ML20207T482
| ML20207T482 | |
| Person / Time | |
|---|---|
| Site: | North Anna  |
| Issue date: | 03/10/1987 |
| From: | Caldwell J, Cantrell F, King L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20207T474 | List: |
| References | |
| TASK-2.K.3.31, TASK-TM 50-338-87-01, 50-338-87-1, 50-339-87-01, 50-339-87-1, IEIN-85-017, IEIN-85-17, IEIN-86-053, IEIN-86-057, IEIN-86-53, IEIN-86-57, NUDOCS 8703240061 | |
| Download: ML20207T482 (15) | |
See also: IR 05000338/1987001
Text
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[Sa us
UNITED STATES
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NUCLEAR REGULATORY COMMISSION
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REGION il
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101 MARIETTA STREET.N.W.
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ATLANTA. GEORGI A 30323
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Repert Nos.: ~50-338/87-01 and 50-339/87-01
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Licensee: Virginia Electric & Power Company
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Richmond, VA 23261
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Docket'Nos.: 50-338 and 50-339
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Facility Name: North Anna l'and 2
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Inspection Conduc d
nua y 12 - February 20,s1987
Inspectors:
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. J . L .'
w 11, SRI
~Date-Signed
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s/Aleh
ah n na
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L. P. King, RI
Date Signed
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Approved by:
M,
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F. Cantrell, Sectian',C
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Datd Signed
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Division of Reactor Pr ects
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SUMMARY
Scope:
This routine inspection by the resident inspectors involved the
following areas: plant status, unresolved items, licensee action on previous
enforcement matters, review of inspector followup items, monthly maintenance
. observation, monthly surveillance observation, ESF walkdown, operational safety
verification, maintenance program implementation, temporary instruction 2515/80
" Data Collection for the Performance Indicator Trial Program", TMI Item
II.K.3.31, IEIN 86-53, and region based inspector review of the Semi-Annual
Effluent Report for January - June, 1986.
Results: One violation was identified - failure to provide a maintenance
procedure and perform post maintenance testing on the control room emergency
ventilation system - see paragraph 6.
This violation was determined to meet the
criteria of 10 CFR 2 Appendix C for a licensee identified violation and will not
be cited.
8703240061 870312
ADOCK 05000338
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REPORT DETAILS
1.
Licensee Employees Contacted
- E. W. Harrell, Station Manager
- R. C.'Driscoll,-Quality Control (QC) Manager
G. E. Kane, Assistant Station Manager
- E. R. Smith, Assistant Station Manager
- R. 0. Enfinger, Superintendent, Operations
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- M. R. Kansler, Superintendent, Maintenance
A. H. Stafford, Superintendent, Health Physics
- J. A. Stall, Superintendent, Technical Services
J. L. Downs, Superintendent, Administrative Services
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J. R. Hayes, Operations Coordinator
D._A. Heacock, Engineering Supervisor
D. E. Thomas, Mechanical Maintenance Supervisor
G. D. Gordon, Electrical Supervisor
R. A. Bergquist, Instrument Supervisor
F. T. Termine11a, QA Supervisor
- J. P. Smith, Superintendent, Engineering
D. B. Roth, Nuclear Specialist
J. H. Leberstein, Engineer
- G. G. Harkness, Licensing Coordinator
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Other licensee employees contacted include technicians, operators,
mechanics, security force members, and office personnel.
- Attended exit interview
2.
Exit Interview
The inspection scope and findings were summarized on February 17, 1987,
with those persons indicated in paragraph 1 above. The licensee
acknowledged the inspectors findings. The licensee did not identify as
proprietary any of the material'provided to or reviewed by the inspectors
during this inspection.
(0 pen) Violation 338,339/87-01-01 - Failure to provide a maintenance
procedure' and perform post maintenance testing on the control room
emergency ventilation system (paragraph 6)
(0 pen)
Unresolved
Item 338,339/87-01-02
Reverification of the
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acceptability of the recirculation spray heat exchanger (paragraph 11)
(0 pen) Inspector Followup Item 338,339/87-01-03 - Potential ASCO solenoid
valve problem (paragraph 11)
(0 pen) Unresolved Item 339/87-01-04 - possible inoperability of the 2H and
2J EDGs (paragraph 11)
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(0 pen) Unresolved Item 338,339/87-01-05
Raychem splice problem
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(paragraph 15)
3.
Plant Status
Unit 1
Unit 1 began the inspection period operating at approximately 100% power
and maintained that power level through to the end of the inspection
period. Unit I has been operating on line without interruption for 111
days.
Unit 2
Unit 2 began the inspection period operating at approximately 100% power
and maintained that power level through to the end of the inspection
period. Unit 2 has been operating on line without interruption for 124
days.
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4.
Unresolved Items
An Unresolved Item is a matter about which more information is required to
determine whether it is acceptable or may involve a violation or
deviation.
Three unresolved items were identified during this inspection and are
discussed in paragraphs 11 and 15.
5.
Licensee Action on Previous Enforcement Matters (92702)
(Closed) Violation 338,339/86-25-01:
Failure of Licensee to Incorporate
Technical Specification Amendments Properly: The inspectors reviewed the
licensee's corrective actions and determined them to be acceptable.
(Closed)
Violation 338/86-17-03:
Failure to Perform a Written Safety
Evaluation. This violation was originally closed in inspection report
338,339/86-24.
However, the licensee changed their response in a letter
dated November 25, 1986.
This new response changes their commitment to
perform a 10 CFR 50.59 safety evaluation on all temporary modifications.
In the new response the licensee committed to perform technical
evaluations on all temporary modifications, but will only follow the rules
of 10 CFR 50.59 for the temporary modifications which fall under the rule.
The inspectors concur with the change to the original response and all the
requirements of 10 CFR 50.59 must continue to be met by the licensee.
6.
License Event Report (LER) Follow-up (90712 & 92700)
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 applicability had
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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) ' conditions
had been identified.
. (Closed) LER 338/86-06: : Reactor Trip. The cause of the "B" sain steam
' line isolation valve inadvertently closing was investigated.
Shaft
movement was measured against the "A" and "C" valves. The-testing did not
disclose any problems.
The best' estimate of cause is prior damage-
sustained to at least one of the rupture diaphragms.
(Closed) LER 339/86-06 (Rev 0 and 1):
Forced Unit Shutdown, Station
Batteries Inoperable. The Administrative Procedure 3.1 has been revised
to ensure that TS . surveillance requirements are satisfied during the
design change process.
(Closed) LER 338, 339/85-31: Control Room Bottled Air System Inoperable.
Action has been taken in licensed operator retraining. to discuss the
event. Guidelines have been issued by the operations manager as to when
to enter an action statement.
(Closed) LER 338/85-20 (Rev 0 and 1): Steam Generators Tube Defects. The
licensee submitted Steam Generator Tube Integrity Reports prepared by
Westinghouse. These reports were submitted November 25, 1986.
(0 pen) LER 338, 339/86-19:
Control Room Emergency Ventilation System
High Flow Rates Due to Inadequate Post Maintenance Testing. During the
week of December 1-5, 1986, a team of NRC inspectors working with licensee
personnel identified to the licensee that the control room' emergency
ventilation system flow rates were outside TS requirements (see inspection
raport 338,339/86-28). The licensee verified this finding and took the
necessary corrective actions to bring the flow rates back into compliance
with TS.'LER 338, 339/86-19 was issued by the licensee to document this
problem and describes the cause for the emergency ventilation system flow
rates to be outside of TS criteria.
The LER states that maintenance,
consisting of cleaning the inlet filters, was performed on the control
room emergency ventilation systems in June of 1986. This maintenance was
performed under a work request but without a maintenance procedure or the
performance of a post maintenance test. The licensee contends that the
cleaning of the inlet filters, which was performed for the first time,
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caused the emergency ventilation system flow rates to increase above the
TS limits. The LER also states: "Since a maintenance procedure did not
exist, post maintenance testing requirements were not identified." This
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implies that a review for post maintenance testing requirements is only
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accomplished when a maintenance procedure is issued.
The inspector
determined that this assumption is incorrect. A review of Administrative
Procedures (ADM) 16.5, Work Request (WR) and 16.7, Corrective Work Orders,
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revealed numerous requirements for both the shop foreman and shift
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supervisor to review:
the work request; the work order prior to work
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starting; and finally the work order after the work is complete, to
determine if adequate post maintenance is performed. These reviews for
post maintenance testing are required to be performed regardless of
whether a maintenance procedure is issued or not.
Technical Specification (TS) 3.7.7.1.a requires the control room emergency
ventilation system to be operable. TS action statement 3.7.7.1.a states
in part, with the emergency ventilation system inoperable, restore the
inoperable system to operable status within 7 days or be in at least hot
standby within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in at least cold shutdown within the
following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.
The failure of the licensee to perform a post
maintenance test following maintenance in June 1986 resulted in the
emergency ventilation system being inoperable from June 1986 until
December 1986 when discovered by the NRC. This failure to comply with TS 3.7.7.1.a will be identified as a violation.
The inspector questioned the licensee on the safety significance of the
control emergency ventilation system flow rates being in excess of the TS
limits. The licensee discussed the situation with the vendor using the
maximum flow rates discovered. Based on the normal filter efficiency, the
vendor supplied information and the licensee's engineering evaluation, the
emergency ventilation system effectiveness at the higher flow rates was
determined to still be better than assumed in the FSAR.
After an evaluation in conjunction with Region II personnel and
considering that the abnormal flow was identified in a joint effort by the
NRC and the Licensee, corrective action was instituted promptly to correct
the abnormal flow, action was initiated to prevent recurrence and the
discrepancy was reported as required, this event meets the requirements of
10 CFR 2, Appendix C as a Licensee identified violation (LIV). The LER
and a LIV will remain open to track completion of all the proposed
corrective action.
7.
Review of Inspector Follow-up Items (92701)
(0 pen) Unresclved Item 338,339/86-28-02: This unresolved item identified
two potentially inadequate surveillance procedures. The licensee has been
able to show that the surveillance procedures verifying control room
emergency ventilation system flow rates were adequate to ensure compliance
with Technical Specification (TS).
This item will remain unresolved
pending the determination of adequacy of the surveillance procedure for
verifying control room bottled air system compliance with TS.
8.
Monthly Maintenance (62703)
Station maintenance activities affecting safety related systems and
components were observed / reviewed, to ascertain that the activities were
conducted in accordance with approved procedures, regulatory guides and
industry codes or standards, and in conformance with Technical Specifi-
cations.
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Early in February 1987 a refurbished charging pump motor was installed on
Unit I charging pump 1-CH-P-1. This charging pump has been inoperable for
the past several months. PT 14.3 was performed satisfactorily to determine
operability of the charging pump. The only problem associated with the
maintenance was a small leak on the outboard pump bearing which was
repaired.
The inspector observed maintenance on Unit 1 "B" main feedwater regulating
valve.
The Baily feedwater positioner feedback cam and roller were
replaced.
This prevents hunting of the valve caused by excessive wear.
The procedure (IMP-C-MISC-05) for troubleshooting, repair and replacement
of non-safety related equipment was used. The parts were replaced without
any problems.
On February 12, 1986, the inspector reviewed EWR 87-123 " Instructions for
MOV Modification and Switch Valve Settings for Compliance with IE Bulletin 85-03 Valve Program." This, together with EMp-P-MOV-3 Predicative Analysis
of Motor Operated Valves, was being used to adjust the torque switch
setting on 2-CH-MOV-2286C.
The result of the test required readjustment
of the torque setting upward.
The inspector reviewed work taking place on the "A" gas stripper. Welding
repairs were being made to various reach rods. The welding permit was
also reviewed.
The inspector observed the welding on the cooling water line to the lube
oil cooler on the turbine driven feedpump on Unit 1.
The procedure used
was MMP-C-W-1 " Mechanical Welding Procedure for Preparation of Welding on
Safety Related Equipment".
No violations or deviations were identified.
9.
Monthly Surveillance (61726)
The inspectors observed / reviewed Technical Specification required testing
and verified that testing was performed in accordance with 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.
On February 4,1987, the inspector observed the performance of 1-PT-77.1A
" Safeguards Area Ventilation System Flow Test Train A Filter".
No
problems were identified.
On February 12, 1987, the inspector reviewed 1-PT-15.1 " Boric Acid
Transfer Pump Test".
No problems were identified.
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On January 29,
1987, the inspector observed the performance of
surveillance' test 1-PT-57.2 " Valve Inservice Test (SI)".
This test
performs the stroke time testing of MOV-1860B and MOV-1863A, the Low Head
Safety Injection (LHSI) pump 18 Suction Valve and 2A Discharge Valve
respectively.
Following the test performance, the inspector discussed
with the licensee the need to evaluate the operability of TS equipment on
which surveillance tests are being performed. If the surveillance test or
any other operation places the TS equipment in a condition which will
prevent it from performing its safety function upon receiving an automatic trip signal, then the equipment is considered inoperable. An example of
this is illustrated by 1-PT-57.2 where the suction valve to.the LHSI pump
from the RWST was shut to allow the cycling of MOV-18608. During this
operation, the LHSI pump is technically inoperable, and the TS action
statement must be entered. The licensee acknowledged this requirement.
The inspector will continue to monitor surveillance tests and other
operations to determine if the licensee's evaluation for equipment
operability is being properly implemented.
On February
8,
1987, the inspector observed the performance of
surveillance test 1-PT-31.7.2 " Pressurizer Level Channel II (L-460)
Functional Test" and 1-PT-32.1.4 " Steam Generator IA' Narrow Range Level
Protection Channel II (L-475) Functional Test".
On February 11, 1987, the inspector observed portions of 2-PT-21.1
" Reactor Core Flux Mapping".
No violations or deviations were identified.
10.
ESFSystemWalkdown(71710)
The following selected ESF systems were verified operable by performing a
walkdown of the accessible and essential portions of the systems on
February 13, 1987.
A walkdown was performed on the auxiliary feedwater system for Unit I
using 1-0P-31.2A,
No discrepancies were noted.
All the valves were
labeled properly with the valve number and functional description.
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No violations or deviations were identified,
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11. Operational Safety Verification (71707)
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By observations during the inspection period, the inspectors verified that
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the ' control room manning requirements were being met. In addition, the
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inspectors observed shift turnover to verify that continuity of system
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status was maintained. The inspectors periodically questioned shift
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Through log review and plant tours, the inspectors verified compliance
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with selected Technical Specification and Limiting Conditions for
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Operations.
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In the course of the monthly activities, the resident inspectors included
a review of the licensee's physical security program. The performance of
various shifts of the security force was observed in the conduct 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
addition, the resident inspectors observed protected area lighting,
protected and vital areas barrier integrity and verified an interface
between the security organization and operations or maintenance.
On a regular basis, radiation work permits (RWP) were reviewed and the
specific work activity was monitored to assure the activities were being
conducted per the RWPs. Selected radiation protection instruments were
periodically 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
and data sheets were reviewed daily.
The inspectors conducted various plant tours and made frequent visits to
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,
annuciator alarms, and housekeeping.
The following comments were noted:
The Senior Resident Inspector at the Surry Power Station (SPS) informed
the residents of a potential problem with the Recirculation Spray Heat
Exchanger (RSHX) diaphragm seals. The SPS has replaced their one quarter
inch thick diaphragms with approximately one inch thick diaphragms to
correct the problem of weld cracks and flexing of the diaphragms during
the type A pressure tests. Since the North Anna Power Station (NAPS) has
similar designed RSHXs and the diaphragm seals are only one eighth inch
thick, the inspector questioned the operability of the RSHXs at NAPS. The
NAPS engineering staff informed the inspectors that the question of the
diaphragm withstanding Design Base Accident (DBA) pressure was addressed
1984. The NAPS staff was informed by Stone and Webster (S&W) in a letter
dated September 7,1984, that "The resulting stresses and strains in the
diaphragms for a DBA pressure loading will be well below ultimate.
Since
the diaphragm plate and its weld to the flange will have strains well
below ultimate, neither will fail during the DBA." This letter, however,
went on to say that the diaphragms would have stresses above their yield
values causing the diaphragm to flex during the type A pressure test with
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no service water flow on the other side of the diaghragm. Therefore, the
licensee installed Dow Corning 3145 RTV adhesive sealant between the outer
edge of the diaphragm and the strong back isolating the diaphragm but not
the weld from the type A pressure test. This would minimize the flexing
of the diaphragm during type A testing.
The inspectors reviewed the licensee's justification for the use of RTV
sealant and the S&W 1etter verifying that the one eighth inch thick
diaphrages were acceptable. However, the inspectors were still concerned
with the fact that SPS replaced their one quarter inch thick diaphragms
with much thicker diaphragms and were issuing a 10 CFR Part 21 report even
though they were aware of the S&W evaluation. The licensee was requested
to determine if there existed any difference in the SPS evaluation and the
NAPS evaluation of the problem. On February 6, 1987, the corporate office
issued a potential Part 21 report recommending a thorough technical review
be performed of both stations' evaluations of the diaphragm seal problem
and to perfonn a reverification of the S&W calculation prior to the
determination of Part 21 reportability. On February 13, another report
was issued from the corporate engineering staff addressing their review of
RSHX designs at SPS and NAPS to evaluate the potential for failures during
the DBA condition that could result in a significant safety hazard. This
report concluded that the designs at both plants were deficient in that
external pressure loading was not considered in the original equipment
design. However, the report went on to say that failures of the diaphragm
or its weld would not occur as a result of the DBA and the design
currently installed at NAPS did not pose a safety hazard for near term
operation. The engineering staff recognized that the effectiveness of the
RTV seal installed at NAPS was not verifiable and therefore not suitable
for long term operation. Consequently, the engineering staff recommended
that a permanent modification be installed at NAPS during the 1987
refueling outage.
In the body of the report issued February 13, 1987, the reverification of
the 1984 calculations performed by S&W for NAPS revealed a new
requirement.
S&W, in a letter dated February 12, 1987, informed the
licensee that their previous evaluation was acceptable with an additional
caveat that the fatigue life of the diaphragm consisted of only five
cycles. On February 16, 1987, the NAPS staff determined that Unit I upper
RSHX diaphragms had undergone six pressurization events (cycles). During
one of the cycles, service water was flowing through the RSHXs preventing
the differential pressure across the diaphragm from flexing the diaphragm.
This reduced the number of cycles to five.
Since the S&W evaluation
indicated a limit of five cycles and a DBA would place the Unit 1 RSHX
upper diaphragm seals in a six cycle condition, the licensee prepared a
Justification for Continued Operation (JCO). This JC0 takes credit for
the RTV installed on the diaghragm to prevent the diaphragm from seeing
the DBA pressure, even though the effectiveness of the RTV is not
verifiable, along with assurance from S&W via a telephone conversation
that new calculations will confirm the acceptability of the current number
of pressurization events (cycles).
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On February 18, 1987, a discussion of the RSHX situation and the
associated JC0 at NAPS was conducted between the resident inspector and
Regional and NRR staffs. Both the Region and NRR concluded that the JC0
was acceptable for short term continued operation, but the licensee must
expedite the results from S&W showing that they can exceed five cycles on
the Unit 2 RSHX diaphragm without a failure. On February 20, 1987 NAPS
stated in a conversation with the NRC that preliminary, unchecked S&W
elastic / plastic finite element analysis indicates that ten cycles are
acceptable. NAPS stated that the supporting data calculations should be
available on March 3, 1987.
Problems with the acceptability' of the RSHX diaphragm seals were first
identified by SPS in 1980, and the question war raised again at NAPS in
1984. The most recent question on the Part 21 reportability was raised by
SPS late in 1986 and now in February 1987, VEPC0 has determined that the
design deficiencies with the RSHX diaphragm are indeed reportable. During
the recent evaluation, both the SPS units were in cold shutdown and
therefore the diaphragms could be replaced with thicker ones. However,
both the NAPS units were operating at 100% power.
The inspector is
concerned that once the question of a design deficiency sufficient enough
to cause the replacement of the diaphragms at SPS and the consideration of
Part 21
reportability was identified, the reverification of the
acceptability of the NAPS RSHX diaphragm was not pursued in an expeditious
manner.
This
item will
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identified as
an Unresolved Item
(338,339/87-01-02) pending the results of the S&W calculations and further
review by the inspectors.
During a review of the Reactor Operators (RO) log on February 2,1987, the
inspectors discovered that 2-TV-BD-200F, "C" Steam Generator (SG) inboard
isolation valve, failed to shut after the solenoid valve had been
de-energized. This valve was being cycled per 2-PT-213.1 Valve Inservice
Inspection (Blowdown System) on January 31, 1987. The R0 log stated that
after mechanical agitation of its solenoid valve, 2-TV-BD-200F closed.
Since this valve is normally open during operation and is required to shut
for containment isolation on either a loss of power or a trip signal to
the solenoid valve the inspector questioned the operability of the trip
valve and its solenoid. The inspector was informed that the solenoid
which failed to operate until mechanically agitated, was manufactured by
Automatic Switch Company (ASCO).
The inspector, aware that other
facilities had identified problems with possible sticking of ASCO solenoid
valves as documented in IE Information Notices (IEIN) 85-17 and 86-57,
again questioned the operability of 2-TV-BD-200F since the licensee
had not determined the root cause of the valve's failure to close. The
inspector also reviewed the licensee's evaluation of IEIN 85-17 and 86-57
and determined the response basically concluded that NAPS did not use the
same model of ASCO solenoid listed in the IEINs. Based on the inspector's
questions, the licensee has committed to cycling 2-TV-BD-200F weekly for a
period of time to ensure that the solenoid valve is operating properly, to
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re-evaluate IEIN 85-17 and 86-57 for generic applicability and to review
the maintenance history to determine if this problem has occurred before.
The licensee has conducted two weekly performances of 2-PT-213.1 with
satisfactory results. The inspector witnessed the first weekly cycling of
2-TV-BD-200F conducted on February 5,1987.
The licensee's commitments
relating to the potential ASCO solenoid valve problem will be identified
as an Inspector Follow-up Item, 338,339/87-01-03.
Along with the follow-up of the 2-TV-BD-200F failure to close, the
inspector reviewed a Deviation Report (DR)87-105 dated February 4, 1987.
This DR identified that the corporate engineering staff became aware late
in 1986 of a potential deficiency in the Environmental Qualification (EQ)
documentation of ASCO solenoid valves.
The DR states that the EQ
evaluation did not take into account the internal heating effects (self
heating) of continuously energized solenoid valves as it pertains to
thermal aging and subsequent qualified life calculations. On December 12,
1986, the licensee requested information on the internal heating effects
from ASCO and received this information on January 9,
1987.
This
information indicated that a significant increase in temperature could be
expected in various portions of the solenoid valve if left continually
energized.
This increased temperature could result in significant
reduction in the qualified life of the ASCO solenoid valves. The DR which
was issued to the plant on February 4,1987, stated that a preliminary
evaluation performed by the corporate engineering staff determined that
maintenance would not be required until sometime in 1988. Therefore, they
concluded that safety system operability was not currently affected. The
planned corrective actions are to identify all solenoid valves which are
continuously energized, identify the critical elastomer for the safety
function and recalculate the qualified life.
On February 9,1987, the licensee reported to the NRC that the potential
existed for both the Emergency Diesel Generators (EDGs) for Unit 2 to have
been inoperable at the same time during the month of January 1987. This
identification resulted from a review of a plant Deviation Report (DR)87-102 issued on February 3,1987, for the 2H EDG and another DR 87-113
issued on February 6, 1987, for the 2J EDG, The review of DR 87-102 which
identified that the 2H diesel governor load limit was set at the 3000KW
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setpoint instead of the maximum setpoint, was determined to be
non reportable because the 2J diesel generator was considered operable.
However, following a review on February 9, 1987, of DR 87-113 which stated
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the same problem existed with the 2J EDG governor load limit, the licensee
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had to conclude that both EDGs could have been inoperable at the same
time. At the time of the discovery of the first event on February 3,
1987, it was reported that the other three EDGs 1H, IJ and 2J had been
checked and the governor load limits were set at maximum. However, after
the discovery of the 2J EDG governor load limit setting of 3000KW on
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February 6,1987, the operators could not remember whether or not 2J.
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which is the EDG located in the last room at the end of the hall, had been
checked on February 3, 1987. TS 3/4 8.1.1.e. requires, with both diesel
generators inoperable, that two offsite A.C. circuits be demonstrated
operable within one hour, and one diesel generator be restored to
operability within two hours or be in at least hot standby within the next
six hours.
The licensee determined the last time the governor was adjusted to the
3000KW setpoint was in the December 1986 to January 1987 time frame during
the performance of a special test, ST ST-69 " Determination of EDG Load
Limiter 3000KW Setpoint", on all four EDGs. The special test was being
conducted in parallel with the normal monthly EDG surveillance test for
the purpose of permanently marking on the EDG load limiter the 3000KW
setpoint. This 3000KW determination was being made for future reference
in case the engineering evaluation could justify leaving the governor load
limiter at the 3000KW setpoint instead of maximum.
This engineering
evaluation is being performed in an attempt to minimize the overloading of
the EDG during operation. The overloading of the EDG has been identified
as one of the causes of previous diesel generator failures. A review of
the completed surveillance procedures revealed that single verification of
the governor load limiter being returned to maximum had been performed on
both the 2H and 2J EDG during the completion of the monthly surveillance
tests in January 1987. This verification was not made by the individual
who signed the procedure but was made based on a report from personnel in
the EDG room performing the surveillance.
The returning of the load
limiter to the maximum setpoint should have been double verified because
of its safety significance. The licensee returned the governor settings to
maximum immediately following their discovery.
The operators performing
the rounds of the EDG compartments are now required to record the position
of the governor setting each shif t.
The licensee is also performing a
human factors investigation in an attempt to determine the cause of the
event.
This item will be identified as an Unresolved Item 339/87-01-04
pending the determination of the diesels operability and the cause of the
event.
12. Maintenance Program Implementation (Units 1 and 2) (62700)
The inspector reviewed the implementation of the maintenance program to
determine if it is meeting regulatory requirements, to determine the
effectiveness of the program on important plant equipment, and review the
maintenance staff's activities in this area. This review consisted, in
part, of a review of equipment operating history for specific component
failures leading to plant shutdowns and recurring safety related equipment
failure. This review included a review to assure that procedures were
followed during the maintenance process.
In addition, various records
associated with the maintenance activities performed were reviewed to
assure approved procedures were used when required, limiting conditions
for operations were met while the work was being performed, procedures
were adequate for the work being performed, functional testing was
performed as required, measuring and test equipment used was calibrated
and controlled, personnel were trained to perform the maintenance as
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necessary, and miscellaneous other required controls were met.
The
following documents were reviewed as part of this process:
Emergency Work Orders
5901017038
5901018019
5901016005
5902016543
5900038774
5900038733
Station Procedures
ADM 16.4 - Maintenance Program dated 8/28/86
ADM 16.5 - Work Request (WR) dated 9/19/86
ADM 16.7 - Corrective Work Orders dated 9/11/86
ADM 16.16 - Safety Related Equipment Failure Analysis Program dated
10/31/85 and draft dated 12/86
MD ADM 8.2 - Maintenance Department Administrative Procedure Equipment
History dated 12/10/85
ICP-NI-2-N31 - Source Range N31 dated 5/17/84
ICP-NI-2-N32 - Source Range N32 dated 5/17/84
IMP-C-SSPS-04 - Troubleshooting and Repair of Solid State Protection
System
IMP-C-MISC-05 - Troubleshooting, Repair and Replacement of Non-Safety
Related Equipment dated 4/5/84
IMP-C-NI-04 - Source Range Detector Replacement dated 3/6/81
2-PT-36.7.2 - Reactor Trip From Turbine Trip Response Time Test dated
11/1/84
EMP-C-EP-1 - Troubleshooting and Repair of Single Phase Static Inverters
dated 4/12/84
The inspector verified calibration equipment used during portions of work
requests listed above. This equipment is as follows:
Digital Voltmeter - NQC item 087
Multifunction Meter - NQC item 092
Counter - NQC item 169
Digital Voltmeter - NQC item 519
No violations or deviations were identified.
13. Temporary Instruction 2515/80, Data Collection for the Performance
Indicator Trial Program
During the month of July 1986, the inspectors collected the data requested
in TI 2525/80 and submitted it to the Region for processing.
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14. THI Item II.K.3.31 (71707)
Per letter dated November 21, 1986, from Leon B. Engle, Project Manager,
NRC, to W. L. Stewart, Vice President, VEPCO, the NRC has reviewed and
accepted the licensee's response to TMI item II.K.3.31.
Therefore, based
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on the safety evaluation attached to the letter, TMI item II.K.3.31 for
Unit 1 and Unit 2 is closed.
15.
IE Information Notice 86-53(92701)
The licensee issued an Engineering Work Request (EWR)87-073 dated
January 15, 1987, in response to IE Information Notice (IEIN) 86-53,
Improper Installation of Heat Shrinkable Tubing, dated June 26, 1986, and
the problems with Raychem splices discovered at the Surry Stattoo. This
EWR established the criteria and list of Raychem splices which wauld be
inspected at North Anna Unit 1. .This inspection commenced on February 2,
1987, and by February 15,1987, only 11 items containing Raychem splices
had been inspected.
Each of these items may have several splices
associated with it.
Of the 11 items inspected, all of the splices were
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determined to be faulty by Raychem criteria.
However, the equipment
associated with the splices inspected had very little, if any, safety
significance and therefore did not cause any operational issues. Based on
the type of equipment being inspected, the speed at which the inspection
was being conducted and the failure rate (100%), the inspector voiced a
concern to licensee management that the inspection program was not
receiving the attention that it should.
Licensee management agreed and
decided to change the scope of the inspection to include items of nore
safety significance and to increase the number of inspection teams from
one to three to expedite the inspection process. The original scope. was
defined based on ease of access and radiological concerns.
This revised inspection program did not recommence until February 17,
1987, at which time four more items were inspected and found to be
defective by Raychem criteria. On February 18, 1987, a conference call
between the licensee and the region was conducted to allow an exchange of
information on the Raychem issue.
The regional staff voiced a concern
that the licensee needed to look at some items of more safety signifcance
and to look at Unit 2 items as well.
The licensee committed to calling
the Region back on February 20, 1987, with an update on the inspection
process results of the Unit 1 and Unit 2 items inspected. Also, during
the call on February 18, 1987, the licensee informed the NRC that they had
just inspected four additional items which proved to be acceptable.
A review of the licensee's Deviation Reports (DRs) and their response to
IEIN 86-53 revealed that the licensee had identified problems with the
Raychem splices as early as December 1985. DR 85-1698 dated December 12,
1985, stated that of the 26 Raychem splices inspected inside Unit I
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containment all 26 were found deficient by Raychem criteria. IEIN 86-53
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was issued _in June of 1986 providing the licensee with additional
inforeation 'of industry problems with Raychem splices.
Finally, in
December of 1986 DR 86-1504 for Unit 1 and DR 86-1505 for Unit 2 were
issued documenting Raychem splice problem on all the narrow range delta
T/1ME protection / control temperature element electrical connections.
Since these splices were deficient, the licensee had to issue a
justification for. continued operation to allow the units to continue to
operate.
On February 20, 1987, a conference call between the licensee and the
region was conducted to provide an update on the inspection progress. The
licensee had examined 93 Raychem splices of which 5 did not meet the most
current acceptance criteria available.
It should be noted that this
acceptance criteria is less stringent than the Raychem criteria referenced
earlier. The licensee has inspection teams working outside containment on
both units ten hours a day, five days per week and estimates completion of
all items outsido containment in late March, 1987.
Items inside
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containment will be inspected during the scheduled refueling outages.
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In light of the above information, the inspector is concerned that the
' licensee had very good indications that a Raychem problem existed at North
Anna in l'!86 but waited until February 1987 to establish and perform a
7
complete w pection program.
Pending the results of the present
inspection program, this will be identified as an Unresolved Item
338,339/87-01-05.
16.
Review of Periodic and Special Reports (90713)
Region based inspectors reviewed the Semi-Annual Effluent Report for
January - June 1986,,against the criteria given in Regulatory Guide 1.21,
Measuring, Evaluating, and Reporting Radioactivity in Solid Wastes and
Releases of Radioactive Materials in Liquid and Gaseous Effluents from
Light-Water-Cooled Nuclear Power Plants, and applicable regulatory
requirements.
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No violations or deviations were identified.
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