ML18152A026
| ML18152A026 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 01/25/1991 |
| From: | Holland W, Tingen S, York J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18152A027 | List: |
| References | |
| 50-280-90-39, 50-281-90-39, NUDOCS 9102110060 | |
| Download: ML18152A026 (31) | |
See also: IR 05000280/1990039
Text
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ur,ITED STATES
!v, ~LE,'.\\h REGULATORY.C0Mf\\li1SSi0N
10*1 h~,AFtiF".T"i h. STREET, N.V.' .
.L:..i LANT/-..., GEORG!A 30323
Report Nos.:
50-280/90-39 and 50-281/90-39
Licensee:
Virginia Electric and Power Company
5000 Dominion Boulevard
Glen Allen, VA
23060
Docket Nos.:
50-280 and 50-281
Facility Name:
Surry 1 and 2
License Nos.:
Inspection Conducted:
October 28 through December 29,
Inspectors:
- ~
H. E. ~
SlOres i dent Inspector
.Approved by:
Scope:
J.~nt~tor
P. E. Freclricson0ectionChief
Division of Reactor Projects
SUMMARY
1990
- J .... ,;i,~ ?I
Date "signed
(-J.,')--7'(
Date Signed
- /-7-.j~fr
Date Signed
This routine resident i~spection was conducted on site in th~ areas of plant
operations, plant maintenance, plant surveillance, licensee event report .
closeout, action on previous inspection findings, cold weather pre~arations,
engineered safety features system wal kdown, i nsta-11 ati on and testing of
modifications, evaluation of licensee quality assurance program implementation,
and plant startup from refueling.
Duririg the performance of this inspection,
the resident inspectors conducted review of the licensee
1 s backshift or weekend
operations on October 29, November 4, 6, 9, 10, 11, 12, 16, 17, 18, 21, 24, 25,
26, 27~ 28, 29, 30, December 1, 2, 3, 8, 9, 15, 16, and 24.
Results:
In the surveillance functional area, a violation of Technical Specification 6.4.D was identified for failure to follow precaution 4.19 of procedure
1-0PT-ZZ-001, resLJlting in the unintentional actuation of B Train emergency
safeguard components during the performance of testing (paragraph 3.f.1).
9102i10060 910125
ADOCK 05000280
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2
In the technical support functionalar*ea, a violation of io CFR 50, Appendix B,
Criterion V, was identified for failure to provide an adequate procedure or
instructions for testfrig, * resulting in a second unintentional actuation of B
- Train emergency safegLJard components *during the performance of 1-0PT-ZZ-001
(paragraph 3.f.2).
In the engineering/technical support functional area, a violation of 10 CFR 50,
Appendix B, Criterion.III was identified for issuance.of field change 43 to DCP
86-15-01 without proper controls, resulting *in unreliable rea.ctor vessel level
indication (paragraph 10.c)'._
..
In the oper~tions fun.ctional -area, a non-cited violation was iclentified for
fa i 1 ure to. fo 11 ow * precaution 4. 8 of procedure . 2:..PT-35. 3, Reactor Power
Calibration Using CALCALC Computer Program, resulting in incorrect gain
adjustments being made on. the *power range nuclear _instruments ( paragraph
3.a).
Iri th~ engineering/iechni~al support ~unctional area, a non-cited violation was
identified for _failure to maintain the Unit 1 feed flow instrumentation
channels .operable in accordance with Tec~nical Specification 3.7.A (paragraph
3.d}.
.
In the operations functional area, a non-cited violation was identifie-d for
failure to sample the waste gas decay tank within Tec.hnical Sp~cification 3.7.E
required timeframe (paragraph 6).* *
In the maintenance funciional area, a non-cited violation was identified for
failure to* follow procedure *or instructions. during installation of Design.
Control Package 87-26 (paragraph 10.a).
In the operations functional- area, a weakness was identified regarding the
absence of a clear policy as to who.is authorized to operate differential
pres~ure detector equalization ~nd isolation v~lves (paragraph J.d).
In the operations functional ar~a~ a strength was identified with respect to
operator attentiveness in the early identification of isolated feedwater flow
transmitters ( paragraph ,3. d).
.
In the surveillance functional area, a strength was identified with regards to
the installation of full recirculation flow capability of the Unit 1 auxiliary
feedwater pumps.
This modification allows for full flow pump testing and is
considered to be a significant improvement over. previous testing capability
(paragraph 5.f).
REPORT DETAILS
1.
Persons Contacted
Licensee Employees
- R. Allen, Supervisor, Shift Operations
- W. Benthall, Supervisor, Licensing
- R. Bilyeu, Licensing Engineer
- R. Blount, Supervisor, Procedures
- D. Christian, Assistant Station Manager
- D. Erickson, Superintendent of Health Physics
- A. Friedman, Superintendent of Nuclear Training
- R. Gwaltney, Superintendent of Maintenance
- M. Kansler, Station Manager
T. Kendzia, Supervisor, Safety Engineering
- G. Marshall, Operations Maintenance Coordinator
J. MtCarthy, Superintendent of Operations
- J. Price, Assistant Station Manager
- K. Sloane, Supervisor, Operations Support
- E. Smith, Site Quality Assurance Manager
- T. Sowers, Superintendent of Engineering
NRC Personnel
- W. Holland, Senior Resident Inspector
- S. Tingen, Resident Inspector
- J. York, Resident Inspector
- Attended exit interview.
Other licensee employees contacted included control room operators, shift
technical advisors, shift supervisors and oth~r plant personnel.
Acronyms and initialisms used throughout this report are listed in the
last paragraph.
On December 11, 1990, NRC Headquarters and Region II" management visited
the Surry Power Station.
The managers were:
S. Ebneter, Region II Administrator
.
A. Gibson, Director, Division of Reactor Safety, Region II
H. Berkow, Director, Project Directorate'*1I-2; NRR
P. Fredrickson, Section Chief, Division of Reactor Projects, RII
B. Buckley, Senior Project Manager, Project Direct-orate II-2, NRR
During this visit, the licensee made a presentation on improvements that
have b.een implemented in their maintenance program and also discussed
activities associated with the ongoing Unit 1 refueling outage. After the
.
.
.
- presentation, region management met with the resident inspectors and.
toured the s~ation with the residents .and the Surry Station Manager.
2.
Plant Status
Unit 1 began the reporti.ng period in day 23 of . a scheduled 60 day
refueling outage..
On November 23_, the unit entered reduced inventory
operation and exited reduced . inventory operation on November 25.
On
.December 4, during startup preparati6n to leave co,d ~hutdown, a leak was
identified from .the RCS to. SG C.
The outage was extended due to discovery.
of this leak.
This item is further discussed in paragraph 3~d.
On
December 7,.the unit again entered reduced inventory operation and exited
. reduced inventory operation on December 8.
Reduced inventory operation is
further discussed in para~raph 3.h .. After repairs were completed on the C *
. SG, the unit recommenced the startup .sequence and the reactor was taken
critical on December 17.
After completion of startup testing {discussed
in paragraph 12), th~ unit was con~ected to the grid and resumed power
operation on December 20.
The unit operated at power*for the remainder of.
the inspection period.
Unit 2 began the reporting period in day 6 of a forced o~~age.
Corrective
actions were accomplished on the SW portion of the _RS system and the unit
. commenced restart -on November lJ.
However, during pull of -:control rods to
criticality~ contr.ol rod Ml2 was determined to be stuck.and the startup
was aborted.
This item is further discussed ih paragraph 3.d .. The unit
was restarted and recommenced power operations on November 17.
On.
December 23, the unit was ramped down to 54: power because of degraded*
.jumper straps on the C phase isolation bus* duct.
The degraded jumper
straps on the C phase isolation bus duct* are further discussed in
paragraph 3~a.
On December 28, the unit was ramped down to 2% power in
order to rep lace the degraded j u_mper straps on* C phase i sol at ion bus duct.
The unit was at 2% power at the end of the inspection period.
3.
Operational Safety Verification (71707 & 42700)
a.
Daily Inspections
The inspectors conducted daily inspections in the following areas:
control room staffing, access, and operator behavior; operator
adherence to approved procedures, TS, and LCOs; examination of panels
containing i nstri.Jmentati on and other reacto.r protection system
elements to determine that required channels are operable;-and review
of * contro.l room operator l_ogs, operating orders, pl ant d_ev_i at ion _.
reports, tagout 1 ogs, temporary modification.--logs, - and- tags-
0*on - 0
components to verify comp 1-i ance with approved procedures.-** The
inspectors al so routinely accompanied station management on pl ant
tours and observed the effectiveness of their influence on activities
being performed by plant personnel.
,_ ..
3
On December 23, 1990, at approximately 0300 hours0.00347 days <br />0.0833 hours <br />4.960317e-4 weeks <br />1.1415e-4 months <br />, the licensee
di.scovered that tw-o of the bolts connecting the Unit 2, C phase
isolation bus duct to its_support structure were glowing red.
Jumper
straps installed across the C phase isolation bus duct joint located
adjacent to th~ glowin~ red bolts were determined .to be degraded t6
an exte~t- which prevent~d C phase isolation bus duct current from
flowing through the jumper straps.
As a result, C phase isolation
bus duct current fl owed through the two bolts to the s1,1pport
structure caus fog the bolts to overheat . In order to reduce the
current flow through the two bolts, power in Unit 2 was reduced from*
90 percent to 54 percent and two.cables were inst~lled from the C_
phase isolation bus duct to the steel support structure in parallel
with. the two bolts that were overheating.
Theie acti-0ns reduced the*
temperature of the bo 1 ts.
__
On December - 27, the 1 i censee
-unsuccessfully attempted to install temporary jumper straps over the
degraded jumper straps on C phase isolation bus duct.
The first
temporary jumper strap 'i rista 11 ed overheated and was irmnedi ately
removed.
Late on December 28, Unit 2 was ramped down to 2% power,
and on the following day the degraded jumper straps on C phase
isolation bus duct were replaced.
On December 28, during the per.formance of 2-PT-35. 3, Reactor Power
Calibration Using CALCALC Computer Program,* dated October 7, 1990,
operators were unable to adjust the power range nuclear instruments'
indication to within the acceptance criteria of 2-PT -35. 3. - The .
purpose of 2-PT-35.3 is to daily .calibrate the nuclear power range
channels against a heat balance standard._
The CALCALC program
indicated that reac~or power was 16%, -while actual power range
indication was approximately 22%~
Operators attempted to reduce
power range i ndi cation to +2, -0% of the CALCALC _ va 1 ue -by
individually adjusting the gain for each of the nuclear instrument
channels.
Nuclear instr~mentation indications could only be adjusted
to approximately 20% when the gain potentiometer for each channe 1
bottomed out and could not be iidjusted further.
At that time,
oper*ators considered that the power range nuclear instruments
indicated conservatively high and submitted a station deviation.
Several hours later *operators determined that 2-PT-35.3 shouid not be
used when reactor power is less than 30%._
The test results were
considered invalid, and the nuclear instrumentation gains were
adjusted back to their original posit_ions prior to the performance of
2-PT-35.3.
A sta_tion deviation explaining that the procedure had
been violated was submitted.
Precaution 4.8 of 2-PT-35.3 requir~s
that the procedure not be used when below 30% reactor power.
Failure
to adhere to this precaution resulted in non-conservative low power
range indication for sev~ral- hours* and -was identified as a non_-:cited
__
violation for fai-lure -of operations personnel to __ follow procedu*re *
(281/90-39-05).
This licensee identified violation is not being
cited because the criteria specified i~ section V.G.1 of the NRC
Enforcement- Policy -were sati sf-i ed.
b.
c.
d.
4
Weekly Inspection~
The inspectors conducted weekly inspections in the following areas: _
operability- verification of selected Esf--systems--by-valve alignment,
breaker positions, condition *of equipment or component, and
opera'bility of instrumentation and support items essential to system
actuation of performance.
Plant touri were conducted which included
observation of general plant/equipment conditions~ fire protection
and preventative measures, control of activities in progress,
- radiation protection controls, physical security controls, plant
housekeeping conditions/cleanliness, and missile hazards.
The
inspectors routinely noted the temperature of the AFW pump discharge
piping to ensure increases in temperature were being pr:operly
monitored and evaluated ~Y the licensee.
-
Biweekly Inspections
- The inspectors conducted biweekly inspections in the foll~wing areas:
verification review*and walkdown of safety-related tagouts in effect;
review of sampli_ng *program (e.g., primary and secondary coolant
samples, boric acid tank samples, plant liquid and g~seous samples);
observation of control room shift turnover; review of implementation
-of the plant problem identification system; verification of selected
portions of containment isolation lineups; and verification that
notices to workers are posted as required by 10 CFR _19.
Other Inspection Activities
Inspections included areas in the Un1ts 1 and 2 cable vaults, vital
battery rooms, steam safeguards *areas, emergen*cy switchgear rooms,
diesel generator rooms, c0ntrol room, auxiliary building, Unit 1
containment, cable penetration areas, independent spent fuel storage
facility, low level intake structure, and the safeguards valve pit
and pump pit areas. RCS leak rates were reviewed to ensure that
detected or suspected leakage from the system was recorded,
investigated, and evaluated; and that appropriate actions were taken,
if required.
The inspectors routinely independently calculated RCS.
l~ak rates ~sing the NRC Independent Measuremerits Leak Rate Program
(RCSLK9).
On a regular basis, RWPs were reviewed, and specific work
activities were monitored to assure they were being co.nducted per the
RWPs.
Selected radiation protection instruments were periodically
checked, and equij:>me.nt operability and calibration frequency were
verified.
-
The inspectors monitored the licensee activities-associated with the
restart of Unit 2 during this inspection period.
The unit co11111enced
_ restart on November 13.
Rowever, during pull- of control rods to
criticality, control rod M12 was determined to be stuck and the
startu~ was aborted.
After several days of evaluation for operation
with an inoperable control rod (M12 problem could not be corrected)
the unit -was restarted and
reconmenced
power operations
{administrative limit .of 90*%) on November 17 *. The inspectors
- _reviewed the TS requirements for operating with an inoperable.control
i. *.
5
rod and noted that licensee actions were in compliance with the
- requirements.
On. December 4, 1990, the.licensee determined that leakage existed in
the C SG from the RCS into the SG secondary.
The unit, which was *at
approximately 175 degrees and on a bubble to* maintain pressure
control, was pl aced i_n a condition to open the* SG primary manways,
inspect for leakage, and effect repairs.
The leak was determined to
be. in a weld area for one of the SG tubes that had been pulled and
plugged d~ring the outage.
The inspectors monitored the licensee's
actions with.regards to establishing plant conditions_ to effect
repairs.
No discrepancies were noted.
On Detember 18, 1990, at approximately 2040 hou~s, I&C reported that
- all -six feedwater flow transmitters were isolated.
These
transmitters, which provide an input to the steam flow/feed ffow
mismatch reactor protection tr,p, were *restored to_ service within one
hour.
. The residents followed the activities of a root cause
evaluatirin team that was formed to*determine how these transmitters
were left isolated during startup.
On December 20, the inspectors
attended a m~eting that was held by the team with management in order
to provide preliminary results of their evaluation:.
The following_
fa~ts were discussed d~ring this meeting.
During a ~ydrostatic ~est
on the main feedwater piping, the test engineer decided to isolate
the six feedwater flow transmitters which were outside the test
boundary.
Some of the valves that were being used as test boundary
isolation had, in the past, allowed some leakage.
For this reason,
the transmitters were isolated to prevent th~em from a potential
over-pressure condition.
Test personnel were using procedure
No. TMP-7, System Hydrostatic/Pneumatic Testing, dated March 30,
1989.
They stated that step 4.4 of the procedure allowed them to
manipulate the flow transmitters' isolation valves.* This step states
that pressure instruments which may be over-ranged must be isolated
and the condition noted on attachment 3 of the procedure.
The test
engineer did isolate the flow transmitters but contrary to the
procedural require~ents:the* position of the isol~tion valves were not
added to the attachment.
The condition was identified by the reactor
operators, wh i1 e feed fl ow was a 1 i gned to bypass these transmitters .
. Although _expected. to read zero flow, erratic fluctuation prompted the
operators to question the instruments.
Failure to maintain the Unit
1 feed flow instrumentation operable as required by TS 3.7.A is
identified as an NCV (280/90-39-06).
This licensee identified
violation is not being cited because the cr.iteria specified in
section V.G.1 of the NRG_Enforcement Policy. were s_atisfied.
The
operators attentiveness to. identify and question the flow*
transmitters operation* resulted in early detection of this problem
and is identified as a strength.
The inspectors also noted that several of the contributing factors to
this event_ were discussed fo the status meeting.
The. unwritten
station policy is that operations personnel operate all ~alves up to
6
the instrument root valves and other instrument valves are operated
by I&C personnel *. Also discussed was a belief that test personnel
co*uld operate certain valves including instrument valves.*
The
absence of a clear poljcy regarding *who is authorized to operate
various plant valves is identified as a weakness.
'Another
contributing factor was the scheduling of a *1arge number of
hydrostatic tests in the last few days of the o*utage wh 1eh pl aced a
con*siderable burden on test personnel to complete these tests within
a short timeframe.
Licensee management was receptive to the teams
initial. results and indicated* corrective actions for final
conclusions would be im.plemented.
e.
Physical Security Program Inspections
In the course of monthly activities, the inipectors included a review
of the licensee
I s phys i ca 1 . security program.
The performance of
various shifts of the security force was observed in the conduct of
daily activities to include: protected and vital areas* access
controls; searching of personnel, packages and vehicles; badge
issuance and retrieval; escortfog of visitors; a.nd patrols and
compensatory posts .. No discrepancies were noted.
f.
Licensee 10 CFR 50.72 Reports
(1)
On December 2, 19~0, the licensee made a report in a~co~dance
with 10 CFR 50.72 concerning a loss of preferred power (C RSS
transformer) to the Unit I H bus and the Unit 2 J bus.
The
event occurred at approximately 1027 hours0.0119 days <br />0.285 hours <br />0.0017 weeks <br />3.907735e-4 months <br /> when an electrician
was performing continuity checks *in. accordance with test
procedure 1-0PT-ZZ-001, ESF Actuation with Instantaneous Under
Voltage~ IH Bus, dated November 20, 1990.
The electrician
inadvertently caused a relay to energize which resulted in the
opening of the C RSS output breaker.
All safety systems
operated as required following the loss of C RSS transformer.
At the. time of th~ event, Unit 1 was in cold shutdown with one
reactor coolant pump running (C RCP) and B RHR pump supplying
. shutdown cooling~
Unit 2 was operating at 90% power.
The Joss
of the C RSS transformer caused the Unit IH bus to momentarily
lose power and also resulted in the loss of power to the Unit IC
station service bus.
The loss *of C RSS transformer resulted in
a power loss to the Unit I operating RCP C.
This loss resulted
in a cooldown- of Unit I; however, *cooldown or*-differential
temperature limits were not-exceeded.
EDG #1 auto started and
restored power to the 1H hus. _:_ RHR- was not affected on Unit I
due to the B RHR pump being powered from the unaffected (IJ)
b~s.
The loss of C RSS transformer also caused the Unit 2J bus
to momentarily* lose power.
EDG #3 auto started and restored
power to the Unit 2J bus.
However,- during the time that power
was not available to the 2J bus, (approximately 10 seconds) the
..
7
-unit experienced a runback (90% to 83%) due to IRPI momentarily
losing power~
After the event,. the. licensee. conducted an .. event review and
concluded *that when performing continuity checks. across contacts
1 and 2 of .relay 27X3-1Hl in accordance with 1-0PT-ZZ-001, the
electrician iricorrectly used th~ voltmeter ohm setting in lieu
of the volt setting. Be~ause there was vo]tage __ across _ contacts 1
and 2, the incorrect use of the voltmeter shorted the contacts*
causing the i5Fl breaker to trip open which initiated the event.
. After the event review, the units were realigned to their normal
preferred power supplies and the EDGs were placed in standby. *
.The inspectors monitored the licensee actions during the event
recovery and_reviewed the licensee's conclusion for the cause of
- tbe event. In the Precautions and Limitations section of
l-OPT-_zz-..001, step 4.19 specifically states that.when verifying
. contact positions, a voltmeter should be used to verify that
there is no voltage across the contacts, and if voltage is
present, the voltmeter will be used to monitor contact position.
During the event r*eview, it became evident that this precaution
was not being adhered to while performing continuity checks.
TS 6.4.D * requires that written procedures for testi~ of systems
involving. nuclear safety be followed. * The failure to follow
precaution. 4.19 whi 1 e performing continuity checks during the
per'formance of procedure 1-0PT-ZZ-001 wa~- identified as a*
violation of TS 6.4.D (280/90-36..eOl).
(2)
On December 3, 1990, the licensee made a report in ac~ordanc~
with 10 CFR 50;72 concerning a Unit 1 unint~ntional B train CLS
HI
(SI) actuation in conjunction with the intentional CLS
actuation on tra fo A.
. The licensee was performing test *
procedure 1-0PT-ZZ-001 ( the same procedure as used in the
preceding paragraph), when the unintentional actuation occurred.'
Unit 1 was in cold shutdown with one RCP running and B RHR pump
supplying shutdown cooling.
As a result of the inadvertent B
train actuation; all train B SI valves went to their emerge~cy
positions~ the #3 EOG started, and the B train of control room
air bottl.es dumped.
The B train SI* pumps were in the
pull-to-lock position and therefore di~ not start; however, with
the SI valves a~to-repositioned and bne operating charging pump,
an SI flow path was established which caused pressurizer level
to increase from 22% to 45% before fl ow was secured.
Operators
-took necessary actions to reestablish nonnal plant alignments.
~nd the test was* s~cured.
After the event, -the 1 icensee conducted -an event-review and
concluded that the cause of the event was procedural error, in
. that a required electrical jumper was not installed which would
- have prevented the B train ESF actuation.
The procedure,
1-0PT-zz~ool, was a new procedure which had been prepared in
.
8
accordance with the new procedu~e upgrade program.
The licensee*
. w*as not able to provide a determination as tci why _the procedure
error was not identified and corrected during the procedure
preparation~ verification, *and validation process at the time of
the event review.
The inspectors* monitored the licensee actions during the event
recovery and reviewed the JJc.e.nsee conclusion for the cause of
the event.
The inspectors concluded that operator responses to
the event were proper, and agieed with the licensee's assessment
that protedure 1-0PT-ZZ-001 was inadequate.
10 CFR 50, Appendix
B, Criterion V, requires that activities affecting quality shall
be pr~scribed by documented instructions or procedures
appropriate to t.he circumstances.
The failure to provide an
adequate procedure or instructions for- teiting, resulting in the
unintentional B train CLS HI (SI) actuation during the
performance of 1-0PT-ZZ-001, was identified as a violation.of 10
CFR 50, Appendix B, Criterion V (280/90-36-02).
g.
temporary Waiver of Compliance - Unit 2
On October 27, the licensee requested a waiver of compliance from the
requir~ments of TS 3~14~C in 6rder to inspect the 48-inch service*
- water headers on Unit 2.
A temporary waiver was granted by the NRC.
On October 30, the licensee requested a waiver of compliance from the
requirements of TS 3.14.C in order to clean the two service water
supply headers on Unit 2.
This temporary waiver was granted by the
NRC.
All cleaning was accomplished within the time restraints and
the watver of compliance is considered closed.
h.
Reduced Inventory Conditions - Unit 1
Unit 1 entered a reduced inventory condition on November 23, 1990- in
order to perform maintenance activities on SI hot leg and cold leg
RCS level was increased out of the reduced inventory
condition approximately 51 hours5.902778e-4 days <br />0.0142 hours <br />8.43254e-5 weeks <br />1.94055e-5 months <br /> later.
Unit 1 reentered a reduced
inventory condition on December 7, in order to perform maintenance
activities on SG C leaking tube plug.
RCS level was increased out of
the reduced inventory condition approximately 11 hours1.273148e-4 days <br />0.00306 hours <br />1.818783e-5 weeks <br />4.1855e-6 months <br /> later. Prior
to entry into .each reduced inventory condition, the inspectors
- conducted reviews of the licensee's responses and implemented actions
with regards t6 the requirements bf Generic Letter 88-17, Loss of
No discrepanci_es were noted during -~ither
evaluation. The specific items .reviewed were:
Generic Letter 88-17 ---The -inspectors revfowed. th.e ... subject __
letter including the licensee's response to the letter dated
January 6, with supplemental responses dated *February 3,
September 29, October 31, 1989; October 5, and November 16,
1990.
9
Administrative Controls - The' inspectors monitored licensee
meetings which re~iewed the sequence of events for plJcing the
unit* in .a reduced inventory condition and discussed controls and
procedures in affect to control reduced inventory operation with
- Operations and Station Management.
Containment Closure Activity - The licensee
1:s procedures require
that the status of the containment confi~uration be established --
and verified prior to entering a reduced inventory condition.
In addition, the procedure for loss of RHR capability directs
containment* closure. action to be initiated and continued until_
the RHR system is returried to service and core condjtions* are
verified- normal. The inspectors verified that the licensee has
prepared procedures. to reasonably assure that containment
closure-will be achieved prior to the time at which core
recovery could occur.
This was done by reviewing l-OP-3.4,
Draining the Reactor Coolant System, dated January 25, 1990,
1-0P-lG, Refueling Containment Integrity and RCS Mid-Loop
Containment Closure Checklist, dated April 2a~ 1989, and AP-27,
Loss of Decay Heat Removal Capability, dated September 27, 1988.
RCS Temperature_ .. The inspectors.,verJfied.that .the controlling
procedure for draining the RCS, 1-0P-3.4 required at least two
tncore temperature indicators. be operable prior to draining the
RCS to a reduced inventory condition.
The inspectors also
verified that the control room operators periodically (every six
hours) recorded the *temperatures in their. log (periodic test
1-PT-36, Instrument Surveillance).* In addition a supplemental
check list, Control Room Operator Reduced RCS Inventory Relief
Checklist, requires at least two core exit thermocouples be
op~rable (i.e. one f~om each train).
RCS Level Indication - The licensee has installed one means of
level indication which provides continuous- readout in the.
control room.
The inspectors verified that the
system also provides a low level alarm for loss of level_ and is
calibrated.
In a letter dated October 31, 1989, the licensee
committed to install a second means of RCS level indication
during the present Unit l refuelin~ outage.
The second means of
level indication was not operable during the November 23,
reduced i nvenfory opera ti on.
The second means of l eve 1
indication was installed and util'ized on a restricted basis
during the December 7, reduced inventory operation.
The second
means of level indication was not considered fully operable
because personnel -were not trained on the:-new--system- and--
procedures were not prepared and approved to operate the new
system..
--*--**-*--**
RCS Perturbation~ - The inspectors verified that the licensee*
has a procedure, OC-28, Assessment of Maintenance Activities for_
Potential Loss of Reactor Coolant Inventory dated March 21,-
10
1989, which allows for operations*assessment of work on syste~s
for potential loss of reactor coolant inventory during reduced
RCS inventory conditions.
.RCS Inventory Addition - The inspectors -verified that procedure
1-0P-3.4 required at least two available .and operable means of
adding inventory to the RCS in addition_ to the RHR system.
The
procedure requires that in a reduced inventory condition, one
charging/safety injection pump and one low head safety injection
_ pump must be available with apprQpriate flowpaths to the core.
Loop Stop Valves -
Th~ licensee .utilizes RCS loop isolation
. valves for loop isolation. -
Nozzle dams are* not used.
_The
inspectors verified that the licensee uses* an operational
checklist to ensure that the RV upper plenum is adequate)y *
_
vented when mainten,nce activities require opening of a RCS cold.
- leg pressure boundary.
During both periods of reduced inventory
operation~ at least one RCS loop was maintained unisolated with
its loop bypass ~pen.
Contingency Plans to Repower *vital Busses . .:. The vital and*
emergency el~ctrical distribution sy~t~m receives offiite ~owe~*
from the three reserve station service -transformers during
normal plant operations.
The RHR pumps* and the CCW pumps (which
. cool the_ RHR heat exchangers) operate off stub buss es attached
to the lJ and lH emergency busses.
The stob busses are attached
- . to -these emergency buss es.
The stub buss es are* shed during
degraded or undervoltage situations *but can be r~connected to
the emergency buSses by closing a breaker.
The eq~ipment for
the two additional means for adding inventory. to the RCS,
charging pumps and low head safety injection pumps, are powered
off the emergency busses.
The number 1 EOG supplies power tb*
the lH emergency bus in case of a degraded or undervol't;age
situation, and the number _3 EOG supplies power to the lJ bus.
During the periods of reduced inventory operations, the licensee
had both EDGs for the emergency busses operable and both reserve
station.serv_ice transformers (offsite preferred power) powering
the emergency busses~
Within the areas inspected; two v*iolations and two NCVs were identified.
4.
M_aintenance Inspections* (62703 & 42700)
During the reporting period, the inspectors reviewed maintenance
activities to assure compliance with the appropriate _procedures.
Inspection areas included the f~llowing:
a.
AFW Pump Inspection and ~ep~ir
11 .
Following. a reactor trip on May 16~ 1988, a reduced flow condition
.was observed in* AFW flow to the A SG.
Subsequent investigations
determined that a. part from the 1-FW-P-38 AFW pump diffuser vane had
broken 1 oose and obstructed fl ow through 'the* AFW fl owpath* (cavitating
venturi) to the A SG.
As a .result, the other AFW. pumps on b6th units
were inspected and any diffuser vanes _exhibit_ing cracking were .
replaced.
In a letter to the NRC dated July 29, 1988, the licensee
corrmitted to inspecting each*pump every three yea*rs (the time period
recommended by the ven*dor) in order to monitor for this type of*
degradation.
In addition to .this inspection, the licensee also*
committed to replacing the smaller:~ecirculatio~ lines in a resporise.
dated August 8~ _ 1988 to IE Bulletin 88-04, Potential .Safety Related
Pump Loss.
During* the current* Unit 1 outage,* AFW pump 1:..FW-P-3A was
.
disassembled, visually *inspected, and dye penetrint i~spected based
on a two-year interval of service *since the previous inspection:
Dye
penetrant indications were found on the first, third, seventh and
eighth stage diffusers.
The indications found were* either random
round~d indications or linear indications on the inside surface of
the vane leading edges at their junction with the plate.
The first
stage diffuser was sent to a metallurgical laboratory for analysis.
A report was prepared addressing the results of the inspections ~nd
analysis.
During this.inspection* period, the inspectors reviewed the report and
discu~sed the conclusions with the licensee.
The report stated that
rounded indications are typic~l of cavitation in the pump and linear
indicatioris are caused by an increase iri the number of the pits. The
analysis revealed that. the cavitation pits formed first and then
fatigue cracks propagated from these pits.
The pits had an
approximate depth of 0.015
11
_ and the deepest fatigue crack had
propagated 0.02011 into the A diffuser.
Prior to the current outage, AFW pumps were tested us i tig a
recirculation line that allowed approximately five percent of full
. fl ow .. EPRI had shown that running this type of pump below 25 percent
of full flow can cause cavitation (Ref. EPRl CS-14445 Project
1266-18).
The report related size of the crack to two other pump crack lengths*
and
estimated that the pump could have been operated under these
same conditions for another six years.
The ins~ector reviewed the
licensee's conclusions.* No discrepancies were noted~--
- --* -
b.
Check Va1ve MaiDtenance
On November 19* and 20, the inspectors witnessed the inspection of
check valve l-SI-107.
The p_urpose of this inspection was to verify
that the check valve's disk traveled to the full open and shut
.positions and to verify that the internals were in goo~ working
.
.
. 12
condition.
The check valve's bolting material and seatin~ ~urfaces
were-inspected and the disk was manually stroked open and close.* The
inspectors attended the prejob brief, witnessed the inspectio*n and
-stroking of the v_alve from the containment, and reviewed the final.
work package, test requirements, radiological controls, system
tag-out,. and administrative controls.
This maintenance* was
accomplished per procedure 1-MPT-0417-25, Inspection Test of Safety
Inj~ction Check Valves l~SI-107, 1-SI-109, 1-SI-128, and l-SI-145,
dated October 16, 1990.
The inspectors noted that one mi nor*
- sequencing *change was required to -*perform this- maintenance. * The
procedure, which was issued as a product of the procedure upgrade
program, was an improvement over previous maintenance procedures.
No
discrepancies_ were noted.
Within the areas inspected, no violations were identified.
5.
Surveillance Inspections
(61726:& 42700)
During the repofting period, the inspectors reviewed various surveillance
activities to assure* compliance with the appropriate -procedures as'
follows:
Test prerequisites were met.
Tests were performed in accordance with approved procedures.
Test procedures appeared to perform their intended function.
Adequate coordination existed among personnel involved in the test.
Test data was properly collected and recorded.
Inspection areas included the following:
a.
Reactor Cavity Seal Test - Unit 1
On November 1, 1990, the inspectors observed the performance of
the reactor cavity seal test _for Unit 1 using procedure 1-0SP-FH-001, .
Unit 1 Reactor Cavity Seal-Test, dated October 25, 1990.
This test
is used to demonstrate that when the reactor cavity inflatable seal
is deflated during refueling, the passive J-seal will preclude
leakage.
The inspectors monitored the leakage of the J_-seal -after
deflation of the inflatable_ seal and. noted no leakage during the
test. *
Prior to performance of the test, the -inspectors observed the removal
of the reactor vessel head.
The head was 1 ifted using the
containment pol~r crane and was then moved directly to the basement.
Once the head was removed, the cavity was flooded to approximately 18
inches in order to test the cavity seal.
The *inspectors monitored
13
performance of the test from the C loop room and made the fo 11 owing
observations:.
The operator performing the test, .visually inspected the drains
during the initi~l flooding!
A calibrated pressure gage was used to verify that the cavity
seal pressure was O when deflated and 28-30 psig when inflated.
The,valves were operat~d in accordance with the procedure~
No leakage was noted from th~ tell-tale dra1n after flooding,
during , the deflation of the sea 1, or after the sea 1 was
rei nfl ated .
. No discrepancies were noted.
b. **Unit lB Inside .Retirculition Spray Pump Test*
On November 9, 1990 the inspectors witnessed the performance of
periodic test 1-PT:..lLB, Flow Test of Inside Recirculation Spray Pump.
1-Rs-P..:.lA and 1-RS.,...P-lB~ dated November 2, 1990.
These pumps are
located inside .containment, therefore, flow.* testing _:_..canno"t: be
performed during plant operation.
The pumps are flow tested during
each refueling outage.* .Flow testing requires th~ insta1lation -0f a
temporary recirculation line and the erection of a temporary dike to
contain recirculat~d water.
During the performance of the test, pump
flow, discharge ~re~sure, aryd vibration levels were measur~d.
The
inspectors observed the testing of pump 1~Rs-P~lB from the Unit 1
containment, and reviewed the procedure and test results.
No
discrepancies were noted.
c.
Control Room Air Bottle Discharge Test
On November 29, 1990 the inspectors witnessed the performance of
. periodic test.PT-33.1, Control Room Leakage Test - Bottled Air dated
July 27, 1989.
This test was being conducted as required by TS 4 .1
to verify that a minimum positive differential pressure of 0.05
inches of water could be maintained in the control room for at least
one hour~
The* inspectors verified that the test air source was 126 *
air bottles located in MER3.
The inspectors verified that
instrumentation was calibrated, that all required data was being
recorded in the test procedur~, that test results were satisfactory,
and that required reviews were accomplished of the test results.
No
discrepancies were noted.
d.
Unit l Cold Leg SI Flow Testing
On November 15, the licensee performed procedure 1-MOP-7.4, Valve
Position Setting For 1-SI-340, * l-SI-338, and l-SI-336, dated
September 17, 1985 .. The purpose of this pr6cedure is to balance the
e.
14
SI flow-between the three cold leg SI lines.
Flow to each cold leg
-is adjusted by throttling valve l-SI-340 for loop 1 cold leg, valve
1-SI-338 for loop 2 cold leg, and valve l-SI-336 for loop 3 cold leg.
Valves 1-SI-340, 336, and 340 ar~ MOVs that have been electrically
determinated.
Following adjustment, the valves' stems are tack
welded in place. In addition to the permanently installed flow
instrumentation, temporary flow instrumentation was installed to
provide a second means of measuring flowrates through valves
1-SI-336, l-SI-338, and 1-SI-340.
Due to anomalies associated with
the temporary flow instrumentation, the test results could not be
initially validated.
Because the 1-MOP-7.4 test results were inconclusive and the original
pl ant conditi ans had changed whereby this procedure could not be
used, on December 10,. the licensee performed Procedure 1-PT-18.3A,
Refueling Test of the High Head Safety Injection Valves to the Cold
Legs, dated November 13, 1990.
The purpose of 1-PT-18.3A is to
verify that the cold leg SI check valves fully open, establish
balanced flowrates between the three SI cold leg injection paths, and
verify that each SI cold leg injection leg passes the minimum
required flow rate.
1-PT-18.3A was similar to 1-MOP-7.4 in that
temporary flow instrumentation was installed to provide a second
means of measuring flowrates through valves 1-SI-336, 338, and 340.
In addition, temporary flow instrumentation was installed to measure
total SI flowrate and the high head SI pump recirculation flowrate.
Based on the problems during the conduct of 1-MOP-7.4, the temporary
flow instrumentation vendor was present to ensure proper setup of the
instrumentation.
The inspectors reviewed the test results of 1-PT-18.3A.
The
test results indicated that valves l-SI-336,.338, and 340 were
adjusted to obtain the required flow to each cold leg, and with the
exception of the cold leg 2 SI flowrate control room indication,
FT-1962, the temporary flow instrumentation and control room
indications were in agreement.
During the test, FT-1962 indicated a
flowrate of 235 gpm and the temporary flow instrumentation indicated
a flowrate of 191 gpm.
The licensee concluded that the FT-1962
flowrate was high and in error, and is investigating why FT-1962 was
in error.
The inspectors will review the results of this
investigation during future inspections.
No other discrepancies were noted.
Unit lJ Bus Testing
On December 4, the inspectors witnessed Unit 1 CLS/UV testing in
accordance with test procedure -1-0PT-ZZ-003, ESF Actuation with
Instantaneous Under Voltage - lJ Bus, dated November 20, 1991.
The
purpose of this procedure is to test the sequencing of loads onto
emergency bus lJ following the injection of an ESF signal with the
simultaneous injection of an undervoltage signal, perform 3/4 logic
..
15
verification for the CLS HI and CLS HI-HI systems (Train B), test
Train B of CLS HI, CLS HI-HI, and SI; test the HI and HI-HI CLS push
buttons, and test delay time -settings of selected agastats.
The
inspectors* monitored the_ test -from the -controk-rooni and switchgear--
room, attended the pretest brief, and reviewed the completed test
procedure.*
- The only discrepancy noted was that procedure 1-0PT-ZZ~003 contain~d
numerous errors in the areas of req~ired pre-test and post-test data.
These errors involved the omission of valves that required position
verification, referencing #1 EOG data in lieu of #3 EOG data,
_
- specifying no voltage present during performance of continuity checks
when voltage was actually present and required to be present, and the
incorrect identification of valves that required position
verification. - The majority of these errors were discovered prior to
the perfbrmance of the test and the procedure was revised.
However,
sev~ral errors were noted during the performance of the test and the
procedure was revised afterwards. Procedure 1-0PT-ZZ-003 ~as a new
procedure and issued . in accordance with the procedure upgrade
program.
This area will receive additional reviews during the next
inspection period.
f.
Motor Driven Auxiliary Feedwater Pump Testing
. On December 12, the _- inspectors wi tne.ssed the performance of.
1-PT-15.lB, Motor Driven Auxiliary Feedwater Pump (1-FW-P-3B), dated
October 31, 1989. _ The purpose of this test is to demonstrate
operability of 1..:Fw-P-3B.
Normally, the AFW pumps are tested on
- minimum recirculation flow.
During the Unit 1 outage, a full flow
recirculation test line was inst_alled for each Unit lAFW pump.
The
Decembe~ 12, test of 1-FW-P-3B was the first full flow test- of the
pump utilizing the full flow rec~rculation test line. The results of.
this test identified that there was excessive flow through the pump's
minimum flow recirculation line. The minimum flow recirculation line
has an orifice in the line that is designed to limit flow to
approximately 20 gpm, however full flow testing identified that
~pproximately 100 g~m was flowing through the minimum fl~w
recircu_lation _ line.
Since the pump's motor amperage was within
acceptable limits with the excessive minimum flow recirculation line
flowrate, the system was considered operable. Similar testing of the
Unit 1 AFW
pump 1-FW-P-3A- utilizing the pump 1s full flow
recirculation )ine also identified that the orifice in that pump
1s.
minimum flow recirculation line passed excessive flo~.
Because pump
1-FW-P-3A motor amperage was within acceptable limits, the system was
considered operable.
The licensee is planning to replace the*
orifices in both Unit 1- pumps 1-FW-P-3A a*nd.:_JB in the *future.
The
Unit 1 turbine driven
and the three Unit 2 AFW pumps have different.
orifice design than pumps 1-FW-P-3A and 38 and therefore were not an_
irrunediate concern.
Subsequent full flow testing of the Unit 1 *
turbine drive AFW pump utilizing the full flow recirculation- line
r
... .i
16
indicated that excessive flow through the pump
1s minimum flow
recirculation line did not exist. *
. The inspectors consider that full flow testing of Unit 1 AFW pumps to
be a significant-i~provement over previous testing of the pumps and
was identified as a strength in the area of surveillance testing.
Within the areas inspected, no-violations--were-identified-.--
6 .. Licensee Event Report review
(92700)
The inspector reviewed the LER's listed below to ascertain whether NRC
reporting requirements were being met and to evaluate initial adequacy of*
the corrective actions.
The inspector's review also included:followup on
implementation of corrective action and review .of licensee documentation
that all required corrective actions were complete.
- (Closed) LER 280/90-11, Main Steam Safety Va 1 ves Out of To 1 erance Due to
Mino~ Setpoint Drift.
The issue involved licensee identification that
four of the fifteen Unit 1 main steam safety valves exceeded their plus or
rrifous 3% setpoi nt range as all owe.d by Tss * .. Setpoi nt -drift \\~ias-"the cause
of the out-of-tolerance settings.
Immediate correctiv~ action involved
adjustment of the safety valves to .within the required setpoint tolerance .
An engineering evaluation also concluded that the as-found setpoints would
not have resulted in any safety limits being exceeded.
The inspectors
monitored the. licensee's actions during Unit 1 main steam safety valve
setpoint testing (Inspection Report 280,281/90-30); and consider that the
licensee's corrective actioris were adequate~
.
.
.
.
(Closed) LER 280/90-13, Failure to Obtain WGDT Sample Within Technical
Specification Sampling Interva,.
The issue involved exceeding the TS* ..
sampling intervaJ for the WGDT due to unexpected delays encountered. in
radiological control activities.
The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> required sample timeframe
was exceeded by 15 minutes.
The delay in the sampling activity was
associated with a delay in being able to obtain proper dosimetry (DAD)
combined with a change in *required contamination control protective
clothing.
All sampling results were within acceptable limits.
The.
inspector reviewed the LER. * Failure to sample the WGDT within TS required
timeframe is identified as *an NCV (280/90-36-07}~
This licensee
identified violation is not being cited because* criteria specified in
Section V.G.l of the NRC Enforcement Policy were satisfied.
Within the areas inspected, one NCV was identified.
7 *. Action on Previous Inspection findings
(92701, 92702)
a.
{Closed) IFI 280,281/89-20-01, Followup on Main Control Room Envelope
Pressurization Improvements.
The issue involved inspector followup
on 1 icensee efforts to improve the integrity of the MCR envelope
following marginally satisfactory test in June 1989.
Since that time
' *
17
the llcensee has made substantial improvements in the MCR. envelope
boundary integrity.
In addition, the capacity of the MCR envelope
air b~nk located in MER 3 has been .fncreased*to 126 bottles and the
cable vault air bank had been* increased to 150 * bottles.
The
inspector monitored testing of these improvements for MER 3. on *
November 29, 1990 (see paragraph 5.d).
The test.results, which
indicated substaritial. margin over the TS req~ir~d positive pressure,
demonstrate that the .licensee's upgrades of the air bank. syste~ and
the improvements made in the integrity of control room envelope were
warranted.
. b.
(Closed) Violation 280,281/89~2~-02, Failure to Follow Pr6cedure_for
Periodic Testing of Turbine Driven Auxiliary Feedwater Pump.
This *
violation involved operators making adjustments to the turbine sp~ed
.of*the subject pump without procedural authorization.
Licensee
corrective action for this personnel error violation i~cluded retest
of the pump to -verify operability.
In addition, the importance of
pre-job briefs was stressed to operations personnel in a memorandum
from the Superintendent of Operations.
Strict compliance to
procedures was reemphasized in the training programs.
The inspectors
noted increased operator awareness after_ implementation of corrective
action for this prpblem.
c.
(Closed) Violation 280,28i/90'-21-0l, *Failure to* Follow Procedure
while Testing *of Turbine Driven Auxiliary Feedwater Pump.*
This
violation, which occurred approximately 10. months after violation
280,281/89-24-02 discussed above, involved operators adjusting the
turbine speed of the subject pump which was not in accordance with
procedural requirements.
This violation was also caused by
operations personnel not following the test procedure.* The operator
involved in this event resigned from the company prior to being able
to provide reasons for his action~
Corrective action for this event
included station management involvement in ree~phasizing the import-*
ance of prejob briefs and strict procedural compliance. * Additional
management communication with all station personnel has emphasized
key requirements for effective procedure utilization including
understanding procedures pr,or to implementation, questioning of
incomplete procedural guidance, understanding of procedure impact on
safety systems, and procedure adherence while perfonning work.
Management directed assessments of operational concerns has also
provided feedback as to the effectiveness of ongoing actions and to
stress proper communication and attentiveness to job tasks.
The
inspectors have monitored licensee actions in this area and consider
corrective actions-to be adequate.
d.
(Closed)* Violation 281/89-34-01, Failure to Provide Adequate
Procedures or Instructions for -Evolutions-Affecting -C-ontrol of Plant * *
Conditions.
The issue involved examples where inadequate procedures
resulted in the inoperability of the RCS accumulators, personnel
contami nati ~n of three 1 i censee employees during a resin transfer
"
1.
18
evolution, and inoperabi 1 ity of valves . in the recirculation spray
system.
The licensee responded to this violation in a letter ~ated
February 6, 1990.
In that letter the licensee stated that* the
followirig corrective actions*would~be implemented~~-~----
Strengthen precaution*s in procedure OP-13 and OP-7 .1.1 to ensure
that RCS pressure is maintained below 1000 psi until the
accumulator MOVs were opened and deenergized.
Develop a* procedure for inservice leak testing and in the*
. procedure include instructions for depressurizing the. piping
being tested i.f it is not placed in service following the test.
Revise procedures that involve use of camlock fitting to include
~ppropriate precautions and instruttions.
Provide information on flood protection barriers in continuing
trainirig sessions for _the technical support-staff.
Process a change to the FSAR in the section of flood control to
provide more information on flood protection barriers.
Perform *an engineering review of the adequacy of* testing and
maintenance flood control measures and revise procedures as
necessary.*
The inspectors reviewed the revised procedures and training plans
that were developed by the licensee in response t6 these corrective
actions and considers that the corrective actions w~re satisfactorily
implemented.
e.
(Open) Violation 280,281/89-34-02, Failure to Implement Adequate
Control Measures to Prevent the Use of Incorrect Materfals or Parts.
The issue involved the installation of Units 1 and 2 pressurizer
safety valves with incorrect gaskets, and the assembly SI check
valves 2-SI-79 and 2-SI-91 with incorrect gaskets.
The licensee
responded to this violation in a letter dated February 6, 1990.
In*
the letter,. the licensee stated * corrective action had been
implemented that established an Engineering Parts Validation program
whereby engineering personnel are required to ensure that correct
parts/components (with regard to technical data and materials) are
- installed in the respective system. per design and licensing
.
requirements.
While attempting* to verify that this -corrective action
had been satisfactorily implemented, the inspectors were informed by
.the licensee that the original En~ineering ~arts=-Validation program
no longer existed and that the planning department-has been--assigned
this task.
Discussion with planning department supervision indicated.
that engineering p~rsonnel were no longer involved.
The inspectors
will continue to review the licensee's corrective action~
!'1 ~.
19
f .. * (Closed) IFI 280/90-05-06, Followup on Licensee Actions with Regards
to Modification of the Control Room Env~lope Temperature Control
System;
The issue involved the licensee's: identification -of needed .
. improvements in the subjett system due to incr~asei in heat load. in
the control room .and ~mergency switchgear rooms over the life of the
g.
plant,
During this inspection period, the licensee installed and
tested new higher capacity air conditioning units for Unit 1 in both
the control room and emergency switchgear rooms.
Testing has
demonstrated that thes.e new air conditioning* units provide the
capacity and redundancy to remove heat loads from -the control room
and emergency switchgear rooms for Unit li The inspectors monitored
installation and testing for this modification.
No discrepancies
were noted.
(Closed). URI 280,281/90-21-03, Review of Classification of Safety
Related Components.
This issue involved a work order improperly
classifying a safety related component as non-safety related.
After
- inspector and licensee investigation of this issue, it was concluded
that this is *an isolated case.
In addition, the licensee has
improv~d its work order system since this incorrect classification.in
order to prevent reoccurrence.
The inspectors will continue to
monitor this area, but preseritly do. not consider it a wfdespread *
problem.
Within the areas inspected, one violati6n was iderttified *.
8.
Cold Weather Preparations
(92714)
During this inspection period, the inspectors* reviewed the licensee's
program for implementation of protective measures for extreme cold
weather .. The program is implemented by monthly performances (October
through March) of STP-52, Cold Weather Protection, dated February 27,
1990.
STP-52 is a detailed check list of areas and components that need
to be routinely inspected to ensure that there is adequate protection to
prevent freezing.
The maj'ori ty of STP-52 is performed by operations .
department personnel.
Maintenance department personnel are required to
verify that pi ping heater tape operates satisfactory.
Deficiencies that
are noted during the performance.of STP-52 are documented and provided to
planning to schedule corrective action~
The inspectors reviewed the
performance copy of* STP-52 that was completed in November, reviewed the
- list of deficiencies generated by the performance of STP-52, and also
checked the work status of these deficiencies.
The in~pectors concluded
that STP-52 contained adequate ,instructions to prevent freezing, and that
- operations and maintenance department personnel satisfactorily performed.*
the procedure.
However, *the inspectors not.ed -that __ the def_iciencies
generated by the performance- of STP-52 were not being completed in a
timely matter.
The inspectors did flQ.:t*::-*:consid_er __ this a significant
deficiency because extreme cold weather has not occurred, and if extreme
cold weather was forecast, the list of STP-52 defici~ncies (installation
of temporary insulation and space heaters for example) could be corrected
in a short period of time.
"?
...
- ./
20
Wtthin the areas irispected, no violations were identified.
9.
ESF System Walkdowns
(71710)
-
.
During the reporting period, the inspectors walked down several ESF
systems that underwent significant maintenance during the Unit 1 outage;
The walkdowns were performed after the completion of the maintenance.
The
following ite~s were verified during the walkdowns:
Valves installed correctly i-n system with no bent stems,
missing handwheels, or improper labeling.
Major components are properly labeled.
Housekeeping is .adequ~te.
Properly installed instrumentation.
Hangers and support~ afe properly in~talled.
System configuration is in accordance with lates~ drawing
revisions.
.
.
a.
. Recirculation Spray Service Water System
The inspectors walked down the recirculation spray service water
system for Unit 1. This system had recently been extensively clea~ned
based on lower than expected flows during testing.
The maintenance
activities required removal of several- safety-related val\\'.eS in order
to accomplish the work.
Additional walkdowns by the inspectors
included the internal examination of the 96, 48, 36, -and 30 inch .
diameter piping in this system.
The insp~ctors observed tnspection,
cleaning, sandblasting and-coating of these interior surfaces.
No
discrepancies were noted.-
b.
Auxiliary Feedwater System
- The inspectors walked. down the AFW system for Unit 1. The AFW
components inspected were located in the Unit 1 containment and
safeguards buildingi.
No discrepancies were noted.
Within the areas inspected, no violations were identified.
10.
Install~ticin and Testing of Modifications (37828)
a.
ATWS Mitigation System (TI 2500/020 Rev.2) --
The NRC mandated the implementation of corrmon mode failure protection
for the reactor in order to reduce the risk of an anticipated
transient without scram event to an acceptable level (10 CFR 50.62).
21
The ATWS Rule requires specific* improvements in the design and
operation of nuclear plants to reduce the probability of failure to
shut down. the reactor following anticipated transients an_d to_
mitigate the consequences of an ATWS event. . The 1 i censee
I s
modifications to incorporate these improvements were partially.*
examined during the 1 ast *inspection period.
This work was being
accomplished in accordance with DCP 87-26.
In inspecting this modification, the following areas were e~amined: -
The NRC's safety evaluation for meeting the rule and lic~nsee.
conmitments*
System designs implementation of the srn*and commitments
Installation of equipment utilized latest design drawings, was
properly located; craft used suftable equipment and tools, and
installation steps and insp~ctions w~re being completed *
Implementation of QA/QC controls
Review of documentation, equipment testing, and training of
operation personnel
.
'
The inspectors reviewed the licensee's commitment to complete.certain
human-factors engineering reviews "for the ATWS modification.
This
mod1fication* adds a new selector switch, annunciator windows, and
status lights on the main control board.
The licensee stated that
the new equipment was designed in accordance with the guidelines of
NUREG-0700, and has been coordinated with the licensee's Control Room
Design Review (CRDR) project.
During this inspection period, the inspectors observed the following:
Craft were observed installing varistors across coil Kl of
relays 3A and 38.
Craft were observed installing a jumper across two terminals in
the main AMSAC panel as required by field change no. 34, dated
November 8, 1990.
Craft were observed performing a continuity check on cable no.
1TSC620 running from the main AMSAC panel to 1MUX-26A and 268.
During this ins_pection period, the inspectors reviewed a licensee
identified problem associated with the AMSAC mo-difica*tion during a
pre 1 i mi nary run after maintenance on aux i 1 i a ry f eedwa ter pump
1-FW-P-3A.
The pump had been tagged out to accomplish necessary
wiring modifications associated with the DCP.
However, the licensee
decided to run the pump in order to verify proper reassembly after
overhaul.
This evolution was receiving priority attention due to-a
,,\\ *.
22
'requirement to return the pump to service to support restart of Unit
2 (AFW crossconnect TS requirements).
When the licensee started the
pump, a: fuse blew associated with breaker-15H4.
Deviation report.
Sl-90-1532 stated that.the-blown fuse was caused.by a wirtng problem~
The licensee's in.vestigation detennined that DCP 87-26 moved wire
KSA-24 from termfnal B115K6 to Bl15K7 which had another wire (15H4Wl)
connected.
This wire was not shown on the design package drawing to
which the craft were working (Dwg. No. S8726-l-1FE3R Rev.a).
Further
reviews determi ne.d that engineering work request 88-039 placed the
other wire, 15H4Wl, on the terminal after initiation of DCP 87-26 and.
this condition caused the fuse to blow.
The licensee stated that the
drawings in the desfgn package may not have incorporated all of the
Surry plant modifications that may* have occurred since inception of *
the design packag~.
The licensee further. stated that the craft are
expected to detect any difference between the .design package drawings
.and the actual c.onfigurations found.
If a difference exists, the
craft should write a construction trouble report.
The QC inspector
is also expected to note any differences.
In the above example both
the craft and the QC inspector failed to detect the difference in the
wiring configuration.
Another problem occurred when the craft and a QC inspector decided to
detenninate cable 1H4PH19 fo cubicle 15H4 in order to perform the
, flow test on the AFW pump.
This cable had been previously terminated
and inspected by QC.
The craft and QC inspector put a notation in
the ~esign change package and determinated the cable without getting
engineering approval through the issuance of a field change.
The inspectors discussed the sequ~nce of events and actions which
resulted in the identification of the problem with engineering and
plant management.
In bot~ cases, all agreed that the craft and QC
failed
to.* follow
required administrative instructions in
accomplishment of the tasks.
The licensee further stated that these
types *of problems would be identified during testing and that they
were taking action to assure that all craft and QC personnel were
fully aware of the administrative requirements. concernin~
. i den ti fi catfon. of configurations other than those .in the DCPs ~
10
CFR 50, Appendix B, Criterion V requires that activities affecting
quality sha 11
be accomplished in accordance with prescribed
procedures and/or instructions.
These two examples of fai 1 ure to
follow administrative instructions are identified as a NCV
(280/90-36-08).
This licensee identified violation is not being
cited because criteria specified iri Section V.G.1 of the NRC
Enforcement Policy were satisfied.
The inspectors reviewed the testing of AMSAC to proye that the system
was operable before it was placed in service.~ Sec;:t1on 5 of _th~
__ .
design package covered this approved testing technique.
Meggering of
electrical cable, verifying proper tenninations, and testing the
system logic with certain input signals were discussed with the
testing engineer.
,,
.,
_,
.1
. 23
When Unit 1 was ascending to power the AMSAC system was *pl aced in the
. bypass mode until the unit reached 35 percent power and then it was
plac;:ed in the normal m*ode. * Approximately two minutes after placing
th_e system in ser*vice, the AMSAC armed annunciator was activated and
the system was placed in bypass.
The inspectors will followup on
this during subsequent inspections~
b.
AFW Pump Full Flow Re~irculation Modification
In response to NRC Bulletin 88-04, Potential Safety-Related Pump
Loss, the licensee identified that the Units 1 and 2 AFW pumps were
- -subject to hydraulic instability during operation at minimum
recirculation flowrates. -Long term corrective action involved pump
di $assembly and inspection, and the i nsta 11 ati on of full fl ow
recirculation piping for testing of each pump.
- The inspectors
monitored the activities associated with the installation of thi full
flow recirculation piping for the Unit 1 AFW pumps.
Th.is
modification was installed in accordance with DCP 87-08-01, AFW Pump*
Full Flow Recirculation Modification, dated August 20, 1990.
The
modification enabJes monthly AFW pump operability testing to be
performed -at full flow in lieu of minimum recirculation flow.
Testing at fuil flow in 'lieu of minimum recirculatfon flow
significantly improves ability to detect pump degradation, and
reduces the time the pumps are operated in the hydraulic instability
range.
Dudng normal operatiol'], th1; full flow recirculation lines
are isolated and not utilized.
The inspectors observed portions of the modification installation and
testing, reviewed post~test requirements, walked down the AFW system
following the installation of the modification, verified that control
room AFW system drawings were updated, and reviewed the partial
engineering technical reviews that released *portio~s of the
- modification back for operation prior to the completion of the
modification.
The only discrepancy identified was in the area of
post-replacement hydrostatic testing of the first weld locate*d in
each of the full flow recirculation lines downstream of the
respective AFW pump.
The licensee interpreted paragraph IWA-5224(d)
of Section IX of the 1980 ASME Boil er and Pressure Vessel Code to
allow the use of the AFW
1 s pump suction design pressure in the
computation of the hydrostatic test pressure for components up to the
first isolation valve located: downstream of the pump.
Since there
was no isolation valve located between each AFW pump and the full
flow recirculation line weld in question, the licensee considered
that the weld did not require a hydrostatic*. test at a pressure
based on the discharge'-*design pressure of the pump. * In lieu *of
performing a hydrostatic test of the weld, the procedure*required a
leak test. at. normal operating pressure.
As a result* of the
inspectors questioning of this .interpretation, the licensee contacted
the Chairman of the Special Gro~p on Pressure Testing, concerning the
applicability of IWA-5224(d)' to post-repair/replacement testing.
In
a licensee*memorandum dated November 16, 1990, from A. McNeill to R.
. 24
MacManus, it was stated that the Chajnnan concluded that the
licensee's interpretation of IWA-5224(d) met the letter of the code,
but did not meet the intent of the code.
The Chairman considered
that the code needed clarification in this area and indicated that he
would clarify the code for***this situation 'in a* rewrite he is chair-
ing.
As a result of. the Chainnan's response, the licensee considered
it prudent to hydrostatic test the ~elds in question at a pressure
based ort the AFW's pump discharge desigri pressure, and also would no
longer interpret paragraph IWA-5224(d) as not requiring a hydrostatic
at a pressure based on pump discharge pressure in similar situations.
c.
DCP 86-15~1, Level Instrumentation to Prev~nt Loss of Shutdown
Cooling/Surry/Unit 1
On November 21, the reactor vessel. level indication in the Unit 1
standpipe assembly *responded erratically when increasing reactor
. vessel level.
The subsequent investigation revealed that an
inadequate field change to ~CP* 86-15~1 caused the erratic indication.
As~ result of this event, the inspectors reviewed field changes 42
and 43, dated November 16 and 19 respectively, to DCP 86-15-1.
The purpose of DCP 86-15~1 i~ to install a reactor vessel standpipe
assembly to provide reactor vessel level i.ndication during periods
the reactor vesse 1 is depressuri zed and. the pressurizer dra i ne_d. * The
system was originally installe9 in accordance with DCP 86-15-1 during
a previous outage utilizing tygon tubing to vent the reactor vessel
head.
During the current Unit 1 outage, piping was installed to
replace the tygon tubing in accordance with DCP-86-15-1.
Portions of
the piping were i.nstalled whfle the reactor head was removed for
refueling operations.
However, the reactor vessel head was ready to
- be reset prior to the completion of the vent piping.
As a result,
field change 42 was issued to document the partial installation of
the vent piping and a partial technical review performed by design
engineering so that the portions of the vent piping that had been
in~talled could be used to vent the reactor.
Followitig the *issuance
of field change 42, and the completion of the partial technical
review on November 16, the vent piping was turned ~ver to operations*.
and placed in service;
During the installation of the reactor head,
it was discovered that the vent piping interfered with the reactor
head bolt tensioning device.
As a result,-field change 43 was issued
to remove the portion of vent piping that interfered with the reactor
head bolt tensionirig device: . Field change 43 was issued tin November*
19, and performed at approximately 0400 hours0.00463 days <br />0.111 hours <br />6.613757e-4 weeks <br />1.522e-4 months <br /> on November 20.
The
following day; .. operators attempted to .raise reactor vessel level from
16.5 fe*et to approximately 17 .6 fee"t _by gravity draining water from
the RWST to the reactor vessel.
During this evolution, the reactor
vessel standpipe *assembly indication was erratic.
The standpipe
1 eve 1 i ncrease_d from 16. 5 to 16. 7 feet in one minute then rapidly
-increased and stabilized at 23.8 feet.
Level then began to slowly
decrease. Several hours later, operators discovered that the reactor
head vent piping opening had been taped over following the removal of
..... _'
. '
25
the section of p1p1ng per Revision 43.
The operators loosened the
tape ~nd standpipe level decreased to 17.8 feet.
Jt was concluded that the tape installed over the vent path
following the removal of the piping per field change 43, caused the
erratic standpipe level indication.
From approximately 0400 on
November 19, to 0640 hours0.00741 days <br />0.178 hours <br />0.00106 weeks <br />2.4352e-4 months <br /> on November 21, the only means of reactor
vessel level indication was unreliable.
The *design engineer who
.prepared field change 43 failed to realize that field change 42
turhed the vent pi~ing over to operations for unrestricteefuse.
As a
result, field ihange 43 was issued without instructions to either
remove the. system from service prior to removing the piping that*
interfered with* the tensioning device, or to ensure that the
standpipe assembly remained vented while the piping was removed._
10 CFR 50, Appendix B, Criterion III requires, in part, that design
changes, shall be subj~ct to the design control measures corrunensurate
with those applied to the original design. Field change 43 to *DCP
86-15-01 was issued without proper controls resulting in unreliable
reactor vessel level indication, and was identified as a violation
(280/90-36-04).
The licensee conducted a toot cause evaluation of the event prior to
.. the* end of the ilispectton period *and concluded that. part of the
problem was associated* with an incorrect assumption about the
opera ti ona 1 status of the vent 1 i ne.
- The 1 i censee was continuing
with their review of this issue when the inspection period ended ..
Within the areas inspected, one violation and one NCV*were identi1ied.
-11.
Evaluation ~f Licensee Quality Assurance Program Implementation
(35502)
Continuing evaluations have been conducted during.this and past inspection
periods s i nee Apri 1 , 1990, of the licensee* s * Quality Assurance Program
._implementation. * These evaluations include review of all inspection
- reports, SALP reports, open items; licensee corrective actions for NRC
inspettion findings, and Lic~nsee Event Rep6rts during this period. - The
evaluation specifically focused on the findings from the previous
assessment period and included a review of licensee corrective actions for
the findings~
Each SALP functional area was review~d for licens~e action
to correct past . weaknesses and problems.
These reviews focused
specifically on ongoing licensee actions to address past problems and the
effectiveness of these actions.
The results of these evaluations were .
discussed with NRC management and --inspections were-focused on the areas
identified as needing additional attention.
Inspection activities to date have noted continuing improvement in those
functional areai evaluated during the last assessment period as improving*
(Radiological Controls and Maintenance/Surveillance).
In addition,
improvement has been noted in other functional areas (Operations and
,.
26
- Safety Assessment/Quality Verification). The licensee's Quality Assurance
Program _efforts appear to be effective in identification of problems and
in monitoring the effectiveness of corrective action.
12~
Plant Startup From Refueling
(71711)
During this inspection period, the inspectors witnessed selected portions
of the Unit 1 startup testing as follows:
-The inspectors witnessed testing and monitored activities associated wit.h
Shutdown Bank A performed in accordance with* periodic procedure*
1-NPT-RX-007; Hot Rod Drops, dated December 4, 1990.
The purpose of this
procedur~ is to measure the rod drop time for each of the 48 RCCAs from
the fully withdrawn position to dashpot entry. *No discrepancies were
noted.
The inspectors witnessed and monitored activities associated with p~riodic
test l~PT-28.11, Startup Phjsics Testing, dated December 4, 1990~
This
procedure is the controlling procedure for several of the tests. that were
required to be performed at low power levels following refueling.
The
following 1-PT-28.11 tests were withessed:
Isothermal Temperature Coefficient
This test involves measuring the MTC by determining the effects
of plant temp.erature changes on reactivity while maintaining constant
rod position and boron concentration.
No discr~pancies were noted.
Rod Swap Reference Bank Measurement
This test a 11 ows for the measurement of rod worth of the reference
bank (coritrol bank D) when fully inserted f~om 225 steps to O steps.
No discrepancies were noted.
Integral Rod Worth Measurements Using the Rod *swap Technique
This test allows for determination of the differential rod worth of
the reference bank (control bank D) when each of the remaining rod
banks is fully inserted from 225 to O steps.
No discrepancies were
noted.
13.
Exit Interview
The inspection scope and results were sulll11arized on January 2, 1991 with
those individuals identified by an.asterisk. in paragraph 1.
The following
summary of inspection activity was discussed by the inspectors during this
exit .
27
A violation of Technical Specification 6.4.D was identified for failure to .
. . follow preca*ution* 4.19 of procedur:e 1-0PT-ZZ-,001, resultjng. in the*
unintentio*nal B Train CLS HI (SI) actuation during the performance of
testing. (280/90 ... 39-01)
A violation of 10 CFR 50, Appendix 8, Criterion V, was identi1ied for
failure to provide an adequate procedure or instructions for testing,
resulting in a second unintentional 8 Train CLS-HI (SI) actuation du.ring
the performance *of 1-0PT-ZZ-001. (280/90-39.,02)
A violation of 10 CFR 50, Appendix 8, Criterion III wa~ identified for,
issuance of field change 43 to DCP 86-15-01_ without proper controls,
resulting in unreliable reactor-vessel level indication. (280/90-39-03)
A non~cited violation was identified fof failure to follow precaution 4.8
of procedure 2-PT-35.3, Reactor Power Calibration Using*CALCALC Computer
Program~ resulting in incorrect gain adjustments being made on the power
range nuclear instruments. (281/90-39-04)
A non-cited viol~tio~ was identified for fai1ure to maintain the Unit 1
feed flow instrumentation channels operable in accordance with Technical
Specification 3.7.A. (280/~0-39-05)
A non-cited viol~tion was identified .for failure to sample the waste gas
. decay tank. within Technical Specification 3.7.E required timeframe.
(280,281/90-39-06)
.
.
.
A non ... cited violation was identified for failure to follow procedure or
- instructions during installation of DCP 87-26 {280/90-39-07)
- A weakness -was identified regarding the absence* of a clear policy as to
who is authorized to operate differential pressure detector equalization.
- and isolation valves.
A strength was identified with respect to operator
attentivenes. in the early identification of isolated feedwater flow
transmitters.
A strength_ was identified with regards to the installation
of full recirculation: flow capability of the Unit 1 AFW pumps.
_This
modification allows for full flow pump testing and is considered to be a
significant improvement over previous testing capability *
. Licensee management was inf armed of the ite!JlS c 1 osed in paragraphs 6
and 7.
The licensee acknowledge*d the inspection conclusions with no
. dissenting comments.
The licensee did not identify as proprietary any of
the materials provided to or reviewed by the* inspectors during this.
inspection.
14.
Index of Acronyms amd Initial isms
ATWS MITIGATION. SYSTEM ACTUATION CIRCUIT*
AMERICAN SOCIETY OF MECHANICAL ENGINEERS
ccw
CLS/UV
CFR
DAD
EOG
EMP
ESWP
GPM-
IRPI
!SI
LCO
LER
MER
MS
MSRC
MSTV
MTC
NI
NRC
PDT
RCCA
R_CP
RS
RSHS
..;
..;
28
ANTICIPATED TRANSIENT WITHOUT SCRAM
COMPONENT COOLING WATER
CONSEQUENCES LIMITING SAFEGUARD/UNDERVOLTAGE
CODE OF FEDERAL REGULATIONS
DIGITAL ALARMING DOSIMETRY
DESIGN CHANGE PACKAGE
ELECTRICAL MAINTENANCE PROCEDURE
ELECTRIC POWER RESEARCH INSTITUTE
ENGINEERED SAFETY FEATURE
EMERGENCY SERVICE WATER. PUMP
EMERGENCY*SERVICE WATER
ENGINEERING WORK REQUEST
FINAL SAFETY ANALYSIS REPORT
GALLONS PER MINUTE
INSPECTION AN~ ENFORCEMENT
INSTRUMENTATION AND CONTROL
INDIVIDUAL ROD POSITION INDICATOR
INDEPENDENT SPENT FUEL STORAGE INSTALLATION
INSERVICE INSPECTION
LIMITING CONDITIONS OF OPERATION
LICENSEE EVENT REPORT
MECHANICAL ENGINEERING ROOM
MAIN CONTROL ROOM
MAIN FEED PUMP
MANAGEMENT SAFETY REVIEW COMMITTEE
MAIN STEAM TRIP VALVE
MODERATOR TEMPERATURE COEFFICIENT
MOTOR OPERATED VALVE
NON-CITED VIOLATION
NUCLEAR INSTRUMENTATION
NUCLEAR REGULATORY COMMISSION
NUCLEAR REACTOR REGULATION
POWER DISTRIBUTION TECHNOLOGY
PRESSURE OPERATED RELIEF VALVE
PREVENTIVE MAINTENANCE
PERIODIC TEST
QUALITY ASSURANCE
QUALITY CONTROL
ROD CLUSTER CONTROL ASSEMBLY
REACTOR COOLANT PUMP
REACTOR PROTECTION
RECIRCULATION SPRAY
RESERVE STATION SERVICE
RECIRCULATION SPRAY HEAT SYSTEM
RECIRCULATION SPRAY HEAT EXCHANGER
....
.. ,.I'
.r
RV
.RWST
sov
. SRO
. ss
TS
WGDT
- -
29
RESERVE STATION SERVICE TRANSFORMER
'REACTOR VESSEL
REFUELING WATER STORAGE TANK
RADIATION WORK PERMIT
SYSTEMATIC ASSESSMENT OF LICENSEE PERFORMANCE
SAFETY INJECTION
SOLENOID OPERATED VALVE
SENIOR REACTOR OPERATOR
STATION SERVICE
SPECIAL TEST PROCEDURE*
TECHNICAL SPECIFICATIONS
UNRESOLVED ITEM
WASTE GAS DECAY TANK