ML20154R483
| ML20154R483 | |
| Person / Time | |
|---|---|
| Site: | Sequoyah  |
| Issue date: | 09/15/1988 |
| From: | Harmon P, Jenison K NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20154R471 | List: |
| References | |
| 50-327-88-34, 50-328-88-34, NUDOCS 8810040275 | |
| Download: ML20154R483 (32) | |
See also: IR 05000327/1988034
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0* ** UNITE 3 STATES
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NUCLEAR REGULATORY COMMISSION
REGION 11
101 MARIETTA ST., N.W.
$q ', , , , j[ ATLANTA. GEORGIA 30323
Report Nos.: 50-327/88-34 and 50-328/88-34
Licensee: Tennessee Valley Authority
6N38 A Lookout Place
1101 Market Street
Chattanooga, TN 37402-2801
Docket Nos.: 50-327 and 50-328 License Nos.: DPR-77 and DPR-79 .
Facility Name: Sequoyah 1 and 2
Inspection Conducted: June 6 - July 11, 1988
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Inspectors:-1 6 M [ A M /iff[
K.mJenyn,seniorRestdentInspector fate /51gned
i A AmAt fri 9kVl88
P. J. Parmon, 5dngr Mesident Inspector Date Signed
Resident Inspectors: D. P. Loveless
W. K. Poertner
P. G. Numphrey
K. D. Ivey I
Approved by: JP[ 7f /E)[
K.fl. J6nisfn Acting Chief, /Date'51gned I
ProjectsStet}on1 l
DivisionofTVAProjects !
2 OfficeofSpecialProjects
Summary
Scope: This routine, announced inspection involved inspection onsite by the <
Resident Inspectors in the areas of operational safety verification !
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including o performance, system lineups, radiation i
protection, perations
safeguards and housekeeping inspections; maintenance i
observations * surveillance testing observations; review of previous
inspection Iindings; followup of events; review of licensee
identified items; review of IENs; and review of IFIs.
Results: Three potential violations were identified.
Paragraph 7, 327,328/88-34-02
Paragraph 8, 327,328/88-34-03
Paragraph 9, 327,328/88-34-04
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- 0ne unresolved item was identified.
Paragraph 4,(327,328/88-34-01)
No deviations were identified.
An Enforcement Conference sur. mary pertaining to Violation 327,328/
88-34-02 is contained in paragraph 7.
"Unresolved items are matters about which more information is required to
determine whether they are acceptable or may involve violations or deviations.
There were no Unit I startup items identified in this report.
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REPORT DETAILS
1. Persons Contacted
Licensee Employees
H. Abercrombie, Site Director
J. Anthony, Operations Group Supervisor
- R. Beecken, Maintenance Superintendent
J. Bynum, Vice President, Nuclear Power Production
M. Cooper, Compliance Licensing Manager
- 0. Craven, Plant Support Superintendent
H. Elkins, Instrument Maintenance Group Manager
R. Fortenberry, Technical Support Supervisor
J. Hamilton, Quality Engineering Manager
J. La Point Deputy Site Director
L. Martin,$iteQualityManager
R. Olson Modifications Manager
J. Patrick, Operations Group Manager
R. Pierce Mechanical Maintenance Supervisor
- M. Ray,SIteLicensingStaffManager
- R.
Rogers,ld, licensing EngineerPlant Reporting Section
8. 3chofie
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- S. Smith, Plant Manager
- S. Spencer, Licensing Engineer
C. W11ttemore, Licensing Engineer
NRC Employees
M. Branch
l A. Long
- Attended exit interview
NOTE: Acronyms and initialisms used in this report are listed in the last
paragraph.
2. Operational Safety Verification (71707)
a. Plant Tours
The inspectors observed control room operations; reviewed applicable
logs including the shif t logs, night order book, clearance hold order
book, configuration log and TACF log; conducted discussions with
control room operators; verified that proper control room staffing
was maintained; observed shift turnovers and confirmed operability
of instrumentation. The inspectors verlfied the operab'lity of
selected emergency systems, and verified compliance with TS LCOs.
The inspectors verified that maintenance work orders had been
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submitted as required and that followup activit es and prioritization
of work was accomplished by the licensee.
Tours of the diesel generator, auxiliary, control, and turbine
buildings, and containment were conducted to observe plant equipment
including potential fire hazards, fluid leaks and
conditions,ibrationsandplanthousekeeping/cleanlinesscondItions.
excessive v
The inspectors walked down accessible portions of the following
safety-related systems on Unit 1 and Unit 2 to verify operability and
proper valve alignment:
SYSTEMS
Auxiliary Feedwater System
Containment Spray System
Residual Heat Removal System
SafetyInjectionSystem
UpperHeadInjectionSystem
No violations or deviations were identified
b. Safeguards Inspection
In the course of the monthly activities, the inspectors included a
review of the licensee's physical security program. The performance
of various shifts of the security force was observed in the conduct
l protected and vital area access
l of daily activities
controls; including:l
searching of personne and packages; escorting of visitors;
badge issuance and retrieval; patrols and compensatory posts.
In addition, the inspectors observed
protected and vital area barrier integr' protectedty. The inspectors area lighting, verified
interfaces between the security organization and operations or
maintenance. Specifically, the Resident Inspectors:
interviewed individuals with security concerns
reviewed licensee security event report
visited central or secondary alarm station
observed power supply test
verified protection of Safeguards Information
verified onsite/offsite communication capabilities
No violations or deviations were identified,
c. Radiation Protection
The inspectors observed HP practices and verified the implementation
of radiation protection controls. On a regular basis, RWPs were
reviewed and specific work activities were monitored to ensure the
activities were being conducted in accordance with the applicable
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RWPs. Selected radiation protection instruments were verified
operable and calibration frequencies were reviewed.
The following RWPs were reviewed:
88-01-12: Unit 1 Containment, All Areas.
88-00-07-01: All RWP Areas (chemistry personnel only).
No violations or deviations were identified
3. Sustained Control Room Observation (71715)
The inspectors observed control room activities and those plant activities
directed from the control room for approximately 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> in each 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />
shift for this rnort period. The observation consisted of one shift
inspector per shif; supported by one shift manager per shift and other OSP
management, on 06/28/88 at 1700, 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> on-site shif t coverage by the
NRC was terminated. Normal inspection coverage was resumed at this time,
a. Control Room Activities Including Conduct of Operations
The inspectors reviewed control room activities to determine that
operators were attentive and responsive to plant parameters and
conditions; operators remained in their designated areas and were
attsntive to plant operations, alarms and status; operators employed
cm.nunication, terminology and nomenclature that was clear and
formal; and operators performed a proper relief prior to being
discharged from their watch standing duties,
b. Control Reom Activities Including Response to Transient and Emergency
Conditions
The inspector witnessed the Unit 2 operations emergency aersonnel
respond to adverse plant conditions created by a severe t1under and
electrical storm that occurred on June 25, at 4:50 p.m. The storm
caused a switchyard breaker to trip and resulted in an initiation of
the "carrier received indicator " alarms and various other control
alarms. At essentially the same time, it was reported that damage
had occurred that had disabled the Safety and Security tower and
winds had resulted in a parked semi-trailer overturning at the plant
site In addition, a fire alarm indicated that a fire had occurred
in the turbine building. The responding emergency team determined
the cause of the alarm to be a result of smoke entering the building
from the auxiliary boiler exhaust via the roof ventilation.
The responses and evaluations of these situations by the operators
were well managed by the shift personnel.
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c. Control Room Hanning
The inspectors reviewed control room manning and determined that TS
requirements were met and a professional atmosphere was maintained in ,
the control room. The inspectors found the noise level and working
conditions to be acceptable. The inspectors observed no horse play l
and no radios or other non-job related material in the control room.
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Operator compliance with regulatory and TVA administrative guidelines l
were reviewed. No deficiencies were identified, i
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. In addition, the control room appeared to be clean, uncluttered, and ;
well organized. Special controls were established to limit personnel '
in the control room inner area.
d. Routine Plant Activities Conducted In or Near the Control Room !
The inspectors observed activities which require the attention and [
- direction of control room personnel. The inspectors observed that t
necessary plant administrative and technical activities conducted in t
or near the control room were conducted in a manner that did not ,
compromise the attentiveness of the operators at the controls. The !
licensee has established a 505 office in the control room area in i
which the bulk of the administrative activities, including the '
i authorized issuance of keys, takes place. In addition the licensee .
has established H0, WR, SI, and modification matrix functions to t
i release the licensed operators from the bulk of the technical i
i activities that could impact the performance of their duties. These ;
j matrixed activities were transferred into the WCC. '
j e. Control Room Alarms and Operator Response to Alarms
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i The inspectors observed that control room avaluations were performed
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utilizing approved plant procedures and that control room alarms were
responded to promptly with adequate attention by the operator to the
alarm indications. Control room operators appeared to believe the
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alarm indications. None were identified by the inspectors that were
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either ignored by the operators or timed-out.
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f. Fire Brigade
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j The inspectors reviewed fire brigade manning and qualifichtions on a
j routine basis. Both manning and qualifications were found to meet TS
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requirements.
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, The inspector reviewed the training received by the new fire brigade
- crew to ascertain whether an appropriate amount of operations
knowledge is imparted to the crews. The fire brigade is broken into
j a "composite crew" format which naturally lends itself to providing
l plant knowledge. The crew is composed of personnel with the
following experience:
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1 Steamfitter
1 Electrician
2 Firefighters
This crew then receives 12 weeks of intensive training. Two weeks
of this training includes familiarization with all safe shut 0wn
(Appendix R) systems. The training includes comaonents, f h pat i s,
and safety significance. Additionally, the training includos cwo
weeks of intensive training on fire protection systems in the plant.
Following the classroom training the crew completes system
qualification cards for in plant knowledge of the systems. Typical
qualification card items are listed below:
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LocatetheUpperHeadInjectionaccumulatorandsurgetank
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State the cooling medium for the Spent Fuel Pit Cooling System
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State whether there is any radiation associated with the EGTS
and describe how it is contained
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i.ist the emergency supply for the 6900 V Shutdown Boards
The training received by the crews appears adequate and appropriate.
the affected unit A505 will res)ond with the crew and
Additionally,"incident
function as command". This indivicual will control all
non-fire protection plant equipment and make reccommendations
concerning priority of plant equipment to be protected. Operation of
plant equipment other than the fire protection systems by the
compoCte crew is prohibited. This arrangement is consistent with
estaolished plant procedures and policies and appears appropriate to
the fire brigade functions,
g. Shift Briefing / Shift Turnover and Relief
The inspectors observed that U0s completed turnover checklists,
conducted control panel and significant alarm walkuown reviews and
significant maintenance and surveillance reviews prior to tellef.
The inspectors observed that sufficient information was transferred
on plant status, operating status and/or events and abnormal system
alignments to ensure the safe operation of the Unit. ASOS relief was
conducted and sufficient information appeared to be transferred on
plant status, operating status and/or events, and abnormal system
alignments to ensure the safe operation of the Unit. ASOS were
observed reviewing shif t logbooks prior to relief.
Shift briefings were conducted by the offgoing 505. Personnel
assignments were made clear to oncoming o:)erations personnel.
Significant time and effort were expended d scussing plant events,
plant status, expected shift activities, shift training, significant
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surveillance testing or maintenance activities, and unusual plant
conditions,
h. Shift Logs, Records, and Turnover Status Lists
The inspectors reviewed 505, 00, A505 and STA logs and determined
that the logs were completed in accordance with administrative
requirements. The inspectors ensured 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 entry into or exit from
TS LCOs were recorded promptly. Turnover status checklists for R0s
contained sufficient required information and indicated plant status
parameters, system alignments and abnormalities. The following
additional logs were also revie,wed:
Night Order Log
System Status Log
Configuration Control Log
Key Log
Temporary Alteration Log
No discrepancies or deficiericies were identified,
i. Control Room Recorder / Strip Charts and Log Sheets
The inspector observed operators check, install, mark, file, and
route for review, recorder and strip charts in accordance with the
established plant processes. Control room and plant equipment
logsheets were found to be complete and legible; parameter limits
were specified; and out-of-specification parameters were marked and
reviewed during the approval process.
4. Management Activities
TVA management activities were reviewed on a daily basis by the NRC shif t
inspectors, shift managers, and Startup Manager,
a. Daily Control of Plant Activities (War Room Activities)
The licensee conducted a series of plant activities throughout each
day to control plant routines. These activities were referred to by
the licensee as War Room activities. War Room activities were
observed by the shift manager on a daily basis and were found to be
an adequate method to involve upper level management in the
day-to-day activities affecting the operation of the units,
b. Management Response To Plant Activities and Events
Review of the licensee's corrective actions associated with restart
following the June 8, 1988, reactor trip:
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The reactor trip of June 8,1988, was the fif th in a series of !
reactor trips that occurred subsequent to the first Sequoyah Unit 2
restart on Ma 13, 1988. Following this trip the NRC requested that
i the licensee'ys post-trip review assess the four previous trips and .
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determine if there were any common factors associated with the trips. !
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Additionally, on June 13, 1988, the licensee met with the NRC in i
Rockville, MD, at a public meeting for the purpose of presenting t
i their assessment and any corrective action planned. During the -
j meeting, the licensee indicated that a major contributor to several t
of the trips was the material condition of the secondary plant as :
- well as a lack of detailed procedures for steam generator (SG) level ;
control. t
1988, the Assistant Of rector for Inspection Programs,
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On June 16)NRC,li
TVAPD OSP
detailsofthe
met with the Sequoyah management and discussed the
censee's immediate and long term corrective actions.
3 The licensee committed to the following corrective actions and i
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evaluations prior to plant restart: ,
! Review and reduce the backlog of outstanding work requests (WRs)
on secondary plant equipment aild evaluate their possible ;
contribution to reducing the risk of balance of plant (80P)
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Revise operating instructions to enhance plant start-up
activities to control feedwater flow and SG 1evels during low !
level power ascension.
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I * Require the Plant Operations Review Committee (PORC) to evaluate l
future plant trips and recommend procedural changes, where !
applicable, to reduce the probability of future plant trips. i
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] Shif t operating crews will be trained on the Sequoyah simulator l
1 in using the revised operating instructions for startup of the i
l feedwater control system.
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) The inspectors reviewed the procedural changes and training >
i incorporated as a result of the licensee's commitments. Each was I
l reviewed as to whether the commitment was implemented and that the [
plant would be in compliance with the safety analysis. The following !
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sumarizes this review and inspector coments: [
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l Training for the operating crews was observed and det. ermined to (
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be acceptable. }
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General Operating Instructions, G01 1, rev. 77, Plant Startup I
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from Cold Shutdown to Hot Standby - Units 1 and 2, and G01-2, i
rev. 56, Plant Startup from Hot Standby to Minimum Load - Units l
l 1 and 2, incorporated the requirement for the shif t operating l
1 supervisor (505) to make a systematic review of all open work
i activities relative to the respective units for the purpose of j
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identifying maintenance activities that could affect system
operability prior to mode change. NRC observation of this
process indicated acceptable condition for Unit 2 operation.
Observation of this review will be conducted by the inspectors
during Unit I startup. Further changes were made to Admin-
istrative Instruction, AI-5, rev 43, Shift Relief and Turnover,
requiring that prior to assuming the watch, the oncoming shift
personnel (505, A505,STA, and representatives from the radio-
logical chemical laboratory radiological control group, and the
waste processing group) ass,emble in the work control center for
a briefing on all work activities in progress and scheduled work
activities to be performed during the upcoming shif t for both
units. The work activities must be approved by the SOS prior to
implementation. The inspectors reviewed the changes pertaining
to the above areas and found them acceptable. The inspector
observed several shift turnovers conducted in the work control
center to verify that proper briefings on work activities were
presented.
GOI-2, rev. 56, incorporated changes for maintaining feedwater
control and SG 1evels during plant startup activities that were
developed through simulator validation. The changes provided
instruction for switching from manual to automatic operation of
the feedwater system. Additionally, the new method changed the
SG 1evels that the operator must try to maintain at low power
levels from the 33% programmed level to 48% in each SG.
The inspectors reviewed these changes and could not determine
that the plant had been analyzed for a condition of a SG water
mass increase of the magnitude required in the G01-2 revision.
The licensee was asked to provide the safety evaluation of this
change. The licensee had only performed a USQD screening and
determined that the FSAR supported the increase in SG 1evel from
33% to 48% level at less than or equal to 3% reactor power. The
inspectors requested that the ifcensee provide a more detailed
analysis to support the level increase. The licensee
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corresponded with the nuclear steam system supplier Westing-
l house, who indicated that they did not have sufficient site
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specific information to support a SG 1evel increase from 33% to
48% at 0% reactor power. Rather, Westinghouse indicated that
the precautions, I'mitations, and sotpoints docutuent indicated
that the control band for SG program level was plus or minus 5%.
G01-2 was again revised (rev. 57) to require the SGs to be
operated at programed level, plus or minus 5%, during startup
and plant operations. The fact that Westinghouse could not
support the licensee position that the plant accident analysis
for a main steamline break was still bounded was of concern to
the NRC. This item is identified as URI 327, 328/88-34-01.
This issue will be reviewed further to determine whether a
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violation of NRC regulations occurred when the initial change
was evaluated for compliance with 10 CFR 50.59 requirements.
The inspector discussed this concern with ifcensee management
prior to the actual implementation of GOI-2. The licensee
- agreed that further review was necessary and revised GOI-2 to
delete the change to the programmed level,
i A!-30, rev. 19, Nuclear Plant Conduct of Operation, incorporated
the requirement that experienced dedicated coaching be provided
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by TVA for inexperienced operators during startup and transfer
from manual to automatic operation of the feedwater control
I system. Although this dedicated coaching later appeared to not
I be fully necessary, actions taken by the licensee to allow the
l A505 to directly supervise significant operations by unit
l operators were considered to be appropriate, effective, and
acceptable.
AI-18, rev. 51, Plant Reporting Requirements, incorporated the
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requirement for the PORC to review and approve each plant trip
l report prior to restart of the plant. The inspector considered
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this practice to be a noteworthy improvement.
5. Engineered Safety Features Walkdown (71710)
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The inspector verified operability of the containment spray system on
Unit 1 by completing a walkdown of the system. This inspection was
documented in the SSQE Inspection Report 327,328/88-29.
6. Shift Surveillance Observations and Review (61726)
Lices.see activities were directly observed to ascertain that surveillance
of safety-related systems and components was being conducted in accordance
with TS requirements.
The inspectors verified that; testing was performed in accordance with
adequate procedures; test instrumentation was calibrated; LCOs were met;
test results met accestance criteria reoutrements and were reviewed by
personnel other than "he individual directing the test; deficiencies were
identified, as appropriate, and any deficiencies identified during the
testing were properly reviewed and resolved by management personne :; and
system restoration was adequate. For completed tests, the inspector
verified that testing frequencies were met and tests were performed by
qualified individuals.
The following activities were observed / reviewed:
SI-2: Shift Log - Units 1 and 2.
SI-3: Daily, Weekly, and Monthly Logs - Units 1 and 2.
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SI-79: Power Range Neutron Flux Channel Calibration By
Incore-Excore Axial Imbalance Comparison. This SI is
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required at least once per month when above 15% reactor
l power. The incore axial imbalance is obtained from a
moveable detector flux map which is analyzed by the incore
computer program.
SI-129.1: SafetyInjectionPumpCasingandDischargeVenting.
l 5!-137.1: Reactor Coolant System Unidentified Leakage Measurement.51-137.2: Reactor Coolant System Water Inventory.
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No violations or deviations were identified.
1 7. Shift Maintenance Observations and Review (62703)
a. Station maintenance activities of safety-related systems and
components were observed / reviewed to ascertain that they were
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conducted
industry codesin accordance with
and standards, andapproved procedures,ith
in conformance w TS. regulatory guides
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The following items were considered during this review: LCOs were
met while components or systems were removed from service; redundant
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components were operable; approvals were obtained prior to initiating
l the work; activities were accomplished using approved procedures and
I inspected as appifcable; procedures used were adequate to control the
l activity; troubleshooting activities were controlled and the repair
record accurately reflected what actually took place; functional
testing and/or calibrations were
components or systems to service; performed
QC records prior
were to returning
maintained;
activities were accomplished by qualified personnel; parts and
materials used were properly certified; radiological controls were
implemented- QC hold points were established where required and were
observed; / ire prevention controls were implemented; outside
contractor activities were controlled in accordance with the approved
QA program; and housekeeping was actively pursued,
b. Temporary Alterations
The following TACFs were reviewed:
0-88-08-02: Condensate Storage Tanks. Temporary connections
to drain valves to allow makeup water feed from a
mobile vendor demineralizer.
No violations or deviations were identified.
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c. Work Requests
The inspectors observed work in progress and reviewed work packages
for the following work requests / work plans:
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WR 8245103: Repair of the "A" train main feedwater pump
turbine speed control system to correct pump t
oscillations and provide a more controlled feed -
flow to the SGs.
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WP E437A-01: Testing and repair of all safety-related room
coolers due to the discovery of broken shafts on
certain room cooler motors caused by impro)er fan
belt tensioning. The inspector observed tie work
on the "A" and "B" trains of the Boric Acid ,
Transfer & AFW Pump Coolers.
No violations or deviations were identified.
Subsequent to the management meeting held with TVA on June 13, the
inspectors reviewed the scope of the maintenance work requests for
Unit 2 that were pending when the reactor trips occurred on June 6 :
j and June 8. The purpose of this review was to establish:
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- Whether the approximately 128 WR's listed as "Startup Priority"
- was complete and conservative in bounding all necessary work to
be performed prior to Unit 2 startup.
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Whether the screening criteria used in the "Startup Priority" .
determination was adequate and conservative. l
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- Selection of a representative sample of those WR's not deter- i
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mined to be "Startup Priority" and apply the screening criteria I
as an independent audit on the process.
I The screening criteria ised was a check list, which was applied to l
> the total outstanding work list of 1308 items listed for Lnit 2 and l
] Comon. Answering "Yes" to any one of the
j sheet placed the WR in the "Startup Priority"questions
category: on the check !
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- If the WR is not completed, will the operators be required to I
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use remote indications, manual controls or other compensatory i
measures?
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If the WR is not completed, could false indications cause the
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in plant operators (AUO's) to notify the control room? (An l
example is a plugged / dirty sight glass on a drain tank). l
- If the WR is not completed, could controller problems develop i
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1 that could cause instability in the secondary plant (BOP)? [
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- If the WR is not completed, could an identified prob 1cm worsen
later and not be isolable / workable at power? (e.g. a minor 1
steam leak that could develop into a serious leak that is not '
isolable with 2 valve protection). i
Is the WR one of those identified by the Operations staff as one
they consider necessary for restart?
The screeninc criteria was considered adequate by the inspector, and I
was then applied to 38 selected WR's that were not on the startup !
list. Each of the 38 were discussed with TVA staff familiar with the ,
screening process. The inspector agrees with TVA staff's
determination of non-startup category for each of the selected sample ;
items. TVA completed all Startup Priority WR's prior to Unit 2 '
startup on June 23.
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No violations or deviations were identified
d. Hold Orders
The inspectors reviewed various H0s to verify compliance with AI-3,
revision 38, Clearance Procedure, and that the H0s contained adequate ;
information to pro)erly isolate the affected portions of the system
being tagged. Adcitionally the inspectors inspected the affected i
equipment to verify that the recuired tags were installed on the ;
equipment as stated on the H0s. The following H0s were reviewed: ;
Hold Order Equipment
2-88-516: "A" Train Main Feedwater Pump for work on I
the governor valve positioner.
2-88-463: 28 Annulus Vacuum Fan. I
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2-88-487: 28 690 Elevation Penetration Room Cooler to
repair a broken shaft.
2-88-520: Positive Displacement Charging Pump to I'
replace a plext glass cover gasket.
No violations or deviations were identified. I
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e. Maintenance Activities Affecting Plant Operations
On 07/05/88, at 2:30 p.m., Unit 2 operators received indication that !
the pressure indicator (2-PIS-87-21) for UHI isolation valve 2-87-21 ;
was erratic and indicating high (4000 psig) when all previous '
readings were steady at approximately 3000 psig. The pressure !
indicator is the sole method on-line to monitor the condition of the i
isolation valve's actuator. The actuator is a hydraulic actuator
pre-charged with nitrogen to 1400 psig, then hydraulically charged to
I
1
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13
3000 psig. A bladder separates the nitrogen from the hydraulic side.
A pre-charge of 1400 asig provides sufficient stored energy to stroke
the UHI isolation va:ve silut when the UHI water accumulator reaches
its low level setpoint during a LOCA event. This action assures
delivery of sufficient water inventory to the core and prevents
injectionofUHIsystemnitrogenintothecore.
The pressure indicator was removed from service and re-calibrated.
07/08/88 at 2:30 p.m.,
After reinstalling )the pressure indicator on(a delay of 3 days , the actuato
be reading below the alarm setpoint of 2970 psig. A Westinghouse
analysis had previously been provided to allow a limited number of
rechargings of the hydraulic side of this accumulator. Assuming that
the pressure decrease was due to nitrogen leaks, a maximum of 4
rechargings was allowed before the nitrogen preload was considered
less t,1an that required to properly stroke the isolation valve. This
is based in part on the volume and pressure of the compressed
nitrogen and the assumed nitrogen loss to decrease pressure to the
alarm point. Af ter 4 such recharges, the licensee's procedure (SI
744) requires a stroke test of the isolation valve to verify
operabil lty. An originally installed weight indication method of
determining the volume of nitrogen in the accumulator was unreif able
and ineffective. Since only pressure could be read on-line, the
alternate method of allowing 4 recharges and then providing positive
assurance of operability by a stroke test was developed by the
licensee and Westinghouse. This is considered a compensatory
measure.
Licensee management (plant manager, maintenance manager, operations
among others) met at 4:30 p.m. on 07/08/88 and
manager
decided toand P0RS,ine valve operability by another method.
determ The
decision was to perform a pre-charqe test instead, which was
considered a more reliable method of determining that sufficient
nitrogen was available. The pre-charge test requires declaring the
isolation valve inoperable, draining the actuator's hydraulic side,
and then measuring the nitrogen side pressure.
A plan of action was drawn up which included gathering any spares or
replacement parts, a procedural change to SI 744 to allow the
pre-charge test in lieu of the stroke test, and several contingency
actions. The spares were not found and made available untti
07/09/88, and the procedure was not changed until 07/10/88. By the
time the licensee was ready to implement the test, the accumulator
pressure alarm had been received and recharging accomplished a total
of 7 more times. After the fourth recharge, at 1:30 p.m. on
07/09/88, the still-in-effect requirements of SI 744 required an
immediate stroke test of the isolation valve. This was not done. By
the time the licensee had finally performed an operability test by
checking the pre-charge at 1:55 p.m. on 07/10/88, over 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> had
elapsed since an operability determination had been required by SI
744. When the pre-charge test was finally performed, the nitrogen
_ - _ _ _ _ _ _
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14
which is less than the minimum of
pressurewasfoundtobe1165psig}mittoensureoperability.
1300 psig specified as the lower 1
The loss of nitrogen was determined to be due to a leaking nitrogen
charging valve (Schrader valve). This valve was replaced, the
nitrogen side recharged to 1400 psig, and the valve returned to
service at 3:55 p.m. on 07/10/88.
While the management decision to perform a pre-charge test rather
than the required stroke test was probably acceptable and would have
adequately demonstrated operability, the execution of the plan was
not well coordinated. Several dela
parts and changing the procedure. ys were encountered
Althou in locating
several levels of
management were involved in this evolution,ghtbeworkwasdelayedfor
over 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> past the point when the valves should have been
repaired or declared inoperable. In conjunction with these delays,
it is considered that the licensee did not take appropriate actions
when conditions (the 4th thru 7th low pressure alarm and recharging
evolutions) indicated potential valve inoperability.
Subsequent to this event, TVA asked Westinghouse to provide an
analysis to determine whether the valve would have performed its
intended function with the as-found pressure of 1165. A Westinghouse
analysis dated 7/12/88, asserted that the valve would have stroked
closed in approximately 8 seconds, as opposed to 4 seconds with a
fully charged accumulator. This asserted condition is stated to
result in an additional injection of 120 cubic feet of t;HI water to
,
the core bringing the total injected volume to 1170 cubic feet.
I This additional volume is within the accident analysis assumption of
I
'
a maximum 1180.5 cubic feet. This sug ests the valve may have been
post facto operable, but does not relieve the licensee of their
commitment to demonstrate operability by compliance with T.S. and
their own procedures.
While the system arrangement provides a second, series valve operated
by the opposite ESF train, which probably would have actuated
properly, single failure criteria require redundant equipment to be
T.S. 3.5.1.2 requires the UHI system to be OPERABLE (including the
isolation valves) or, to restore the system to OPERABLE in 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> or
be in HOT STANDBY within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. This action statement was
not entered until 12:31 p.m. , on 07/10/88, when work on the valve
began. Since the valve is determined to be operable by performance
of a verification test whenever 4 recharges have occurred, the valve
should have been declared inoperable after the recharge performed at
1:30 p.m. , on 07/09/88, when procedural actions to stroke time test
the valve were not taken. The appropriate action statement was not
entered on a system required for safe shutdown. This is considered a
violation of T.S. 3.5.1.2, for failure to comply with a TS action
statement. This item is identified as Violation 327,328/88-34-02.
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,
On July 28,1988, the NRC held an enforcement conference with TVA at i
the Sequoyah Nuclear Plant to discuss concerns related to the t
l
apparent noncompliance with T.S. 3.5.1.2 described above. Attendees '
at the conference are delineated in the attachment to this report. '
The meeting was opened by J. Partlow, Director, Office of Special
Projects, who along with F. McCoy, Assistant Director for TVA
Inspection Programs, discussed the NRC concerns with this specific ,
event. NRC management stated their concern that the licensee had
- failed to comply with procedures established to confirm UHI valve
3
operability when cond'tions indicated a potential for valve >
inoperability. Additionally, given this set of circumstances, the !
licensee failed to enter the action statement of T.S. 3.5.1.2 until '
operability could be confirmed. NRC management questioned the l
conservatism and safety consciousness of TVA's actions with respect .
j to this event. !
l
l TVA was asked to address their own investigation into the event and I
] the specific concerns of the NRC. TVA presented their evaluation of (
, the event and their conclusions as to how the the noncompliance with !
'
! T.S. was allowed to occur.
l
TVA presented background information and details of the event which !
agreed with the NRC's evaluation in most instances. A copy of the !
material presented by TVA at this conference has also been included l
in the attachment to this inspection report. The Sequoyah plant -
manager acknowledged at the enforcement conference that the plant had ;
been in violation of T.S. 3.5.1.2 for a period of approximately 23 i
hours, from 1:30 p.m. on 07/09/88 until 12:31 p.m., on 07/10/88. TVA ;
presented an analysis performed by Westinghouse that supports their '
.
determination that the safety significance associated wit 1 this event
was minimal and that the valve in question would have functioned if
called upon during the time frame the plant was outside the T.S. TVA
demonstrated at the enforcement conference that the event was caused
by a lack of coordination among various site groups and was not a
result of nonconservative management action.
8. Event Followup (93702, 62703)
At 11:59 p.m., on 6/29, a blackout signal was initiated on Unit 16900
volt shutdown board 1-B-8. The initiating event was the tripsing of the
feeder breaker to the shutdown board from the 6900 volt unit 30ard. The
feeder breaker (#1722) tripped when maintenance workers were attempting to
replace a fuse in the breaker's position indicating light circuit. The
circuit was inadvertantly grounded when maintenance workers were replacing
the blown fuse, causing the breaker trip circuit to actuate. When the
1-8 8 shutdown board was deenergized, all 4 EDG units started. The 1 B-8
shutdown board was reenergized when the 1-B B EDG care up to speed and
tied onto the bus. The other EDG's did not tie on to their respective
buses because those buses continued to be energized from the unit boards.
Af ter resetting the breaker 1722 trip circuit, the unit boards were
paralleled with the 1-B-B EDG, and the EDG's were stopped. All systems
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performed as designed, and an ENS notification made to NRC at 12:08 a.m.
on 6/30. !
At 7:29 p.m., on June 3,1988, EDG 1A-A was made inoperable for the
performance of SI-307.1, Degraded Voltage Relay Response Time Testing and *
Timer Verification. At that time the Unit 2 00 logged in the LCO log that '
LCO for TS 3.8.1.1 was entered. At 10:40 p.m. on June 3, 1988, SI 307.1
was completed and EDG 1A-A was returned to service. During the subsequent '
shif t turnover meeting at approximately 11:30 p.m. a discussion of the '
work performed for the previous shif t resulted in the 505 realizing that :
the requirements of TS 3.8.1.1 had not been met. TS 3.8.1.1 requires that
with an EDG inoperable, the operability of the remaining AC sources must ,
be demonstrated by performance of SR 4.8.1.1.1.a and 4.8.1.2.a.4 within :
one hour and at least once per eight hours thereaf ter. Failure to meet l
the requirements of TS 3. 8.1.1 is identified as Violation :
327,328/88-34-03, j
s
9. Followup on Previous Inspection Findings (92702) ;
(Closed) URI 327,328/88-26-03, Resolution of RCS Leak Rate Determination !
Process.
{
On April 6, at approximately 6:50 a.m., the licensee completed f
Reactor Coolant System Water !
computations
Inventory. The forresults
Part 1indicated
of SI-137.2,
an initial unclassiffed RCS leak i
rate of 1.09 _gpm which if considered unidentified, would have :
exceeded the T5 Ifmit of 1 gpm. As required by procedure the i
chemistry laboratory was notified to perform Part 2 of SI-13).2. At ;
the time, the 505 was at the shif t meeting preparing for turnover of i
the watch to the oncoming shift crew. He informed the Assistant 505 !
by phone, not to enter the LCO for RCS leakage because procedural , i
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 shift. '
At 7:55 a.m., the licensee entered LCO 3.4.5.2 for RCS leakage when a i
gasket on 2-PDT 62-47, the differential pressure transmitter on the r
- 4 reactor coolant pump seal return line, was found to be leaking. A [
Notification of Unusual Event was not made within 5 minutes per !
IP-1, RCS Leakage, which required entry into the Radiological (
Emergency Plan if leakage exceeds the TS limit. At 8:20 a.m. , !
licensee management personnel reviewed the decision and issued a [
NOVE. At 8: 42 a.m., the differential pressure transmitter was
isolated utilizing the root valves. At 9:11 a.m. , the licensee ,
notified NRC Headquarters in accordance with the one hour emergency
reporting requirements. Although this notification was made within
one hour of the management decision to enter the NOVE, the inspectors ,
noted that this was accomplished approxiestely 76 minutes af ter entry [
into LCO 3.4.5.2 (which, by the licensee's radiological emergency [
procedures, required a declaration of unusual event) and nearly 2.5 i
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hours after the operators had verifiable indi:ation that leakage l
might be outside of TS limits. l
AOI-6, Small Reactor Coolant System Leak (Modes 1, 2, & 3), had not
been entered. A01-6 states that one pose,ible 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 elarm was received twice during the shif t as !
stated above. Additionally with the high leak rate as calculated in !
SI-137.2 and the discovery, of 2-PDT-62 74 leaking the inspector
cont,iders that it would have been prudent to perform the actions of
AOI-6. Although non performance of the recommendations in A01-6 does l
not appear to violate any licensee or NRC requirements, the
inspectors have concern that the licensee's annunciator response t
procedures do not provide an initiation path for the A01 procedures, i
l
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At 5:45 p.m.dicatedthe
SI-137.2 in an licensee
acceptable exited the NOUE
leakage when
rate of 0.48a gpm.
new performance of
l
Subsequent performance of SI 137.5 Primary to Secondary Leakage via '
Steam / Generators, reflected that 0.16 gpm of this leakage rate was
attributable to the tube leak in steam generator 3 discussed in '
Inspection Report 88-26. 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
i of the pocket sump levels. The licensee issued a statement to the ;
l press on this occurrence at 11:00 a.m. on April 6. i
! The delays in entering and reportint the NOUE and the LCO on RCS leak !
j rate and the concerns involving in' tiation of A0! procedures were f
, identified as Unresolved Item 88-26-03. ;
J
l During this event TVA had used a cumbersome method to calculate I
i unidentified RCS leakage and to determine what part, if any, that a j
i
pricary to secondary leak p, layed in this unidentified leakage value. :
j the licensee s RCS inventory measurement procedure !
- Specificallyld
SI-137.2 wou perform an inventory balance and if the unclassified
>
1eakage was ebove a specific value they would then recuest that a
, primary to secondary leakage measurement be performed 'n accordance .
with SI-137.5. Performing a primary to secondary leakage calculation ,
only to quantify unidentified leakage resulted in both a delay in l
completing the RCS unidentified 1(akage measurement and a lack of l
'
consistent primary to secondary leakage trending data. The staff ;
considers that this methodology was a maior contributor to the delays t
, associated with entry into (and applicable reporting of) the NOUE and i
- LCO, as identified in Unresolved Item 86-26 03. l
I !
! Revision 22 of $1-137.2 revised the method to require that primary to l
i secondary leakage measursent 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-137.2. This j
,
ne method should produce both consistent primary to secondary '
1eakage trending data as well as expedite the determination of RCS
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leakage. This method also provides adequate corrective action to
preclude raising questions such as those indicated under Unresolved
Item 88-26-03 discussed above.
The NRC staff reviewed the e/ent with respect to the utilization of
SI-137.2. It was determined that the intent of LCO 3.4.5.2 was to
'
consider any known leakage to be unidentified until an identification of
the source was made. Therefore, unclassified leakage is unidentified
leakage and LC0 3.4.5.2 chould have been entered at 6:55 a.m. Although j
the Lispector had earlier discussions with the licensed operaters, it was
determined that not entering the action statement was identi, led and
resolved independently by the licensee management.
At 7:55 a.m. , on April 6, the operators entered LCO 3.4.5.2 when the leak
'
was actually observed. At this time the operations staff still did not l
enter a NOUE as required by the REP because the 505 haf left instructions '
to the contrary. Tne inspector discussed this decision with the operators i
at the time.
The Sequoyah Radiological Emergency Plan IP-1 Emergency Plan :
Classification Logic which implements these requi,ements,
r requires that t
the operators enter a NOUE if the primary system leak rate is greater than ;
that allowed in the TS. In addition, REP Implementing Procedure IPel, j
also states, if there is any reason to doubt whether a given condition has '
actually occurred, the shift engineer or Site Emergency Director will
proceed with the required notification without waiting for formal
confirmation. 1
In addition, REP Implementing Procedure IP-1, also states, if there is any :
reason to doubc whether a given condition has actually occurred, the shift
engineer or Site Emergency Director will proceed with the required ,
notification without waiting for formal confirmation. l
_
IP-2, Notification of Unusual Event, requires that the not'tication of the [
Operations Duty Specialist be made within 5 minutes af ter .he declaration r
of the event.
on A)ril 6,1988 at 7:55 a.m. the licensee entered i
Contrary
LCO 3.4.5.2to the above,ing tlat the RCS leakrate was greater than the TS
acknowledg
allowable limits but did not enter a NOVE until 8:20 a.m. when licensee
and NRC management reviewed the event. This is a violation of the above j
requirements and will be considered Violation 327,328/88-34-04. This
portion of URI 88-26-03 is closed.
The inspector reviewed AI-4, Preparation, Review, Approval and Use of Site I
Procedures / Instructions, for guidance on use of A0Is. Section 16.3 states !
that:
'
A01s and Els are prepared to act as guides during potential
emergencies. They are written so that a trained operator will know ,
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i
in advance the expected course of events that will identify the
situation and will provide the immediate action to be taken.
It is the operator's res
particular situation is.ponsibility to analyzethe
Once identified andoperator
determine what
is to takethe
prompt appropriate action to prevent or mitigate the consequences of
a serious condition.
The inspector reviewed the operator training lesson plans associated with
A0I-6 for new license training and requalification training including both
classroom and simulator portions. Also, a selected nurrber of additional
AOI training lesson plans for licensed operators were reviewed. Training
appeared to be adequate and appropriate for the procedure usages. ,
,
Initiating documents for A0Is are not provided at Segouyah. The many
unique situations which could occur in the plant are too numerous to
provide instruction for every scenario. Therefore, the A0Is are designed
as symptom based instructions. The operators are trained on what
parameters may indicate a need to enter the procedure.
The inspector reviewed the event in question and determined that the
operators had handled it in an appropriate manner. There is no
requirement for an entry into the A01. Furthermore, discussions with the '
operators and training personnel have shown that a more significant
leakage event would have prompted A0I entry. This portion of URI 88-26-03
is closed.
,
Additional review of this event and licensee corrective actions and
responses will be reviewed under Violation 88-34-04. Therefore, URI
327,328/88-26-03 is closed.
10. ExitInterview(30703)
The inspection scope and findings were summarized on July 18, 1988, with L
those persons indicated in paragraph 1. The Senior Residents described ;
the areas inspected and discussed in detail the inspection findings listed
below. The licensee acknowledged the ir,spection findings and did not ;
identify as proprietar -
during the inspection.y any of the material reviewed by the inspectors
Inspection Findings: :
Three violations were identified in paragraphs 7, 8, an 9.
One URI was identified in paragraph 4. :
No deviations or inspector follow-up items were identified. !
During the reporting period, frequent discussions were held with the Site
Director, Plant Manager and other managers concerning inspection findings. -
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No commitments were made by the plant manager or his designee during the
exit meeting.
11. List of Abbreviations
ABGTS- Auxiliary Buf1 ding Gas Treatment System
ABSCE- Auxiliary Building Secondary Containment Enclosure
AFW -
AI -
Administrative Instruction
A0I -
Abnormal 0)erating Instruction
AU0 -
Auxiliary Jnit Operator
A505 - Assistant Shift Operating Supervisor
BIT -
BoronInjectionTank
C&A -
Control and Auxiliary Buildings
CAQR- Conditions Adverse to Quality Report
CCP -
Centrifugal Charging Pu.sp
CCfS - Corporate Commitment Tracking System
COPS - Cold Overpressure Protection System
CSSC - Critical Structures, Systems and Components
CVI - Containment Ventilation Isolation
DC -
Direct Current
DCN -
Design Change Notice
DNE -
Division of Nuclear Engineering
DTVAP - DivisionofTVAProjects
ECCS - Emergency Core Cooling System
EDG -
EI -
Emergency Instructions
ENS -
Emergency Notification System
ESF -
Engineered Safety Feature
FCV -
Flow Control Valve
FSAR - Final Safety Analysis Report
G0C -
General Design Criteria
GL -
Generic Letter
HIC -
Hand-operated Indicating Controller
H0 -
Hold Order
HP -
Health Physics
IN -
NRC Information Notice
IFI -
Inspector Followup Item
IM -
Instrument Maintenance
IMI -
Instrument Maintenance Instruction
IR -
Inspection Report
KVA -
Kilovolt-Amp
KW -
Kilowatt
KV -
Kilovolt
LER -
Licensee Event Report
LCO -
Limiting Condition for Operation
LOCA - Loss of Coolant Accident
HI -
Maintenance Instruction
NB -
NRC Bulletin
NOV -
Notice of Violation
.
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NRC -
Nuclear Regulatory Commission
OSLA - Operations Section Letter - Administrative
OSLT - Operations Section Letter - Training
OSP -
Office of Special Projects
PMT -
Post Modification Test
PORC - Plant Operations Review Committee
P0RS - Plant Operation Review Staff
PRO -
Potentially Reportable Occurrence i
-
Quality Assurance t
-
Ouality Control !
RCS -
RG -
Regulatory Guide .
RM -
Radiation Monitor
RHR -
RWP -
Radiation Work Permit .
RWST - Refueling Water Storage Tank '
SER -
Safety Evaluation Report
SG -
SI -
Surveillance Instruction
S0I -
System Operating Instructions
SOS -
Shift Ooerating Supervisor
SQM
-
Sequoyah Standard Practice Maintenance ,
SR -
Surveillance Requirements
! SR0 -
Senior Reactor Operator l
STI -
Special Test Instruction
i
TACF - Teworary Alteration Control Room t
TROI - Tr s king Open Items i
TS
-
Technical Specifications I
TVA -
Tennessee Valley Authority
UO -
Unit Operator
URI -
Unresolved Item
.
USQD- Unreviewed Safety Question Determination
'
WCG -
Work Control Group
- WP -
Work Plan
WR -
Work Request f
i
{
i Attachment.
- Enforcement Conference Attendance (;
- List and Licensee Slides
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, ATTACHMENT
- ,
. TENNESSEE VALLEY
AUTHORITY
.
SEQUOYAH NUCLEAR PLANT
EVENTS SURROUNDING
.
THE 2-FCV-87-21
UHI ISOLATION VALVE
! ISSUE
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4
JULY 28,1988
.
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ATTENDANCE LIST
Enforcement Conference
July 28, 1988
Attendees
S. A. White R. L. Gridley J. R. Walker Ken Meade
J. R. Bynum N. C. Kazanas M. A. Cooper Ed Vigluicci
J. T. LaPoint M. J. Ray L. E. Martin J. B. Brady
S. J. Smith H. R. Rogers B. Charleson
NRC
J. Partlow B. Pierson
P. Harmon F. McCoy
K. Jenison K. Poertner
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SUMMARY OF EVENTS
UHI ISOLATION VALVE
.
02/15/88 SI 744 WRITTEN TO PROVIDE METHOD OF MONITORING CHARGES TO
ACCUMULATOR BASED ON WESTINGHOUSE ANALYSIS
03/88 PRE-CHARGED 2 FCV 87 21 N2 ACCUMULATOR TO 1382 psig PRIOR TO
ENTRY TO MODE 3 AND VERIFIED VALVE OPERABILITY
07/05/88 OPERATIONS NOTED ERRATIC PERFORMANCE OF 2 PIS 87 21 (HYDRAULIC
SYSTEM PRESSURE INDICATOR). WR B788800 WRITTEN TO REPAIR.
07/08/88 AT 1400, PORS HAD A DISCUSSION WITH NRC ON THE INOPERABLE
PRESSURE INDICATOR (2 PIS 87-21)
07/08/88 AT 1430 EDT, PIS REPA! RED AND HYDRAUUC SYSTEM PRESSURE FOUND
LOW (2647 psig). OPERATIONS RECHARGED TO 3034 psig. SYSTEM
ENGINEER NOTIFIED AT 1530 EDT.
07/08/88 AT 1830 EDT, PLANT MANAGEMENT WAS INFORMED OF THE LOW HYDRAULIC
SYSTEM PRESSURE AND DETERMINED A PRE CHARGE CHECK WAS THE
APPROPRIATE ACTION TO TAKE. MANAGEMENT DIRECTED SYSTEM
ENGINEERING / MAINTENANCE TO ESTABLISH A PLAN OF ACTION
TO PERFORM PRE CHARGE
l
l 07/08/88 AT 1930 EDT AND AT 0450 EDT ON 07/09/88, HYDRAULIC ACCUMULATOR
PRESSURE REACHED LOW SETPOINT (2970 psig) AND WAS RECHARGED
BY OPERATIONS
j 07/09/88 AT 1100 EDT, SCHRADER VALVE N BLADDER WAS CHECKED FOR
2
l LEAKS SMALL LEAKAGE NOTED.
07/09/88 AT 1300 EDT, HYDRAUUC ACCUMULATOR PRESSURE REACHED THE LOW
SETPOINT (2970 psig) AND WAS RECHARGED BY OPERATIONS. THIS
WAS THE FOURTH PHYSICAL CHARGE AND IN HINDSIGHT SI 198
SHOULD HAVE BEEN PERFORMED AT THIS POINT.
ROCUS1. 35
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SUMMARY OF EVENTS
UH1 ISOLATION VALVE
(cont.)
.
07/09/88 AT 1800 EDT, CALLED NRC RESIDENT AT HOME TO DISCUSS AND
GIVE THE STATUS OF THE ACTION PLAN FOR REPAIR OF 2-FCV 87 21.
07/09/88 AT 1820 EDT, AT 2100 EDT, AND AT 0333 EDT ON 7/10/88,
HYDRAULIC ACCUMULATOR PRESSURE REACHED LOW SETPOINT
(2970 psig) AND WAS RECHARGED BY OPERATIONS.
07/10/88 AT 0930 EDT, PORS TALKED Wi1H THE NRC TO INFORM THEM OF
THE PROGRESS MADE AND THE ACTIONS REMAINING BEFORE VALVE
REPAIR WAS COMPLETED.
07/10/88 AT 1231 EDT, ENTERED LCO 3.5.1.2 TO PERFORM PRECHARGE ON
2 FCV 87-21 AND PERFORM MAINTENANCE ON SCHRADER VALVE.
NITROGEN PRESSURE WAS FOUND TO BE 1164.5 psig. LEAKAGE
FROM THE SCH1ADER VALVE WAS REPAIRED.
07/10/88 AT 1555 EDT, LCO 3.5.1.2 WAS EXITED. THE NITROGEN PRESSURE
WAS LEFT AT 1387 psig.
l 07/10/88 DNE WAS REQUESTED TO EVALUATE AS FOUND AFFECTS OF NITROGEN
PRESSURE ON RESPONSE TIME OF 2 FCV 87 21 AND ACCIDENT ANALYSIS.
07/11/88 WESTINGHOUSE EVALUATED THE CONDITION AND CONCLUDED THE LOW
NITROGEN PRESSURE AND SUBSEQUENT VALVE RESPONSE TIME IS
BOUNDED BY THE CURRENT UNIT 2 CYCLE 3 UHI ANALYSIS.
l
l
ROGERS 7, 35
1
,
-
- ".' ,
.
-
CONCLUSIONS
- SI-196 ' PERIODIC CALIBRATION OF UPPER HEAD INJECTION SYSTEM
INSTRUMENTATION" IS THE INSTRUCTION WHICH RESPONSE TIME
HSTS THE SUBJECT VALVES TO PROVE OPERABILITY.
- SI-744, "MONITORING OF UHI ISOLATION VALVE ACCUMULATOH PRESSURE,"
DID NOT CONTAIN SUFFICIENT INFORMATION TO PERFORM AN
ADEQUATE ASSESSMENT FOR VALVE OPERABILITY.
RESULTED IN GEVERAL RECHARGES PRIOR TO VERIFICATION OF PRECHARGE.
- MANAGEMENT DETERMINED THAT A NITROGEN PRECHARGE WAS THE MOST
ACCURATE AND 5:"alENT WAY TO DETERMINE SYSTEM STATUS WITH
RCTCur TO ACCUMULATOR HYDRAULIC PRESSURE.-
- MANAGEMENT INTERPRETED SI-744 TO INDICATE THAT A NITROGEN PRECHARGE
CHECK WAS AN ALTERNATIVE TO THE RESPONSE TIME TEST AFTER THE
FOURTH CHARGE.
- THE NITROGEN PRECHARGE CHECK WAS PLANNED BUT NOT EXPEDITIOUSLY
PERFORMED.
l
( * OPERATIONS PERSONNEL RELY ON SYSTEMS ENGINEERING TO
I DETERMINE THE NUMBER OF CHARGES TO EACH UHI ISOLATION
l VALVE ACCUMULATOR AND WHEN ACTION IS REQUIRED.
- DASED ON AN EVALUATION FROM WESTINGHOUSE, THE "AS FOUND' CONDITION
OF LOW NITROGEN PRESSURE DID NOT REPRESENT A SAFETY CONCERN.
i
l
P
j KONC.143
l
--- -- . . ---- _ . _ ._ . . . _ - - - - _ . . . _ _ . -- _ _ _ _ _ _
.
- .'.
.
ASSESSMENT OF
SAFETY SIGNIFICANCE
- 2 FCV 87-21 WAS CAPABLE OF PERFORMING iTS INTENDED
FUNCTION.
- THERE WAS A MINIMAL EFFECT ON UHI ISOLATION VALVE STROKE
TIME DUE TO THE LOW NITROGEN PRESSURE IN THE VALVE
ACCUMULATOR. TESTING ON UNIT I INDICATED THE RESPONSE
TIMES WERE APPROXIMATELY .2 SECONDS SLOWER DUE TO THE
LOW PRESSURE.
- THE UNIT 2 CYCLE 3 ANALYSIS INDICATES THE "AS FOUND'
CONDITION OF LOW NITROGEN PRESSURE IS BOUNDED EVEN
IF A SINGLE FAILURE OF THE REDUNDANT ISOLATION
VALVE IS ASSUMED.
- THE REDUNDANT UHI ISOLATION VALVE, 2 FCV 87 22 WAS
OPERABLE DURING THIS EVENT.
- A SECOND UHI INJECTION PATH WAS OPERABLE DURING
THIS EVENT
,
l
EATETf.143
_
- '/. .'
.
.
ACTIONS
1.81-744 IS BEING REVISED TO PROVIDE ACTI
IN THE DETERMINATION OF.AUHI VALVE OPER
NUMBER OF CHARGES, DEPENDENT U
HITROGEN PRECHARGE.
2.
OPERATIONS
INTERPRET THE ACTIONSPERSONNEL
OF SI 744, WILL BE TRAINED
3.
AN EVALUATION WILL BE MADE CONCERNI E
HITROGEN PRESSURE IN THE ACCUMULATO
ADDITIONAL
CHECK CHARGES ARE ALLOWED BEFO
TEST IS REQUIRED.
4.
THE NON TS sis WILL BE REVIEWED AND REVIS
\
BE TAKEN IN THE EVENT THE A
ARE NOT MET.
5.
l
THE UHI SYSTEM REMOVAL PLAN WILL BE PURSU .
WESTINGHOUSE HAS PERFORMED PRELIMINAR
1 WHICH INDICATES THE UHI SYSTEM CAN .
\
i
\
\
\
S744, 143
-_- . --
*
.
- .. .
-
.
ACTIONS
i
1.81-744 IS BEING REVISED TO PROVIDE ACTIONS TO AID
IN THE DETERMINATION OF UHI VALVE OPERABILITY. A
RESPONSE TIME TEST WILL BE REOUIRED AFTER A CERTAIN
NUMBER OF CHARGES, DEPENDENT UPON THE ORIGINAL
NITROGEN PRECHARGE.
2. OPERATIONS PERSONNEL WILL BE TRAINED ON HOW TO l
lNTERPRET THE ACTIONS OF SI 744.
3. AN EVALUATION WILL BE MADE CONCERNING INCREASING THE
NITROGEN PRESSURE IN THE ACCUMULATORS SUCH THAT
ADDITIONAL CHARGES ARE ALLOWED BEFORE A PRECHARGE
CHECK TEST IS REQUIRED.
4. THE NON TS sis WILL BE REVIEWED AND REVISED AS
APPROPRIATE TO CLARIFY THE ACTIONS WHICH SHOULD
BE TAKEN IN THE EVENT THE ACCEPTANCE CRITERIA
ARE NOT MET.
5. THE UHI SYSTEM REMOVAL PLAN WILL BE PURSUED.
WESTINGHOUSE HAS PERFORMED PRELIMINARY ANALYSIS
WHICH INDICATES THE UHI SYSTEM CAN BE REMOVED AT SON.
!
l
51744. 143
- _ - - _ - _ _ .
- _ _ _ _ _ _ _ _ _ _ ___ _ _
'
' ' *
. : '; ;
-
.
.
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