ML20234D700
| ML20234D700 | |
| Person / Time | |
|---|---|
| Site: | North Anna  |
| Issue date: | 06/26/1987 |
| From: | Caldwell J, Cantrell F, King L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20234D639 | List: |
| References | |
| 50-338-87-15, 50-339-87-15, NUDOCS 8707070309 | |
| Download: ML20234D700 (15) | |
See also: IR 05000338/1987015
Text
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UNITED STATES
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NUCLEAR REGULATORY COMMISSION
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REGION 11
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$
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101 MARIETTA STREET, N.W.
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ATL ANTA, G EORGI A 30323
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Report Nos.:
50-338/87-15 and 50-339/87-15
Licensee:
Virginia Electric & Power Company
Richmond, VA 23261
Docket Nos.:
50-338 and 50-339
Facility Name:
North Anna 1 and 2
Inspection Conducted:
May 13 - June 16, 1987
Inspectors:
M@
-
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,
[/ M
J.L.
Caldwell, Senio'r es Went Inspector
Date 51gned
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L. .P. ' King, Resident IhspWtor
Oate Signed
Approved by:
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F. S'.*Cantrell, Section Chjp
B' ate Si' ned
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Division of Reactor Projects)'
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SUMMARY
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Scope:
This routine inspection by the resident inspectors involved the
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following areas: plant status, licensee action on previous enforcement matters,
licensee event report (LER followup), review of inspector follow-u) items,
monthly maintenance observation, monthly surveillance observation,
ESF walk-
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down, operator safety verification, design change modifications, verification
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of containment integrity and plant startup from refuelling.
During the perfor-
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mance of this inspection, the resident inspectors conducted reviews of the
licensee's backshift operations on the following days - May 13, 14, 18, 19, 22,
23, 26 and 30 and June 1, 2, 3, 4, 5, 8, 9, 10, 11, 12 and 16.
Results:
Two violations were identified:
Violation of Technical Specification 3.6.1.1, Containment Integrity; and Failure to follow procedure resulting in
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movement of a fuel assembly while still partially inserted in a fuel rack (see
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paragraphs 7 and 11, respectively).
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REPORT DETAILS
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1.
Licensee Employees Contacted
- E. W. Harrell, Station Manager.
- R. C. Driscoll, Quality Control (QC) Manager
- G. E. Kane, Assistant Station Manager
- M. L. Bowling, Assistant Station Manager
- R. O. Enfinger, Superintendent, Operations
- M. R. Kansler, Superintendent, Maintenance
- A. H. Stafford, Superintendent, Health Physics
- J. A. Stall,-Superintendent, Technical Services
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J. L. Downs, Superintendent, Administrative Services
J. R. Hayes, Operations Coordinator
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D. A. Heacock, Engineering Supervisor
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D. E. Thomas, Mechanical Maintenance Supervisor
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G. D. Gordon, Electrical Supervisor
R. A. Bergguist, Instrument Supervisor
F. T. Termine11a, QA Supervisor
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J. P. Smith,
Superintendent, Engineering
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0. B. Roth, Nuclear Specialist
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J. H..Leberstein, Engineer
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- G. G. Harkness, Licensing Coordinator
- D. J. VanDeWalle, Licensing Supervisor (SEC)
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Other licensee employees contacted include technicians, operators, mechanics,
security force members, and office personnel.
- Attended exit interview
2.
Exit Interview (30703)
The inspection scope and findings were summarized on June 16, 1987, with
those persons indicated in paragraph 1 above.
The licensee acknowledged
the inspectors findings.
The licensee did not identify as proprietary any
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of the material provided to or reviewed by the inspectors during this
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inspection.
(0 pen) Violation 338,339/87-15-01:
Violation of T.S.
3.6.1.1,
Containment Integrity (paragraph 7).
(0 pen)~ Violation 338/87-15-02:
Failure to follow procedure resulting
in the movement of a fuel assembly while still partially inserted in
a spent fuel rack (paragraph 11).
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3.
Plant Status
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Unit 1
Unit 1 began the inspection period in day 25 of the refueling outage
with the fuel removed from the core.
The unit completed reloading the
core on May 18, 1987, and is presently in Mode 5 day 59 of the refueling
outage,
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Unit 2
Unit 2 began the inspection period operating at approximately 100% power.
On May 21, 1987, the leakoff rate from the #1 seal of "C" Reactor Coolant
Pump (RCP) increased to approximately 5.8 gpm indicating a degradation of
the #1 seal.
By May 23, the "C" RCP seal leakoff had increased to approx-
imately 8 gpm, and the decision was made to shut Unit 2 down.
Shutdown
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commenced on May 23,1987, after 217 days of continuous operation.
Shortly after the
"C" RCP was secured following the shutdown, the #1
seal failed completely.
The seal leakoff was isolated, and the #2 seal
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maintained the reactor coolant pressure boundary until the cooldown and
depressurization could be completed.
The licensee completed the replacement of the seal package on "C" RCP,
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and on June 1,1987, commenced a startup of Unit 2.
The unit achieved
100% power on June 4, 1987, and is presently operating at 100% power.
4.
Unresolved Items
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Unresolved items were not identified during this inspection.
5.
Licensee Action on Previous Enforcement Matters (92702)
(Closed) Violation 338,339/86-28-03:
Failure to Document Rubidium 88
Contamination.
The licensee has com
response to the Notice of Violation. pleted the action as stated in their
6.
Licensee Event Report (LER) Followup (90712)
The following LERs were reviewed and closed.
The inspector verified that
reporting requirements had been met, that causes had been identified
that corrective actions appeared appropriate, that generic applicabili,ty
had been considered, and that the LER forms were complete.
Additionally,
the inspectors confirmed that no unreviewed safety questions were involved
and that violations of regulations or Technical Specification (TS) condi-
tions had been identified.
(0 pen) LER 338/85-03:
Flooding Potential not Previously Evaluated.
(Reference Inspection Report 338,339/85-12) Corrective action in the LER
stated that long-term action was currently being developed.
The turbine
building contains safety related equipment which could be affected by
flooding.
A Type I VEPC0 engineering study showed possible options to
prevent this occurrence.
To date, the licensee has not taken any long-
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term corrective actions.
The insaector requested the licensee provide
a date when corrective action will be taken or submit a supplemental
response to the LER stating that long term action will not be taken and
provide the reasons why.
(Closed) LER 339/86-07:
Reactor Trip Caused by Turbine First Stage
Pressure Spike.
This item has been corrected by instrumentation.
(Closed
Device.) 10 CFR 2185-01:
K-Line Breaker with Improper Overcurrent Trip
The licensee provided the inspector with a memorandum dated
May 19, 1987, stating that the breakers in question have not been
purchased for use at North Anna.
7.
ReviewofInspectorFollow-upItems(92701)
(Closed) IFI 338,339/86-20-01:
Inconsistencies in Locking .9equirements
for Auxiliary Discharge Valves.
1-0P-31.2A has been revised to lock
valves closed similar to Unit 2 valves and an engineering work request
was submitted to update the drawings.
(Closed) IFI 338/86-20-02:
Inadvertent Safety Injection PT 36.1.
The'
I&C Department has changed PT 37.1A and PT 36.1B on both units to:
1)
Require single action steps
2)
Have an operator sign the PT step
3)
Only reset the train under test
This should preclude further events of this type.
(Closed) IFI 338,339/86-28-06:
Determine Source of CS-138 Which Caused a
Hi-Hi Air Particle Monitor Alarm.
The licensee took appropriate action
to determine the cause of the alarm.
Air samples were taken and analyzed
but a source determination could not be made.
(Closed) URI 338,339/86-28-04:
Verify That Rubidium 88 Did Not Exceed
The licensee demonstrated to the inspectors
that appropriate action was taken to ensure the 10 CFR 20 limits were not
exceeded.
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(Closed) URI 338,339/86-28-07:
Modification of Commitments to NRC Regarding
Inspector Concerns and a Violation.
The licensee has taken steps to
modify the procedure to ensure it is not misinterpreted.
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(Closed) URI 338/85-31-02:
Refueling - Fuel Transfer Equipment.
The
engineering work request for Unit 1 was completed prior to the refueling
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outage, and the transfer mechanism performed acceptably.
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(Closed)URI 338,339/85-05-03:
Battery Inspcction Comments. 'The licensee
changed the technical specification surveillance requirement for the
inspection of diesel fire pump battery cells.
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(Closed) IFI 338,339/84-27-05:
Organization of Offsite Review Committee.
This item will be closed until another review can be made of the Offsite
Review Committee.
The licensee has responded to all of the inspector's
concerns.
(Closed) URI 338,339/86-18-01:
Outstanding Work Requests.
This item
will be closed and monitored on a monthly basis. .The licensee made an
initial effort to reduce the amount of safety related work requests.
(Closed) IFI 338,339/86-03-03:
Rockwell Edward Valve Failure.
Periodic
tests were )repared for Unit 1 and Unit 2 for those valves which experi-
ence high tiermal transients.
The licensee performed radiography on the
RTD bypass line valves and made repairs where flow caused the valve to
seat.
(Closed) IFI 339/84-19-01:
Drawing Updates and Valve Lineu) Corrections
Required on D/G Support System.
The licensee has revised tie drawing by
Engineering Work Request 84-508.
All commitments have been completed on
this item.
(Closed)URI 338,339/87-10-02:
Review Licensee Actions Following Discovery
of Potential Unreviewed Safety Question.
In a memorandum dated May 13,
1987, from R. M. Berryman, VEPC0, to J. A. Stall, VEPCO, North Anna, the
licensee stated that a preliminary analysis on April 16, 1987 indicated
there were enough conservatisms in the current accident analysis to
consider them still bounding.
This preliminary analysis was supplied by
Stone and Webster (S&W) and reviewed by the VEPC0 corp, orate Nuclear
Eng'neering Staff on A)ril 16, 1987.
S&W completed their final review
on April 22, 1987, anc the conclusions were reported to be consistent
with the preliminary indications.
After discussions with the inspectors, the licensee agreed to perform a
formal 10 CFR 50.59 evaluation of the issue.
In a memorandum dated
May 19,1987, from R. M. Berryman, VEPC0 to J. A. Stall, VEPCO, North
Anna, the licensee documented that no unreviewed safety question existed
concerning the use of 24.7 psia instead of 30 psia for the Hi-Hi contain-
ment pressure setpoint.
The determination that an unreviewed safety
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cuestion did not exist had been addressed previously but not formally
cocumented.
(Closed) URI 338,339/85-12-01:
Proper Description & Testing of Thermal
Hydrogen Recombiner System.
In April' of 1985, the inspectors identified
a situation to the licensee where performance cf Technical Specification
(TS) surveillance 4.6.4.2.a on the hydrogen recombiners in Modes 1, 2 3
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or 4 would cause the licensee to be in violation of TS 3.6.1.1 (Prima,ry,
Containment Integrity).
The inspectors also had a concern that the
hydrogen recombiners could not withstand the design bases containment
pressure increase of 45 psig.
In April of 1986, the licensee performed an
engineering evaluation, Engineering Work Request (EWR)86-156, which
concluded that the recombiners could withstand the maximum containment
pressure caused by a design based accident.
However, a S change allowing
theperformanceofTSsurveillance4.6.4.2.a,whichrequ]iresnon-automatic
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containment isolation to be open for approximately four hours, was net
submitted to the NRC until May 27, 1987.
At the time, it was the ins)ec-
tors' understanding that performance of TS 4.6.4.2.a would not be concutted
with the units in Modes 1, 2, 3, or 4 until the licensee received an NRC
approved TS change.
During a recent review of the unresolved item, the inspectors discovered
that the licensee had performed TS 4.6.4.2.a numerous times, beginning in
1985, with the associated unit operat,ing in Mode 1,,2, 3, or 4.
The
inspectors had been given the impression that the licensee had not, and
would not, perform this surveillance unless the unit in question was in
Modes 5 or 6.
Based on further discussions with the licensee, there
appeared to be a misunderstanding among personnel within the licensee's
staff and with the inspectors.
Personnel involved with the performance
of the hydrogen recombiner surveillance felt that since the recombiner
had been demonstrated capable of being an extension of the containment
boundary, and since it would be required to be placed in service following
an accident, then performance of TS 4.6.4.2.a in Modes 1, 2, 3, or 4 was
acceptable.
However, the inspectors had made it clear to other licensee
personnel that performance of the hydrogen recombiner surveillance,
opening of non-automatic containment isolation valves for greater than
an hour, with the unit in Modes 1, 2, 3, or'.4 would be a violation of
containment integrity as presently stated in TS 3.6.1.1.
The inspectors reviewed the procedure for performance of the hydrogen
recombiner surveillance and determined there was no mention of shutting
the containment isohtion valves if an accident occurred.
In fact, there
was no discussion in the procedure precaution or otherwise which described
these valves as containment isolation valves and what should be done in
case of an accident.
The inspectors concluded that the administrative
controls over the oaeration of these containment-isolation valves with the
plent operating in iodes 1, 2, 3, or 4 was inadequate.
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Based on the fact that this item was identified in April of 1985, the
insaectors indicated to the licensee that performance of the surveillance
in iodes 1, 2, 3, or 4 was a violation of TS 3.6.1.1 the EWR demonstrating
the recombiner could withstand design bases pressur,e was not completed
until a year later in April 1986, the administrative control of the valves
did not address the containment integrity issue and finally, the TS change
was not issued until May 1987, over two years after the.need was identified,
the performance of the hydrogen recombiner surveillance with the unit in
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Modes 1, 2, 3, or 4 will be identified as a violation (338,339/87-15-01)
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of TS 3.6.1.1.
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8.
Monthly Maintenance (62703)
Station maintenance activities affecting safety related systems and
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components were observed / reviewed, to ascertain that the activities were
conducted in accordance with approved procedures, regulatory guides and
ir,idustry co&s or standards, and in conformance with Technical Specifica-
tions.
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The licensee informed the inspector that during inspections of several
Limitorque Motor Operated Valves (MOVs), grease was discovered in the
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valve spring packs.
This grease was also beginning to seoarate into an
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oil-like substance and a wax-like substance.
The licensee was concerned
that the separated grease could inhibit the operation of the spring pack
and consequently prevent the torque switch from stopping the motor.
Based on this discovery, the licensee decided to look at the grease in
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all of the safety related Limitorque MOVs.
The licensee also changed
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their preventative maintenance procedures to recbire removal of the spring
pack cover to inspect for excessive grease anc grease separation, and
initiated a p ogram to replace the grease on MOVs in containment with
Exxon NEBULA
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On May 21, 1987, the inspector observed the disassembly of Limitorque MOV
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1286B, the "B" charging pump discharge valve. This disassembly was being
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performed under maintenance
3rocedure MEMP-C-MOV-1.
The inspector observed
the grease separation, and tie location of grease in the spring pack.
The
harder portion of the grease was observed to be still pliable with i'he
consistency of axle grease.
On May 22,1987, the inspectors reviewed the Engineering Work Request
(EWR)87-375whichprovidedtheinstructionsforthemodificationofsix
incore flux thimbles. These thimbles were being modified because they
discovered to have wall thinning greater than'35% (see Inspection
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Report 338,339/87-10, paragraph 7).
Along with the EWR, the ins 3ectors
reviewed the 10 CFR 50.59 safety evaluation which demonstrated tlat the
repairs did not present an unreviewed safety question and the_ temporary
maintenance procedure TMMP-C-RC-8 which provided the instructions to
perform the modification.
The inspectors did not identify any problem
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associated with these procedures.
During this inspection period, the licensee , performed the disassembly,
inspection and repair of the 1J Emergency Diesel Generator (EDG) (see
Inspection Report 338,339/87-10, paragraph 7).
The preliminary results
of this inspection indicated one piston pin floating bushing had extruded.
This bushing, from the number 3 upper piston, had extruded to the extent
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that it had become an interference fit in one section of the bushing.
The area of the bushing that had grown showed signs of discoloration,
indicating it had been abnormally heated and showed signs of rubbing
against the fixed bushings.
The discovery of this bushing, and the number
10 upper bushing on the 1H EDG, indicates that the floating bushings can
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become heated and extruded in one section uf the bushing without being
identified as a problem during the six-month piston pin bushing, gap
measurements.
The licensee was requested to evaluate this situation and
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provide some discussion and conclusions in their diesel rtport due to be
issued to the NRC in September 1987.
The licensee has comp (leted the various types of eddy current testing of
the steam generators SG).
The result of this testing indicates numerous
tubes in each of the SGs require plugging.
Based on the results of the
sample of tubes required to be inspected by TS, the licensee is required
to get NRC concurrence prior to operation of the SGs.
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described their tube pluggi,ng criteria.in a meeting in Washington with th
the licensee
This criteria bas
of the following:
all indications greater than 40% of nominal tube wall
thickness will be plugged which is in complicnce with TS, all distorted
indications which cannot be accurately evaluated will be plugged, and all
tube sheet possible indicaticas will be plugged.
Based on this criteria,
the number of tubes requiring plugging in SG "A" is 83; SG "B" is 62; and
SG "C" is 118.
The totai
6.17%; SG "B" equals 5.25% percentage of tubes plugged in SG "A" equals
- and SG "C"
equals 7.99%.
The licensee
performed a 10 CFR 50.59 evaluation on the effects of plugging SG tubes
and determined that with less than 12% plugged, they were still within
their accident analysis and did not present an unreviewed safety question.
Based on this meeting, the NRC committed to send a letter to North Anna
Power Station stating that it is acceptable to operate the SGs following
the completion of the plugging of the SG tubes as committed to by the
licensee on June 3, 3997.
It came to the inspectors' attention, that during the Unit 2 shutdown on
May 23, 1987
followin
associated discharge ckeck valve hung 03en.thesecuringofthe"B"MainFeed
the
Following discussions w
the licensee, the inspector discovered tlat at least on two other occasions,
one in 1985 and one approximately five months earlier, MFP discharge check
valves failed to shut following the securing of the associated MFP.
The licensee has inspected and repaired as necessary all of the Unit 1
and Unit 2 MFP discharge check valves.
The one that failed during the
Unit 2 shutdown was discovered to have one dowel pin and one hinge pin
missing.
The other past failures could not be determined as to their
cause
but the licensee documented replacement of their bushings and
pins. , The recent inspections of Unit 1 and Unit 2 check valves revealed
various problems from degraded wear of the dowel pin, the hinge pins and
the bushings to missing dowel and hinge pins.
Based on these findings, the licensee repaired the check valves as neces-
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sary and is in the process of establishing a preventative maintenance
procedure to , periodically ins 3ect these check valves.
One important thing
to note; unlike the MFP disclarge check valves at the Surry Station that
failed during the recent feedwater pipe rupture event, the North Anna-
check valves have their seats welded to valve body and the dowel pins
holding the hinge pin in place were welded.
These modifications to the
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check valves were identified to North Anna by Crane through Stone and
Webster in 1978 during construction.
The inspectors observed the following maintenance items during this
inspection period:
EWR 86-054c, installation of hush trim on main feedwater regulating
valves.
The maintenance associated with pulling diesel generator bearing.
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Reactor Coolant Pumps - The inspectors observed the replacement of
the seal package on the "B" pump, and the teardown of the "A" motor
for the five year inspection.
The. five year inspection on the "A"
motor showed signs of overheating on the motor windings.
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The recirculation spray heat exchanger diaphragms replacement on the
recirculation spray heat exchangers.
The installation of new Exide batteries for the 1-III battery bank.
The maintenance on 1-SI-MOV-1890D, Low Head Safety Injection Pump
Discharge to the Cold Leg.
A work request had been written because
of a body to bonnet leak.
The inspectors reviewed the procedure, the
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material certification and the radiation work permit.
No problems
were identified.
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The replacement of piping and welding of the main feedwater piping.
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The installation of the new environmentally qualified cable for the
incore thermocouples.
This was being done under design change
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package 85-07.
The installation and torquing of the main steam relief valves.
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During the outage, the "B"
residual heat removal pump motor showed
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evidence of smoking.
The lug terminal connection was burned off.
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readings were taken, the lug replaced, and the motor restarted.
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New air cylinders and tubing have been installed for the decay heat dump
valve and the steam valves to the Terry turbine for the auxiliary feedwater
pump.
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The service water valve to the recirculation spray heat exchangers 101
A&B are being replaced with refurbished valves.
No violations or deviations were identified.
9.
Monthly Surveillance (61726)
The inspectors observed / reviewed technical specification recuired testing
and verified that testing was performed in accordance wit 1 adequate
procedures, that test instrumentation was calibrated, that limiting
conditions for operation (LCO) were met and that any deficiencies
identified were properly reviewed and resolved.
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The inspectors observed portions of the following surveillance procedures;
2-PT-71.1 " Operation of Auxiliary Feedwater Steam Turbine"
1-PT-213.14 " Valve Stroke Test for Instrument Air Supply, TV-1A-102A
and 1028.
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1-PT-61.2.3 " Containment Type B Equipment Hatch Testing".
The "0"
ring seals at the enclosure passed, but the "0" rings for the air
lock failed and were replaced.
They were retested and passed.
1-PT-83.4 " Blackout of Emergency Bus for Shutdown Loads" for the IJ
bus portion.
The diesel started and picked up the loads.
Type "C" Valve Testing - Approximately 44 valves have to be retested
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as a result of excessive leakage identified during , Type "C" testing.
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The inspectors reviewed
the Type "C" testing requirements outlined
in 1-PT-61. 3.
The "as found" and "as left" conditions are documented
on the summary pages of the procedure.
A review was made of past
Type"C"andTye'A" tests.
There are some valves.that consistently
fall the Type
C" test.
Theseincludetheairejectordivertcheck
valve in the containment, the recirculation spray heat exchanger
service water valves and the containment purge valves.
The inspectors witnessed the Type "C" testing of 1-RH-36 and 1-RH-37
which were leaking approximately 18 SCFH and the Type "C" testing of
the containment purge inlet valve.
The inspectors made a survey of the containment loop rooms and the
3enetration area to look for valve leaks.
No leaks were identified which
lad not been previously identified by the licensee.
No violations or deviations were identified.
10.
ESF System Walkdown (71710)
The following selected ESF systems were verified operable by performing a
walkdown of the accessible and essential portions of the systems on
June 16, 1987.
The inspectors verified the valve lineup for the 1H and 2J Emergency
Diesel Generator (EDG) auxiliaries per the following procedures:
1-0P-46.4A - Valve Checkoff - Diesel Air
1-0P-6.3A - Valve Checkoff - 1H Diesel Engine Lube Oil System
1-0P-6.1A - Valve Checkoff - 1H Diesel Engine Cooling Water
200P-6.2A - Valve Checkoff - 2J Diesel Engine Cooling Water
2-0P-6.4A - Valve Checkoff - 2J Diesel Engine Lube Oil System
No violations or deviations were identified.
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11.
Operational Safety Verification (71707)
By observations during. the inspection period, the inspectors verified
that' the control room manning requirements were being met.
In addition,
the inspectors observed shift turnover to verify that continuity of system
status was maintained. .The inspectors periodically, questioned shif t
personnel relative to their awareness of plant conditions.
Through log review and plant tours, the inspectors verified compliance
with selected Technical Specification (TS) and Limiting Conditions for
Operations.
In the course of the monthly activities, the resident inspectors included
a review of the licensee's physical security
arogram.
The performance
of various shifts of the security force was o] served in the conduct of
daily activities to include:
protected and vital areas access controls,
searching of personnel, packages and vehicles, badge issuance and
retrieval
escorting of visitors, patrols and compensatory posts.
In
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addition,, the resident inspectors observed protected area lighting,
arotected and vital areas barrier integrity and verified an interface
aetween the security organization and operations-or maintenance.
On a regular basis,ity was monitored to assure the activities were being
radiation work permits (RWP) were reviewed and the
specific work activ
conducted aer the RWPs. Selected radiation protection instruments were
periodical'y checked and equipment operability and calibration frequency
was verified.
The inspectors kept informed, on a daily basis, of overall status of both
units and of any significant safety matter related to plant operations.
Discussions were held with plant management and various members of the
operations staff on a regular basis. Selected portions of operating logs
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and data sheets were reviewed daily.
The inspectors conducted various plant tours and made frequent visits' to
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the control room.
Observations included:
witnessing work activities in
progress; verifying the status of operating and standby safety systems
and equipment; confirming valve positions, instrument and recorder
readings, annunciator alarms, and housekeeping.
On Mav 18, 1987, the inspector conducted a tour of the Unit 1 containment
building.
During this tour, the inspector witnessed the transfer of
several fuel assemblies from the fuel pool into the vessel.
The insoector
observed the licensee's performance of loading fuel into the vessel' from
the containment refueling bridge.
The operation of.the transfer system,
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up-ender and refueling bridge was performed by Westinghouse contract
personnel.
The VEPC0 personnel observin
refueling Senior ' Reactor Operator (SRO)g the operation consisted of the
and a Quality Assurance (QA)
inspector.
The reloading fuel operation began on May 15, 1987, and was
completed cn May 18, 1987.
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On May 23, 1987, the inspector observed portions of Unit 2 reactor shut-
down.
The unit was being shutdown due to a degraded "C" RCP #1 seal.
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Following the completion of the control rod insertion, the licensee
secured the
"C"
RCP.
Approximately five minutes after the RCP was
secured, the #1 seal failed completely.
The licensee followed 1-AP-33
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" Reactor Coolant Pump Seal Failure" and. shut the #1 seal leakoff valve.
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The #2 seal maintained the reactor coolant pressure boundary until the
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unit could be cooled down and depressurized.
During the repair, the
inspectors made a containment entry to witness replacement of the seal.
Based on a request from the Region, jection (LHSI) and Higo Head Safetyth
operation of the Low Head Safety In
Injection (HHSI) System transfer from the injection , phase te the recircu-
lation phase.
This review determined that the suction of tne LHSI pumps
automatically swaps from the Refueling Water Storage Tank (NST) to the
reactor compartment sump on a low level in the RWST.
Not oniv does the
LHSI system change state on a RWST low level, but so does the' valve for
LHSI discharge to the suction of the HHSI pumps.
Therefoi . 'A safety
injection system will automatically swap from the injection m, ele taking a
suction from the RWST to the recirculation mode where the LHSI pumps take
a suction from the containment sump and discharges to the reactor vessel
and/or supplies the necessary net positive suction head to the suction of
the HHSI pumps.
Following the recent discovery of deposits of boron on the vessel head at
the Surry Nuclear Station, and the earlier problems at another facility,
the inspector requested the licensee make a determination to see if the
problem exists on either unit at the North Anna Power Station.- At the
time of the request, Unit I was in a refueling outage and Unit 2 had just
shutdown due to a degraded reactor coolant pump seal. The licensee had
already inspected the Unit 1 reactor vessel head and bolts and informed
the inspectors that they did not discover any boron deposits on the vessel
head or the bolts.
Unit 2whichhadjustshutdownwasinspectedandthere
did not appear to be any indication of previous leaking or identification
of boron deposits in the vessel head area.
The licensee also performed a
review of past leakage problems since the last refueling outage for Unit 2
and did not discover any in the vessel head area.
On Ma"
Mode!I.25,1987, the licensee changed modes on Unit 1 from Mode 6 to
Following this mode change, the inspectors became aware of a
problem associated with the pressurizer code safety that was being taken
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credit for in TS 3.4.3.
This TS requires a minimum of one code safety
to be operable in Modes 4 and 5.
This specific code safety was' fully
o eretional except for a snubber supporting the discharge tail piece
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w1ich was inoperable.
TS 3.7.10 requires snubbers located in systems
required to be operable in Mode 5 to also be operable.
The licensee
evaluated the inoperable snubber and determined that in the condition
-of the unit at the time of the mode change, approximately 90 degrees
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Fahrenheit, the snubber was not required to support the operation of the
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code safety.
The licensee also considered in this evaluation that the
pressurizer PORVs were blocked open, the RHR reliefs were on line and the
vessel was partially drained making it unlikely that the safety would be
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required to relieve pressure and then it would be water not steam.
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However, this evaluation did not address all the possible failures of
the snubber and code safety discharge pipe and how they could affect
the operation' of the code safety.
One question not addressed, was the
possibility of the failure of the discharge pipe in such a way that
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would restrict flow out of the safety also, even though reactor coolant
temperature was 90 degrees Fahrenheit and the vessel level was partially
lowered, Mode 5 allowc up to 195 degrees Fahrenheit and the unit could be
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filled with a steam bubble in the pressurizer.
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Based on the condition of the plant at the time of the mode change, the
failure of the code safety to relieve pressure would not have presented a
safety probiem due to the other relief paths.
However, TS 3.0.4 states
in part... entry into an operational mode or other specified applicability
condition shall not be made unless the conditions of the Limiting Condition
for Operation are met without relevance on the provision contained in the
action statements unless otherwise excepted.
Since the snubber was
technically required to support the operation of the code safety and the
4
snubber was inoperable also making the code safety technically inoperable,
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then both TS 3.4.2 and 3.7.10 LCOs wer2 in action statements.
Even though
the safety significance is minor, the entry into Mode 5 from Mode 6 with a
technically ino,perable code safety was being considered a viciation of TS 3.0.4.
Following the identification of the potential violation the
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licensee re-examined the circumstances involved in the mode change.
This
re-examination revealed that one of the other relief valves previously
considered inoperable because the valve had not been fully torqued was in
fact torqued enough to be considered operable.
The licensee stated that
,
the inlet flange had been torqued to at least 250 ft-lbs and an engineering
calculation demonstrated that the bolts would take the stresses present at
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pressures up to 2485 psig.
The licensee also stated that the inlet flange
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was made up metal to metal and would have prevented leakage at the maximum
pressures experienced in Mode 5.
Based on the fact that all three safeties
were installed, the plant conditions at the time of the mode change did
not present a potential for an overpressurization event and the TS
requirement for one operable safety relief was met without the reliance on
an action statement this event is no longer being considered a violation.
The inspector will continue monitor the licensee's decision process in
making mode changes and complying with TSs.
On May 16, 1987, while moving fuel in the spent fuel pool in preparation
for transferring the fuel to the Unit 1 containment, a fuel assembly,
,
G-56, was moved'in the lateral direction while still partially inserted
in the spent fuel rack.
The fuel handling operator recognized that
something was wrong after moving the spent fuel handling bridge approxi-
mately 4 to 12 inches and immediatelv returned the fuel handling equipment
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back directly over the fuel rack. 'The fuel assembly was withdrawn and
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inspected to determine if any damage occurred.
The inspection included a
visual, with binoculars, and a video tape examination.
The licensee
reported that neither examination revealed any damage to the fuel assembly.
,
Following the licensee's investigation into the cause of the event, the
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fuel assembly was transferred to the Unit 1 containment for loading into
the core.
The mishandling event resulted in an approximate four and
one-half hour delay in the core reload.
Refueling operations were performed by a contractor (Westinghouse) under
the supervision of a VEPC0 SRO.
Just prior to the mishardling event, the
fuel handling equipment operator had been relieved, and the turnover did
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not include the position of the fuel assembly.
The on-coming operator
assumed that the assembly was fully withdrawn and did not h.. at the
assembly to ensure that it was withdrawn.
This was further complicated by
the fact that VEPC0 policies require two operators on the bridge; one
handling the fuel assembly tool and the other operating the bridge.
At
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the time of the event, there was only one oparator on the bridge
performing both functions.
This policy, along with other VEPC0
- fueling, procedures and policies,
were ex)lained to the contractor personnel prior to any fuel manipula-
tion.
iowever, the inspector was informed that on several occasions, the
licensee had to reinform the operators on the correct procedures and
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methods of operation required to be performed during fuel assembly
manipulations.
The licensee's investigation into the event revealed several discre-
pancies.
The contractor's o)erator failed to follow both the VEPC0
policies ar.d instructions inc the contractor's fuel handling procedure.
The contractor's fuel handling procedure F-5, step 6.2.3, prohibits
lateral movement of the fuel handling hoist while any part of the latched
fuel assembly is inserted into the storage cells, transfer system or
elevator.
The VEPC0 policies and instructions, which were explained to
the contractor's personnel on several occasions,icies, however, are not
require two operators on
the bridge during fuel manipulation.
These pol
spelled out in the licensee s procedures.
The operator failed to conduct
an adequate shift turnover, and the turnover was not performed at an
appropriate point in the fuel handling operation.
Finally, the
Westinghouse operators were not following the directions of the refueling
senior reactor operator as demonstrated by the need on several occasions
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to caution the operators on their fuel handling techniques,
Technical Specification 6.8.1 requires written procedures be established,
implemented and maintained covering refueling operations.
Contrary to
the above, on May 16, 1987, the spent pool refueling bridge operator
failed to follow the contractor's refueling procedure. F-5 and the
licensee's policies and instructions for fuel handling,1e still partially
operations which
resulted in the lateral movement of a fuel assembly wn1
inserted in the spent fuel rack.
This misnandling event could have
resulted in a damaged fuel assembly and is a violation (338/87-15-02).
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12. Design Change Modifications (37700)
The fc: lowing completed design changes were reviewed.
84-59 - Reg. Guide 1.97, Pressurizer Liquid Temperature Modification
83-34 - Class IE RTD, Replacement Safety Related
84-46 - Reg. Guide 1.97, Waste Gas Decay Tunic Instrument Modification
84-005 - Reactor Trip Breaker Shunt Modification.
The design changes were reviewed to verify that drawings and procedures
had been updated and the testing had been completed.
The inspector
verified that the written basis upon which the change was based was
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technically correct and no unreviewed safety question existed.
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The inspectors noted that several design changes had been installed but
not completed.
In one case, DCP 84-72 " Pressurizer Safety and Relief
Valve Discharge Pipe Support Modification" was not completed because the
pressurizer belly band support was not modified.
A review of other design change packages indicated that too much time
elapses before closing out the design change deficiency reports.
This
results in changes being installed, but not completed for long periods of
time.
No violations or deviations were identified.
13.
Verification of Containment Integrity (61715)
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Verification was made of integrity of the equipment airlock on June 6,
1987, by witnessing 1-PT-61.2.3.
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The conteinment penetration area inside the containment was inspected to
ensure proper valve lineup.
Included in the penetrations checked were
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Penetrations 22, 18, 17, 35, 37, 44, 48 and 54.
The accumulator systems were walked down as part of this module.
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No violations or deviations were identified.
14.
Plant Startup from Refueling (71711)
Valve checkoff 1-0P-7.3A was used to verify the position of the accumulator
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valves on
"A"
The motor operator was removed from the
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accumulator outlet valve as part of the program to change out the grease.
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No violations or deviations were identified.
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