IR 05000327/1988026

Insp Repts 50-327/88-26 & 50-328/88-26 on 880403-0504. Violations Noted.Major Areas Inspected:Control Room Observation & Operational Safety Verification,Including Operations Performance,Sys Lineups & Radiation Protection

ML20195J679
Person / Time
Site:	Sequoyah
Issue date:	06/17/1988
From:	Branch M, Jenison K, Long A NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20195J655	List: IR 05000327/1988026 ML20195J649 ML20195J672
References
50-327-88-26, 50-328-88-26, NUDOCS 8806290192
Download: ML20195J679 (40)

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UNITED STATES

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+ Iog NUCLEAH REGULATORY COMMISSION

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• n$e 101 MARIETTA STREET. N.W., SUITE 2000 i o ATLANTA, GEORGIA 30323  !

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Report Nos.: 50-327/88-26, 50-328/88-26 Licensee: Tennessee Valley Authority 6N 38A Lookout Place 1101 Market Square Chattanooga, TN 37402-2801 Docket Nos.: 50-327 and 50-328 License Nos.: DPR-77 and DPR-79

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Facility Name: Sequoyah Units 1 and 2 Inspection Conducted: April 3, 1988 thru May 4, 1988 Project Engineer: b- % @

A. Long, Pro' ject Engineer Date Signed Shift Inspectors: P. Harmon, Shift Inspector G. Humphrey, Shift Inspector K. Ivey, Shift Inspector A. Long, Shift Inspector D. Loveless, Shift Inspector i W. Poertner, Shift Inspector  ;

Shift Manager Approval: M- or 61? 7?

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K. J so Shift Manager) Date Signed Y ' , 6 { ') . R T ,.

M. Branci, Shift Manager Date Signed

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8806290192 880617 POR ADOCK 05000327 l

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Summary

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Scope: This announced inspection involved onshift and onsite inspections by the NRC Restart Task Force. The majority of inspection effort was expended in the areas of control room observation and operational safety verification including operations performance, system lineups, radiation protection, and safeguards and housekeeping inspections. Other areas inspected included maintenance observatiors, review of previous inspection findings, follow-up of events, review of 31censee identified items, and review of inspector follow-up items. During this period there was extended control room and plant activity coverage by NRC inspectors and managers.

Results: One Violation was identified:

327,328/86-26-01: Failure to Implement Procedures Associated with Configuration Control, Five Examples (Paragraph 11.H)

Two Unresolved Items were identified:

327,328/88-26-02: Resolution of Operator Work Areas and Definition of "At the Controls" (Paragraph 3)

327,328/88-26-03: Resolution of RCS leak Rate Determination Process (Paragraph 10)

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REPORT DETAILS Persons contacted Licensee Employees H. Abercrombie, Site Director DJ. Anthony, Operations Group Supervisor OR. Beecken, Maintenance Superintendent J. Bynum, Assistant Manager of Nuclear Power M. Cooper, Compliance Licensing Supervisor H. Elkins, Instrument Maintenance Group Manager R. Fortenberry, Technical Support Supervisor J. Hamilton, Quality Engineering Manager

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M. Harding, Licensing Group Manager CJ. La Point, Deputy Site Director L. Martin, Site Quality Manager R. Olson, Modifications OJ. Patrick, Operations Group Supervisor R. Pierce, Mechanical Maintenance Supervisor R. Prince, Radiological Control Superintendent OR. Rogers, Plant Operations Review Staff M. Skarzinski, Electrical Maintenance Supervisor E. Sliger, Manager of Projects OS. Smith, Plant Manager J. Sullivan, Plant Operations Review Staff Supervisor 0B. Willis, Operations and Engineering Superintendent NRC Employees GF. McCoy, NRC Startup Manager GP. Harmon, NRC Inspector

• A. Long, NRC Inspector 0 Attended exit interview I Exit Interview The inspection scope and finaings were summarized on May 4, 1988, with those persons indicated in paragraph The Startup Manager described the areas inspected and discussed in detail the inspection findings.

, The following new items were identified:

Violation 327,328/88-26-01: Failure to Implement Procedures Associated with Configuration Control, Five Examples (Paragraph 11)

Unresolved Item 327,328/88-26-02: Resolution of Definition of "At the Controls. (Paragraph 3)

Unresolved Item 327,328/88-26-03: Resolution of RCS Leak Rate Determination Process. (Paragraph 10)

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The licensee acknowledged the inspection findings and did not identify as proprietary any of the material reviewed by the inspectors during the inspectio The following issues were identified at the Exit Interview as requiring resolution prior to changing Modes:

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Configuration Control - Prior to Mode 4 (Paragraph 11)

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RTD Issue - Prior to Mode 3 (Paragraph 8)

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UHI operability - Prior to Mode 3 (Paragraph 10)

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Loose Parts Analysis - Prior to Mode 2 (Paragraph 10)

Subsequent to the period of the inspection, the above items were resolved prior to entry into the specified Modes. The resolutions will be documented in Inspection Report 327,328/88-2 NOTE: A list of abbreviations used in this report is contained in paragraph 13, control Room Observation (71715)

The inspectors observed control room activities and plant activities directed from the control room on a routine basis during the period of this report. Coverage was reduced during the mode-5 period covered by this inspection to one shift inspector per shift supported by other OSP management, as necessary. Approximately fifty percent of the shift inspectors' time was spent conducting observations in the control roo Control Room Activities Including Conduct of Operations The inspectors reviewed control room activities to verify that operators were attentive and responsive to plant parameters and conditions; that the operators remained in their designated areas; and that they were attentive to plant operations, alarms and )

statu The inspector observed at least one instance where, with the Unit in Mode 5, a Unit 2 operator momentarily left the horseshoe area of the control room to go to one of the back panels, leaving no licensed operator in the horseshoe. This practice was allowed by licensee procedures while in Modes 5 and 6. Resolution of which areas licensed operators may frequent and still be considered to be "at the controls" was identified as an UNR 88-26-0 The inspectors also observed operator activities to ensure that they employed communication, terminology and nomenclature that was clear and f ormal. Operators observed prior to being discharged from their watch standing duties performed proper reliefs and ,

utilized valid communication l

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. Control Room Manning During the inspection period, the licensee was operating six full operatienal shifts in the control roo Some control room manning changes were expected in the near future in order to supply

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approximately four ROs to fill SRO training vacancies. These SRO candidates were expected to take SRO license examinations in the latter part of 198 The inspectors reviewed control room manning and determined that Technical Specification requirements were me As discussed above, ,

"operator at the control" issues will be addressed as UNR 88-26-0 The licensee had operated with an administrative control room staffing level of one additional SRO above the TS required leve In addition several of the shifts have an additional RO assigne During ascension to power the licensee will have on-shift operations assistants who hold SRO licenses. These assistants will ensure that the shift supervisor is kept informed of plant activitie The inspectors found the control room noise level and working conditions to be acceptable. The inspectors observed no horseplay and no radios or other non-job related material in the control room, and no distractive instances were identifie A professional ;

atmosphere was maintained in the control room. Operator compliance with regulatory and TVA administrative guidelines were reviewed, and no deficiencies were identifie In addition, the control room appeared to be clean, uncluttered, and well organize Special controls were established to limit personnel both in the control room inner area and in the control room areas behind the back panel ' Routine plant Activities Conducted in or Near the Control Room  ;

The inspectors observed activities which required the attention and l

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direction of control room personnel. The inspectors observed that ,

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necessary plant administrative and technical activities conducted in or near the control room were conducted i a manner that did not '

compromise the attentiveness of the operato.2 at the controls. The .

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licensee had established a shift supervisor office in the control room area in which the bulk of the administrative activities, including the authorized issuance of keys, took plac In addition the licensee had established hold order, work request, surveillance  ;

instruction, and modification matrix functions to release the  :

licensed operators from the bulk of the technical activities that  !

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could impact the performance of their dutie These matrixed activities were transformed into the Work Control Center located in i the Technical Support Center space f Activities in the Work Control Center .ere observed on several *

I instances in order to ensure that the licensed operators were released from administrative burdens and that they maintained

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control of safety related activities. These activities appeared to

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be effective and no deficiencies were identifie Control Room Alarns and Operator Response to Alarms The inspectors observed that control room evaluations were performed utilizing approved plant procedures, and that control room alarms were responded to promptly and with adequate attention

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by the operator to the alarm indications. Control room operators appeared to believe the alarm Jndication Several of the events described in other sections of this report were observed in the control room by the shift inspectors. The operator responses appeared to be adequate and no alarms were identified by the inspectors that were either ignored by the ,

operators or-timed-ou Fire Brigade The inspectors reviewed fire brigade manning and certain personnel qualifications on a routine basis, as part of the shift inapectio Both manning and qualifications were found to meet TS requirement Shift Briefing / Shift Turnover and Shift Relief The inspectors observed that reactor operators completed turnover checklists, conducted control panel and significant alarm walkdown reviews, and significant maintenance and surveillance reviews prior to relie Much of the maintenance discussed in paragraph 9 of this report was discussed during shift briefings and/or relie Operators seemed to understand the impact of the maintenance tasks 3 on other plant activitie The observed shift briefings / shift turnovers and shift reliefs also included detailed discussions of equipment surveillance requirements and the impact that those surveillance requirements would have on other plant activities and on plant restar The inspectors observed that suf ficient information was transf erred on plant status, operating status and/or events and abnormal system i alignments to ensure the safe operation of the unit. Assistant SOS j relief was conducted in the control room and inf ormation appeared i to be adequately transferre Assistant SOS were observed reviewing shift logbooks prior to relie Shift briefings were conducted by the offgoing SOS. 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, significant surveillance testing or maintenance activities, and l unusual plant condition Of the several operator watch reliefs observed, the inspectors i found no recurrences of the turnover difficulties encountered j

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previously (reference NRC inspection report 327, 328/88-20). It

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appears that the corrective actions instituted by the licensee to improve watch relief turnovers have been effective and that the difficulties encountered were isolated instance Shift Logs, Records, and Turnover Status Lists As a result of a recent pump alignment issue (reference NRC inspection report 327,328/88-20), the licensee had instituted several corrective actions to strengthen logkeeping activities in the control room. The inspectors reviewed the SOS, assistant SOS, shift technical advisor, and reactor operator logs and determined that the improvements in logkeeping were effective and that logs were completed in accordance with administrative requirement The inspectors reviewed the above logs to ensure that entries were legible; errors were corrected, initialed and dated; logbook entries adequately reflected plant status; significant operational ,

events and/or unusual parameters were recorded; and entries into or !

exits from TS Limiting Conditions for Operation were recorded promptl Turnover status checklists for R0s contained sufficient required information and indicated plant status parameters, system i alignments, and abnormalitie Log keeping weaknesses identified '

in NRC inspection report 327,328/88-20 appeared to have been '

adequately corrected.

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Additionally, the following logs were reviewed in detail:

Night order Log System Status Log Key Log ,

Temporary Alteration Control (TACP) Loa

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No violations or deviations were identified during iae reviews of the above logs.

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The configuration log was also reviewed, in conjunction with an overall review of control of plant configuration status. Several instances were identified where configuration log entries were not made as required by procedures (See paragraph ll.h).

The licensee is currently considering improvements in the '

accountability of station keys. Any changes in plant key control will be reviewed by the inspecto The licensee has reviewed the use of the TACF log as a first step

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towards the reduction of the total number of TACFs outstanding (See paragraph 8). Control Room Recorder / Strip Charts and Log Sheets l The inspector observed operators check, install, mark, file, and route for review, recorder and strip charts in accordance with the established plant processes. There were no events that caused the

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immediate control room review of recorder / strip chart peaks during this inspection peliod. However, there were two events (described in paragraph 10 of this report) that required the use of control room graphs in ordar to evaluate the even Control room and plant equipment logsheets were found to be complete and legible; parameter limits were specified; and out-of-specificacton parameters were marked and reviewed during the approval proces No violations or deviations are identified. Manacement Activities TVA management activities were reviewed on a daily basis by the NRC shift inspectors, shift managers, and Startup Manage Daily Control of Plant Activities by Management The licensee conducted a series of plant meetings in the War Room during each day to control plant activitie These meetings were observed by NRC managers on a daily basis and were found to be adequate to involve upper level TVA management in the day-to-day activitie Several conclusions were drawn by the NRC inspectors and managers with respect to the efficiency of these TVA management r;.eetings :

First, most problems were attacked by providing immediate action to resolve the problem, but the actions did not always appear to be developed based on experience and facts, and did not normally include contingency plans of actions that would be taken if the desired results were not obtaine An example of this problem was the modifications performed on the safety valve loop seals and the testing of the safety valves, as described in paragraph 1 A second observation was that, in some cases, there did not appear to be a single assigned individual to coordinate the interface of all disciplines involved in problem resolutio One example of this observation was identified with the work performed on main feedwater pump discharge valve 2-FCV-3-81 (see inspection report 327,328/88-22), where the licensee failed to assure that the replacement actuator was functioning properly before it was installed, requiring it to be taken down and repaire A second and third example of this observation involved the resolution of problems associated with accumuletor #3 leakage (see inspection report 327,328/88-17) and pressurizer loop seals (paragraph 10.A)

A third observation was that on several occasions decisions were made based on engineering judgement, without adequate in depth engineering analysis of the proble The consequences of this approach were demonstrated by the attempts to resolve

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the pressurizer safety valve loop seal problems (paragraph

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10). Also, there appeared to be a reluctance to contact other utility organizations regarding how they resolved similar problem The above observations did not constitute a violation of any regulatory requirements or deviation from any commitment In addition, the above described management processes did not affect the operability of equipment needed to support the safe condition (mode 5 operations) of Unit 2. The activities did, however, indicate the need to improve the efficiency and responsiveness of the TVA Department of Engindering and Department of Construction

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(modifications) organizations and improve the level of support

. supplied to Sequoyah operations by these TVA organization These examples also indicated that some of the decisions made were heavily startup schedule biase '

These observations were specifically discussed with plant

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management during the-exit meeting on May 4, 1388. 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 plan More first line supervisor involvement in the field has also been observe Management Response To plant Activities and Events In general, management response to those plant activities and events that occurred during this inspection period was quick and effectiv However, as identified in paragraph 4a above, the support function of DNE and DNC did not seem to be well coordinated and the outage scheduling function seemed to be a dominating factor in problem resolution.

2 Site Ouality Assurance Activities (OA) in Succort of Ooerations The inspector reviewed the QA activities which took place during this inspection period and met with site QA management. The activities reviewed involved QA surveillances, audits and maintenance participatio The QA organization appeared to be managed by a strong site manager and supported by several dedicated subordinate manager Those surveillances and audits reviewed by the inspector and discussed with QA management were positive and supportiv When questioned, the site QA management staff responded that their findings were well received by the plant management staf . Chronoloav of Unit 2 Plant Op3 rations At the beginning of the NRC Restart Task Force shift coverage, Unit 2 was in Mode 5 (Cold Shutdown) with three reactor coolant pumps operating

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and the 2A-A residual heat removal pump in service. The reactor coolant system was at 180 F and 370 psi Pressurizer level was at 26 percen All steam generators were filled to the operating range, the condensate system was on long cycle 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 heated using RCPs 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, approximately nine personnel errors had occurre None of the events resulting from those personnel errors represented significant safety concerns of their own accord and collectively appeared to be typical of what one would expect at a Near Term Operating License plant going through the same evolutio Unit 2 entered Mode 3 on February 27 and was maintained in mode 3 with four RCPs operating 6 until April 7. The RCS was maintained between 350 F/1600 psig and 546 F/ 2250 psi A number of events occurred during this time period, including an inadvertent closure of all four MSIVs, exceedirig 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 auxiliary f eedwater pump operabilit The majority of these events were personnel related and with regard to corrective actions, were responded to by the licensee in an adequate manner. Escalated enforcement was proposed for the charging pump operability event and this action is currently under management review. Within this time period, several equipment related events also occurred. The most significant of these involved the l operability of the reactor trip breakers, RCS letdown orifice isolation

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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 re-star On March 30, the NRC approved entry into hode 2 (Startup).

Prior to actually beginning dilution, at approximately 12:30 am on March 31, it was determined that modifications associated the pressurizer loop seals, would be required and the restart was delaye A number of specific events which occurred during this inspection period are listed below:

On April 2, 3, and 4 respectively TREVI testing of pressurizer l safety valves A, B and C determined that the setpoints were above j the TS limi After having all three pressurizer safety valves i removed and set point checked at Wyle Labs, TVA reported that the 10 ,

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results of the inplace TREVI testing were not appropriat'e and the r

valves were reset and reinatalle I On April 6, 1988, a tube leak was identified in the #3 steam generato On April 7, the licensee identified that TS 3.0.3 had unintentionally been entered when portions of both trains of ECCS were simultaneously inoperabl On April 7, Unit 2 began a cooldown from Mode 3 to Mode 5 to repair the SG tube leak and complete pressurizer loop seal modification Mode 4 was entered at 11:23 pm on April 7. Mode 5 was entered at 10:10 am on April 8. On April 8, draining of the RCS for SG repairs was started. On April 10, RCS draining was completed and level was being maintained at RCS loop centerline plus eight inche On April 15, a water hammer which damaged three piping hangers occurred during startup of the condensate system as a result of ]

procedural and personnel error On April 24, the licensee determined that a SG tube plug which had been installed in 1986, was missing and could not be foun TVA requested Westinghouse perform a loose parts analysis of the missing materia On April 27, licensee personnel observed a loss of pressure in the hydraulic control system for 3 of 4 UHI isolation valve accumulator On April 28, RCp #4 tripped 25 seconds after it was started for venting gas from the RCS. Also on April 28, RCP #1 experienced excessive vibration during a brief run to support RCS ventin On April 29, 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 A detailed discussion of each of these events is contained in paragraph 1 . Ooerational Safety Verification (71707) Units 1 and 1 l plant Tours 1

The inspectors observed control room operations; monitored conduct of testing evolutions; reviewed applicable logs, including the I

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

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l with TS LCO The inspectors' verified that maintenance work orders  !

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had been submitted as required and that follow-up activities and' l prioritization of work were accomplished by the license Tours of the diesel generator, auxiliary, control, containment, and l turbine buildings were conducted to observe _ plant equipment l

conditions, including potential fire hazards, fluid leaks, excessive vibrations, and plant housekeeping / cleanliness condition No violations or deviations were identifie Safeguards Inspection In the course of the NRC inspection activities, the inspectora included a review of the licensee's physical security progra 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 ,

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In addition, the inspectors observed protected area lighting, and protected and vital area barrier integrity. The inspectors veri-fled the interfaces between the security organization and both operations and maintenance. Specifically, the shift inspectors inspected security during the outage period and reviewed licensee security event report No violations or deviations were ide.1tifie ' Radiation Protection The inspectors observed health physics practices and verified the implementation of radiation protection controls. On a regular basis, radiation work permits were reviewed and specific work activities were monitored to ensure the activities were being I conducted in accordance with applicable RWP Selected radiation protection instruments were verified operable and within calibration frequenc i j The following RWPs were reviewed:

88-0-14: Calibration of transmitters and gauges for all areas excluding containmen Three workers were i identified who were not documented as having had ,

J pre-work briefing Inspector review of RCI-10,

, ALARA Planr.ing, and RCI-14, Radiation Work Periait  ;

I (RWP) Program, and audit of other RWps for similar

, occurrences, was identified as shift follow-up item 4/11/88-1-1 (See paragraph 12)

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] 88-2-14: Unit 2 Upper Containment with Access to Lowe No j deficiencies were identifie ,

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Minor work, No deficiencies were identified.

88-2-75: Remove, replace, add new heat trace and associated wor No deficiencies were identifie : plugging of tubes in SG #2 and # No deficiencies were identifie : Plugging of tubes in SG #1 and # No deficiencies were identifie The inspector observed work in progress to place the leg covers and the tube sheet camera for the SG work. The inspector also reviewed the computer printout dose records for workers involved in the actual SG tube plugging efforts and found that none had exceeded ,

one third of the quarterly limi A dose of approximately 100 mrem was received per individual per entry. The inspector determined that Workers were following ALARA principles. No deficiencies were identifie The inspector attended a briefing on RWP 88-2-78, for entry into containment to remove blind flanges and pipe caps as necessary to drain down the RCS for SG tube repairs. The briefing covered the ,

task, protective clothing requirements, dosimetry, specific instructions for the task, radiation personnel control coverage, and respiratory protection. No deficiencies were identifie , Shift Surveillance Observations and Review (61726)

The inspectors observed or reviewed the perf ormance of TS required surveillance instructions and verified that testing was performed in accordance with adequate procedures; test instrumentation was calibrated; LCOs were met; test results met applicable acceptance criteria and were reviewed by personnel other than the individual directing the test; deficiencies were identified, as appropriate, and

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any deficiencies identified during the testing were pioperly reviewed and resolved by management personnel; and system restoration was adequat For completed tests, the inspector verified that testing frequencies were met and tests were performed by qualified individual The following surveillance activities were observed or reviewed:

1 SI-2: Shift Lo No deficiencies were identifie ,

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SI-3: Daily, Weekly and Monthly Log No deficiencies were I identifie SI-7: Electrical power System: Diesel Generators Unit 1 and No deficiencies were identifie SI-45.3: Essential Raw Cooling Water pump L- No deficiencies were identifie SI-45.4: Essential Raw Cooling Water Pump M- No deficiencies were identified.

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SI-45.5: Essential Raw Cooling Water Pump N- No deficiencies were identifie SI-45.6: Essential Raw Cooling Water Pump P- No deficiencies were identifie SI-127: RCS and Pressurizer Temperature and Pressure Limit No deficiencies were identifie SI-128.1.: RHR Pump and Piping Ventin No discrepancies were note SI-137.2: Reactor Coolant System Water Inventor On one occasion the SI indicated unidentified leakage in excess of the TS limit of 1 gpm, which was determined to be the result of temperature changes. The problem was corrected and the SI was repeated with acceptable result On a second occasion, perf ormance of the SI again indicated leakage in excess of TS limitatio This occasion is discussed in paragraph 10 and unresolved item 327,328/88-26-0 SI-137.5: Primary to Secondary Leakage via Steam Generator The inspectors reviewed activities in progress to determine the amount of primary to secondary leakage in the 83 S The inspectors observed portions of the performance of TI-12, Radiological Analytical Methods, utilized to analyze for tritium. No deficiencies were note SI-166.1: Full Stroking of Category A and B valves required in all modes. This particular activity tested valve 2-FCV-70-153A stroke timin No deficiencies were note SI-166.15: Containment Spray Check Valve test performed during operation. The valve failed the SI acceptance criteri l The valve had previously been worked and the WR was !

returned to planning for corrective actio SI-673: RCS Level Verificatio No deficiencies were identifie l SI-747: Pressurizer Safety Valve Test. The inspector reviewed 1 the safety evaluation, and no deficiencies were identifie SI-488: RCS RTD Sensor Verification of Calibration l On April 24, as the licensee discussed the replacement of the wide range RCS hot leg RTD 68-0065, the inspector noted that no mention 4

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was made of repeating the RTD cross calibration per SI-488. TS 4.3.4.7 requires a channel check, of which SI-488 is par The

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licensee was requested to provide their basis for not requiring SI-488 to be reperformed as a post maintenance test after the replacement of the RTD. This was identified as shift follow-up item 4/24/88-1-1 and resolution was required prior to entering mode 3. The item was resolved subsequent to the end of this inspection period and the resolution will be documented in Inspection Report 327,328/88-2 . Shift Maintenance Observations and Review (62703) Observations and Review of Maintenance Activities Station maintenance activities of safety-related systems and compo-nents were observed or reviewed to ascertain that they were conducted in accordance with approved procedures, regulatory guides, industry codes and standards, and in conformance with T The review included verification that LCos were met while components or systems were removed from service; redundant components were operable; approvals were obtained prior to initiat-ing the work; activities were accomplished using approved procedures and inspected as applicable; procedures used were adequate to control the activity; troubleshooting activities were controlled and the repair record accurately reflected what actually took place; functional testing and/or calibrations were performed prior to returning components or systems to service; Quality Control records were mainta.ned; activities were accomplished by qualified personnel; parts and materials used were properly certified; radiological controls were implemented; QC hold points were established where required and were observed; fire prevention controls were implemented; outside contractor activities were controlled in accordance with the approved Quality Assurance program; and housekeeping was actively pursue No violations or deviations were identifie Temporary Alterations The inspectors reviewed the following TACFs and the attached USQDs, and verified that the equipment specified had been installed and tagged:

2-87-2001-30: Installation of thermocouples in the East and West valve rooms 2-88-2008-03: Addition of pulsation dampeners to the TDAFW pump low suction pressure switches 2-88-2009-68: Four foot span level recorder for RCS draindown In addition, the licensee's current schedule for elimination of approximately one hundred older TACFs was reviewed. The current status of this action was that approximately thirty percent of the

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older TACFs had work plans established to replace them at the next .3

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scheduled outage.

I No violations or deviations were identified.

> Work Requests The inspectors observed work in progress and/or reviewed-the com-pleted work packages for the following work requests:

WR B257430: Repair / replacement of Loop 4 wide range hot leg RTD TE-068-65

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WR B264178: Cleaning inter-cell connections on 125V vital Battery II, performed in accordance with MI

10.53, Vital Battery Cell Replacement-and or

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Battery Bank Bus Rework WR B267375: Repair of the seal water supply union WR B275987: Four foot span level recorder for the RCS draindown B

WR B279313: ECT, tube plugging, and helium leak testing in

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WR B293698: Installation of pulsation dampeners on TDAFW ;

, suction pressure switches PS-3-121 A, B 'and D

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! WR B759633: Calibration and/or repair of level indicators on UHI surge tank (Level indicators had been reading

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WR B784757: ECT, tube plugging, and helium leak testing in

the 83 SG

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WP 7394-01: Prcssurizer safety valve replacement

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No violations or deviations were identifie ' Hold Orders

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The inspectors reviewed various hold orders to verify compliance with AI-3, revision 38, Clearance Procedure, and to verify that the  ;

, H0s contained adequate information to properly isolate the af f ected  !

!

portions of the system being tagged. Additionally the inspectors  !

walked down the affected equipment to verify that the required tags

,

were attached as stated on the Hos. The following H0s were re-l viewed:

Hold Order Equioment

.

1-88-548 1B-B Boric Acid Transfer Pump i

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! -- _ . _ , _ . . _ . _ _ . _ , . _ , . . _ _ . - . _ _ , _ _ _ _ _ _ _ _ _ - - _ . _ , _ -

_ .- _ .

_ -

.r

/ ..

.

i

l 2-88-333 pI-63-74 '

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2-88-341 RCS (For SG Tube Repair)

2-88-343 N3 Steam Line (MSIV and Bypass)

2-88-378 2B-B CCS pump (packing Repair)

2-88-404 CS Check valve 72-507 In reviewing the Unit 2 Assistant SOS Hold Order book, the inspector noted that hold orders were being inserted in the book after the hold was in place, and then removed when the hold was release In addition, the inspector noted that a log was not kept in the notebook to indicate which H0s were open. Although these administrative issues did not violate AI-3 or cause any H0s to be ,

inadequate, they did indicate a lack of discipline with respect to hold order log book maintenance which under certain circumstances could contribute to inadequacy of hold order control. The licensee was advised of this observatio No violations or deviations were identified.

1 Event Follow-un (93702, 62703) pressurizer Loop Seals i NRC follow-up continued on the pressurizer loop seal problems which i had originated prior to the inspection period. Background information and developments during the period of this inspection are summarized belo Each Sequoyah unit was constructed and initially operated with an i ambient water filled pressurizer safety valve loop sea Sequoyah participated in the Electric power Research Institute sponsored tests and referenced those tests in a response to THI item II-D- Only one instance of pressurizer safety valve leakage related ,

maintenance was identified from the time of initial construction to November 1983 (Unit 2, safety A, WR A-047328).

ECN 5856 was generated, in May 1983, to change the trim on the safety valves and install drain lines at the bottom of each loop ;

sea The sample line for level transmitter LT-68-320 was rerouted '

and the sample line tap was used for the loop seal drai This modification resulted in pressurizer level transmitter 1-LT-68-320 becoming inoperable and caused entry into LCO 3.3.1.1 on April 4, 1984. This issue was reported by the licensee in LER 327/84-25 and reviewed in NRC inspection report 327,328/86-69. The location of the sataple lines was resolved through ECN 6439, which was applicable for both units. The following Wps and FCRs supported this ECN and were reviewed by the inspector:

- -_ - --

~ _ _ _ _ __ _ . _ . _ _ _ . - . _ . _ _

,

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~

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WP.10719 WP 10720 WP 10721 WP 10755-  :

Wp 10762 FCR 2442 FCR 2019 FCR 2279 FCR 2291 FCR 2388 j In March 1984, a Design Change Request was initiated to allow tLe

~

operation of the safety valves with a steam tri Unit 1 was changed to steam trim in April 1984 with the loop seals drained.

1 Some leakage was identified on Unit 1 which was initially attributed to Safety Valve A and repaired under WRs A-233504 and

A-047198, Following the repair of Safety Valve A, leakage again occurred on Unit 1, and was identified to be the result of Safety-Valve B leakage. The leakage was repaired under WR A-28668 In August 1984, Sequoyah performed a maintenance required shutdown on Unit 2 to repair a rupture of the. pressurizer relief tank-

rupture disc. This event was reported in LER 50-328/84 013 '

Revision 1 and repaired under WR A-291415. As a result of this event safety valve A was removed and leak teste It was found to have gross leakage at 2300 psig which made the determination of ,

.

setpoint impossible. The valve was-replaced following this  ;

)

discover DCR 1808 was written in December 1984, to install heat tracing on the pressurizer loop seals to maintain the temperature of the

,

trapped water at a minimum 300 degrees F. The heat tracing was to be controlled with thermostats at the loops, and low temperature alarms were to be provided in the main control roo ,

ECN 6196 was written July 19, 1984 to insulate the pressurizer loop i seals with metalli reflective insulation. This was done to raise the water seal temperature to between 300 and 350 degrees F, in order to reduce water slug forces and to provide the option for a water trim safety valve. The USOD for this ECN had several special  !

requirements that had to be met in order not to increase the probability of occurrence or consequence of an acciden Some of ,

s these were:  !

' An engineering evaluation shall be performed to verify i i

that no unacceptable consequences occur before the liquid loop seal reaches the minimum design temperatur , The pipe and piping support system shall be revaluated a for the heated liquid loop seal loads and to reduce '

i normal loads on the safety valve discharge flang Tne i

supports shall be modified to withstand any increased 3

' '

loads caused by the liquid loop seal and metallic reflective insulatio !

18  :

i_ _ .. _ .-._._ _ .-._._.._ _ _ _. _ ._ _ _ _ . _ . _ . _ _ - . _ . _ . _ , _ -

_ _ . _m . _ _ _ _ _ _ __

a' .

.-

t

'

t The pipe and piping support system shall be evaluated and

'

be determined acceptable for the loads caused by water hammer from the valve chatter due to the liquid loop seal

discharge. The evaluation shall be in accordance with

.

EPRI test results and shall have special' emphasis on the

] inlet piping from the pressurizer to the safety valv i Administrative controls to insure reinstallation of insulation af ter maintenance activities

, Post modification testing is required to ensure that the

minimum design temperature of 300 degrees.F-is achieved and maintained at' the saf ety valve inlet flange and to

"

verify that any loop seal formed shall be heated to-300 degrees F prior to entering mode 2 and maintained between

300 and 350 degrees F while in mode 2 or '

! ECN 6196 was supported by the following work plans and field changes which were reviewed by the inspector:

WP 11290

. WP 11347 l WP 11593 i i

WP 11602

WP 11639 j WP 11655 WP 11707 WP 11775 FCR 2442 FCR 2019 l FCR 2279

FCR 2291 FCR 2388 FCR 3469 l FCR 3476 [

FCR 3482 FCR 3495 FCR 3453 I

FCR 3470 FCR 3471 FCR 3476 '

FCR 3482  !

FCR 3758

,

FCR 3777 FCR 3805 FCR 3825 FCR 3840

'

FCR 3852 FCR 3855 FCR 3857

'

FCR 3858 FCR 3867 FCR 3870 FCR 3890

,

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_ _ _ _ _ _ _ _ _ . _ _ . _ _ . _ . _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ . _ _ _ . _ . _ . _ _ _ . . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ . _ _ _ _ . _ _ . _ _ _ _ _ _ _ . _

. _- .-.- .- -.

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FCR 3911 4 l

FCR 3912 l

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FCR 3913 FCR 3928-FCR 3937 '

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L FCR 3948 FCR 3968 '

FCR 3977 FCR 4265 ECN 6221 was written in October 1984. . No formal setpoint'

,

calculation was documented under the' scope of this EC The alarm limit of 280 degrees F did not appear to have a technical basis'. In addition, the USQD supporting this ECN stated that two

, thermocouples were to be installed on each loop. Two oil filled capillary thermostate were installed instead. No indication was given as to the required installation location of the-oil filled capillary thermostats and no documentation was identified which indicated that these thermostats were field routed or the location  !

to which they were route The following documents supported this !

'

j ECN and were reviewed by the inspector:

I i WP 11312 (October 29, 1984) -

Thermostat sensing bulbs were l t

installed near the loop seals in accordance with step 1. 2.1 o f the WP . This WP also established heat trace transformers, low temperature alarm thermostats and heat trac The thermostat sensing bulbs were installed in -

,

accordance with Thermon installation instructions which  !

did not include a determination of where on the loop the l'

bulbs were to be attached. This WP established the low temperature alarm at 312 degrees F. The heat trace l thermostat setpoint was established at 325 degrees ;

The post modification functional test (PMT) that was performed, did not verify that the heat trace would

'

maintain the loop seal above 325 degrees F. The PMT consisted of a series of electrical circuit continuity

'

checks.

. FCR 2936

! FCR 2943 I

FCR 2953

~

TVA letter dated June 30, 1982, RIMS A27 820 630 22 CAQR 871378 i DCN 192 was issued to increase voltage on the heat trace i

. transformer The following documents were issued to support this l

} DCN and were reviewed by the inspector: i

!

WP 19201

,

WR 247357 .

! TACF 2-88-2003-68  !

! FCR 6905  !

FCR 6913

!,

!

._- . - . - -__ _ _ _ _ _ . _ _ _ _ _

.' .

.

a FCR 6933 FCR 6935 ECN 6410 was issued but was later cancelled through memo RIMS HBR/JPU 501 850 718 851. This letter also established three other actions to be implemented. These actions were to: remove the heat tracing from unit 2 under ECN 6221, remove the Nukon insulation f rom unit 2 under ECN 6196, and change the thermocouple designations of FCR 2837 to test points and leave the conduit and terminal box in place for future use through ECN 624 ECN 6247 was issued for installing thermocouples on portions of the safety valve and safety valve piping to help detect any safety valve leakage and to determine valve temperatures for setpoint testing for steam service. The inspector had the following observations on the WP and FCR supporting this ECN:

WP 11297 (November 7, 1984) - This WP installed eleven thermocouples on pressuricer relief line to monitor temperatur FCR 2837 - This FCR established the locations of the thermocouples in accordance with drawing 47W610-68-5, Following the modifications described in ECN 5856, leakage was l identified from sa'fety valve A during the Unit 2 heatup in 198 At the time this leakage was identified, the Unit 2 safety valves had drained loops and were set for steam tri A heated liquid loop seal was established on all the loop seals as a result of this leakag Safety valve B exhibited leakage after the heated liquid loop seal was established as a result of a leaking loop drain valve which was repaired. No further pressurizer loop seal leakage on ,

either unit was identifie In July 1985, Unit 1 was shutdown to perform a routine outag Heat boxes were installed on each safety valve to heat the loop seals with pressurizer generated waste heat (ECN 6196, WP 11639).

This activity was not completed because Unit 1 has not returned to normal operating pressure and temperature to perform the post modification test (PMT-61).

DCN 67 was issued for the replacement of Mercury filled bulbs with oil filled bulb In August 1987, heat trace control temperature sensor and switch assemblies were replaced during the extended outage in order to eliminate the switches that contained mercur The following documents supported this DCN and were reviewed by the inspector:

I WP 12693 The original, oil filled bulb, post modification I test (PMT), stipulated by this WP, used heat guns to I increase the loop seal temperatures in the areas of l the sensors in order to clear the annunciators and '

,

l

1

. .- -. . . .

.' .

.

s alarms in the control room. The pMT was unable to

! be performed adequately because the heat guns were not capable of generating the necessary heat to clear the annunciators and alarm As a result, the test was amended through an.instru'ction change form

.

,

'

I and-the functionality of the loop seal heating arrangement was based on lifted lead and shop calibration data. A lowest mode determination was performed (Safety Evaluation Report dated March 22, 1988 and calculation SON.B45 870515) by the licensee and it was decided that the annunciators would be 1 monitored during the actual plant heatup.

1 FCR 6093

"

FCR 6086 FCR 6240 FCR 6096

,

On or about March 21, 1988, the licensee determined that their expectations of being able to use heat tracing to maintain adequate loop seal temperatures, while at normal operating temperatures, had faile Consequently, TVA relocated the existing heat tracing on the loop seals and installed four band heaters on each loop sea i The heaters were initially set and testing commenced in order go I demonstrate the heaters' ability to maintain approximately 273 F '

in each loop seal are An annunciator alarm was installed in the Unig 2 control room to provide an alarm if temperature decreased to ,

251 F in any loop seal. Early testing identified a specific j problem with the loop "A" relief valve body, in that if the body

,'

temperature was greater than 243 F, the seat-appeared to lea '

The licensee suspected that the leakage was caused by distortion of

the seating surface. Additional testing at the temperatures l identified above showed that the A relief valve body temperature

-

could be maintained less than 243 F. Computer calculations were

performed by Bechtel for TVA that indicated that blgwdown loads 1

were acceptable with seal water temperatures of 210 F (loop A) and  ;

.

240 F (loops B & C) at the respective valve bodies. Safety 4 Evaluation FCR 6933, Revision 1, dated March 30, 1988, was

'

reviewed by the NRC office for this modification, and following

'

resolution of comments was determined to be acceptabl However, further monitoring / trending of loop seal temperatures on March 30,  ;

1988, indicated a degradation of the "A" pressurizer loop water j seal.

On March 22 the Sequoyah PORC approved USOD 88-21 which concluded that the operation of Unit 2 in Modes 3, 4, and 5 g with the

,

pressurizer safety valve loop seals less than 300 F would not .

represent an unreviewed safety question. The analysis on whi7h i this USOD was based on was supplied by Bechtel (SON-OSG7-003) and I j attached to the USOD.

i 1 On March 31, 1988, following the degradatlen of pressurizer loop I seal "A", TVA performed an analysis indicating that induced stress 1

from a nearby pipe restraint could cause the relief valves geak b j

!

Consequer.tly, plant temperature / pressure was reduced to 375 F/900 I I

, 22  !

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_ . . _ _ . . . _ . ___,____._--_______._____.m_,_ -..~ , _ , _ _ _ _ _ . . . . ~ . _

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psig to modify the pipe restraint associated with the safety valve on loop In addition, to ensure the leakage past the "A" relief valve wasn't due to a low relief point setting, TVA made arrangements with Fermanite to set point test the valve in place (TREVI test) once the pipe restraint modification was complete Following pipe restraint modification, plant pressure was increased to approximately 1700 psig in support of TREVI testing. On April 2, 1988, initial setpoint testing on the pressurizer loop seal "A" safety valve demonstrated it to be set at 2634 psig, which is out of specification high (in excess of the TS limit of 2485 psig i 1%). Its setpoint was readjusted and subsequently verified to be in specificatio Consequently, setpoint verification of the "B" and "C" safeties was deemed necessary and the licensee proceeded to test them as wel They too were out of specification high (B:

2678 psig; C: 2660 psig) and had to undergo readjustment /setpoint verification testing. Although the plant remained in Mode 3, cooldown towards Mode 4 (in accordance with TS) did take place during the testing of both the "A" and "B" safety valve An Unusual Event was declared in both cases as required by the site radiological emergency procedures. The Unusual Events were exited when the cooldowns were terminated. Additionally, the generic aspects of the "A" and "B" safety valves' initial out of specification condition was also reported pursuant to 10 CFR 50.7 On April 5, 1988, with the plant at NOT/NOP, the licensee deter mined that safety valves A and D were leaking due to the effects on their seats from the external heat being added by the loop heater All loop heaters were subsequently deenergized and analysis to sapport operation with loop seals was conducte On April 7, the licensee determined that modifications to seven hangers would be necessary to support the operation of a heated safety relief pressurizer loop seal. The total number of hangers requiring modification was later increased to nine. In addition, i the licensee determined that current heat trace and ring heater i arrangements were not capable of maintaining the desired I temperature range on the pressurizer safety relief valve loop l seal The temperature monitoring arrangement was also in doub '

On April 7, a cooldown to Mode 5 was commenced to repair a tube leak in the #3 steam generator. The decision was made to send the I pressurizer safety relief valves to Wyle for setpoint verification and adjustment if necessar On April 12, all three pressurizer safety relief valves had been removed from the system to be sent to Wiley for setpoint verificatio Wyle determined that all three pressurizer SRVs had been set below the TS allowable setpoints as a result of the earlier TREVI testing. By April 16, the setpoints of all of the SRVs had been readjusted, and the SRVs had been returned to the site and reinstalle On April 17, at 12:45 pm, the licensee notified tne NRC (4-hour report) that all three pressurizer safety relief valves had been found below the setpoints allowed by T *

.

.

b

.

On April 25, through the use of a contractor (Bechtel), the

licensee determined that the existing hanger arrangement did not meet current code requirements or TVA structural interim acceptance criteria with ambient temperature liquid pressurizer safety relief loop seals installe This was the result of a nonconservative assumption in the earlier TVA engineering analysis. The TVA analysis had assumed that the p0RVs would open during pressure transient conditions, whereas the reanalysis by Bechtel assumed that the p0RVs could possibly be closed during the high pressure safety valve actuation transient. This scenario became the more limiting of the two for piping reanalysi On April 28, the licensee decided to replace the existing'

pressurizer safety relief valves with steam trim valves. This plan was discussed and approved by the NRC during a public meeting on April 29, in White Flint, Maryland. ECN 622 was amended to add steam trim valves, with the f ollowing additional documents supporting the change:

WP 11312 FCR 2936 FCR 2943 FCR 2953 TVA letter dated June 20, 1982, RIMS A27 820 630 22 Installation of the steam trim valves was completed on May 2, and were verified to be operable through the measurement of RCS leak rates and Wiley setpoint verificatio RCS Leakage I On April 6, at approximately 6:50 am, the licensee completed compu-tations for Part 1 of SI-137.2, Reactor Coolant System Water Inven-tor The results indicated an initial unclassified RCS leak rate of 1.09 gpm, which if truely un!.dentified, would have exceeded the TS limit of 1 gp As required by procedure, the chemistry l laboratory was notified to perform Part 2 of SI-13 At the l time, the SOS was at the shift meeting preparing for turnover of l

'

the watch to the oncoming shift crew. He informed the Assistant SOS, by phone, not to enter the LCO for RCS leakage because procedural problems had caused them to enter the same LCO unnecessarily in the past. This decision was made even though the operators had noted abnormal increases in the reactor building auxiliary floor and equipment drain sump levels throughout the shif At 7:55 am the licensee entered LCO 3.4.5.2 for RCS leakage when a gasket on 2-PDT-62-47, the differential pressure transmitter on the

1. 4 reactor coolant pump seal return line, was found to be leakin A Notification of Unusual Event was not made at this time per IP-1, RCS Leakage, which required entry into the Radiological Emergency Plan if leakage exceeds the TS limi At 8:20 am licensee management personnel reviewed the decision and issued a NOUE. At

,

.

8:42 am, the differential pressure transmitter was isolated utilizing the root valve At 9:11 am the licensee notified NRC Headquarters in accurdance with the one hour emergency reporting requirement Although this notification was made within one hour of the management decisicn to enter the NOUF, the inspectors noted that this was accomplished approximately 76 minutes after entry into LCO 3.4.5.2 (which, by the licensee's radiological emergency

'

procedures, required a declaration of unusual event) and nearly hours after the operators had verifiable indication that leakage might be outside of Technical Specification limit At approximately 2:50 pm the licensee made an Emergency Notification System four hour notification to NRC HQ to report that a news release had been made to tne public at 13:00 am concerning the on-going Unusual Even AOI-6, Small Reactor Coolant System Leak (Modes 1, 2, & 3), had not been entere AOI-6 states that one possible symptom of a small reactor coolant leak is receiving the "Reactor Building Auxiliary Floor and Equipment Drain Sump High" alarm, window 19 of XA-55-5A on panel 1-M-5. This alarm was received twice during the shift as stated abov Additionally, with the high leak rate as calculated in SI-137.2 and the discovery of 2-PDT-62-74 leaking the inspector considers that it would have been prudent to perform the actions of AOI- Although non-performance of the recommendations in AOI-6 does not appear to violate any licensee or NRC requirements, the inspectors have concern that the licensee's annunciator response procedures do not provide an initiation path for the AOI procedure At 5:45 pm, the licensee exited the NOUE when a new performance of SI-137.2 indicated an acceptable leakage rate of 0.48 gp The licensee estimated that between 250-300 gallons of inventory had leaked during the entire event by estimating the leakage rate from  ;

2 PDT-62-47 to be 0.61 gpm and by confirmation of the pocket sump level The licensee issued a statement to the press on this occurrence at 11:00 am on April The delays in entering and reporting the NOUE and the LCO on RCS leakrate and the concerns involving initiation of AOI procedures are identified as Unresolved Item 88-26-0 During this event TVA had used a cumbersome method to calculate unidentified RCS leakage and to determine what part, if any, that a primary to secondary leak played in this unidentified leakage valu Specifically, the licensee's RCS inventory measurement procedure SI-137.2 would perform an inventory balance and if the unclassified leakage was above a specific value they would then request that a prinary to secondary leakage measurement be performed in accordance with SI-13 This method of performing a primary to secondary leakage calculation, only if needed to quantify unidentified leakage, resulted in both a delay in completing the RCS unidentified leakage measurement and a lack of consistent primary to secondary leakage trending data. The staff i l

I 25  :

_ _ _ _ _ _ _ - _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ .

_ .

.

.

.

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consider that this methodology was a major contributor to the

'

delays associated with entry into (and applicable reporting of) the NOUE and LCO, as identified in unresolved item 86-26-0 Revision 22 of SI-137.2 revised the method to require that primary to secondary leakage measurement be performed every 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> and be a prerequisite to the inventory balance performed by SI-13 This new method should produce both consistent primary to secondary leakage trending data as well as expedite the determination of RCS leakag This method also provides adequate corrective action to alleviate raising questions such as those indicated under UNR 88-26-03 discussed abov Steam Generator Tube Leeks During the r solution of pressurizer loop seal pc,blems while in Mode 3, the licensee received indication of a SG tube lea On April 3, the licensee detected initial indications of a steam

. generator tube leak when a low pH sample was obtained from water in the #3 steam generato The presence of lithium and boron in blowdown samples was confirmed that day. Earlier radionuclide analyses had indicated no evidence of leakag ,

The amount of boron identified in the steam generator was approximately 8 pp The acknowledged accuracy of the boric acid filtration analysis is approximately 20 ppm. Therefore, the licensee was only able to determine qualitatively that trace amounts of boron were present in the steam generato A quantitative determination of steam generator boron concentration was based on best estimate, considering the accuracy of the

,

filtration analysis accurac On April 6, a newly established tritium analysis method was used to quantify the leak in the #3 steam generator as approximately 234 to 435 gallons per day, compared to the TS limit of 500 gallons per da The licensee issued a press announcement at 11:30 pm concerning the primary to secondary leakag On April 7, at 5:00 pm, Unit 2 began a cooldown to Mode 5 from Mode 3 to repair the apparent tube leak in the #3 steam generato At I this time TVA management was advised that the NRC Hold Point for Mode 2 entry would be reinstated. Mode 4 was entered at 11:23 pm on April Mode 5 was entered at 10:10 am on April On April 8, actions were initiated to drain the RCS. An administrative hold was placed in the procedure to stop draining the RCS when the level reached the 5% indicated level in the pressurize At that point, notification was to be made to I specific plant management and their presence was required prior to going below the 5% level. Tygon tubing and a sight glass were installed with TV cameras and associated control room monitoring to provide accurate level indication of the RCS level. In addition, a recorder was installed to provide level read-out during the

26

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draining and for maintaining the level. Level was to be maintained

'

at the centirline of the hot-leg nozzle to insure that the levels remained low enough to allow the manhole cover to be removed from the steam generato A calculation was made to determine the amount of inventory to be drained from the RCS based on the amount of water received in the B hold-up tank. Draindown from the 5%

pressurizer level hold point commenced at 7:00 pm on April 10, and the desired level was reached at 11:30 pm that day. A continued drain rate of approximately 20 gpm was experienced due to

"gurgling" after the desired drain level was reache On April 12, the Combustion Engineering robot machine "Genesis" was placed in SG #3 for a helium leak tett of the tubes. Based on previous industry experience, tube leaks were considered most likely to occur in Westinghouse Blairsville tubes. The helium testing was completed un the #3 SG on April 13, with one tube leak having been identified in the Row 1, Column 39 tub Subsequent eddy current inspection of this tube revealed a through-wall defect in the U-bend inside radius at approximately 10:00 from the top of the apex on the hot leg sid The tube, which was made by Huntington Alloy rather than Blairsville, was then plugge Eddy current examination on SG #3 Row 1 revealed indication that the tube in Row 1 Column 3 had a wall reduction in the bend radiu The licensee plugged this tube also. A subsequent helium leak test was performed on Row 1 and two additional leaking tubes were detected in row 1, columns 48 and 49. Eddy current testing failed to identify these tube leaks, which was attributed to noise levels caused by the probe not fitting well i n the U-bend are The licensee also plugged these tube On April 18, the licensee advised the NRC of their decision to preventatively plug all of the row 1 tubes in all four steam generators. After the tubes had been plugged, helium leak testing was performed on SG #3 at 95 psi The licensee also advised the NRC that all other tube bend radii except in SG #4 had been inspected during the 1986 SG outag During discussions between the licensee and NRC HO technical personnel, it was agreed that a 10 percent inspection (10 tubes)

would be performed on row 2 of SG #4 for additional in f or ma t i on .

Eddy current examination determined that these tubes were acceptabl This inspection was superior to previous inspeculons in that a new ECT probe was utilized that produced better results of inspection in the bend area of the tube On April 24, 1988 TVA reported that a plug, which had been ,

,

installed in the cold leg Row 1 column 61 tube of SG #1 in 1986,  !

was missin Westinghouse was contacted to perform a loose parts j analysis in order to determine if operation with the missing plug l was acceptabl l i

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NRC headquarters staff met with the licensee during the aforementioned April 29 public meeting, and agreed that the actions

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- - - - - + yw - ,. - - - - m , . . . - - - - - - - * - - - - - - - - - - - - - , -

.. .

a

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taken to correct the steam generator tube leaks had adequately

addressed the problem. Completion of the Westinghouse loose parts analysis of the effects of the missing tube plug was identified as an open item to be completed prior to entering Mode Subsequent to the period of the inspection, this item was resolve The resolution will be documented in Inspection Report 327,328/88-28, 1 No violations or deviations occurred in association with the steam generator tube lea Source Range Detectors NRC follow-up continued on problems with source range detector signal noise, which had originated prior to the current inspection perio Intermittent excessive noise, both in the form of spiking and periods of constant high count rate levels, had been a problem on Unit 2 for several weeks. Some of the noise problems had been observed to correlate with the TDAFW pump low suction pressure alarm in the control room. On April 1, Unit 2 had received a reactor trip signal from high flux on source range channel NI-31 when a control power fuse was replaced on NI-3 The fuse had been misoriented and the operator was attempting to realign it when the trip occurre The reactor trip breakers were open at the time of the event, so an actual trip did not occu On April 16, Unit 2 source range detector NI-31 was returned to service after the repair of a ground at the cable connectio On April 24, at approximately 10:04 pm, a source range high flux reactor trip signal was generated on Unit 1 due to a noise spike on NI-3 The reactor trip breakers were open at the time so an actual trip did not occur. The spike was apparently caused by welding in the Unit 1 containment. The trip signal was reported to the NRC at 1:17 am on April 2 On April 26, at approximately 9:00 pm, NI-31 on Unit 2 spiked then leveled off at a noise level of approximately 50 cp On May 3, at approximately 9:00 pm, Unit 1 again received a source ,

range high flux reactor trip signal due to welding in the Unit 1 containmen I The source range noise problems are assumed to be ground related, and do not affect the source range operability as evidenced by a successful surveillance of the NI channels. The licensee implemented controls for monitoring the backup source range NI during startup as a third source of indication and stated that these controls would remain in effect throughout the startu Additionally, the licensee proposed to monitor instrument response of the NI channels at different stages of adding positive reactivity, prior to the criticality in order to verify operabilit The NRC considered this acceptable resolution of the ,

,

- _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ .____ __ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ .

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problem with regards to Mode 2 entry. The use of the separate NI

channels will be monitored by NRC staff during Unit entry into critical operation Upper Head Injoction Accumulator Level Switches On April 29, during an evolution of draining the UHI accumulator to adjust boron concentration, licensee personnel observed a loss of pressure in the hydraulic control systems for three of the four UHI accumulator isolation valve The UHI lines are provided with four accumulator isolation valves, two in each line, which function to isolate the UHI accumulator to prevent the injection of nitrogen gas into the RCS following the blowdown of the UHI water accumulator. Actuation of UHI accumulator isolation is controlled by UHI level switches LS-87-21, LS-87-22, LS-87-23, and LS-87-24. Each level switch closes one of the four UHI accumulator isolation valves when UHI water level reaches the TS limit of 87 inches above the bottom of the tan The level switches respond to differential pressure, with the two level switches in each train sharing a common reference leg. When the low UHI accumulator level setpoint is reached on each level switch, a snienoid valve is actuated to release the hydraulic oil pressure whien operates the valve, and causes the associated isolation valve to clos During normal operation, water level in the UHI system is maintained in the surge tan There is no level indication in the UHI accumulator itself since the tank is normally i maintained completely full. During normal operation water level is

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above the reference leg tap and the reference leg will be full, prior to the draindown of the UHI accumulator, the hydraulic pressure for all four isolation valves had been verified by the licensee to be at the operating level of approximately 3100 psi The accumulator was then drained through a sample line, with the isolation valves close Tank pressures and ideal gas laws were used by the operators to infer approximate accumulator water level, due to the lack of level indication. During normal rounds on April 29, licensee personnel found the hydraulic pressure for the two B train valves, 87-22 and 87-24, at 400 psig. pressure on A train valve 87-21 was normal at 3100, and the 87-23 valve pressure was at 1600 psi Both B train level switches were found actuated, and both A train level switches were found unactuate The UHI had .

been drained with power on the solenoid valves, allowing oil I

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pressure to be released when the level switches activated. With !

power on the solenoids the licensee recharged each of the

discharged hydraulic operators to 3130 psi The B train valves, with level switches still actuated, promptly discharged hydraulic ,

pressure to 400 psig. The charge on A train valve 87-23, with the l

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l level switch not actuated, gradually drifted down to approximately i 2600 psi The licensee attributed this pressure drop to the I system cooling after being charged, but the pressure response did not rule out the possibility of a lea Temperature changes normally result in several chargings being required before the 29 i

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system will retain a charge to full pressur When the B train

hydraulics were recharged with power removed'from the solenoids, the charge hel A work request was issued to do a volumetric check of the hydraulic system bladder for leak The operators assumed that the accumulator level had drained past the actuation point of all four level switches, and began investigating why only the B train had tripped and why pressure on 87-23 had dropped to 1600. Accumulator level was drained for approximately eight hours in an attempt to actuate the A train level switches, but the switches did not tri On May 1, it was discovered that the reference leg for the A train level switches was dry. This accounted for the fact that the pressure switches were not in the actuated positio Licensee personnel checked the system and found no obvious leaks and found that all valve alignments were correc On M3y 2, the licensee began refilling the UHI system, with the hydraulic systems for all four valves fully charged and the level switches actuated. The switches should have reset as the tank was refille On May 3, the hydraulic pressures on A train valves 87-21 and 87-23 were found to be 1400 and 2600, respectivel The reference leg for the B train level switches, which had actuated on the low level signal, was found to be at least partially plugged, probably with boron. The licensee began investigating a possible correlation between the plug in the reference leg and the fact that the B leg had not draine Demonstration of full operability of UHI was identified at the Exit Interview as requiring resolution prior to entering Mode Subsequent to this inspection period, and prior to entering Mode 3, the licensee determined that the drain down of the A train 1 reference leg resulted from a loose and leaking packing gland nut on the reference leg isolation valve. The licensee had not been able to positively identify the cause of the partial drain down of the hydraulics for the single A train valve. The licensee had

, tightened the loose packing gland nut, refilled the reference leg, recharged the hydraulics and tested the syste No further evidence of reference leg draining had been observe Following hydraulic system recharging, no further pressure decreases were

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observed and the hydraulic system appeared to be functioning properl NRC closure of this issue is documented in inspection report 327,328/88-28,

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Other Events on April 7, at 12:26 pm, the licensee identified that TS 3.0.3 had unintentionally been entered when portions of both trains of the ECCS were simultaneously inoperabl The 2B-B RHR pump had been placed in the pull-to-lock position at 9:55 am for preventive maintenance on a minimum flow line. During heavy control room activity, the same operator had placed 2A-A charging pump in pull-to-lock at 11: 56 am f or a per f ormance of SI-40.1, Centrifugal Charging pump Casing and Discharge piping Venting. Thic was done without entering LCO 3.0.3 for having two trains of ECCC inoperabl Approximately ten minutes later the situation was noticed by operations personnel and LCO 3.0.3 was officially entere The situation was corrected by returning the 2A-A CCp to service at 12:26 pm, after both trains had been rendered inoperable for approximately 30 minutes. The TS LCO was not exceeded. The inspectors determined that the licensee planned to issue an LER, and the NRC will assess the licensee's resolution of the problem when the LER is issued. No TS violations were identifie On April 7, the licensee identified that a low boron concentration existed in the B Boric Acid Tank and Boron In)ection Tank. This was apparently due to inleakage into the BIT either from the RCS or the charging system. The licensee generated a PRO to investigate this even On April 11, at 1:50 am and again at 1:53 am, Unit i received a steam generator low level signal coincident with an existing steam flow / feed flow mismatch signa This resulted in a reactor trip signal, but the trip breakers were open at the tim Upon investi-gation, it was found that personnel working in the Unit 1 #4 accumulator room had keyed hand held radios at the times that the trip signals had been generate The licensee surmised that keying the radios had caused the SG 1evel transmitter, located in the same room, to spike low and trip the bistable. The licensee controls the use of hand held radios by administrative instruction and is evaluating further restrictions on radio us On April 14, an alignment check on the #1 RCp motor bearing indicated that it was out of tolerance, and work was initiated to adjust the bearin On April 15, a water hammer occurred during startup of the conden- (

sate system and at least three hangers were broken loose. SOI and 3.1 specified starting up the system by throttling one pump's

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discharge isolation valve 25 turns from full closed, starting one condensate pump, then starting another pum The purpose of this starting sequence was to fill the presumably empty discharge lines gradually through the throttled discharge valv After the second pump is started, the firat pump may either be stopped or its dis-charge valve fully opened. The procedure did not specify either a waiting time between starting the pumps, or require waiting for all system indications such as pressure, flow, hotwell level, and amps to stabiliz A precaution directed the operator to wait until the

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pressure stabilized. Following these procedures, the BOP operator

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started the C hotwell pump, which had an operator aid sticker on its handswitch indicating that the pump's isolation valve 2-FCV-2-537 was throttled 25 turns from full close The operator then started a second pump. The time in val between starting the two pumps was estimated at less than one minut The licensee is investigating to determine whether this waiting time between starting the pumps was sufficient. In addition, the position of the C pump isolation valve was determined to be approximately 100 turns open, rather than the specified 25 turn Further NRC review of the event was identified as shift follow-up item 4/15/88-2- On April 17, while on a tour of the auxiliary building, an inspector observed an AUO on duty at the radwaste station who appeared to be less than fully alert. A second AUO arrived, and the inspector asked both AUOs general questions. The incident was reported to the shift enginee The operator was performing non-licensed functions and appropriate actions were taken by the license On April 25, the licensee reported a spill of about fifty gallons of sulfuric acid in the makeup water plant. The acid was contained within the sump, and there was no injury to personnel or release of radioactivity to the environmen On April 28 at approximately 10:00 pm, RCP #4 tripped 25 seconds after it was started for a ten minute run for RCS sweepin The next day, the pump was turned by hand and was meggered, and no problems were foun RCP #4 was restarted and then secured on April 2 Additional follow-up investigation of the 84 RCP trip indicated that the most probable cause was that the #4 pump experienced high starting current when it was started due to cold RCS water and reverse flow from the #3 RCp, and this resulted in a trip on overcurren A check of the overcurrent relay indicated that it was set low in the operating band, and the relay was subsequently readjusted. On April 28, the licensee had stopped RCP

1. 1 during two ten minute pump runs due to vibration on the pump shaf The shaft on RCP #1 was rebalance On April 30, dur!ng fill of the RWST a leak was observed near the boric acid storage tanks. The evolution was secured until the source of the leak was identifie The leak was determined to be coming from a flange on PI-62-234, which is the pressure gauge to l the inlet to boric acid filter Boric acid filter B was bypassed I and blending to the RWST recommence It appeared that the IMs had I removed a temporary gauge earlier but did not ccmplete the jo l The root valve, 2-62-392A, had been isolated but the valve leaked throug The inspector determined that the root valve being shut ,

was not entered in the configuration log, and although the job was !

still in progress no tag had been hung to isolate the work are j An investigation of the root cause was initiated by the license l NRC review of the root cause analysis was identified as shift l follow-up item 4/30/88-2-1. The lack of a configuration log entry i

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for the closed root valve was identified as an example of violation

88-26-01 (See paragraph 11).

1 Operational Readiness Insoection Prior to releasing TVA from previously established NRC hold points for the original mode 5-4 and 3-2 mode changes, the NRC performed operational readiness assessments which are documented in inspection reports 327,328/87-73 and 327,328/88-1 A new operational readiness inspection was implemented in order to determine TVA's readiness to change modes after the steam generator tube repair outage. The inspection objectives, accompanied by the significant findings and conclusions, are listed belo Discuss with OSP HQ staff the acceptability of TVA's technical resolution of several current issues, including 1) SG tube repair, 2) missing SG tube plug, 3) pressurizer safety valve leakage and setpoint problems, and 4) pressurizer safety valve loop seal and piping support modification Results Based on discussicn with members of the OSP HQ projects and technical staff, the only outstanding technical issue involved the acceptability of the loose parts analysis for the missing SG plu This was identified as a Mode 2 item, and subsequent to this inspection period was determined to have been satisfactorily resolve Review status of outstanding NRC open items as listed on the outstanding items list (OIL) and determine if items are required to be resolved prior to startu Verify through discussion with OSP HQ staff that no additional restart items have been identifie Results This objective was satisfactorily completed, with no outstanding issees identifie Review outstanding PR0s, LERs, and PORS incident reviews in order to ensure there are no outstanding issues that have to be resolved j prior to mode chang ;

Results This objective was satisfactorily completed with no outstanding issues identifie ! Review outstanding shift inspector items to ensure there are no outstanding issues that have to be resolved prior to startu . _ _ _

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) This objective was satisfactorily completed, with no mode related

issues currently outstandin ;

i l Discuss with the licensee's QA organization their audit plan and !

the activities expected of them prior to each mode chang !

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Etsults l l This objective was satisfactorily completed with no outstanding -

issues identifie Review completion of GOI 1, 2, and 3 prior to the appropriate mode ,

change.

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Resultrl The review of GOI-1 and GOI-3 was completed. A review of GOI-2 was j assigned to the shift inspectors for full completion prior to entry -

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! Review S AL, ECp, CCTS, CAQR, SI and TROI for adequate tracking and

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resolution of mode related items, i  !

Results

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This objective was satisfactorily completed with no outstanding .

, issues identifie ! Audit configuration log, recent system realignment SOI completion j and walkdown portions of a selected syste *

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Results

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d The inspectors reviewed licensee control of system configuration status by auditing the configuration log and recently completed SOI ;

checklists for compliance with AI-58, Maintaining Cognizance of Operation Status - Configuration Status Contro In addition, the ;

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inspectors walked down the RHR and UHI systems to independently verify system alignmen j t

i Four examples of failure to properly implement procedures

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I associated with controlling plant configuration were identified:

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J 1) on April 30, during till of the RWST, a leak occurred from I

a temporary pressure gauge on the inlet to boric acid filter l' B. Root valve 2-62-392A had been isolated but both the root ;

valve and the downstream pressure gauge had leaked throug i Isolation of the root valve was not entered in the l configuration log, as required by AI-5 The inspectors also i

noted that the instrument mechanics had operated a valve under ,

I the control of operations, and had walked away from an  !

incomplete job without hanging tags as required by procedure l

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2) On May 1, while walking down a portion of the UHI system,

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the NRC inspector determined that UHI surge tank sample point valves87-543 and 87-542 were not in their normal position due to the installation of a temporary pressure indicator. No configuration log entry had been made to document the valves being cut of positio ) In the May 1 perf ormance of SOI-72.1, independent verification that FCV 72-504 was in the locked ~ closed position had been signed off by two individual The licensee subsequently repeated the double party verliication while performing another procedure, and the valve was found to be closed but not locked. The AUOs involved acknowledged that they had signed the procedure without actually verifying the valve position was as specified. The second individual had remained outside of the contamination zone, and had therefore not complied with the requirements of AI-37, Independent Verification, and GOI-6, Apparatus operations. These procedures require both individuals to physically test the position of each manually controlled valv ) On May 4, a licensee QA audit found that the CST B supply to the AFW, Valve 0-2-505, was shut rather than locked open as required by the SOI checklist and indicated in the system statu Although none of the plant systems involved in these examples were required to be operable with the unit in Mode 5, the incidents indicated that the licensee was not adequately maintaining the configuration control required by AI-58. The licensee had not relaxed configuration control during the return to Mode 5, and was relying on administrative controls to assure proper system alignment for startup and operation. Although the licensee stated to the inspectors that they believed other mechanisms would have I eventually restored the out of position components to proper l configuration, the NRC remained concerned that the configuration control program was not adequate to assure proper system alignment or cognizance of actual plant configuration condition l The inspector noted that a number of similar problems with l configuration control have been documented relatively recently in I previous inspection reports. Reports 327,328/87-24 and 1 327,328/87-30 documented two spills of primary coolant water as a result of misconfigured components, for which violations were ;

issue On February 1, 1987, five valves were shut in an attempt l to isolate a SG maintenance area from the RWST, without proper l authority or configuration control. This resulted in an RCS spill when a valve was stroke teste On April 27, 1987, another RCS spill occurred when the licensee did not enter in the configuration log that the pressurizer spray line drain isolation valve 1-HCV-594 was open rather than in the closed position specified as the normal alignmen Inspection Reports 327,328/87-66 and 327,328/88-06 also cited examples of components being out of position for which a reason was never identifie Report 8G-06 documented that some SOI

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checklists had to be reperformed.because one of the independent verifiers had not physically verified the valve positions as required by plant procedures. These repeated occurrences.give cause for concern that the licensee's configuration control process was not working adequately. The observed problen s included both failures to make configuration log entries when reeded, and failures to properly complete SOI checklist Inspection report

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327,328/88-16 documented that the licensee Operational Re&diness j report identified weaknesses in the configuration control system l and recommended that when double party independent verification is ,

j required, that the two verifiers be physically separated by-time and distanc The licensee has not yet implemented this recommendation, considering it to be a "procedural enhancement",

but has identified an implementation date of June, 198 Examples one through four above were identified to the licensee as examples of Violation 88-26-0 Although examples 3 and 4 were discovered by the licensee, they will be cited because of the~

previous violations in the area of configuration contro Demonstration of adequate configuration control was identified as a requirement for restar Subseqilent to this inspection period this item was adequately resolved for restart and will be documented in Inspection Report 327,328/88-28.

I SOI checklist 68.1A, completed on April 25 to verify the alignment ,

of the RCS following the steam generator tube work, contained a i number of deviations for equ.pment not in the position required by the SOI checklist. The unit ~ould not have entered Mode 4 with the RCS equipment in the configurations documented in the deviation Deviating the checklist in this manner was contrary to AI-58, which stated that SOI checklists having components that cannot be aligned to the normal position defined by the checklist and affect the I intent of the instruction, system operability, or mode changes 1 shall not be deviate These checklists shall be held open until the component can be aligned to its normal checklist configuratio Deviating the checklist was apparently the result of the SOI being I a prerequisite for GOI-1, even though at that point in GOI-1 not all checklist components could be put in their normal at power lineu The licensee identified this to be a problem with other SOI checklists as wel Improperly deviating checklist 68.la was identified as a fifth example of Violation 88-26-01. No specific corrective actions for this example were required prior to Mode 4 entry because the inspector determined that the operators had maintained cognizance and control of equipment status, although not according to procedur Ensure shift manning (operators, aecurity, HP) are in place and are being conducted in accordance with established practice .

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Re9"Its This objective was satisfactorily completed, with no outstanding issues identified, i Conduct a housekeeping tour and observe the licensee closecut of l the containmen RLulnl.t1 This item was saticfactorily completed on May 6 and 7, 1988, In connection with containment cloceout by the license . Shift Insoector Follow-uo Issues Issue Number Descriction Status / Resolution 2/26/88-2-1 Evaluate New Work Control Resolved. TVA Group's Effectiveness developed a common Regarding Recognizing LCO equipment checklist Conditions for the emergency diesel generato This item will continue to be monitored by the NRC during plan operation. It is part of the NRC Inspection Plan to be performed during shift observatio /27/88-2-1 Review of Improper Open. Currently under Operation of COPS NRC Revie /28/88-1-1 SIS Check valve Leakage Ope During the SG tube leak repair outage TVA repaire several chec' valve test valves which they believed to be the cause of the indicated leakag The inspec- l tors will monitor ,

leakage testing during )

the heat up and )

pressurization. This item remains open <

pending retestin I

3/08/88-1-1 Drawing Control Resolved. Adequate engineering reviews are being' conducted on drawing revision <

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3/12/88-1-1 RCP #1 Upper Thrust Resolved. . WR 267455

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Bearing Temperature Alarm was reviewed and the

. Problem inspector determined that the work was completed on 3-16-8 /12/88-2-3 Evaluate PRO 2-88-81 Ope Currently under dealing with no PMT being NRC Revie performed after work on 2-FCV-67-67 3/18/88-1-1 Determine if rod position Resolve The rod problem for rod E-3 was problem was deter-stuck rod or instrument mined to be an IRPI problem problem which was corrected by the completion of SI-67, IRPI calibratio /25/88-2-2 Resolution of NI-31 Source Ope To be evaluated Range Detector problem during startu /11/88-1-1 Review of April 11 Event Ope Currently under for Violations of RWP and NRC revie RCI-10 or 14

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4/15/88-2-1 Review Cause and Events Ope Currently under Associated with Failure of NRC revie Pipe Supports and Hangers on the Condensate System 4/24/88-1-1 RTD cross calibration Ope Currently under per SI-48 NRC revie /25/88-1-1 Pressurizer relief line Ope Currently under

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hanger analysi NRC revie /30/88-2-1 Review spill event of Resolve Violation 4/30/8 /88-26-01 addresses this issu I l

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1 List of Abbreviations

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AI -

Administrative Instruction AFW -

Auxiliary Feedwater ALARA - As Low As Reasonably Achievable AUO -

Auxiliary Unit Operator AOI -

Abnormal Operating Instruction ASME - American Society of Mechanical Engineers BIT -

Boric Acid Tank BOP -

Balance of Plant CAQR - Conditions Adverse to Quality Report CCP -

Centrifugal Charging Pump CCS -

Component Cooling System CCTS - Corporate Commitment Tracking System COPS - Cold Overpressure Protection System CS -

Containment Spray CST -

Condensate Storage Tank DC -

Direct Current DCN -

Design Change Notice DCR -

Design Change Request DNC -

Division of Nuclear Construction DNE -

Division of Nuclear Engineering ECCS - Emergency Core Cooling System ECT -

Eddy Current Testing

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ECN -

Engineering Change Notice ECP -

Estimated Critical Position EDG -

Emergency Diesel Generator EGTS - Emergency Gas Treatment System ENS -

Emergency Notification System EPRT - Electric Power Research Institute EQ -

Environmental Qualification ERCW - Essential Raw Cooling Water ESF -

Engineered Safety Feature F -

Fahrenheit FCR -

Field Change Request FCV -

Flow Control Valve FSAR - Final Safety Analysis Report GOI -

General Operating Instruction HO -

Hold Order HP -

Health Physics HQ -

Headquarters IM -

Instrument Maintenance Technician IMI -

Instrument Maintenance Instruction IRPI - Individual Rod Position Indication KV -

Kilovolt LER -

Licensee Event Report LCO -

Limiting Condition for Operation i LOCA - Loss of Coolant Accident l MI -

Maintenance Instruction MOVATS - Motor Operated Valve Activator Testing 1 MSIV - Main Steam Isolation Valve )

NI -

Nuclear Instrument l

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NOT -

Normal Operating Temperature NOP -

Normal Operating Pressure j

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NOUE - Notification of Unusual Event I NRC -

Nuclear Regulatory Commission OIL -

Outstanding Items List OSP -

Office of Special Projects PM -

Preventive Maintenance PMT -

Post Maintenance Testing PORS - Plant Operation Review Staff PORV - Power Operated Relief Valves PRO -

Poten:ially Reportable Occurrence PRZ -

Press 1rizer QA -

Quality Assurance  !

QC -

Quality Control RCI -

Radiological Control Instruction RCS -

Reactor Coolant System RCP -

Reactor Coolant Pump RHR -

Residual Heat Removal RO -

Reactor Operator RTD -

Resistance Thermal Devices RWP -

Radiation Work Permit RWST - Reactor Water Storage Tank SAL -

Sequoyha Activities List SG -

Steam Generator SI -

Surveillance Instruction SIS -

Safety Injection System SOI -

System Operating Instruction SOS -

Shift Operating Supervisor SRO -

Senior Reactor Operator SRV -

Safety Relief Valve SS -

Shift Supervisor STA -

Shift Technical Advisor TACF - Temporary Alteration Control Form TAVE - Average Reactor Coolant TDAFP- Turbine Driven Auxiliary Feedvater Pump TDAFW- Turbine Driven Auxiliary Feedwater TI -

Technical Instruction TMI -

Three Mile Island TS -

Technical Specifications TSC -

Technical Support Center TVA -

Tennessee Valley Authority UE -

Unusual Event UHI -

Upper Head Injection UNR -

Unresolved Item USOD - Unreviewed Safety Question Determination VCT -

Volume Control Tank VIO -

Violation WCC -

Work Control Center WO -

Work Order WP -

Work Plan WR -

Work Request

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