA core component o erational safety evaluat' on No. SQ-CCOSE-12 Revision 1, dated Ma 5, 1988. This evaluation was conducted as a result of discover ng that one of the mechanical SG tube plugs that was installed in 1986 in tube 1-61 of l SG #1 was missing. The CCOSE was the TVA approval of tha Westinghouse safety evaluation check list (SECL)-88-251 Revision 2 dated May 4, 1988. The conclusions of this analysis indicated that the loose part did not adversely affect the structural integrity of SG components and did not impact operability of the RCS or its i components. Therefore, the analysis concluded that operations with
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the loose part did not involve an unreviewed safety question per
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10 CFR 50.5 The issue was resolved for Mode change, in that the ins)ector considered the licensee evaluation to be thorough and comp ete. NRC ,
OSP HQ staff was requested to also evaluate the licensee analysis and i determined that the evaluation was adequate. No issues were '
identifie d. Configuration Control l
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i Inspection Report 327,328/88-26 cited the following examples of components not being in the positions specified in the system status file:
1) On April 30, during fill of the RWST, a leak occurred through a temporary pressure gauge on the inirt to boric acid filter Root valve 2-62-392A was shut but had also leaked throug Closure of this root valve had not been entered into the configuration log, as required. In addition, the IMs had operated a valve which was under the control of operations per G0I-6, and had left an incomplete job without hanging tags as required by procedures AI-58 and AI-3. The work request for the job being performed had identified the affected equipment as non-CSSC, and did not specifically state that root valve 2-62-392A was invche ) On May 1 UHI surge tank sample point valves87-543 and 87-542 werepositioneootherthannormaltosupporttheinstallationof a temporary pressure indicato No configuration log entry was
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mad ) On May 1, two individuals signed the 501-72.1 verification that valve FCV-72-504 was locked close The valve was closed but was not locke ,
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4) On May 4, a licansee QA audit foend that the CST B supply to AFW, Valve 0-2-505, was shut rather than locked open as required by the 50I checklist and indicated in the system status lo Licensee evaluatiin of the incident revealed that on May 25, a configuration log entry was made that this valve was in the locked closed position. On May 25, the entry was cleared and return to normal was documented. On May 28, the chemistry lab requested that valves 2-503, 505, and 507 be closed, and that ,
valve 2-506 be opene A configuration control log entry was not made per AI-58 prior to changing the valve 30sitions. After the valves were positioned, the operator cons:dered making a configuration log entry but didn't because there was no section in the log for the condensate syste At the May 4, exit interview for inspection report 327,328/88-26, the licensee was directed to demonstrate prior to entering Mode 4 that the identified configuration control problems listed above did not compromise safe plant operation. Prior to entering mode 4, corrective measures were taken by the licensee and were presented to the inspection staff by the Operations Manager, the Operations Supervisor, and a P0RS superviso P0RS evaluations of the miscon-figuration events had not been completed as of that tim These corrective measures completed prior to entering Mode 4 included:
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The licensee revt:rified all valve alignments performed by the two AV0s who improperly signed the po;ition verification of
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valve 72 504 as locked close No additional errors were identifie A separate walkdown was performed by the licensee to verify that locks were installed on all valves required to be locked in positio No misconfigurations were identifie An instrument availability checklist was performed, per the G0 No misconfigurations were identifie Training letters on configuration control problems were issued to both operations personnel and to instrument mechanic The inspectors considered these corrective actions taken by the licensee adequate to support the mode chang Subsequent to NRC inspection 327 328/88-26, and subsequent to entry into Mode 4 on May 7, the following additional examples of
, configuration control problems were identified:
1) the CCS return from BAE B was found by the licensee OnApril27}gnedwhileperformingSI-32,ComponentCoolingWater to be misa1 Valves (Position Verification) Units 1 and SI-32 required valve 2-HCV-70-661, the CCS return from bnric acid evaporator B, to be 21 i 1/8 turns from full open and sealed in the required position. The valve was found in the fully open position, with the seal removed. The valve was accurately refleci.ed on the status board as fully open, although the fully opened position was not allowed by the SI. The most recent performance of SI-32 on March 3, 1988 indicated that the SI was performed and completed with no deficiencies. The P0RS investigation determined that the person who manipulated the valve did not understand that the flow balance of CCS could be adversely affected by a full open position on the valve, and that throttled valves, by procedure, should only be in the properly throttled position or fully closed for maintenance. In investigating this event, the licensee also found that all evidence of configuration changes had been Erased from the marked-up status board. When the misalignment was discovered,
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the valve was realigned, and PRO 2-88-131 was issue ) On May 17, valves 2-FCV-67-680 and 0-67-FCV-5518 were found out of position during the performance of SI-682, ERCW Flow Balanc Valve 680 was found approximately five turns off-normal and valve 551B was approximately two turns off norma These issues were documented in PRO 2-88-148 and PRO 2-88-14 The cause of the errors in the throttled positions were attributed to
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dit~ferences between valve throttling practices of different individuals, and the lack of a reference point on the valve wheel to aid in counting revolutions. The valves were returned to the correct positions by the operator \
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i 3) The leaking valves in the HUT valve gallery on May 17 (See paragraph :.0) resulted from beginning a flow transfer evolution :
without first establishing the proper valve alignment as !
required by - AI-58 section 4. A and AI-30 Section 10, in that valve 2-FCV-62-951 was misconfigured. Additionally, the
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position indicator on the valve was missing. Finally, the reach rod to the misconfigured valve was bound, giving the-AVO the impression the valve was.open when it was actually close ) The leakage in the HUT valve gallery on May 18 resu?ted from the radioactive waste system status board improperly indicating the position of valve 2-62-945 as open when the valve was actually close ) The loss of Unit 1 RHR suction on May 23 resulted from an AVO mistakenly opening the wrong valve and therefore aligning the RHR pump discharge to the RWST. The AVO had written an
incorrect valve number on his han Prior to release of Hold Point #5 (75% power), the licensee was required to present to the NRC an evaluation of the identified configuration control problems, along with planned corrective actions. P0RS representatives and operations management met with the inspectors on May 26. Based on the root cause evaluation oresented by the licensee and a review of the configuration control incidents to date, the inspector identified the following apparent problem areas:
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Personnel failing to follow procedures
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Inadequate reviews for impacts on configuration control prior to performing work or making valve manipulations
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Not restoring the system to a safe condition if desired response was not obtained after manipulating a component
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Problems with communications within Operations, and in the interface between operations and maintenance regarding configuration control process
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Lack of understanding by personnel of the requirements for proper throttling of valves
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Mechanical problems such as missing position indicators and defective reach rods
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The use of certain exceptions to configuration control and clearance requirements, such as "Human Hold Orders"
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The level of complexity of the AI-58 procedure
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Lack of adequate independent review of status boards to assure accuracy and completeness
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Lack of aermanent records or traceability in the status board system, 'ncluding erasure of status records
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The lack of duplicate control room configuration log entries under affected systems for items configured on the status board
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The lack of operator aids for equipment with flow paths etc. affected by out of position components
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The practice of making configuration log entries after the component manipulations had already been made The licensee identified the following actions to correct the apparent weaknesses in the configuration control program:
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AI-30, Nuclear Plant Conduct of Operations would be revised to include the use of Manipulation Request index cards as an operator aid. When verbally directed to change the status of plant equipnent, the operator will enter the instructions on this card prior to verbally re verification by the supervisor. peating This card thewillinstruction for not be retained as a QA recor AI-58 would be revised to require that prior to manipulation of any valves in Appendix A , Appendix D or in the RCA that are not covered in an approved plant instruction, an AI-58 A)pendix B configuration control form shall be filled out and ;he ASOS shall determine if configuration log entry is required. If configuration log entry is specified as not being required, the SR0 will document the justificatio AI-30 was revised on May 26, 1988 to require that an AVO '
assigned to make local valve manipulations shall contact the Unit operator or ASOS prior to making the manipulation, to verify that conditions have not changed and that the operator is prepared for the manipulatio AI-30 was revised on May 26, 1988 to require that if desired results are not obtained durinc plant manipulations, the plant shall be placed in safe condit< ons and the operator called to :
discuss the situatio AI-58 would be revised to replace the status board system with a configuration log. Configuration logs for the radwaste and COWE r
. systems will be fully maintained in accordance with AI-58. When !
radwaste system :onfiguration log entries affect systems tracked in the control room configuration log, duplicate Appendix B L
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sheets will be placed in each locatio Prior to full implementation of the revised system, the SR0 will be required to independently review all radwaste configuration changes with the AVO prior to the changes being performe Operator aids would be used as required to assure that equipment or systems affected by off-normal components will not be inadvertently operate SI performance crews would be trained on proper valve throttling method Provisions will be implenented to estah11sh reference points on the handwheels of throttle valve A revision of AI-3 was initiated to clarify and restrict exceptions to requirements for clearances. The revised guidance was issued in a night order dated May 24, 198 A preventive maintenance program would be established for extension stem operator Operations management and QA personnel would be on shift to verify proper implementation of the new configuration control requirements, beginning May 27 and continuing for at least ten days and ur;til the effectiveness of the new program has been establishe The NRC considered that these proposed corrective actions adequately addressed each of the configuration control incidents and the general areas of weaknesses which were identified. The inspectors will continue to monitor the effectiveness of the corrective actions through the resident inspector coverag The inspector attended a training session on the new 3rogram, and training sessions on several of the individual inc' dents of configuration control problems. These training sessions were conducte.1 at the shift turnovers and clearly and thoroughly addressedtheprocedurechangesandlessonslearne The examples of loss of configuration control identified during this inspection period are identified as further examples of violation 327,328/S8-26-0 e. Condensate System Waterhammer Event On April J5, waterhammer caused damage to numerous pipe supports in the Condensate Syste An investigation by the licensee determined that failure to allow enough time for system filling and stabiliza-tion using a throttled hotwell pump prior to starting a second, unthrottled, pump caused the event. When the second pump was started a large mass of water was accelerated through long sections of piping
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that had drained to the hotwell and impacted the stationary water in the upper horizontal headers to the condensate demineralizer The root causes were determined to be personnel error and inadequate
)rocedures. 50I 2.1 and 3.1, Section G, Startup and Shutdown of a lotwell or Condensate Booster Pump, did not clearly caution operators concerning the need for system stabilization or provide system parameters to be monitored or verified prior to starting the second hotwell pump. A possible contributor to the event, or the extent of damage, was an improperly positioned downstream valve 2-FCV-2-35A which had failed closed when its positioner was damaged by the high vibratio Corrective actions included completed or planned inspection and repair of system pipe supports, support attachment welds and piping welds; DNE evaluation of critical system valves and valve operator design; increased preventive maintenance on secondary plant equipment; revisions to 501 2.1. and 3.1 for precautions and specific system stabilization criteria and instruction of operating crews concerning the event and actions to prevent recurrenc The licensee investigation, evaluations and corrective actions appear to be appropriate. Corrective actions for system operability were taken prfor to plant mode change. This issue is resolve . NRC Inspector Follow-up Items, Unresolved Items, Violations, Bulletins (Closed) URI 327,328/88-26-02: Definition of "At-The-Controls" for Licensed Operator The licensee was in the process of revising AI-?,0, Nuclear Plant Conduct of Operations, to better define the areas that must be manned by the license operator during all modes of plant operatio The change wa necessary to ensure that the recommendations of Regulatory Guide 1.114, Guidance on Being at the Controls of Nuclear Power Plant, are correctly implemented. Reg Guide 1.114 requires that the operator at the controls be in an area where continuous attention can be given to reactor operating conditions and where direct access to the reactor controls can be maintaine The Regulatory Guide lows momentary absence from this area in the event of an emergency affecung the safery of operation Revision 15 of AI-30 did not restrict absence from the "At the Controls" area to just emergency conditions and allowed the operator to leave the area as operating conditions allowed in order to enter the back panel and other areas that would restrict his ability to continuously monitor operating condition A Night order issued May 5,1988 provided sufficient controls to ensure the requirements of Reg Guide 1.114 would be met. Al-30 was revised on May 7,1988 to fully implement the guidelines of Reg Guide 1.114. This item is closed.
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12. Shift Inspector Followup Issues Issue Number Description Resolution 2/27/88-2-1 COPS Enable Setpoint Resolve Pressure
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Question transmitter was calibrated and alarm setpoint and i actuation verifie /28/88-1-1 SIS Check Valve Leakage Resolved. During the SG tube leak repair outage TVA repaired several check valve test valves which they believed to be the cause of the indicated leakage. The inspec-tors have monitored L leakage testing during the heat up and found no problem /8/88-1-1 Determine whether drawing Resolve The inspec-review process implemented tor reviewed the by SQEP 30 and SQEP 42 is engineering review ~
adequat process to control *
drawing changes and determined that an adequate engineering review is being s conducte ~
3/12/88-2-3 Evaluate PRO 2-88-81 Resolve Licensee dealing with no PMT being identified and performed after work on corrected. (See May 11 2-FCV-67-6 entry in paragraph 9)
3/25/88-2-2 Resolution of NI-31 Source Resolved. The cable Range Detector problem and detector were repaired and functioned properly !
during startu /11/88-1-1 Review of April 11 Event Resolved. This was for Violations of RWP and e termined to be an RCI-10 or 14 isolated occuranc (See paragraph 6)
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4/15/88-2-1 Revier Cause and Events Resolve Associated with Failure of Pipe Supports and Hangers on
the Condensate System 4/24/88-1-1 Follow-up on whether SI-488 is Resolve Work Required for testing request and replacement RTO manufactor data reviewed by NR /25/88-1-1 Pressurizer relief tailpipe Resolve Evaluated hanger analysis by NRC staf /19/88-1-1 Review licensee report on Resolve The-May 19 Reactor Trip inspector reviewed trip report prior to unitrestart(see paragraph 9)
5/21/88-1-1 Review Unit 1 RCS draindown Open. Currently under event of 5/21/88 NRC revie . List of Abbreviations AI -
Administrative Instruction AFW -
Auxiliary feedwater AVO -
Auxiliary Unit Operator A0I -
Abnormal Operating Instruction ASME - American Society of Mechanical Engineers ASOS - Auxiliary Shift Operating Supervisor AUX -
Auxiliary BAE -
Boric Acid Evaporator BAT -
Boric Acid Tank 8IT -
BoronInjectionTank BOP -
Balance of Plant C&A -
Control and Auxiliary Buildings CAM -
Continuous Air Monitor CAQR- Conditions Adverse to Quality Report CCP -
Centrifugal Charging Pump CCOSE- Core Component Operational Safety Evaluation CCS -
Component Cooling System CCTS - Corporate Commitment Tracking System CDWE - Condensate Demieralizer Waste Evaporator COPS - Cold Overpressure Protection System CRDM Control Rod Drive Mechanism CS -
Containment Spray CSSC - Critical, Structures, Systems, and Components CST -
Condensate Storage Tank CVCS - Chemical and Volume Control System DC -
Direct Current
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DCN -
Design Change Notice DI -
Deionized Water DN8 -
Departure from Nucleate Bioling DNE
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Division of Nuclear Engineering ECCS - Emergency Core Cooling System EDG -
Emergency Diesel Generator EGTS - ' Emergency Gas Treatment System ENS -
Emergency Notification System EQ
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Environmental Qualification ERCW - Essential Raw Cooling Water ESF - En ineered Safety feature ESFAS- En ineered Safety Feature Actuation Signal-FCR - Fi 1d Change Request FSAR - Final Safety Analysis Report G0I - General Operating Instruction
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Heater Drain Tank H0 -
Hold Order HP -
Health Physics HQ
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-Headquarters HVAC - Heating, Ventilation, and Air Conditioning HUT -
Holdup Tank
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Instruction Change Form IDI -
IE - IntegratedDesio$nInspection Inspection and nforcement IE8 -
Inspection and Enforcement Bulletin IM -
Instrument Maintenance
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IMI -
Instrument Maintenance Instruction IRPI - Individual Rod Position Indication XV
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Kilovolt LER -
Licensee Event Report LCO -
Limiting Condition for Operation LCV -
Level Control Valve LOCA - Loss of Coolant Accident MDAFP- Motor Driven Auxiliary Feedwater Pump-MFPT - Main Feed Pump Turbine MI -
Maintenance Instruction
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Microbiological 1y Induced Corrosion H0 VATS - Motor Operated Valve Analysis and Testing System MSIV - Main Steam Isolation Valve NEP - Nuclear Engineering Procedures
, NRC - Nuclear Regulatory Commission ODCM - Offsite Dose Calculation Model OSP -
Office of Special Projects PCM -
Percent Hilli-rho PD -
Positive Displacement PM -
Preventive Maintenance
, PMT - Post Modification Test PPM - Parts Per Million PORC - Plant Operations Review Committee PORV - Power Operated Relief Valve
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P0RS - Plant Operation Review Staff ;
PRO -
Potentially Reportable Occurrence i PRT -
Pressurizer Relief Tank PZR -
Pressurizer QA
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Quality Assurance i QC
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Quality Control RARC - Radiological Assessment Review Committee RCS -
Reactor Coolant Pump RHR -
Reactor Operator RTO -
Resistance Thermal Devices i RTI -
Restart Test Instruction RWP - Radiation Work Permit RWST - Reactor Water Storage Tank SECL Safety Evaluation Check List SER -
Safety Evaluaticn Report SG -
Surveillance Instruction SIS -
SafetyInjectionSystem i SMI -
Special Maintenance Instruction 501 -
System Operating Instructions SOS -
Shift 0)erating Supervisor SQM
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Sequoya1 Standard Practice Maintenance SRO -
Senior Reactor Operator '
STA -
Shift Technical Advisor STI - Special Test Instruction TACF - Temporary Alteration Control Room TAVE - Average Reactor Coolant System Temperature ,
T0AFP - Turbine Driven Auxiliary Feedwater Pump >
TH0T - Hot Leg Reactor Coolant System Temperature l TS -
Technical Specifications TSC -
TVA -
Tennessee Valley Authority UHI -
UpperHeadInjection ,
URI -
Unresolved Item j VO -
Unit Operator USQD- Unresolved Safety Question Determination VCT -
Volume Control Tank i
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WBC -
Whole Body Count WCC -
Work Control Center WO -
Work Order .
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Work Plan WR -
Work Request ,
14. Exit Interview The inspection scope and findings were summarized on May 20 and on June 8, 1988, with those persons indicated in paragraph 1. The Startup Manager described the areas inspected and discussed in detail the inspection findings listed below. The licensee acknowledged the inspection findings
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and did not identify as proprietary any of the material reviewed by the inspectors during the inspectio The following violation was identified:
327,328/88-28-01: Failure to follow procedures (paragraph 9).
' Additional examples of the fol_ lowing previous violation were identified:
327,328/88-P6-01: Failure to implement procedures associated with configuration control (paragraphs 9 and 10).
NOTE: A list of abbreviations used in this report is contained in paragraph 13.
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