IR 05000259/1988033
| ML20235K496 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 02/13/1989 |
| From: | Carpenter D, Little W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20235K477 | List: |
| References | |
| TASK-2.F.2, TASK-TM 50-259-88-33, 50-260-88-33, 50-296-88-33, GL-84-23, IEB-88-003, IEB-88-3, IEIN-86-081, IEIN-86-81, IEIN-87-008, IEIN-87-8, NUDOCS 8902270138 | |
| Download: ML20235K496 (28) | |
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.g n Mcg UNITED STATES
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Report Nos.: 50-259/88-33, 50-260/83-33, and 50-296/88-33 Licensee: Tennessee Valley Authority 6N 38A Lookout Place 1101 Market Street Chattanooga, TN 37402 2801 Docket Nos.
50-259, 50-260, and 50-296 License Nos. DPR-33, DPR-52, and DPR-68 Facility Name:
Browns Ferry Nuclear Plant Units 1, 2, and 3 Inspecticn at Browns Ferry Site near Decatur, Alabama Inspection Conducted:
November 1 - 30, 1988 Inspectors:
t D.' R. C'ariiefiter, NRC Site Manager
/D~atd Signed Accompanied by:
C. Brooks, Resident Inspector E. Christnot, Resident Inspector W. Beardan, Resident Inspector A. Johnson, Project Engineer J. York, Senior Resident Inspector, Bellefonte Approved by:
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W. S. Little/Section Chief, Cat ( Signed Inspection Programs, TVA Projects Division SUMMARY Scope:
This routine resident inspection was in the areas of operational safety verification, modifications, surveillance observations, modifications, system return to service, status of 10 CFR 21 Reports, reportable occurrences, configuration control drawings, restart test program, followup of open inspection items and licensee action on previous enforcement matters.
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Results: One violation was identified which met the' criteria in - Sectin V of the NRC Enforcement Policy for not' issuing a Notice of Violation.
This violation was not cited.
259, 260,.296/88-33-05: Failure To Follow Procedure GOI-100-2 (Paragraph 11.c.).
No deviations were identified.
One unresolved item * was identified:
259, 260, 296/88-33-03:
Unauthorized, Undocumented and Inadequate Maintenance Activity (Paragraph 5)
Three inspector. followup items were identified:
259, 260, 296/88-33-01:
Lack Of Locked Valve Criteria-(Paragraph 2.a.)
260/88-33-02: Questionable Relay Rating In' The Scram Discharge Volume Level Switches (Paragraph 4)
259, 260, 296/88-33-04: Limitorque Motor Operator Failures (Paragraph 7.a.)
The three IFIs and the URI described above are required to be resolved prior to the restart of Unit 2.
In paragraphs 9, 11.d and 11.e, a review of the status of the licensee's CCD program is documented.
The NRC inspector believes
'that the licensee's program is adequate to support fuel load, but additional review, prior to Unit 2 restart, is necessary to verify the quality of the drawings that result from this program.
In paragraph 2.b, examples of poor housekeeping practices are documented.
Although, the licensee appears to be initiating aggressive action to correct these problems, the resident inspectors
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will routinely follow the licensee's progress in this area.
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In paragraph 7, reviews of status reports on all 10 CFR 21 reports l
which still have outstanding activities remaining at fuel load are documented. The NRC inspector concluded that sufficient management attention had been focused on the question of open Part 21 Reports for fuel load and that the licensee had provided, with an adequate degree of confidence, a comprehensive summary of the open issues for
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Part 21 Reports.
Unresolved items are matters about which more information is required to
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determine whether they are acceptable or may involve violations or deviations.
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REPORT DETAILS
'1.
Licensee Employees Contacted:
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0. Kingsley, Jr., Senior Vice President,. Nuclear Power
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C. Fox, Vice President and Nuclear Technical Director
- J. Bynum, Vice President, Nuclear Power Production
- C. Mason, Acting Site Director
?G. Campbell, Plant Manager H. Bounds, Project Engineer R. McKeon, Assistant to the Plant Manager
- J; Hutton, Operations Superintendent
- R. Laverne, Maintenance Superintendent.
- D. Mims, Technical Services Supervisor G. Turner, Site Quality Assurance Manager
- P. Carier, Site Licensing Manager B. Schofield, Compliance Supervisor.
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A. Sorrell, Site Radiological Control Superintendent R. Tuttle, Site Security Manager L'..Retzer, Fire Protection Supervisor H. Kuhnert, Office of Nuclear Power, Site Representative T. Valenzano, Restart Director Other licensee employees or contractors contacted included licensed reactor operators, auxiliary operators, craftsmen, technicians, public safety officers, q'uality, assurance, design, and engineering personnel.
NRC Exit Interview Attendees
- D. Carpenter, Site Manager
- E. Christnot, Resident Inspector
- C. Brooks, Resident Inspector
- W. Bearden, Resident Inspector
- A. Johnson, Project Engineer
- Attended exit interview Acronyms used throughout this report are listed in the last paragraph.
2.
Operational Safety Verification (71707)
The NRC inspectors were kept informed of the overall plant status and of any significant safety matters related to plant operations.
Daily discussions were held with plant management and various members of the plant operating staff.
The NRC inspectors made routine visits to the control rooms. Observations included instrument readings, setpoints and recordirgs; status of operating systems; status and alignments of emergency standby systems; onsite and offsite emergency power sources available for at.tomatic
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operation; purpose of temporary tags on equipment controls and switches;
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annunciator alarm status; adherence to procedures; adherence to limiting conditions for operations; nuclear instruments operability; temporary
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alterations in effect; daily journals and logs; stack monitor recorder
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traces; and control room manning. This inspection activity also included numerous informal discussions with operators and supervisors.
General plant tours were conducted.
Portions o f.
the turbine buildings, each reactor building and general plant areas were visited.
Observations included valve positions and system alignment; snubber and hanger conditions; containment isolation alignments; -instrument readings; housekeeping; proper power supply and breaker. alignments; radiation area controls; tag controls on equipment; work activities in progress; and radiation protection controls.
Informal discussions were held with selected plant personnel in their functional areas during these tours, a.
Locked Valves I
While following up on an event that resulted in an emergency diesel generator being overheated due to a period of operation with - no l
cooling water from the. Emergency Equipment Cooling Water system, the NRC inspector began orobing into locked valve criteria.
The two valves involved in the event (one on the EECW north header and one on the EECW south header) were inspected in the field and were found to have locking chains hanging from the valve bodies but not locked through the valve handwheels. Neither the drawirigs nor the Operating Instruction valve checklist required these valves.to be locked, but it was obvious that at some time in the.past the valves had been locked. The NRC inspector questioned the licensee's criteria used in determining which valves in the plant should be locked in order to independently review the criteria against the two valves in questicn.
The licensee was unable to determine what criteria were used in establishing the plant's locked valve program. The licensee was also unable to determine what criteria would be applied to future modifications which might install new valves and establish new locking requirements.
During discussions with licensee management representatives, both the NRC inspector and licensee representative agreed that criteria should exist.
Final resolution of this issue will be tracked as Inspector Followup Item 259, 260, 296/88-33-01, Lack af Locked Valve Criteria, and should be resolved prior to restarting Unit 2.
Examples of unique features of any valves which should be considered
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in development of the criteria are as follows:
Manual isolation valves Valves that are inaccessible for normal operations or visual checks (about 25 feet in the overhead)
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Valves.that have a history of manipulation' errors'such as those
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'. incapable.of performing-their intended function Valves with no valve' positior. indication in the main control'
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Valves for which there is no ' process flow' instrumentation in the main control room that would warn of improper valve position b.
Housekeeping The NRC inspectors conducted a number of general tours of the Unit 2 Drywell for the purpose of observing overall conditions.
Various work.was ongoing including hanger and_ small bore piping modifications, electrical cable tray repairs, and electrical cable replacement / terminations.
The NRC inspectors noted the following conditions which require corrective actions by the licensee prior to Unit 2 startup:
General housekeeping throughout the Unit 2 Drywell was poor. Dirt, grit, and debris from modification work were found.
I over much of the floor space and on cables inside of cable
trays.
One cable tray, HX ESI, was noted to contain a loose hold down clamp and loose bolting.
No work appeared to be ongoing which could have explained this condition.
The NRC inspectors discussed the identified conditions with the Plint Manager. He stated that he was also not satisfied with the overall housekeeping in the Unit 2 Drywell and that cleanup efforts and walkdowns to correct any problems were already planned.
During the discussion the Plant Manager was informed that an NRC resident inspector would accompany operations personnel during the final closecut inspection of the Drywell prior to restart.
The NRC inspector toured the Residual Heat Removal Service Water Building on November 17, 1988, af ter the day shift had ccmpleted their maintenance activities, and noted that post-shift cleanup activities were inadequate, leaving the housekeeping in the area unacceptable.
Cigarette butts were prevalent, as were disc arded cigarette wrappers.
TVA internal public affairs bulleti1s were discarded on the floor and a deficiency tag had become separated from its affected component and was laying loose or-the floor.
Paint brushes and discarded labeling tags were found resting on a valve bonnet. Styrofoam cups, plastic spoons and plastic bags were lying about.
Several of the items of trash had slipped through the protective grating covering the sump and could potentially foul the sump pump.
The licensee was informed during a management meeting that these conditions were unacceptable and that immediate corrective action should be initiated.
No violation will be issued since the
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. licensee is' initiating aggressive action to correct housekeeping problems and should have all plant areas adequately cleaned up-prior J
to fuel load.
No violations or deviations were identified in the area of Operational-I Safety Verification.
3.
Modifications (37700)
An NRC inspector observed ongoing work associated with work plan 2117-88
which involved replacement of coaxial nuclear instrumentation cables I
associated with the Local Power Range Monitoring system located in the Unit 2 Drywell.
Work observed included cable termination, stripping, soldiering activities, and Quality Control inspection of ongoing work. No-problems were identified with the WP or the ongoing work.
The NRC inspectors continued to follow the ongoing work associated with-Engineering Change Notice E-2-P7131. This modification reroutes the Unit 2 reactor water level reference legs in order to reduce the routing of the reference legs inside the drywell.
This is intended to minimize the
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potential for erroneous reactor water level indications resulting from
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post-accident boiling in the reference legs.
When completed, this NUREG-0737, Item II.F.2 related modification is intended to satisfy actions identified in Generic Letter 84-23 as listed in the TVA Nuclear Performance Plan.
The NRC inspectors performed a physical walkdown of selected portions of the rerouted piping located inside and outside the Unit 2 Drywell. This walkdown included observation of the sections of tubing routed inside of the Containment-Atmospheric Dilution ducting anci abandoned Residual Heat Removal penetration X-17. At the time of the inspection the piping work was complete with the welding accepted bv licensee QC personnel, but required hanger work had not been performed and insulation up to the condensing pots had not been installed.
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An NRC inspector noted that the modification, as installed, appeared to satisfy all recommendations associated with the instrumentation line locations that are contained in General Electric Service Information Letter (SIL) No. 470, Reactor Water Level Mismatches, with the exception of recommendation number IC. This recommendation stated that the optimum condensing chamber centerline location is at least 3 inches above the reactor pressure vessel nozzles and 3 feet horizontally from the RPV, thus providing optimum reliability and performance. The actual locations are at 2' 10" above both RPV nozzles and 7'4" and 8' 8" horizontally from the RPV nozzles.
The NRC inspector reviewed Bechtel North America Power Corporation letter dated November 15, 1988 and DNE Quality Information Request, QIRNEBWBN87345, which documents the licensee's engineering evaluations which justify water level instrument line locations and the current locations of the condensing chambers.
In these evaluations, the licensee determined that due to obstacles and interference and in keeping with other GE and Code requirements, it was not possible to achieve the i
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recommended GE optimum locations'. However, since the actual locations did-meet minimum pipe slope requirements of 1/2 inch per foot, and the TVA Design Standard 05-E18.3.11 which gives a maximum. length for sens'ing lines
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between pressure tap and condensing chamber of 131/4 feet, the licensee!
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determined that this was an acceptable configuration.
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l The activity inspected in this area appears to be effective with respect-l to meeting the objectives of the NUREG-0737 modification.
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No violations or deviations were identified in the Modifications area.
4.
Surveillance Observation (61726)
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The inspector observed a'nd/o-reviewed the surveillance instructions described below.
The inspection consisted of a review of the procedures for technical adequacy and conformance to technical specifications, verification of test instrument calibration, observation of the conduct of the test and the. removal from service and return to service of the system, and a review of test data.
The inspectors verified that limiting conditions for operation were met, that testing was accomplished by qualified personnel, and that the SI was completed at the required frequency.
On November 1,1988, the NRC inspector observed SI 4.1.B.8(B), "RPS High Water Level Scram Discharge Tank Calibration."
This was the first performance of this calibration following installation of these new level switches as an environmental qualification upgrade. The procedure was found to be adequate and it was properly executed by the instrument technicians. During performance of the SI, the NRC inspector noted that a pen-and-ink write-over had been made on the manufacturers printed label on relay R2 of 2LS85-45H. The contact current rating printed on the Potter &
Brumfield label was 2 amps, but it had been changed to 5 amps. Identical relay R1 had no handwritten change made to the label and was a 5 amp relay. The NRC inspector requested that the instrument technicians open the junction box for redundant instrument 2LS85-45M for inspNtion. The labels for both relay R1 and R2 on this instrument had been changed in handwriting from 2 amps to 5 amps. The NRC inspector reviewed contract documents associated with the new level switches and found that the I
purchase order specified 1 - 5 amp contacts at 120 VAC. A similarity analysis in the EQ documentation stated that the qualified relay was a 10 amp relay and the qualification test procedure specified that a 10 amp relay was the relay that was qualified. A review of a vendor bulletin indicated that the standard commercial version of this level switch contains 2 amp rated contacts.
The licensee was asked to investigate these apparent inconsistencies and determine which relay or relays are acceptable for this application.
This will be tracked as Inspector Followup Item 260/88-33-02, " Questionable Relay Rating in the Scram Discharge Volume Level Switches" pending resolution by the licensee. This item must be resolved prior to the restart of Unit 2.
No violations or deviations were identified in the area of Surveillance Observation.
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5.
Maintenance Observation (62703)
Plant maintenance. activities of selected safety-related systems and components were observed / reviewed to ascertain that they were conducted in accordance with requirements. The following items were considered during this review:
the limiting conditions for operations were met; activities i
were accompitshed using approved procedures; functional testing and/or
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calibrations were performed prior to returning components or systems to service; quality control records were maintained; activities were accomplished by qualified personnel; parts and materials used were properly. certified; proper tagout clearance procedures were adhered to;
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Technical Specifications were adhered to; and radiological controle were
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implemented as required. Maintenance requests were reviewed to determine the status of outstanding jobs and to assure that priority was assigned to safety-related equipment maintenance which might affect plant safety.
During a routine ' tour on November 7,1988, the NRC inspector observed improper. thread engagement on 5 of the 8 bolts that secured a flange to a test connection between the Unit 2 Refuel Zone inboard and outboard suppiy dampers (2-FCO-64-6B and 2-FCO-64-5B).
This improper condition was created by undersized bolts which resulted in less that half of the threads on the nut being engaged by the bolt.. This flange provides a boundary for secondary containment over the 6-inch diameter test port.
The licensee was asked to investigate this condition and no documentation could be located for a maintenance activity. However, the licensee deter-mined that personnel performing sheet metel work in a nearby location noticed that five bolts were missing on the flange and installed the short bolts thinking that short bolts were better than none.
The licensee initiated an MR to repair the deficient condition and counselled those involved in the maintenance. The NRC inspector questioned whether this was a random occurrence or if other examples of this type of activity were still occurring.
This will be tracked as Unresolved Item 259, 260, 296/88-33-03, " Unauthorized, Undocumented and Inadequate Maintenance Activity," pending final evaluation by the licensee and review by the NRC.
This item is requiced to be resolved prior to restart.
No violations or deviations were identified in the area of Maintenance Observation.
6.
System Return To Service (71711)
In preparation for fuel reloading, the licensee intends to complete a systematic evaluation of known restart issues and deficiencies, establish prerequisites, and complete specific work required to ensure fuel loading is conducted in a safe and reliable manner.
For each system required by TS to support fuel loading, the licensee will complete modifications, correct known deficiencies, and complete work requests that impact the safety function or operability of the system. For those NPP, Volume III,
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7-special programs where the. discovery and corrective action implementa '
tion is incomplete, 'the licensee will prepare written justification
.for concluding that system operability is not likely. to be impaired by undiscovered' deficiencies or unfinished corrective actions.
The 'NRC review of TVA's return to service activities consists of a sampling of.the following aspects of the program:
The licensee's position papers-developed to justify the acceptability of fuel load (FL) given.the status of the major NPP programs such as Electrical Issues, Seismic, Instrument Line Slope, and Procedure Upgrades The scope of systems required for FL and system boundaries required to be reviewed under the System Pre-operability i
Checklist (SP0C) process System design completion verification as controlled by the DNE system acceptance evaluation process System alignrent, status assessment, and operability determination System configuration control and control over special operating conditions following declaration of system operability The licensee developed and began implementation of a management checklist to ensure readiness for fuel loading.
Site Director Standard Practice 12.9, Fuel Load Prerequisite Checkli st, created a Fuel Load Review Committee (FLRC) which is responsible for implementation of the procedure and checklist. The committee has been tasked with reviewing all SPOCs for adequacy of exception and deferral justifications, verifying that all organizations have completed a readiness review, and reviewing non system-related issues which need to be addressed prior to fuel load but which are not captured in the SP0C process.
SDSP 12.9 contains, in Attachment A, the fuel load issue criteria which is to be used in evaluating whether an issue must be considered prior to fuel load. This criteria i s very similar to the restart criteria established by the licensee in the NPP which was accepted by the NRC. The major distinction between the fuel load criteria and the restart criteria is that the scope for fuel load applies only to those systems designated in the SDSP as required for fuel load.
The SDSP also contains, in Attachment B, the
criteria to be used for deferral of an issue which has been determined to be necessary for fuel load should it not be possible to completely resolve the issue prior to fuel load.
Written justification is required for all deferrals.
The NRC inspector observed a meeting of the FLRC on November 17, 1988, during which the System 18, Fuel Oil System, SP0C was reviewed.
The committee determined that the engineering statement for return to service (the System Plant Acceptance Evaluation) needed to be updated based on i
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recent changes to the process brought on by Engineering Assurance audit findings, and that two Condition Adverse To Quality Reports related to a different EA review had been inappropriately coded as restart items as
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opposed to fuel load items. The committee took action to correct these concerns and made plans to review the SPOC package for System 18 again after it is ready for fuel load.
The NRC inspector concluded that the FLRC was adequately fulfilling its responsibilities as specified in SDSP 12.9 during the observed meeting and that the Fuel Load Prerequisite Checklist provides an adequate mechanism for ensuring that the status of those non system-specific issues is reviewed prior to fuel load.
No violations or deviations were identified in the System Return To Service Area.
7.
10 CFR Part 21 Reports (36100)
The NRC resident inspector had previously requested from licensee management a report on all 10 CFR Part 21 Reports which will have outstanding activities remaining at fuel load. The following status was provided on open Part 21 Reports (where available, other tracking systems designations are used to identify the Part 21 report subject):
a.
NRC Information Notice 87-08 This report concerned degraded motor lead insulation on Limitorque DC motor operators. Ten motor operators on Unit 2 were susceptible to the failure described in the report. Seven motors have been replaced to alleviate the concern and the remaining three motors were judged to be acceptable as is. Outstanding activity remaining for this Part 21 Report involved evaluation of the condition on the Unit 1 and Unit valves which will not be completed until after restart of Unit 2.
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The NRC inspector asked the licensee whether any mechanism had been established to flag potentially affected Unit 1 and Unit 3 motors to prevent their inadvertent use on Unit 2 in the case of an unrelated failure on Unit 2 that results in scavenging Unit 1 or Unit 3 motors as a replacement. The licensee indicated that a procedure was being developed to control scavenging Unit 1 and Unit 3 components. This issue along with a similar issue identified in paragraph 7.e and 7.f will be tracked as Inspector Followup Item 259, 260, 296/88-33-04,
"Limitorque Motor Operator Failures," to ensure the program controls are adequate to prevent inadvertent use of deficient components
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This item is required to be resolved prior to Unit 2 restart.
b.
Diesel Bearings l
The Bhv DG vendor (Morrison-Knudson Co., Inc) informed TVA, by letter l
dated September 9, 1987, that some main and connecting rod bearings l
were defective. The licensee determined that none of these items had been installed.
The defective bearings were located in storage,
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tagged to prevent inadvertent' use, :and segregated pending final.
disposition. -The only activity remaining for closure of this issue wu for. the' licensee to return the defective parts to the vendor.
The status. of this issue 'was therefore, acceptable for Unit 2 restart.
c.
NRC Bulletin 88-03 HFA Latching Relays i
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The licensee partially completed the activities recommended by -the vendor ~ in this Part 21. Report and planned to perform the remaining inspection after fuel load but before restart of Unit 2.
The vendor recommended two checks be performed on the affected HFA latching relays:
(1) contact carrier clearance measurement and (2) leaf spring tension measurement.
Item (1) was completed for all 125-
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relays on site and all met the minimum 1/32 inch clearance criteria.
Item -(2) requires extensive electrical outages, which were to be i
performed after fuel load.
The licensee performed. an engineering
.j evaluation based upon the function of the installed relays and the
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failure mechanism (the relays actuate properly but fail to
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mechanically latch in the actuated state). The evaluation concluded
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that a failure of a relay to latch would not prevent the automatic tripping and manual restart of equip nent.
The licensee also confirmed that for safety related relays, perioiic testing is, performed that would-detect a failure with the exception of auto start lockout relays associated with the emergency DG stop circuitry.
The licensee stated that a failure of this relay to latch would not prevent an emergency stop of the DG. The NRC inspector reviewed the licensee's evaluation and concluded that it acceptably addressed the technical aspects of the concern for Unit 2 fuel load.
d.
LER 85-51, Deteriorated Cable in the RPS System This Part 21 Report was generated by TVA upon finding a deteriorated cable in a Reactor Protection System panel supplied by GE. The cable insulation showed evidence of overheating and was cracked.
The licensee replaced the deteriorated 6AWG cable and similar cables in other trains on all three units with higher capacity 2AWG cables.
The licensee is awaiting a final engineering evaluation from the vendor before closure of this item can be accomplished.
This item must be resolved prior to Unit 2 restart.
e.
LER 85-17, Unqualified Valves in H 0 Analyzer
The licensee determined that teflon material in H 0 analyzer valves
could not withstand the postulated accident radiation environment.
The valves on Unit 2 have been replaced with qualified valves.
However, the Unit 1 and 3 valves remain unqualified.
Implementation of programmatic controls to prevent scavenging of Unit I and 3
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components for use in Unit 2, as discussed in paragraph 7.a also
applies to this Part 21 report.
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LER 85-15 Inadequate Voltage to HPCI Controller
- The licensee determined while ' performing special tests on the ?igh Pressure Coolant Injection control circuitry that the Electronic Governor Motor control box was not being supplied with it's minimum i.
l voltage requirements.
The cause was attributed to the equipment supplier not being in -compliance with the contract documentation.
The licensee performed hardware modifications and additional analyses to correct this situation for Unit 2.
Unit 1 and Unit 3 problems have not yet been fixed. Control of items scavenged from Units 1 and 3 must alse be established for this Part 21 Report and this issue must be resolved as part of the IFI identified in paragraph 7a.
g.
NRC Information Notice 86-81, MSIV Valve Springs The licensee completed inspection of all installed and spare valve springs and found 2 cracked springs on Unit 1 Mcin Steam Isolation Valves (MSIVs) and son crack indications on spare springs in stock.
Repair of the Unit I springs had not been completed and final disposition of the spares had not been made.
Several discussions were held between the NRC inspector and licensee-representatives in the Nuclear Experience Review (NER) program regarding the inability to sort the NER data base for Part 21 Reports. In order for the licensee to provide a summary on Part 21 Reports, a lengthy review of all items in the data base was conducted.
Some uncertainty was present regarding completeness on any licensee statement on Part 21 concerns, Additionally, internally generated Part 21 Reports have a separate data base to be searched which likewise cannot be sorted for only Part 21 concerns.
The licensee indicated that they were initiating changes to include a unique identification on Part 21 related items such that in the future, sorts on those issues can be accomplished.
The NRC inspector concluded that sufficient management attention had been focused on the question of open Part 21 Reports for fuel load and' that the licensee had provided, with an adequate degree of confidence, a comprehensive summary of the open issues for Part 21 Reports.
No violations or deviations were identified in the area of Part 21 Reports.
8.
Reportable Occurrences (90712, 92700)
The licensee event reports listed below were reviewed to determine if the information provided met NRC requirements.
The reviews included:
adequacy of event description, verification of compliance with 1S and regulatory requirements, corrective action taken, existence of potential generic problems, reoorting requirements satisfied, and the relative safety significance of each event.
Additional in plant reviews and discussion with plant personnel, as appropriate, were conducted, i
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-(CLOSED, Unit 2 and Unit - 3 only) LER No. 260/85-20,- Unqualified >
d Reactor Protection System Instrument Panels-
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On -_ June 27, 1985, the.licentee's' configuration control program -
identified that-eight. local RPS panels on each Unit were identified'
P as not beir,g. constructed per design drawings.
The as-constructed configuration of.the panels onl Unit 3 were.found to be. seismically-qualified in an August, 1985 engineering analysis. The Unit 1 RPS panels will be analyzed..and c,orrective action completed prior to restart of Unit 1.
The analysis of the Unit 2 RPS panels determined r
that six of the panels were seismically qualified but the remaining two panels (25-5-001 and 25-6-001) were not qualified. The analysis showed ' that the ' material of two panel anchor bolts could not be identified and it was conservatively determined that a failure would -
occur.
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The-licensee's corrective action for Unit 2 was to modify RPS panels.
25-6-001 and 25-5-001.
DCN W1097A and ECN E-2-P7082 were completed on October 6,.1988, and October 18, 1988,- respectively.
The NRC inspector reviewed and evaluated the occumented corrective actions, observed the modified panels in the Reactor Building, and considered the action appropriate. This LER is closed for Unit 2 and 3 only, b.
(CLOSED)
LER No. 260/86-11, Rev. I and Rev. 2, Reactor Protection System Trips Due to MG Set Problems On July 18, 1986, the Unit 2 RPS 2A Motor Generator (MG) set tripped causing a half scram, partial primary containment isolation, and secondary containment isolations.
A second RPS MG set problem occurred on July 24, 1986, when the Unit 1 RPS MG set caught on fire and tripped causing a half scram, partial primary containment isolation, and secondary containment isolations.
The licensee determined that the cause of the MG set trip and fire was excessive dust buildup on the motor's intake and exhaust vents which precluded proper motor coil ventilation cooling.
' As 'a precautionary measure, the licensee switched the MG set offsite power source from the 161 kilovolt source to the 500 kilovolt source because the 161 kilovolt source runs at the high amperage end of the alloyable 480 volt band. This increased voltage created a noticeable amperage decrease in certain RPS MG set motor windings.
Switching the offsite power sources resulted in the RPS MG set motors running 10 degrees F cooler. The licensee also implemented a monthly and a six month preventive maintenance procedure to ensure that the MG set intake and exhaust vents are properly cleaned.
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The NRC inspector reviewed and evaluated the licensee's corrective actions, including the completed preventive maintenance procedures.
The corrective actions were adequate ar.d this LER is closed.
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(CLOSED) 'LER 259/86-18', Unit 2 only, Neutron Monitor Surveillance L1 Test Deficiencies-
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On. April ' 18, 1986,.during performance of the surveillance upgrade program,. a licensee.. instrumentation engineer reviewing..the.
Intermediate Range Monitoring ~(IRM) SI determined that;the'SI did not-completely. fulfill TS requirements.
Specifically, the TS required?
the 'IRM.-high' flux scram to be functionally checked ~ once per week during ! refueling and prior to startup, and required the rod block
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function to be. checked once per month. The SI was conducted with the
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IRM '. channel in "inop", which in itself - causes a trip signal.
Therefore,.the test was inadequate because it did not actually verify the individual trip signals to completion (half scram or rod block).-
The licensee determined that the root cause was an oversight by the instrument personnel in formulating the SI.
The licensee's; corrective actions for Unit.2 were to modify the IRM channel.with an "inop" bypass switch to allow 8 rect testing of circuit elements, re' vise the IRM SI to incorporate the "inop" bypass function, and complete the review and upgrade of the remaining neutron monitoring sis as part of the procedures upgrade program for Unit 2.
These actions were completed by August 31, 1988.
The NRC inspector reviewed and evaluated the above documented.
licensee corrective action and considered the action adequate to support Unit 2 restart. This LER is closed for Unit 2 only.
d.
(CLOSED) LER 259/88-24, Unplanned Isolation of Secondary Containment Due to Actuator Diaphragm Rupture and Subsequent Supply Damper Closure.
On August 28,,1988, a refueling zone isolation occurred when the pressure differential between the refuel zone and atmospheric pressure exceeded the negative pressure setpoint of one-half inch of water. Tne pressure differential was caused by the closure of a Unit 1 secondary containment isolation damper in the refuel zone ventilation supply line while the exhaust fans were running.
The isolation was caused by the rupture of the diaphragm in the damper actuator because the damper is designed to fail in the closed position on loss of air pressure. The diaphragm had been in service for over four years and the preventative maintenance program had set the frequency for replacement of the diaphragms at every refueling outage.
The units have been shut down since early 1985 and the
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preventative maintenance on these dampers had been deferred until a time closer to unit restart.
The licensee considered this an end-of-life failure. The licensee also determined that the diaphragm had been installed backwards. Based on discussions with the
manufacturer, this could have accelerated the failure due to stresses induced by bending the diaphragm in the opposite direction from that intended.
At the time the diaphragm was originally installed, a i
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detailed procedure specifying the proper orientation did not exist.
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.The licensee's corrective actions involved the repair and testing of the failed damper, issuing a' maintenance procedure which provided a detailed description _ for ' diaphragm installation and ' orientation, revision of the preventative maintenance frequency for all secondary:
containment isolation dampers to once every 24 months, and on October 24, 1988,- replacement of all secondary. containment. isolation damper-d',phragms on Units 1, 2, and 3.
The NRC inspector reviewed and evaluated the documented licensee corrective action and considers the action appropriate to support Unit 2 restart. This LER is closed.
No violations or deviations were identified during the review of LERs.
The inspector concluded ihat the LERs we< < adequately assessing root causes.
9.
Configuration Control Drawings (39702)
Volume 3 of the NPP,Section III, paragraph 2.0, stated that the licensee had initiated action'to ensure that the actual plant configuration is reflected on plant documents and conforms to the design requirements as established by the Design Baseline and Verification Program. The program was to develop the design basis documents for systems or portions of systems covered by the pre-restart phase of the program as listed in Table III-3 of the NPP.
These systems were selected from. descriptions of,
systems required to mitigate FSAR Chapter 14 Design Base Accidents and provide for safe shutdown.
One of the outcomes of the DBVP. was development and issuance of new Configuration Control Drawings. A CCD.is a single approved drawing which depicts the latest engineering plant configuration for all operations and engineering activities.
CCDs are unit specific and when issued will replace both the as-constructed drawings used by operations personnel and the as-designed drawings used by engineering personnel. Drawings that are to be converted to the new CCDs are either primary drawings (drawings necessary to start up, operate, and shutdown the plant under both normal and emergency conditions) or critical drawings (drawings depicting system features which are used by the TSC to determine system operation and function and make recommendations for mitigation of the consequences of an accident during a radiological emergency). Additionally, the drawings are one of the following types:
Flow diagrams Contro' f'agrams Element (ry Schematics Single line diagrams An NRC inspector met with members of licensee management for the purpose
l of determining the status of the existing program for completion of the CCDs. The licensee representatives stated that approximately 1500 primary
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Of these, 485 new CCDs associated with 47 systems will be issued prior to
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the restart of Unit 2.
This commitment is based on the Safe Shutdown
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Analysis performed as part of the DBVP.
An additional 100 secondary drawings not in the control room area are planned for CCDs prior to the restart of Unit 2.
Furthermore, a separate commitment exists to issue a
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i CCD as part of the normal design process for any primary or critical drawings affected by modification work. The end product of this effort would be the eventual replacement of all primary and critical drawings with CCDs.
As of November 1, 1988, 185 CCDs were issued.
The licensee made some major modifications in their program during January,1988, which resulted in changes in the method used to reconcile any identified drawing discrepancies, scope of future work, and schedule for completion of the program.
The licensee decided to change the program such that no future drawings would be issued prior to validation, i.e.
field verified and design evaluated.
Prior to the change the as-designed drawing remained in use after CCD issuance until validation was complete.
Additionally, the method of reconciliation of drawing discrepancies was changed to consider all differences between the as-constructed drawings and the as-designed drawings. Differences between the two drawings are identified and punchlisted for resolution. Since the as-constructed drawings had been verified as part of the onsite field engineering service phase of the DBVP, and the as-designed drawings had been evaluated by DNE personnel, elimination of any differences would allos replacement of both drawings by a single CCD. Issuance of the CCD is the final step in the process since the licensee had also changed an earlier plan to issue CCDs prior to validation. Each issued CCD will then contain two references as follows:
Referenced document which provided the reconciliation between the as-constructed and as-designed drawings.
Both drawing numbers superseded by issuance of the CCD.
Due to various concerns associated with drawing usage among operations personnel CAQR BFP88-0152 was written to disposition the concerns.
The licensee management representatives stated that operations personnel are now involved in the process and satisfied with the program.
For CCDs not planned until after fuel load, all outstanding Drawing Discrepancies and associated DCNs have been reviewed for fuel load applicability by Ebasco and Bechtel. All identified as needed will be resolved prior to fuel load.
Existing system drawings marked by operations personnel with fuel load boundaries were used to make this determination.
No violations or deviations were identifie m; w
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"A 10.
Restart Test Program (RTP) (99030B)'
.The inspector attended RTP status meetings, reviewed RTP test procedures, observed RTP tests and associated tests performances, reviewed. RTP test results, including test exceptions and attended selected Restart Operations Center (War Room) and Joint Test Group meetings. The following are' the RTP activities and associated activities monitored and status of testing.during this reporting period:
a.
RTP Program Status and Restart Test Performances The inspector maintained cognizance. of ongoing restart test.
activities, and monitored particular activities in detail as appropriate.
Speci f'ic inspection observations are discussed in paragraphs 10.b and 10.c below.
The following information summarizes the status of procedures performed, and the hardware related test exceptions identified by the RTP group, at the time of the inspection:
Required for Required for Fuel Load Criticality Total Procedures Issued and Approved
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Tests completed as of 11/30/88
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28 Completed tests approved by the plant manager
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Unresolved Hardware TEs
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The following restart tests were in progress during this reporting period:
o RTP-023, Residual Heat Removal Service Water l
o RTP-030, Diesel Generator and Reactor Building Ventilation o
RTP-031A, Control Building HVAC (Water Side)
o RTP-031B, Control Building HVAC (Air Side)
o RTP-047, Turbine Generator / Electro-Hydraulic Control o
RTP-064A, Primary Containment Isolation o
RTP-067, Emergency Equipment Cooling Water
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o RTP-069, Reactor Water Cleanup o
RTP-070, Reactor Building Closed Cooling Water
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RTP-073, High Pressure Core Injection-o RTP-085, Control Rod Drive o-
.RTP-099, Reactor Protection System.
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o RTP-ICF, Integrated Cold Functional The above tests were either in the prerequisite stages, - system performance stages, initial RTP Group reviews, DNE reviews or final JTG reviews.
b.
Specific Test Witnessing and Results Evaluation The NRC Inspector reviewed the.results of RTP-069, Section 5.3, Fuel Pool Cooling Anti-Siphoning Check Valves Operability Test as well 'a~s the original pre-operational test performed and signed off on January 4, 1974. The original test called for isolating the two fuel pool coolers and the two pump suctions, draining down that portion of the~
system, removing the bonnett of two valves located within the drained down boundary, attaching a hose to the bonnets and with air still in the system, attempting to establish a siphon.
The restart test required that the system be filled and vented, the two pumps be secured, the common suction valve for the pumps be closed, and that five one inch drain valves be opened to start a siphoning action.
The initial RTP test was not successful in that the fuel pool level continued to fall past the acceptance criteria.
The RTP Test Director issued a test exception (TE-03) which called for the check valves to be removed and reworked.
A modification was made where a nipple was installed in the check valve body which would break the siphon.
The RTP section was reperformed successfully.
No violations or deviations were identified in the Restart Test Program Area.
l 11.
Licensee Action on Inspector Followup Items (92701)
a.
(OPEN) Inspector Followup Item (259, 260, 296/84-32-02), Torus Level Instrumentation Problems Between Separate Level Detectors The inspector reviewed ECN P5434 and WPs 2186-87 and 2187-87 which j
indicated that all field work was completed on level transmitters J
64-54 and 64-66 on March 13, 1988.
This item is adequate for fuel load; however, this item will remain open pending review of the post d
l modification test associated with these work packages and it must be closed prior to restart.
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(CLOSED) Unresolved Item (259, 260, 296/86-14-04), Wrong Impeller on
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Five RHRSW/EECW Pumps
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In April 1986, the licensee initially believed that the 7 pump.
replacement impe11ers ordered 'for the Residual Heat-Removal. Service
~ Water / Emergency Equipment Cooling Water pumps were of j the. wrong design.. When - the pumps were tested, they did not meet the FSAR.
requirement on total head, where each pump.' is rated at 400 horese-power with a capacity of 4500 gallons per ' minute at 275-foot total head.
However, on November 19,-1986, at the pump vendor's test lab, a RHRSW pump with the replacement impe11ers was tested. and it met the original design capacity of 4500 gallons per minute at 275-foot total head as described in the FSAR.
In a letter dated October P.4,1988, the pump vendor certified that there was~ no change in the replacement -impeller design that would effect the hydraulics as originally designed.
The vendor further-stated that the location of the balance holes was changed, but that this change would have absolutely no effect' on the hydraulics of the -
impeller.
The. licensee obtained a new baseline pump performance curve for the rebuilt pumps, Lwhich met the TS operability requirement. of 4500 gallons per minute. The new baseline pump performance curves will be used for all future testing or until-the pumps are rebuilt based on not meeting the baseline pump performance curves.
Based on the above, the licensee determined that the pumps having the new impellers installed are capable of meeting their design' function, if the system is flow-balanced by testing, The TS requirement of 4500 gallons per minute is achievable using the new baseline pump -
performance curves.
The NRC inspector reviewed the licensee's evaluation associated with this item, including the documented correspondence between the licensee and pump vendor, the pump testing, and the baseline pump performance curve testing.
The licensee's corrective actions 'and evaluation were acceptable. This item is closed.
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(CLOSED) Inspector Followup Item 259, 260, 296/86-22-01, Control of Heavy Loads During a TVA Quality Assurance (QA) audit conducted from March 24 through April 4,1986, the licensee identified deviations from NRC commitments.
The four major areas of deviation identified by the licensee are listed below:
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Commitments made in response to NUREG-0612, Control of Heavy Loads at Nuclear Power Plants, were not being implemented in a timely manner.
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Requirements of.-NUREG-0612' that should have' been implemented were not currently being met by the plant.
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Previously' identified deficiencies with control of plant rigging.
equipment were recurring.
Plant instructions that-implement. upper-tier TVA. requirements in
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support of NUREG-0612 were not fully adequate.
Also, during the time-frame of the identification and correction of.
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the above licensee-identified deviations, an NRC' inspector identified on June 20, 1986, that a stationary electric hoist.used to place fuel channels over new ~ fuel assemblies had not ' been load tested as required by G01-100-2, New Fuel Operations, which included required inspections of stationary electric hoists.
The licensee took immediate corrective action to load test the hoist, and'to correct the problems identified in the TVA audit.
As a result of OSP management review, this issue meets the discretionary enforcement criteria' of 10 CFR Part. 2, Appendix C.,Section V.G.I.
A notice of-
-violation will not-be issued because the problems were primarily l
licensee identified and the corrective action has been satisfactorily completed.
This item will be documented as Licensee Identified Violation (LIV) 259, 260, 296/88-33-05, Failure To Follow Procedure G01-100-2.
No further review is necessary.
The licensee's corrective ' action for the -licensee identified deviations above are listed below:
The licensee completed a review of commitments to NUREG-0612 and
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implemented those commitments through September 26, 1986, revisions of Mechanical Maintenance Instruction (MMI) 119, Lifting Instruction for the Control of Heavy. Loads and MMI-102, Rigging Equipment and Portable Hoist Program.
The licensee completed training sessions associated with
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NUREG-0612 for all plant crane operators.
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The licensee revised the drawing of the safe-load paths and critical lifting zones on the plant's refuel zone to comply with
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The licensee incorporated all rigging equipment into MMI-102.
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The licensee removed the ability to lift 125 percent of the maximum rated capacity of the reactor building crane in the critical lifting zone from MMI-119.
The licensee removed rigging equipment identified as damaged or
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unacceptable for service.
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The licensee verified that no. defective or fiber-core slings were in use.
The licensee incorporated ANSI B 30.9 criteria into MMI-102 for
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wire-rope slings.
The licensee revised MMI-102 to contain all inspection criteria
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for portable lif ting. equipment,. slings, and other rigging hardware.
.The NRC inspector reviewed and evaluated the above documented corrective action and considers it appropriate to support Unit 2 restart.
This item is closed.
d.
(OPEN) Inspector Followup Item 260/87-09-05 Unverified Portions on Configuration Control Drawings The NRC inspector identified a concern that CCDs would be issued with.
unverified portions. Only one system CCD (System 86, D/G Air Start)
had been issued on a trial basis.
The inspector noted that the drawing contained various unverified portions and an interface with one other system which had not been verified. That system interface was not clearly marked to denote the boundary. Additionally, there was no apparent plan for removing unverified portions from the
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drawings.
The NRC inspector met with members of licensee management to determine the status of the CCD program. A detailed discussion of the results of that mceting are included in paragraph'9. The current program and' schedule for completion of the new CCDs is acceptable for fuel load. However, further inspection is necessary prior to restart of Unit 2 in order to verify adequacy of the drawings and ensure adequate information is provided to operations personnel to allow safe startup and operation of the unit. To assist in this review, the licensee will need to provide to the NRC inspector the following:
Copy of any associated QA or EA audits parformed in this area Documentation to support closure of CAQR BFP88-0152 Any revisions to the CCD completion schedule
This item will remain open pending review of the program during
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upcoming reporting periods.
e.
(CLOSED)
Inspector Followup Item 260/87-09-06, Validations of Configuration Control Drawings The NRC inspector identified a concern that CCDs would be issued without being validated. The validation process was to occur after drawing issue with each drawing receiving a validation stamp to
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Additionally, there were plans to perform only
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partial validation on some drawings.
Since no CCD validation had I
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the NRC inspector was concerned'about confusion or misinterpretation;
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during drawing usage.
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Subsequent to the original inspection, the licensee has changed the CCD. program such that drawings are not issued prior to validation.
Since this ' change eliminates the possibility ' of confusion or misinterpretation due to lack of drawing validation,- the NRC inspector agrees that the issue is no longer a concern. This item is-closed.
f.
(OPEN)
Unresolved. Item 259, 260, 296/87-27-03, Standby Gas Treatment System (SGTS) Blower - Train C Seismic Qualification Most of the aspects of this concern were inspected in May 1988 and reported in Inspection Report 259, 260, 296/88-16.
The remaining issue related to failed glue on one of the neoprone seismic bumpers which was repaired by the licensee and confirmed by a visual inspection performed by the NRC inspector.
Licensee actions were acceptable for fuel load. This item remains open pending NRC review-for enforcement action or discretion pursuant to 10 CFR Part 2, Appendix C, V.G.2.
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(CLOSED) Inspector Followup Item 259, 260, 296/88-08-01, Operators Need Training on the Modified Simulator -d Revised Unit 2 Procedures During the March, 1988, training inspection of the licensed operators in the fourth accelerated requalification group, the NRC inspectors were concerned that the operators might not receive training on the updated Unit 2 simulator and the updated and revised Unit 2 procedures prior to Unit 2 restart.
The licensee action was to complete the Browns Ferry simulator modifications on May 22, 1988, to make the simulator similar to Unit 2 instead of Unit 1.
The first cycle of operator training on the Unit 2 simulator using the upgraded and revised Unit 2 procedures was completed on August 12, 1988, in order to prepare for the restart of Unit 2.
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The NRC inspector reviewed and evaluated the documented licensee action and considers the action adequate.
This item is closed.
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(CLOSED)
Inspector' Followup Item 260/88-18-06, Deficiencies Identified During LOP /LOCA Test D This item was initiated shortly after the completion of this complex
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test and a preliminary review of results were performed.
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significant deficiency was identified' after a more extensive review
' of results.were performed which involved the automatic transfer of-
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the power supply for the Automatic Depressurization System (ADS)
safety nelief valves 2-PCV-1-22 and 2-PCV-1-30. The licensee wrote TE-08 and generated change number 07 to retest this portion of the'
test.
This was necessary in order to sign - off test acceptance criteria 6.16, " verify ADS SRVs 2-PCV-1-22 and 2-PCV-1-30 had power available to operate". The' retest was performed on June 21, 1988.
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However, upon review of the results of the retest by the RTP manager,
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RTP procedures review group, and the Test Director, it was determined
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that the retest was not adequate because it could not be demonstrated that the normal and alternate power to the SRVs were from two different batteries. The licensee initiated a second TE, number 22, which in turn generated change 13 to the procedure and adequately-addressed the retest issue.
This item is closed.
1.
(CLOSED) inspector Followup Item 259, 260, 296/88-21-03, RHRSW Corrosion
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In July 1988, the NRC inspector was concerned that the excessive general corrosion of RHRSW valves and piping at the intake structure had significantly reduced the wall thickness. The licensee conducted an evaluation of the metal loss from corrosion and determined that only about three mils had been lost from the piping.
However, the valve bonnets were the worst case. The licensee determined that the minimum acceptable wall thickness was 0.480 inches.
After preparation by sandblasting for ultrasonic measurement, the smallest actual thickness was 50 percent above this minimum.
In order to avoid additional corrosion, the licensee sandblasted all affected RHRSW piping and valves in the intake structure and preserved the surfaces with an appropriate corrosion resistant oaint. The licensee concluded that the observed corrosion would not affect the design integrity or intended function of the system.
The NRC inspector reviewed the licensee's documentation associated with the evaluation and the maintenance documentation associated with the restoration activities. In addition, the NRC inspectors conducted several tours of the intake structure during the evaluation and restoration activities over the past few months.
The NRC inspector agreed with l
the licensee's evaluation of the corrosion and concluded that I
acceptable restoration activities had taken place to prevent a dditional corrosion.
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(CLOSED)' Inspector Followup Item 259, 260, 296/88-24-03, Cable Tray.
. Acceptance Criteria This' item identified the lack of quality control acceptance criteria associatec' with. installation of three replacement sections of safety related cable tray in the Unit 2 Drywell that were damaged during the
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drywell fire during 1987.
Additionally, one of the replacement
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sections of cable tray RR-ESI, was noted by workers to be sagging.
Both ' conditions had been documented by the )icensee. on CAQR BFP
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880351.
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'The NRC inspector-reviewed Specification Revision Notice (SRN) G-40-20 (B22 88 0810 092) issued August 10, 1988, that included established inspection criteria addressing all of the concerns identified in the original. NRC inspection report. A special data sheet was added to-WP 2072-88 on September 26, 1988 to document the reinspection of the replacement cable trays.
The licensee determined that the new cable tray was not adequately-supported.to offset the cable weight resulting in twisting of the cable - tray.
A temporary support was provided to hold the sagging tray until repaired.
DCN B00046A was. written to initiate necessary design activities. The actual work consisted of modifying existing cable tray support MK 51 to provide additional support for cable tray.
RR-ESI at the point where the cabling leaves the tray at the penetrations.
This item is closed.
k.
.(CLOSED) Inspector Followup Item 259/84-44-02, 250 Volt DC Board Filter Circuit Breakers This item was initially identified as an open item for Unit 1.
However, it applied to all three unit 250 volt DC boards and the common board, in that the following breakers were being left open by'
the operators as a matter of routine due to system grounds:
Breaker 713 - Unit 1, 250 Volt DC Board #1 Filter Breaker 711 - Unit 2, 250 Volt DC Board #2 Filter Breaker 713 - Unit 3, 250 Volt DC Board #2 Filter Breaker 211 - Unit (Common) 0, 250 Volt DC Board #4 Filter.
The licensee had replaced all filter capacitors, and the inspector l
verified that the circuit breakers for the #1, #2, and #3 boards were closed and being maintained closed.
Board #4 is considered non-safety related.
Thit item is Liosed.
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12.
Licensee Action on Previous Enforcement Matters (92702)
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.(OPEN) Violation _259, 260, 296/85-28-04, Inadequate Procedures
This violation identified two examples of inadequate procedures'in use by the licensee.
The procedural problems were as follows:
01-71, Reactor Core Isolation Cooling (RCIC) system,. contained incorrect root isolation valve numbers for RCIC steam flow instruments PDIS-71-1A and PDIS-71-1B.
Incorrect instructions were included in SI-4.11.C.1 and SI-4.11.C.S.
These sis are intended to satisfy TS' surveillance requirement 4.11.C.5 for checking smoke detector sensitivity' values in accordance with the manufacturers instructions.
The NRC inspector reviewed the licensee's response dated September 23, 1985.
In that response, the licensee attributed the violation to the following causes:
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Lack of vendor information control FT-200 type smoke detectors are no-longer in production and no vendor supplied equipment is available Correct RCIC valve numbers were omitted from the 0I-71 valve'
checklist The NRC inspector reviewed documentation to verify the following corrective actions:
The licensee has received the latest vendor information associated '
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with Model No. CPD-1212 smoke detectors.
The current revisions of SI-4.11.C.1 and SI-4-11.C.5 are in accordance with that vendor-information.
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A RCIC system walkdown has been performed and the 01-71 valve checklist was revised to include the correct steam flow instrument root isolation valve numbers.
A letter, dated June 19, 1985, from the vendor that provided the type FT-200 smoke detectors stated that the licensee's current testing method is an acceptable and recommended procedure.
However, that letter (R39-860621-801) failed to contain adequate details or specific information to allow the NRC inspector to determine what practices were or were not recommended.
The NRC inspector met with members of plant management and discussed the concern about the inadequate test method for the type FT-200 smoke detectors. Subsequent to that meeting, the NRC inspector determined that Design Change Notice (DCN) WO215A is being worked to replace existing obsolete type FT-200 smoke detectors with newer Gamewell Model #DI-4A l
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The licensee's SMPL shows that DCN status to be open, but to be completed prior to restart.
The NRC inspector believed the licensee's actions are adequate to support refuel, however this item will remain open pending review of the completion of DCN WO215A and associated new sis to support testing in accordance with the manufacture's instructions.
No violations or deviations were identified in the area of Licensee Action on Previous Enforcement Matters.
13.
Exit Interview (30703)
The inspection scope and findings were summarized on October 28, 1988, with those persons indicated in paragraph 1 above.
The inspectors described the areas inspected and discussed in detail the inspection findings listed below. The licenseo did not identify as proprietary any of the material provided to or reviewed by the inspectors during this inspection.
Dissenting comments were not received from the licensee.
Item Number Description and Reference 88-33-01 Inspector Followup Item, Lack of Locked Valve Criteria (Paragraph 2.a)
88-33-02 Inspector Followup Item, Questionable Relay Rating In The Scram Discharge Volume Level Switches (Paragraph 4)
88-33-03 Unresolved Item, Unauthorized, Undocumented and Inadequate Maintenance Activity (Paragraph 5)
88-33-04 Inspector Followup Item, Limitorque Motor Operator Failures (Paragraph 7.a)
88-33-05 Discretionary Enforcement, Failure To Follow i
Procedure, G01-100-2 (Paragraph 11.c)
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14. Acronyms and Initialisms ADS Automatic Depressurization System ANSI American National Standards Institute ARI Alternate Rod Injection ARP Annunciator Response Procedure BFEP Browns Ferry Engineering Pro het
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BFNP Browns Ferry Nuclear Power P' ant BFNPP Browns Ferry Nuclear Performance Plan CAD Containment Atmospheric Dilution CAQR Condition Adverse to Quality Report
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CCD Configuration Control Drawings
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-CS Core Spray CSSCL Critical Structures, Systems, and Components DCN-Design Change Notice 1 DD Drawing Discrepancies DG Diesel Generator DNE Department of Nuclear Engineering.
.DBVP Design Baseline and Verification. Program EA
_ Engineering Assurance ECN Engineering Change Notice EECW.
Emergency Equipment Cooling Water EGM Electric Governor Motor EQ-Environmental Qualification-ESF.
. Engineered Safety Feature FLRC Fuel. Load Review Committee FPC Fuel Pool Cooling FSAR Final Safety Analysis Report GE General Electric HCU Hydraulic Control. Unit HPCI-High Pressure Coolant Inspection HPFP High Pressure. Fire Protection HVAC Heating, Ventilation, & Air Conditioning IE Inspection and Enforcement IFI, Inspector Followup Item INP0 Institute Of Nuclear Power Operations.
IRM Intermediate Range Monitor JTG Joint Test Group KW Kilowatt LER Licensee Event Report LOP /LOCA Loss of Power / Loss of Coolant Accident
.LPRM Local Power Range Monitor MG Motor Generator MMI Mechar' al Maintenance Instruction MR Maintenance Request MSIV Main Steam Isolation Valve NER Nuclear Experience Review NI Nuclear Instrumentation NPP Nuclear Performance Plan
.NRC-Nuclear Regulatory Commission NRR Nuclear Reactor Regulation OI Operating Instruction OSP Office of Special Projects PMI Plant Manager Instruction PMT Post Modification Test PORC Plant Operations Review Committee QA Quality Assurance QC Quality Control RCIC Reactor Core Isolation Cooling RHR Residual Heat Removal
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RHRSW Residual Heat Removal Service Water I
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RPV-Reactor Pressure Vessel
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Site Director Standard Practice ~
j SGTS Standby Gas Treatment System
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. Service:Information Letter,
SMPL Site Master' Punch l List SNM-Specia? Nuclear Material SP0C.
System : re-Operation Check 1_ist SRN Specification Revision Notice SR0 Senior, Reactor Operator SRV-Safety Reifef Valve TACF Temporary Alteration Change Form TE Test Exceptions TI Technical Instruction TS Technical Specifications
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TSC Technical Support Center TVA Tennessee Valley Authority USQD Unreviewed Safety Question Determinations l
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