ML19350D207
| ML19350D207 | |
| Person / Time | |
|---|---|
| Site: | Vermont Yankee File:NorthStar Vermont Yankee icon.png |
| Issue date: | 02/20/1981 |
| From: | Collins S, Foley T, Martin T, Raymond W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML19350D206 | List: |
| References | |
| 50-271-80-17, NUDOCS 8104140021 | |
| Download: ML19350D207 (54) | |
See also: IR 05000271/1980017
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O.S. NUCLEAR REGULATORY COMMISSION
50271-800107
0FFICE OF INSPECTION AND ENFORCEMENT
50271-800630
50271-801017
Region I
50271-801007
50271-801013
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Report No.
80-17
50271-800908
50271-800903
Docket No.
50-271
50271-800904
50271-800114
License No.
Priority
Category
C
50271-800731
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50271-800815
Licensee:
Vermont Yankee Nuclear Power Corporation
50271-800417
50271-801027
1671 Worcester Road
50271-801014
50271-801014
Framingham, Massachusetts 01701
Facility Name:
Vermont Yankee
Inspection at:
Vernon, Vermont
Inspection conducted.: October 20-November 14, 1980
Inspectors:
.
M/btr
d' # # # /./ M
/ 3d
/
W. J. Raymona
enior/desicent inspector
date sighed
Yl
INIBl
S /J. Gollins Resident Inspector
~ da te' igned
/ 3oM/
/IW
/,
M
T. F.
oley,
esid r/t Inspect 6r-
date signed
Approved by:
_ /&t4mg
g
.M
/
Section Nc'.f, Ch{pf, Reactor Projects
date ' signed
. T. Mar,ti
3, R0&NS Branch
Insoection Summary:
Inspection on October 20-November 14, 1980 (Report No. 50-271/80-17)
Areas Inspected: Routine, onsite, regular and backshift inspection by the Resident
Inspectors.
Areas inspected included: Actions Taken on Previous Inspection Findings;
Review of Plant Operations, including:
Instrumentation and Alarms, Shift Manning,
Radiation Protection Controls, Plant Housekeeping, Fire Protection / Prevention, Con-
trol of Equipment, and Shift Logs and Operating Records; System Operational Safety
Verification; Licensee Staffing; Licensee Reporting; IE Bulletin Review; Witness of
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surveillance Tests; Response to Plant' Events; Observations of Physical Security;
Plant Maintenance, Modifications, and Refueling Operations; and inspector Followup
on Regional Requests.
The inspection involved 124 inspector hours onsite by three
Resident Inspectors.
Results: No items of noncompliance were identified during this inspection.
Region I Form 12
(Rev. April 77)
8104140Q &\\
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DETAILS
1.
Persons Contacted
The below listed technical and supervisory level personnel were among those
contacted:
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Mr. L. Anson, Plant Training Supervisor
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Mr. R. Branch, Assistant Operations Supervisor
Mr. P. Donnelly, Instrument and Control Supervisor
Mr. D. Girroir, Technical Assistant
Mr. S. Jefferson, Reactor Engineering Supervisor
Mr. B. N. Leach, Chemistry and Health Physics Department
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Mr. M. Lyster, Operations Supervisor
Mr. W. Murphy, Plant Superintendent
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Mr. J. Pelletier, Assistant Plant Superintendent
Mr. D. Reid, Engineering Support Supervisor
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Mr. S. Vekasy, Technical Assistant
The inspectors also interviewed other licensee employees during the inspec-
tion, including members of the Operations, Health Physics, Instrument and
Control Maintenance, Security and General Office staffs, and Refueling
Outage contractor personnel.
2.
Action Taken on Previous Inspection Findings
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(Closed) Noncompliance (50-271/80-11-01): Manber of security force not
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qualified in one area. The inspector reviewed Licensee response to subject
item and NRC reply from Region I Safeguards Branch to Vermont Yankee Nuclear
Power Corporation, dated October 29, 1980.
Based on the content of the
above correspondence the subject item has been withdrawn. This item is
considered resolved.
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(Closed) Noncompliance (50-271/80-11-04):
Communications device not
tested at required frequency.
The inspector reviewed Licensee response
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to subject item and NRC reply from Region I Safeguards Branch to Vermont
Yankee Nuclear Power Corporation, dated October 29, 1980. Based on the
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content of the above correspondence the subject item has been withdrawn.
This item is considered resolved.
(Closed) Noncompliance (50-271/80-11-02): Security procedure not consistent
with security plan. The inspector reviewed Revision 1 to the Physical
Security Plan for Vermont Yankee Nuclear Power Station, Section 13.7,
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Records Retention and confirmed that the inconsistency between Security
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Procedure No. 0941, Revision 1, dated June 6, 1980 and the Plan has been
corrected by a revision to the security plan which states that all security
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records will be retained in accordance with Plant Procedures.
This item is
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closed.
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(Closed) Noncompliance (50-271/80-11-03):
Isolation zone not maintained
as required. The inspector reviewed Licensee response to subject item
and noted the obstructions in question were removed prior to the conclusion
of the inspection.
Discussions with Security Department Supervision and
onshift personnel indicate that an internal system of tracking security
related work items has been implemented with daily reviews of outstanding
items perfomed by supervision. The inspector toured the isolation zone
on November 11, 1980, and found the area clear and free from obstructions
as required by the Vermont Yankee Nuclear Power Station Physical Security
Plan. This item is closed.
(Closed) Noncompliance (50-271/80-11-05):
Door alarm not tested as required.
The inspector reviewed Revision 1 to the Vermont Yankee Nuclear Power Station
Physical Security Plan, Section 12.2, Alams and Annunciators and confirmed
that the Plan now addresses a revised testing program for the subject door.
Discussions with onshift security supervisory personnel indicate that testing
of the door is logged in the Intrusion Alarm Log upon completion. This item
is closed.
(Closed) Inspector Follow Item (50-271/80-02-01):
Incorporation of an ADS
accumulator air supply leak test into the licensee's periodic test program.
The inspector verified that procedure VY OP 4028, ADS Air Supply Accumulator
Surveillance, has been scheduled to be perfomed during the 1980 Refueling
Outage currently in progress.
The inspector also verified that the Licensee's
Master Surveillance Schedule has been updated per VY AP 4000, Revision 6,
Surveillance Testing Control, to provide for periodic performance of the ADS
accumulator air supply leak test. This item is considered closed.
(Closed) Inspector Follow Item (50-271/80-10-04):
Revision of AP 0503 to
incorporate requirement for a radiation work permit (RWP) in specified con-
taminated areas.
The inspector verified that Revision 6 to AP 0503,
Establishing and Posting Controlled Areas, dated October 16, 1980, has
been issued incorporating the following requirements into procedure section 6,
Contaminated Area:
If the area is not posted with any condition which re-
quires a RWP but contamination levels are greater than 10,000 dpm/100cm2
in the general area, either have the area decontaminated immediately or
post it, RWP required for entry. This item is considered closed.
(0 pen) Inspector Follow Item (50-271/80-15-07):
Environmental Qualification
of Stem Mounted Limit Switches used on Containment Isolation Valves (IEB 78-04).
The inspector reviewed Technical Specification Tables 4.7.2a and 4.7.2b in
conjunction with various plant system flow diagrams to identify the type,
location and functional requirements of containment isolatien valves subject
to PCIS control. Aside from the four inboard main steam isolation valves
(for which the licensee has documentation to establish environmental
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qualification), only one other air operated CIV was found located inside the
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drywell. Valve V2-39 is an air operated (ASCO) valve in the recirculation
loop sample line.
The inspector observed V2-39 during a drywell tour on
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October 24, 1980 and noted that it did not contain a stem mounted limit
switch for position indication.
Based on this review, the inspector identified
no discrepancies with the licensee's position that all applicable containment
isolation valves with stem mounted limit switches were environmentally
qualified. The inspector had no further comments in regard to qualification
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of components within the scope of discussions with the licensee on this item
(open NRC staff items on other environmental qualification issues are
docume.nted elsewhere). This item remains open, however, pending NRC review
of the licensee's IEB 79-01B November,1980 submittal to verify that qualifica-
tion of stem mounted limit switches is addressed in the information provided
to NRC:NRR.
(Closed) Inspector Follow Item (50-271/80-15-13):
Jet Pump Beam Replacement.
The inspector reviewed licensee procedure OP 1416, Revision 1, Replacement of
Jet Pump Hold Down Beams, October 16, 1980, which was developed by the licensec
to replace the cracked beam on jet pump No. 8
The procedure provided detailed
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instructions for jet pump beam removal; jet pump tensioning; keeper installation,
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weld qualification and welding; and, visual verification of proper placement.
The repair plan involved replacing the BWR/3 type hold down beam with a BWR/4
type which is designed for increased strength, heftier fabrication, and lower
stress levels, and is thus less susceptible to an intergrannular stress
corrosion cracking mechanism.
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The inspector reviewed licensee preparation for the jet pump beam replacement
on October 13, 1980, including the verification of selected prerequisites.
The jet pump beam was subsequently replaced, as documented in the licensee's
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followup report to the NRC, LER 80-33/1T.
The inspector reviewed LER 80-33
to verify that it was complete and accurate in the description of tile event.
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The inspector had no further questions on this item. This item is closed.
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(Closed) Inspector Follow Item (50-271/80-15-14):
Core Spray Sparger Crack
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Repair.
The following references document actions taken by the licenseeeon
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core spray (CS) sparger junction box 'C' and NRC staff review of these actions:
+ LER 80-32/1T dated October 28, 1980
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+ VY Letter WVY 80-164, Results of Core Spray Sparger Inspection
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NRC Staff Meeting Summary dated November 5, 1980, for a meeting held with
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the licensee and his consultants on October 31, 1980.
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+ NRC Region I Inspection Report 50-271/80-16
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Following a complete visual inspection of both core spray headers, no
cracks in addition to the one on junction box 'C' was identified.
NRC
Resident and Regional inspectors also reviewed video tapes of the sparger
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inspections on a sampling basis; this review identified no findings different
sfrom the licensee's (see also NRC Region I Inspection Report 50-271/80-16).
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The crack occurred on the end cap of the 'C' junction box, with visual indi-
cations for approximately 1800 on a 2.5 inch diameter circle surrounding a
1 inch plug welded in the center of the end cap. An air test of the subject
sparger showed that the crack was not through wall, as evidenced by a lack
of air bubbles with the header under pressure.
Licensee review of sparger fabrication records showed that the end caps
were fabricated from type 304 stainless steel material with a carbon content
of 0.052%. The sparger arms were fabricated with 304 stainless steel with a
0.04% carbon content. The crack occurred along the heat affected zone
created during the welding of one inch diameter inspection port plug.
It
is probable that the sensitization of the end cap material and residual
shrinkage stresses associated with the welding, together with sparger
environmental conditions, all led to the crack being formed through the
intergrannular stress corrosion mechanism. Although no other crack indi-
cations were observed on the other sparger junctions boxes, which contain
similar plugs, it must be assumed that the other junction boxes are sus-
ceptible to the came corrosion mechanism. The lack of crack indications on
the sparger arms is likely attributable to the lower carbon content of the
fabrication material. Future licensee inspections during refueling outages
of the CS spargers and junction boxes in accordance with IEB 80-13 require-
men M will serve to monitor sparger integrity.
Since the magnitude of the plug weld /end cap residual stresses could not
be accurately determined, the licensee conservatively assumed that the
observed crack could propagate and create a 2.5 inch diameter hole in the
end cap (i.e., the welded plug is assumed to detach from the end cap).
To limit leakage flow and retain the inspection port plug should the crack
propagate to failure, the licensee procurred and installed a stainless steel
clamp device on the junction box and adjacent piping.
The clamp was designed
also to minimize the potential for loose parts to enter into the reactor
coolant system. The inspector observed that the clamp was installed on the
'C' junction box on November 2, 1980.
Further licensee evaluations of crack repair and core spray sparger integrity
also included considerations for loose parts generation, the potential for
sparger blockage and core spray /ECCS performance.
These matters were dis-
cussed with the NRC staff during a meeting in NRC:HQ on October 31, 1980.
Based on the results of this meeting and supported by the licensee's
December 1, 1980 submittal to the staff, the NRC staff concluded that
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resumption of reactor operation with the clamp in place would be acceptable.
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The inspector also reviewed LER 80-32 and found that it was complete and
accurately described the event.
The inspector had no further comments in
regard to core spray sparger repair.
This item is closed.
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(0 pen) Unresolved Item (50-271/80-16-02):
Loose Parts Analysis for Core
Spray Sparger Clamp. The integrity and acceptability of the tac welds
on the core spray sparger clamp locking cups was evaluated by the
licensee. The results of the licensee's evaluation were presented to
the NRC staff during a meeting on October 31, 1980, and are documented
in the licensee's December 1,1980 submittal to the NRC.
Additionally,
a loose parts analysis was performed for the parts in question and, as
reported in the December 1, 1980 submittal, no unacceptable consequences
were identified.
This item will remain open, however, pending inspector
review of the analysis on a subsequent inspection.
(Closed) Unresolved Item (50-271/80-15-02):
Penetration Box Closure.
During an inspection tour inside the drywell on November 5, 1980, the
inspector noted that the covers for the penetration boxes in question
had been returned to a configuration in agreement with Ebasco Drawing
G-191377, including installation of all cover screws, proper mating of
gaskets at box corners and proper gasket sealing.
This item is closed.
(0 pen) Unresolved Item (50-271/80-15-06):
Broken Flexible Conduit.
During
an inspection tour on November 5,1980, the inspector noted that the
flexible conduit on M0-10-17 had been repaired.
Disucssions with the
plant Maintenance Supervisor indicate that untennirated wires in penetra-
tion connection boxes X101D and X105A had been secured.
However, the
inspector noted that flexible conduit on valve M0-23-15 had not been
repaired.
This item remains unresolved pending completion of licensee
action on M0-23-15.
(0 pen) Inspector Follow Item (50-271/80-15-14):
Revised Plant Emergency
Procedures, IAL 80-34. The inspector was informed that, subsequent to his
previous review in this area (see NRC Region I Inspection Report 50-271/
80-15, paragraph 14), the emergency operating proceduces had undergone
additional VY staff review and further revision.
Th3 procedures were
still in draft form awaiting final PORC reviu and approval prior to
issuance. The inspector reviewed the new procedure drafts (see paragraph
14 of IR 80-15 for listing) to verify that:
procedure "Immediate Action" and " Followup Action" sections directed
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the operator to the emergency plan implementing procedures;
the emergency plan implementing procedures referenced by each E0P
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was appropriate, based on a review of FSAR Section 14.5 and 14.6,
with considerations given to projected offsite and site boundary
doses; and,
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all E0Ps concerning events with the potential for offsite radiological
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effects were included in the listing of procedures addressed under
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IAL 80-34 requirements.
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The inspector noted that one procedure, OP 3101, Loss of Normal Power,
was initially revised into the emergency plan implementing procedure
format, and then left unchanged from the original format in the second
draft. The reasons for these changes were discussed with a licensee
representative; the inspector acknowledged that revision of OP 3101 to
incorporate the emergency plan implementing format did not appear to
be necessary.
Inspector comments on procedures OP 3115 and 3124 were
discussed with the licensee and addressed in the final E0P drafts.
The inspector stated at the exit interview that the procedures, if approved
as written in the second draft, would meet the IAL 80-34 requirements.
The
licensee stated that the procedures would be issued and operator traiaing
on the revised procedures would occur during the week of November 17, 1980.
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This item remains open pending issuance of approved procedures and completion
of operator training.
Additional inspector review in the emergency planning
area is discussed in paragraph 13 of this report.
3.
Review of Plant Operations - Plant Inspection
The inspector reviewed plant operations through direct inspection and
observation throughout the reporting period. Activities in progress
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consisted of refueling operations,
a.
Instrumentation
Control Room process instruments were observed for correlation between
channels and for conformance with Technical Specification requirements.
No unacceptable canditions were identified.
b.
Annunciator Alarms
The inspector observed various alarm conditions which had been received
and acknowledged. These conditions were discussed with shift personnel
who were knowledgeable of the alarms and actions required.
During plant
inspections, the inspector observed the condition of equipment associated
with various alarms. No unacceptable conditions were identified andr
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except as noted below the inspector had no further comments in this area.
c.
Shift Manning
The operating shifts were observed to be staffed to meet the refuelie.g
operations requirements of Technical Specifications, Section 6, both
to the number and type of licenses.
Control room and shift manning
were observed to be in conformance with Technical Specifications and
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site administrative procedures.
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d.
Radiation Prcr.ection Controls
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Radiation p.otection control areas were inspected.
Radiation Work
Permits in use were reviewed, and compliance with those documents,
as to protectivs clothing and required monitoring instruments, was
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inspected.
Proper posting of radiation and high radiation areas was
reviewed in addition to verifying requirements for wearing of
appropriate personal monitoring devices.
Except as noted below, the inspector had no further comments in this
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area.
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Storage of Solid Radioactive Waste
On November 4,1980, the inspector interviewed Vermont Yankee Health
Physics supervisory personnel in response to a questionnaire concerning
the licensee's storage of radioactive waste,
The following information
was forwarded to Region I personnel at the request of the Division
of Fuel Facilities and Material Safety Inspection:
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Vermont Yankee presently ships the majority of its low-level
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waste to Barnwe11, S. C. for disposal.
In the past, they have
shipped to Beatty, NV and Richland, WAs, but very infrequently
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If the above low-level waste sites were closed the licensee
estimates it would take approximately 12 months to reach the
full capacity of existing onsite storage
The difference in rate of accumulation of low-level solid
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radioactive waste between " normal operation" and " shutdown"
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condition is minimal.
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The inspector had no further questions in this area.
Equipment Removal / Decontamination
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The inspector observed work in progress on November 13, 1980, near
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the Southeast corner of the reactor building 252 foot elevation to
remove / decontaminate equipment from the torus area.
Controls esta-
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blished for equipment separation, surveying and removal were observed
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and discussed with HP personnel directing the work.
Confinnatory
radiation survey measurements were made by the inspector.
No items of noncompliance were identified.
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e.
Plant Housekeeping Controls
Storage of material and components was observed with respect to
prevention of fire and safety hazards.
Plant housekeeping was
evaluated with respect to controlling the spread of surface and
airborne contamination. There were no unacceptable conditions
identified,
f.
Fire Protection / Prevention
The inspector examined the conditon of selected pieces of fire
fighting equipment. Combustible materials were being controlled
and were not found near vital areas.
g.
Control of Equipment
During plant inspections, selected equipment under safety tag
control was examined.
Equipment conditions were consistent with
information in plant control logs.
h.
Shift Logs and Operating Records
During the inspection period, the inspector reviewed on a sampling
basis the following logs and records for the period of Octobe r 20-
November 14, 1980:
Shift Supervisor's Log
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Shutdown Control Operator's Round Shees
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Auxiliary Operator's Round Sheet
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Shutdown Shift Turnover Data and Checklist
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Night Order Book
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The logs and records were reviewed to verify that entries are pro-
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perly made; entries involving abnonnal conditions provide sufficient
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detail to communicate equipment status, deficiencies, corrective
action, restoration and testing; records are being reviewed by manage-
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ment; operating orders do not conflict with the Technical Specifications;
logs and incident reports detail no violations of Technical Specifica-
tions or reporting requirements; logs and records are maintained in
accordance with Technical Specification and Administrative Control
Procedure requirements.
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1.
Switching and Tagging Order File Review
The Switching and Tagging Order File was periodically reviewed for
a determination of the types of equipment affected, duration of
temporary system alteration and impact on Technical Specification
LC0 requirements,
None of the tagging orders reviewed were deemed
to constitute a LC0 degradation nor an item requiring a 10 CFR 50.59
review.
No items of noncompliance were identified.
4.
System Operational Safety Verification
a.
SLC System Return to Operation
A detailed review was conducted of the Standby Liquid Control System
(SLC) following completion of system maintenance to verify the system
was properly aligned and fully operational in the standby mode.
Review
of the above system included the following:
(1) Verification that plant valve lineup procedures were consistent
with plant system drawings.
Plant procedure OP 2114 and drawing
G-191171 were used to verify proper lineups for the SLC system.
(2) Walkdown of system by inspector to verify positions of accessible
valves in the flow path were correct by visual observation of the
valve or its remote position indication.
(3) Visual inspection of major components for leakage, proper lubrica-
tion, general condition and other conditions that might prevent
fulfillment of their functional requirements.
(4) Verification by observation that instrumentation essential to
system actuation and performance was operational.
No items of noncompliance were identified.
b.
Torus Closecut Inspection
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The inspector accompanied a licensee inspection team during a torus
closecut inspection on November 13, 1980, to review torus work com-
pleted during the outage and to ascertain torus readiness for a return
to operation.
Items reviewed on a sampling basis included the four
T-Quenchers installed on the safety relief valve discharge; installed
vent header deflectors; installed downcomer ties; rerouted RHR return
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lines; and, thermocouple and differential pressure instrumentation
installed in torus bay No.' 10 in preparation for future torus /SRV
testing. The inspector noted that housekeeping and cleanliness in
tha torus interior was exceptionally good. The inspector also
noted that grating on the torus interior catwalk had been removed.
No inadequacies were identified. The inspector had no further
comments in this area.
5.
Licensee Staffing
The following change,s in licensee personnel were made:
T. Watson was hired as the Operations Training Assistant.
6.
In-Office Review of Licensee Event Reports
The licensee event reports (LERs) listed below were reviewed in the NRC
Resident / Regional Office.
The reports were reviewed to detemine whether:
the information provided was clear in the description of the event and
identification of safety significance; the event cause was identified and
corrective actions taken (or planned) were appropriate; the report satis-
fied requirements with respect to information provided and timeliness of
submittal; and, on-site followup was warranted. Those reports annotated
with an asterisk (*) concern events that occurred when the inspector was
onsite and inspector review / evaluation of the event is documented elsewhere,
in this or other inspection reports.
LERs 80-03, 80-21, 80-36, 80-35, 80-34, 80-28, 80-26, and *80-27.
No items of noncompliance were identified.
7.
Review of Periodic and Special Reports
Upon receipt, periodic and special reports submitted by the licensee
pursuant to Technical Specification 6.7 and Environmental Technical Specification 5.4 were reviewed by the inspector to verify that reporting
requirements had been met. The following reports were reviewed:
Monthly Operating Reports for the months of September and October, 1980.
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No unacceptable conditions were identified,
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8.
IE Bulletin Review and Followup
Licensee responses and actions taken for the IE Bulletins listed below
were reviewed to verify that:
the bulletins were received onsite and reviewed for applicability
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to the facility;
bulletin action items, if applicable, and-identified problems were
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appropriately dispositioned;
corrective actions taken, or planned, were appropriate; and,
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responses to the NRC were accurate and within the time period
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specified in the bulletin.
Inspector followup on selected bulletins is summarized below. The
inspector had no further comment on the subject bulletins, except
as indicated below.
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a.
IEB 80-01, Operability of ADS Valve Pneumatic Supply, dated
January 14, 1980
References:
(1) VY Inspection Report 50-271/80-02, dated
April 2,1980
IEB 80-01 required actions be taken by licensees to verify continued
operability of the ADS valve pneumatic supply. A previous inspection
documented by reference (1) verified licensee actions complete with
the exception of an outstanding inspector follow item to verify
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incorporation of an ADS accumulator air supply leak test into the
licensee's periodic test program. This follow item is complete ac
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noted in section 2 of this report.
b.
IEB 80-20, Failures of Westinshouse Type W-2 Spring Return to Neutral
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Control Switches, dated July 11, 1980
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The inspector reviewed licensee response dated August 22, 1980, which
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provided all information requested by the bulletin in that Vermont
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Yankee does not utilize the Westinghouse Type W-2 Spring Return to
Neutral Control Switch in any safety related system.
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No items of noncompliance with bulletin requirements were identified,
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c.
IEB 80-19, Failure of Mercury-Wetted Matrix Relays in Reactor
Protective Systems of Operating Nuclear Power Plants, dated
August 15. 1980
The' inspector reviewed licensee response WVY 80-119 dated
August 22, 1980. The inspector verified that subject IEB
requirements have been completed in that the licensee reported
that Vermont Yankee does not utilize Mercury-Wetted Matrix
relays in its reactor protection system.
No itens of noncompliance with bulletin requirements were
identified.
c.
IEB 80-09, Hydramotor Actuator Deficiencies, dated April 17, 1980
The inspector reviewed licensee response WVY 80-89 dated June 30, 1980.
The inspe-tor verified that subject IEB requirements have been completed
in that tha licensee reported that Vermont Yankee does not presently
utilize or plan to use the hydramotor actuators in any system.
No items of noncompliance with bull.etin requirements were identified.
9.
Observations of Physical Security
The inspector made observations, witnessed and/or verified during regular
and offshift hours that selected aspects of plant physical security were
in accordance with regulatory requirements, the physical security plan
and approved procedures.
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a.
Physical Protection Security Organization
observations indicated that a full time member of the security
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organization with authority to direct physical security actions
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was present as required.
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manning of all shifts on various days was observed to be as
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required.
b.
Access Control
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Observations of the following items were made:
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identification, authorization and badging
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access control searches, including the use of compensatory
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measures during periods when equipment was inoperable
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escorting.
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c,.
hsicalBarriers
_
selected barriers in the protected area and vital area were
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!
observed and random monitoring or isolation zones was per-
formed. Observation of vehicle searches were made.
No iteras of noncompliance were identified.
10. Response to Plant Events
The inspectors responded to events and Prompt Reportable occurrences that
occurred during the inspection to observe / review the licensee's response to
the events and to verify continued safe operation of the reactor in accordance
with the Technical Specifications and regulatory requirements. Some or all of
the following items, as applicable, were considered during the inspector's
review of operational events:
observations of plant parameters and systems important to safety
--
to confirm operation within nonnal operational limits;
description of event, including cause, systems involved, safety
--
significance, facility status and status of engineered safety
features equipment;
verification of conformance to Technical Specification LC0 require-
--
ments;
determination that root causal factors were identified and that
--
corrective actions, taken or planned, were appropriate to correct
the cause;
verification that corrective action taken was appropriate to
--
prevent recurrence;
determination whether the event involved operation of the facility
--
in a manner which constituted an unreviewed safety question as
defined in 10 CFR 50.59 (a) (2), or in such a manner as to repre-
sent an unusual hazard to health and safety of the public and
environment;
determination whether the event involved continued operation of the
--
facility in violation of regulatory requirements or license
conditions; and,
evaluation of whether applicable reporting requirements were met.
--
4
Items reviewed during this inspection are summarized below.
--
_
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15
l
a.
Reactor Water Cleunup System Leakage and Repair
Licenseeinspection of reactor water cleanup system piping inside the
drywell was performed during the 1980 refueling outage as part of the
routine inservice inspection (ISI) program.
During the ISI inspection,
certain defects in excess of code allowable were identified. The
defects initially identified were located in 4 inch diameter, schedule
80 stainless steel piping downstream of the inboard containment isolation
valve V12-15 and were not through wall.
Details of these initial findings,
as well as NRC review in the area, are documented in NRC Region I Inspec-
tion Report 50-271/80-16.
As a result of the initial findings, the licensee extended the scope
of piping examinations to include sections upstream of valve V12-15
to the RWCU system tap off point from the 20 inch diameter shutdown
cooling suction drop line. On November 2, 1960, the licensee reported
to the NRC Resident Office that additional, through wall leaks were
identified in the upstream piping. The through wall defects were
located on the RHR to RWCU system sweepolet and at the sweepolet to
RWCU pipe weld interface. The leaks were located upstream of manual
isolation valve V12-46 and were thus non-isolable.
Leakage from the
sweepolet was characterized as minimal to the extent that immediate
corrective action was not necessary. Based on these findings, the
licensee extended the scope of RWCU system pipe replacement to include
the schedule 120 piping and the sweepolet. Additional NRC review of
the RWCU pipe replacement work was performed during a special inspec-
tion by NRC Region I personnel and is documented in NRC Region I
Inspection Report 50-271/80-20.
Independent observations were made by the inspector and discussions
were held with licensee personnel to review the operational considera-
tions of the RWCU system leaks.
Inspector findings in this review
are summarized in the following areas.
(1) RWCU System Leakage
The inspector observed the sweepolet defects during a drywell
entry on November 5, 1980. With the piping under about 35 psi
pressure (due to reactor vessel level elevation head), the
inspector noted that one defect (sweepolet body) was dry and
the second defect (sweepolet to pipe interface) was weeping
slightly. The weeping could be characterized as moisture that
could be wiped away with a cloth, and then several seconds
would elaspe before new moisture would appear.
The defect on
the sweepolet body, although dry, showed signs of previous
leakage /weepage, assumed to occur under higher system pressures.
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The location of the defect on the sweepolet was in a high
stress area. The defect on the sweepolet to pipe interface
was located in the pipe side of the weld in the heat affected
zone. This defect is characterized as a pinhole sized exterior-
flaw about 1 mm in diameter. The inspector noted that the amount
of leakage with the reactor system shutdown did not constitute
an immediate safety concern prior to development and implementa-
tion of a repair plan.
'
The inspector also considered what the pre-shutdown leakage
from the defects could have been with the reactor system under
pressure. Although this leakage could not be quantified by the
,
inspector, the inspector noted through daily review of drywell
leakage monitoring systems that no appreciable unidentified
j
leakage was recorded during pre-shutdown operations (reference:
NRC Region I Inspection Reports 50-271/80-08,80-10,80-13).
-
'
4
The inspector also noted the location of the sweepolet with
'
respect to the adjacent drywell wall and drywell to torus vents
located on the 238 foot elevation. The inspector concluded that
the probability for sweepolet leakage to flow into the drywell/
3
torus vents, and thereby(bypass the drywell leakage monitoring
'
systems, was negligible reference:
NRC Region I Inspection
Report 50-271/80-08).
Based on the above, the inspector con-
cluded that pre-shutdown leakage from the RWCU system was very
small.
The inspector had no further comments on this item.
(2)
Reactor Vessel Cleanup and Core Discharge
'
Upon discovery of the RWCU leakage, the licensee isolated the
3
RWCU system to the extent possible prior to offloading the
core and draining the reactor vessel and affected piping. A
temporary suction line was installed to the RWCU pumps to pro-
vide for continued reactor vessel cleaning during the repairs
and to maintain refueling pool clarity for fuel movement opera-
tions. The inspector observed fuel pool conditions during sub-
sequent operations and noted that pool clarity was very good.
The licensee considered alternate methods for repair of the
!
non-isolable portions of the RWCU line, including the use of
inflatable dams to be installed on the reactor vessel side of
.
the leak; and, total core off load and draining 'of the reactor
i
vessel and attached piping to below the repair area.
The latter
approach was chosen and procedure OP 1121.01, Preparation of the
,
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. , - - . _ . . , , _ _ , _ ~ , .
..m.
.,,--
, ,-., , _ ~ - ,
,~
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17
Reactor Yessel for the RWCU System Repair, was prepared to
govern the evolution.
The inspector discussed the overall
aspects of the draining operation with licer.see personnel and
noted that a temporary level measuring system would be employed
to provide inner-shroud level indications.
Removal of all fuel from the reactor vessel started on
November 6,1980 and was completed on November 11, 1980.
Paragraph 12 of this report discusses inspector review of
core discharge operations.
Subsequent draining of the reactor
vessel was periodically observed by the inspectors.
The inspector had no further comments on.this item.
(3) Radiological Considerations
Radiological aspects of the core discharge / vessel drain evolution
were discussed with licensee personnel.
Licensee review of the
job included considerations for:
+
the need for special controls at the Reactor Building
345 foot elevation to restridt personnel access and to
minimize / monitor airborne activity levels with the reactor
vessel drained;
+
identification of the stellite balls on control rods nearest
the cleanup repair site (East side of reactor) as presenting
the highest source term with the reactor vessel drained.
Several peripheral control rods near the "A" recirculation
nozzle outlet were moved to the fully inserted position to
reduce gamma streaming through the recirculation nozzle and
to move the stellite balls out of the verticle plane of the
work area; and,
+
use of lead blanket shielding between the reactor vessel
and the repair area to reduce background radiation levels.
Independent radiation surveys of the work site made by the
inspector prior to draining the vessel showed general area
l
radiation levels ranging from 0.5 to 1.0 R/hr, with " hot
j
l
spots" on contact with nearby piping up to 1.5 R/hr.
Inspector surveys of the work site after installation of
lead shielding (vessel drained) showed the radiation levels
had been reduced to 0.2-0.3 R/hr.
1
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,.
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The inspector had no further comment on this item at the
present.
Review of personnel exposure control for RWCU system
repairs will be conducted as part of the routine inspection
program on subsequent inspections.
(4) Metallurgical Analyses / Reporting
'
i
The licensee submitted LER 80-37/1T in accordance with
Technical Specification 6.7.B.1 to document his ISI inspection
'
findings and describe planned corrective actions. The report
i
was reviewed by the inspector and was found to accurately re-
flect the event circumstances.
Part of the licensee's correc-
,
tive plan, as described in the November 10, 1980, LER letter,
was to replace the existing RWCU piping with conforming
material per NUREG 0313, Revision 1, from the RHR branch
connection to the outboard isolation valve. Material con-
fonning to NUREG 0313 contains controlled quantities of carbon
and is less susceptible to stress corrosion cracking mechanisms.
Inspector review of the ISI findings, with consultation from
NRC Regional and HQ staff, concluded that the VY actions were
appropriate, in that the nature, location and service environ-
ment of the identified defects presented strong evidence in
support of intergrannular stress corrosion cracking as the
cause mechanism for the majority of the cracks.
However,
ultimate determination of the cause for the identified cracks
rests on the results of metallurgical analysis of crack
specimens.
The licensee's November 10, 1980 letter to the NRC
committed to reporting the results of the metallurgical
analyses in an LER supplement. The results are expected to
be available around the first of February,1981.
This item is open pending NRC review of the metallurgical
analyses report, and a determination of what further corrective
actions, if any, are considered necessary (IFI 50-271/80-17-01).
The inspector had no further comments in this area at the present.
Inspector review of subsequent licensee actions to evaluate / repair
RWCU system cracks will be followed on subsequent inspections.
,
,
b.
i
On November 11, 1980, the NRC Region I Office received a letter
(dated November 3, 1980) from Chemtrol Corporation of Texas which
questioned whether penetration fire barrier seals installed at the
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~ _ , , . . - . . - _ . _ _ _ _ - . _ . - . . , , , - -
.-.
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_ _ _
__
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19
VY plant conformed to applicable industry standards.
The inspector
reviewed the information presented by the Chemtrol letter dated
November 3, 1980, interviewed licensee personnel and reviewed
facility records and penetration seal installation drawings to
determine whether the concerns raised were applicable to the
facility and if so, their significance.- Findings are sumarized
below.
l
(1) References
'
(a) Chemtrol Corporation letter to NRC Region I dated
November 3, 1980
(b) Chemtrol Corporation letter to NRC Region I dated
November 14, 1980
.
(c) ANI Penetration Seal Acceptance letter dated July 2,1979
(d) Chemtrol Corporation letter to GE Company dated
,
February 27, 1980
j
(e) Chemtrol Test Procedure CTP-0203 dated October 22, 1979
(f) ANI letter to Chemtrol Corporation dated January 31, 1980
!
,
'
(g) Portland Cement Association Test Report for CTP-0205
dated October 27, 1980
(h) Chemtrol Corporation Drawing No. A-114, Revision 1,
dated January 22, 1980
,
.
(1) Chemtrol Test Procedure CTP-0205 dated January 23, 1980
4-
l
(j) NRC Staff letter to VYNPC dated October 24, 1980
(2) Background
'
!
Fire barrier seals are used to seal electrical penetrations between
vital plant areas to stop/ impede the spread of a fire from one
l
!
area to the next.
Industry / regulatory standards for fire barrier
seals require that the barriers be rated for 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />; that is,
.
the barrier must remain intact for 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> when subjected to a
fire of specified intensity. The fire barrier seals act in
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20
conjunction with other fire suppression systems (such as
water sprinkler, CO2 deluge) to provide protection against
loss of safety system function caused by fire.
Following the
Browns Ferry fire in 1975, all nuclear power plants were re-
quired to upgrade fire prevention / detection / suppression
capabilities, to include the installation of penetration
fire barrier seals.
The Chemtrol Corporation was contracted by VYNPC to install
fire barrier seals at the VY plar.t in the Fall of 1979. Fire
barrier seals were installed in a number of " configuration
types" using either of two types of silicone elastomer
_GE RTV 6428 and GE 850 RTV). All installation types at VY,
(.except one, received acceptance notifications by American
Nuclear Insurers as approved 3-hour fire rating configurations.
One configuration, labeled " Typical H", did not have the ANI
approval at the time of installation but was scheduled for
acceptance testing. Submittal of information on the Typical
H configuration to the NRC for review was recognized as an out-
standing item in an NRC:NRR October 24, 1980 letter to VY.
Chemtrol Corporation scheduled the perfomance of three
separate test with an independent laboratory in October, 1980.
Testing of materials CT-19/GE 850 RTV Silicone Foam and
CT-800/GE 6428 RTV Silicone Elastomer were to be tested under
configurations specified in test procedures CTP-0204, CTP-0205
and Typical Drawing "H".
Testing completed on October 20, 1980,
under CTP-0204 using the 850 RTV Silicone Foam was completed
satisfactorily. Testing of th e 6428 RTV Silicone Elastomer
was done on October 27, 1980, with unacceptable results.
The
test was terminated as a failure after one hour and thrity-one
minutes.
Based on the performance of the 6428 RTV Silicone
Elastomer in the CTP-0205 configuration, Chemtrol decided not
to test the Typical H configuration.
In that the Chemtrol
test results were at odds with previous tests which were
successful to qualify the 6428 material, Chemtrol initiated
steps to analyze samples of tested material to detemine
whether a change in chemical formulation had occurred.
The
results from this analysis were not yet available as of
November 30, 1980.
The October 27, 1980 test results prompted concern within the
(
Chemtrol Corporation over the use of the 6428 RTV Silicone
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21
Elastomer in the VY installations.
In a letter dated
November 3,1980, Chemtrol estimated that 75% of the penetra-
tion seals at VY use the 6428 RTV Silicone Elastomer.
This
estimated value was lowered to 27% in a November 14, 1980
letter to the NRC.
(3) Findings
,
Through discussions with licensee personnel and tours of the
facility, the inspector noted that the 6428 RTV Silicone
Elastomer was installed at the plant and, for the most part,
associated with cable penetrations in one area. Most 6428 RTV
Silicone Elastomer in use at VY is installed on two banks of
cable tray penetrations that run between the cable vault / switch-
gear room and the Reactor Building NW corner; these penetrations
are of the configuration type called Typical H.
The licensee
estimated that the use of the 6428 RTV Silicone Elastomer con-
stituted 20% of all fire seals installed at the plant, and 80%
of this amount was associated with the aforementioned penetra-
tions. The inspector noted the fire loading conditions on both
sides of the penetration barriers. The cable vault /switchgear
room are routinely monitored by the . inspector during inspection
tours and have been found free of transient combustible materials.
The inspector also noted that the RB side of the penetrations were
clear of combustibles, although this area had been used as ar HP
control point for torus work crews prior to the completion of the
torus modifications.
Licensee review and evaluation of the Chemtrol findings were
in progress, but incomplete.
Further information from Chantrol
regarding the specifics of the testt completed on October 27 and
October 28, 1980, was required.
The licensee did state that
based on preliminary evaluations, the October 27th test performed
by Chemtrol may not be applicable to the VY installation. The
principle factor in support of this assumption was based on the
physical differences between the CTP 0205 test configuration and
the Typical H configuration installed at the plant.
The inspector
noted through review of engineering drawings for both configuration
types that the CTP 0205 configuration employed a greater total
area of silicone elastomer fill than did the Typical H configuration.
The licensee stated further that previous analyses and acceptance
testing using 6428 RTV Silicone material in configurations similar
to the VY installations had successfully demonstrated the 3-hour
fire rating capability.
However, the licensee stated that this
matter would be pursued with the Chemtrol Corporation to resolve
outstanding questions raised by the October 27th testing.
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22
'
The inspector had no further questions on this item for the
present. The item is considered open pending:
completion
of licensee actions to evaluate the applicability of the
October 27, 1980 Chemtrol test results to VY installations;
1
and, further NRC staff review of licensee actions and findings
(IFI 50-271/80-17-02). A special inspection of this area by
NRC Region I Specialist was conducted; see NRC Region I
Inspection Report 50-271/80-18.
1
11.
Surveillance Testing
The inspector reviewed licensee actions related to (i) the completion
of core shutdown margin surveillance testing for the beginning of cycle 8
operation; and (ii) procedures and preparations for the conduct of a
Primary Containment Type A leak rate test (LRT).
Findings are
summarized below,
a.
Shutdown Margin Test
Core shutdown margin testing was completed on October 31, 1980, in
accordance with Technical Specification 4.3.A.1
equirements for the
beginning of cycle 8 operations. Testing was conducted in accordance
.
with procedure OP 4426, Shutdown Margin Check, Revision 7, dated
September 14, 1979, with tne reactor at 640F and the vessel head
removed. Control rod 30 '3 was used as the object rod, with
diagonally adjacent rod 34-27 selected as the margin rod. A calculated
integral worth for rod 34-27 supplied by the NSSS vendor was used.
The following completed data sheets were reviewed:
+
VYOPF 4426-01, Revision 7, Shutdown Margin Data Sheet
+
VYOPF 4450.02, Revision C, Rod Worth Minimizer Check
Post test review of data sheets indicated that test prerequisites
had been met. The value chosen for R1, the expected increase in
excess reactivity over the cycle due to gadolinium burnup, was 0.5%
delta k/k.
The value for R2 was 0.07% delta k/k, which is a penalty
taken to account for potential shutdown margin loss due to boron
carbide settling. An overall rodworth uncertainity of 10% was
assumed.
Inverse multiplication plots wet e maintained as both rods
were withdrawn from the core. The test demonstrated that the reactor
remained subcritical with both rods withdrawn. Adding the calculated
worth of rod 34-27 to the. core k-effective (at 80oF with the worst
rod, 30-23, withdrawn) and applying a moderator temperature
coefficient correction, the minimum shutdown margin was determined
to be at least 0.524% delta K.
Based on the calculated inteoral worth rod
_
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.
23
34-27, the minimum shutdown margin was femonstrated with rod 34-27
at position 16. The Technical Specification requirement that mini-
mum shutdown margin be greater than R+ 0.57%, or 0.82% delta k,
was satisfied.
The inspector had no further comments on this item.
No items of noncompliance were identified,
b.
Preparations for Containment Integrated Leak Rate Test
Plans and preparations for the conduct of a containment Type A leak
rate test were discussed with licensee personnel during the inspection
period.
During these discussions, the licensee asked what the NRL
staff position was for the conduct of a reduced length Type A test.
This matter was discussed with NRC Regional and Headquarters
personnel in a conference call on November 3,1980.
The NRC staff
has accepted reduced duration Type A tests in the past, when conducted
precisely in accordance with topical report BN-TOP-1, Revision 1.
Under the BN-TOP-1 Methodology, the leak rate test interval is taken
at 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> instead of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
Licensee personnel compared the VY test instrumentation and capabilities
with the requirements of BN-TOP-1 and concluded the requirements could
be satisfied with the exception of the following:
+
repeatability for drybulb temperature measurements
+
a lack of data to demonstrate repcatability for exactel and dew
point sensor measurements.
The licensee concluded, however, that repeatability for the above
instruments could be demonstrated based on data from previous Type A
tests.
During the conference call on November 3,1980, the NRC staff
stated that the VY proposal would have to be submitted in writing for
review before approval could be given for the proposed VY test
methodology. Due to the shortness of time before the Type A test
was scheduled for conduct and NRC staff limitations for providing a
quick response to a VY submittal, the licensee decided to not seek
approval for a rec'uced length Type A test for this outage. A 24-hour
test would be conducted.
The inspector had no further comments in this area. VY Type A leak
rate testing will be followed on subsequent inspections.
.
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24
12.
Plant Modifications and Refueling Operations
Licensee activities in the areas of maintenance, facility modifications
and refueling operations were reviewed during the inspection period.
Refueling and reactor vessel work during the inspection period included
a variety of activities and followed the following general sequence:
(1) fuel shuffle and core verification complete - 10/24; shutdown
margin test complete - 10/31;
installation of core spray sparger "C"
junction box clamp - 11/1;
initial ISI findings of non-isolable leak
on RWCU system - 11/1; TS change request submitted to allow core off load
without 3 cps on SRMs to support RWCU repair - 11/6; core off load for
RWCU repair started - 11/6; core off load complete - 11/11; and, refuel
cavity and reactor vessel drained to level of recirculation nozzle - 11/14.
Inspector review and findings in this area are summarized below,
a.
Refueling Operations
(1) Fuel Handling Activities
Fuel movement activities were periodically monitored by the
inspectors throughout the reporting period.
Related records
were reviewed and activities were observed to varify that:
prior to handling of fuel in the core, all surveillance
--
testing was completed.
--
during the refueling outage, periodic testing of refueling
related equipment was performed.
inspector observance of fuel handling operations for
--
verification of conformance to Technical Specification
and approved procedure requirements.
containment integrity was maintained.
--
observation of licensee housekeeping in the refuel area.
--
review of licensee staffing during fuel handling operations
--
to verify minimum crew and type on license requirements
were met.
No unacceptable conditions were identified and, except as noted
below, the inspector had no further comments in this area.
,
.
.
25
During the fuel movement period of October 22 through
October 24 periodic inspections were conducted to ascertain
whether licensee fuel handling operations were being conducted
as required by Technical Specifications and approved procedures.
The following references were used to evaluate licensee actions:
OP 1100, Revision 9, issued August 23, 1979, Refueling
--
Platfonn Operation
OP 1410 Revision 9, issued June 30, 1980, Fuel Loading
--
AP 1000, Revision 5, issued September 18, 1979, Refueling
--
Vennont Yankee Technical Specifications, Section 3.12 and
'
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4.12, Refueling and Spent Fuel Handling
During the review of licensee procedures the inspector noted
conflicting requirements pertaining to the inspection of the
refueling platform grapples and cables, and subsequent logging
of the completed action.
The inspector noted that:
OP 1410, Fuel Loading, Precautions step 9, requires that:
-
--
grapples and cables shall be inspected daily and checked
to insure correct operation. Verification of this check
shall be logged in the Refueling Log.
AP 1000, Refueling, step B.7, requires that:
the refueling
--
platform grapples and cables shall be visually inspected
daily and checked to insure correct operation. Verification
!
of this check shall be logged in Control Room Operations Log.
AP 1000, Refueling, Page 6, step 11, requires that:
the
--
Senior Licensed Operator on the refueling floor visually
inspect grapples and cables each shift to insure correct
operation, and insure this is logged.
The inspector verified by review of the shift supervisor's log
>
that inspections of the refueling platform grapples and cables
were being conducted and logged at least daily. The inspector
,
interviewed selected Senior Licensed Operators on the Refueling
Floor and determined that each visually inspected grapples and
cables on a shift basis, although this action was not always
logged.
A review of the Refueling Log revealed no entries con-
cerning inspection of the refueling platform grapples and cables.
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26
Following discussion with Operations Department personnel, it
was determined that a daily verification of the refueling plat-
form grapples and cables was required by the licensee in an attempt
to minimize fuel handling problems.
The licensee noted the
inspectors comments and will issue changes to the above refer-
'
enced procedures to provide consistent inspection and logging
requirements. The results of the licensee's actions will be
reviewed during a subsequent inspection (IFI 50-271/80-17-03).
(2) Technical Specification Change
Repair of the non-isolable portion of the RWCU system required
a complete off load of the reactor core.
Licensee review of the
off load evolution identified that minimum source range count
rate requirements (defined as 3 cps per Technical Specification 3.12.B.2) could not be maintained with no fuel in the reactor.
Further, the minimum count rate could not be achieved prior to
reinsertior, of the first fuel assembly following RWCU repairs.
A scheme to optimize SRM count rates with a partially loaded
core was developed. The scheme defueled the reactor in a
modified spiral pattern.
Core reload would occur in the
exact opposite sequence. The licensee submitted to NRC:NRR
a proposed Technical Specification change, along with an
accompaning safety evaluation, to allow for using the spiral
unload scheme and core reload with less than 3 cps on i.he
SRMs.
NRC:NRR approved the proposed changes to Technical Specifi-
cation 3.12 on November 10, 1980.
The inspector had no further comment on this item.
(3) CORE Loading Verification Procedures
VY procedures for core load verification were reviewed in
accordance with special review instructions contained in
TI 2515/40, BWR Core Loading and Verification Procedures
dated October 1, 1980.
References for this review included
the following:
OP 1411, Core Verification, Revision 4, September 14, 1979
--
AP 1000, Refueling, Revision 6, September 26, 1980
--
OP 1140, Fuel Loading, Revision 9, August 23, 1979
--
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27
Administrative controls established by the above procedure
were reviewed to verify the following were included:
(a) videotaping of the loaded core with camera equipment
mounted on the fuel handling mast;
(b) a minimum of two staff members involved in the observation
and recording of core load information;
(c)
requirements that infonnation verified for core load
verification included core location, fuel assembly serial
number, bail orientation, fuel channel clip position
and cell orientation;
(d)
requirements for QA verification of bundle orientation.
During this review, the inspector noted that sufficient procedural
guidance was given to adequately verify the items specified under
paragraph (c) above, but that no information was presented in the
procedures to show the proper orientation for 12 peripheral fuel
bundles that are not part of a complete cell.
The Reactor Engineer
stated that such an item was assumed to be general knowledge through
staff training.
Inspector discussions with RE personnel found this
to be the case.
The inspector stated, however, that the appropriate
procedures should be changed to incorporate the required positions
of the 12 peripheral fuel bundles.
The inspector also noted during review of the referenced procedures
that no requirement existed to provide for second level /QA review
of the loaded core. The inspector noted during discussions with
RE personnel that in spite of the lack of administrative require-
ments, third and fourth levels of review are provided for core load
verification on a routine basis. Aside from the two RE staff
members that record the core verification data and videotape the
core, an 0QAD staff member is present during the verification.
Beyond this, one or more members of the RE staff, including the
Reactor Engineer, reviews the completed videotapes as a final
check of core load orientation. The inspector adknowledged the
above, but stated that the appropriate procedures should be
changed to require, at a minimum, second level /QA verification
of core loading.
The required procedure changes were discussed with the Reactor
Engineer, who stated that the appropriate changes would be made
during the next procedure review cycle.
This item is unresolved
pending incorporation of the requirements (URI 50-271/80-17-04).
!
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28
The inspector also conducted an independent review / verification
of the completed core on Octcber 27, 1980 and noted proper FA
-
positioning by core location, serial number, cell orientation,
clip position and bundle orientation.
This review was completed
subsequent to licensee verification checks.
The inspector had
no further comments on this item.
b.
Plant Modifications
Preparations for and modifications in progress during the inspection
period were reviewed to verify activities were completed in accordance with
administrative requirements and licensee committments. Areas reviewed
and inspector findings are summarized below.
(1) Drywell Leakage Deflectors, EDCR 80-36
EDCR 80-36, Primary Coolant System Leakage Deflectors, dated
October 6, 1980, was written to uddress concerns raised in
LER 80-18.
The licensee evaluated the sources of leakage inside
the drywell from main steam, HPCI, RCIC, RHR and feedwater lines
to determine the potential for leakage to bypass the drywell floor
and equipment drain sumps.
Leakage from the main steam, HPCI and
the drywell continuous air monitor
RCIC systems can be detected by(fan cooler collectors) due to the
and the equipment drain system
high temperature and radioactivity of the steam associated with
the systems. Only leakage from the feedwater and RHR supply / return
lines has the remote potential to go unmonitored.
The EDCR adds
deflector plates, made of'no, 11 guage galvanized sheet steel
cut to dimensions of 72"L X 48"W, under the appropiate feedwater
and RHR lines. The deflector plates are to be installed above
four drywell to torus vent pipes, in the vicinity of drywell pene-
trations X-9B, X-9A, X-13A, X-12, and X-138. The intent of the
deflector plate is to deflect leakage from the line protected,
rather than protect the entire vent pipe opening.
The deflector
plates are to be tac welded to the I-beam and grating structure
on the drywell 252 foot elevation, with an epoxy seal to the dry-
well skin.
The licensee also considered the effects of the deflectors
on LOCA blowdown capability and concluded that the functioning of
the vent headers would not be affected (i.e., no reduction in
vent area) due to the four foot seperation between the deflectors
and the vent opening.
Installation of the deflectors is scheduled to be completed during
the 1980 refueling outage. This item will be examined by the
inspector on a subsequent inspection, following installation of
the deflectors.
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4
(2)
Recirculation Pump / Analog Trip System, EDCR 79-02
Installation of the RPT/ Analog Trip System continued during the
outage. Activities in progress were observed periodically by
the inspector to verify work was done in accordance with the
governing procedures.
The RPT system will provide an ATWAS
trip function on high reactor pressure (at 1150 psig) and low-low
vessel level (-44.5 inches with 10 second time delay).
The
'
recirculation pump generator field breakers are automatically
opened if the trip setpoints are reached.
Installation of the
Analog Trip system will replace certain YARWAY level trans-
mitters and Barksdale pressure switches mounted on the 25-5
and 25-6 racks with Rosemont Pressure and Level transmitto s.
Change-out of the YARWAY/Barksdale transmitters is intendea to
enhance the reliability of the RPS by providing a more accurate
monitoring of reactor vessel pressure and level, and initiate
protective functions through RPT and alternate rod insertion.
The inspector noted through discussions with licensee staff
that installation of the alternate rod insertion feature, although
the outage due to the
part of the EDCR, will not occur during(valves).
non-availability of certain components
The inspector
also noted that the NRC's confirmatory order to VY dated
,
February 21, 1980, addressed installation of the RPT only.
On November 2, 1980, the inspector used the Installation Procodure
for EDCR 79-02, dated October 11, 1980 to perform a partial
verification of field run wiring between analog system cabinets
and instruments mounted on racks 25-5 and 25-6.
Installation
of the following circuits was verified:
CABINET RPS-CP-25-6A, Subassembly A2,B2
Conduits: A2-1101PRA2, 18550RA2, 1855 ARA 2, 18592
B2-1856DRB2, 11103PRB2, 1851ARB1
Cables / Wires
Terminals
C1806P-RA2
AA1, AA2, AA3, AA4
C1855A-RA2
AAS, AA6
C1855B-RA2
AA7, AA8, AA9
C18590
BB4, BBS
C11103P-RB2
KK6, KK7
C18568-RB2
JJ10, JJ11, JJ12
._
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30
CABINET ECCS-CP-25-6B
Conduits:
1865DS1, 1867DS1, 1865FS1, 11293, 1865ASI
Cables / Wires
Terminals
C1866ASII
CC1, CC2, CC3
C1867BSI
CC7, CC8, CC9, CC10
C11451VSI
KK4, KK5
CABINET ECCS-CP-25-5A, Subassembly A1, B1
Conduits: Al-1850 ERA 1,1803QRA1,1850DRA1,1850 ARA 1,1855 ARA 2
B1-1851 ERB 1, 1810QRB1, 1851ARB1, 1851DRB1, 1859C, 1859F
Cables / Wires
Terminals
C1803Z-RAL
AA1, AA2, AA3, AA4
C1850A-RA1
AA5, AA6
C1850C-RA1
AA10, AAll, AA12
C11100Z-RA1
BB8, BB9
CABINET ECCS-CP-25-5B
Conduits:
1860FSII, 1129A, 1862ESII, 1860ASII, 1862ASII, 1860GSII
Cables / Wires
Terminals
C1862CSII
DDI, DD2
C1862BSII
CC7, CC8, CC9
CC10, CC11, CC12
C112500-SII
EE3, EE4, EES, EE6
C1861ASII
CC1, CC2, CC3
No inadequacies were identified during the above review. The
inspector had no further comments on this item at the present;
however, NRC review of the RPT installation and testing will con-
tinue on subsequent inspections.
(3) Drywell High Range Radiation Monitors, EDCR 80-02
The inspector reviewed the design pacPage for EDCR 80-02, Contain-
ment High Range Radiation Monitor, dated September 24, 1980. . Work
completed under the design change will satisfy Item II.F.1.2.c of
Work in progress this outage will install two
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Victoreen Model 877 ion chamber detectors above the equipment
hatch inside the drywell. The detectors will provide _ gamma _
field dose rate measurements over the range of.1E+0 to 1E+7
R/hr, with control room readout consisting of two panel indica-
tors on CRP 9-2, two sigma indicators on CRP 0-3 and alarm
only annunciator on CRP 9-3 (D/W RAD LEVEL HijiQUIP FAIL).
The inspector had no further comment on this item at the present.
This item will be reviewed further on subsequent inspections.
13.
Inspector Followup on Rdgional Request
The inspectors conducted special inspections of specific areas during
the inspection period at the request of the NRC Regional and/or HQ
staffs. Areas reviewed during this inspection included:
+
susceptibility of the VY containment to the Indian Point 2 type
flooding event;
further followup of licensee actions taken in response to IEB 80-17
+
requirements, BWR Failure to Scram;
+
adequacy of certain emergency plan implementing procedures for per-
forming postulated off-site dose projections; and,
+
completion status of VY actions taken in response to the Category A,
TMI Short Term Lessons Learned items of NUREG 0578.
Inspection findings in these areas are summarized below,
a.
Susceptibility of Flooding Events
During the period of November 3 and 4, 1980, the inspector conducted
an inspection to determine Vermont Yankee's susceptibility to the Indian
Point No. 2 type of flooding event. As a result of the inspection, the
following information was forwarded to Region I personnel at the request
of the Division of Reactor Operations Inspection:
Vermont Yankee is equipped with both a Drywell Equipment Drain Sump and
a Drywell Floor Drain Sump. The Equipment Drains are provided for
varicus components in the drywell, including valve and pump seal leak-offs.
The Drywell Floor Drain system collects and disposes what is considered
to be " unidentified" leakage.
In addition, the reactor cavity drains
to the floor drain sump.
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The Drywell Equipment and Floor Drain Sumps are equipped with
level switches used for a leakage rate alarm system.
Leakage
rate measurement is accomplished by measuring the time interval
between activation of two different level switches in the sump
as the sump fills with water. Whenever the time interval de-
creases to a prescribed point (indicating an increase in leakage
rate), or if a sump pump runs longer than a preset time interval,
,
an alarm annunciates on Control Room Panel (CRP) 9-4 indicating.either
Drfwell Equip ~m~ent Drain ~ SumpJeillage"High_(A-4/A-9)~or Diywel_1_Elo.or
~
DrainSumpLeakageHigh(A-4/C-8).~Eachsumpisequippedwith
-
two 50 GPM aumps. A sump pump will start automatically upon the
liquid reacting a preset high level and will stop upon the liquid
being lowered to a preset low level.
A second pump starts and
an alarm sounds in the Control Room if the liquid reaches a
high-high level.
Pump)run indication is provided in the control room by operating
(red or secured (green) status lights on CRP 9-4 horizontal
section; in addition, a flow recorder (2 pen) and integrating
flowmeters are provided on CRP 9-4 for detennining leakage rate
over a period of time.
Components inside containment utilize a closed cooling water system
RBCCW, whose surge tank level is monitored by weekly surveillance.
The following documents were reviewed during the inspection:
OP 4152, Revision 8. July 11, 1980, Drywell Equipment and
-
Floor Drains Surveillance
OP 2152, Revision 7. July 11, 1980, Drywell Equipment and
-
Floor Drains
Dwg 191177 Revision 6, Flow Diagram - Radwaste System
-
OP 3140, Revision 4, April 16, 1980, Alarm Response
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RP 2182, Revision 8, August 14, 1980, Reactor Building Closed
-
Cooling Water System
The inspector had no further questions in this area.
b.
Scram on Scram Discharge Header Low Pressure:
NRC staff review of the VY response to IEB 80-17, Supplement 3,
Item 1.a noted that the licensee had incorporated changes to
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33
procedures (DI 80-45, Revision 1 to OP 2111) that instructed the
.
'
control room operator (CRO) to initiate an immediate manual scram
of the reactor whenever scram pilot air pressure decreases to
65 psi (a value at least 10 psi above the scram outlet valve opening
pressure), based on local indications from PI-3-229.
The use of local
(outside the control room) pressure indication as a basis to initiate
CR0 action was discussed with the licensee. The NRC staff position
presented was that the use of local position indication was unacceptable
in this case, due to the following considerations:
+
PI-3-229 is mounted near the backup scram valves on the 252-foot
elevation of the Reactor Building.
Upon receipt of the CRP 9-5
annunciator, SCRAM PILOT HDR PRESS HI/LO (panel A-8, window D-4),
the information immediately available to the CR0 is that scram
pilot air pressure is either_above 75 psig or below 70 psig. To
determine whether the air header pressure was below 70 psig would
require that an auxiliary operator be dispatched to PI -3-229 for
a reading and then report back to the control room.
This
determination could take 3 to 5 minutes to accomplish under ideal
conditions.
.
+
NRC staff evaluation of various scram discharge system failure
mechanisms 4dicated for a certain postulated failure, the scram
discharge headers could fill in as fast as 2 to 3 minutes without
attendant rod-in motion.
Under this scenario, immediate manual
action by the CR0 is necessary to assure the scram function occurs
before loss of the scram discharge system.
Based on the above, the inspector stated that the licensee's
response to Item 1.a was unacceptable and that either (i) a control
room indication of scram pilot air pressure must be provided; (ii) pro-
cedures must be revised to require a manual scram based on receipt of
the annuncistor alarm; or, (iii) other compensatory measures be taken
to address the concerns discussed above.
Actions to address the NRC
staff position must be completed prior to startup from the 1980 refueling
outage.
The licensee acknowledged the inspector's comments and stated that
the staff position would be reviewed and actions taken as appropiate.
This item is unresolved pending completion of licensee action in this
area and subsequent review by the NRC (URI 50-271/80-17-05).
,
c
EPIP Review - Offsite Dose Projections
During the inspector's review of VY emergency operating procedures
(EOPs) and emergency plan implementing procedures (EPIPs),
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34
particular attention was given to OP 3013, Initial Evaluation of
Offsite Radiological conditions. This procedure provides instructions
for the offsite and EOF response members to assess the type and
magnitude of postulated radioactive releases, Appendix A and Table I
requirements - see paragraph 2 above) y the E0Ps (per IAL 80-34
to this procedure are now referenced band would be used by the
shift supervisor, acting as the emergency director, to determine
an initial, rough estimate of offsite radiological conditions upon
which to base recommended protective actions.
The instructions,
dose projections and information provided by Appendix A to OP 3013
were reviewed to verify the procedure was technically adequate and
capable of accomplishing the desired function when implemented.
Appendix A of OP 3013 provides a tabulation of plant area radiation
monitom (ARM) with corresponding projected dose rates at the site
boundary, assuming a full scale reading on the ARM.
Information
tabulated includes type of release (elevated or ground); ARM;
panel location; ARM full scale reading; and, the 1/50 and 1/100
boundary valve cloud concentration and dose rate..For Appendix A
purposes, the site boundary is divided into two sectors:
one
900 sector pointing West from the site; and, one 2700 sector for
all other directions. A plume travelling _toward_the_ West would
constitute _the.most.. restrictive releas_e_ direction,_f_ or_ the_ assumed ___
meteorology, and a dilution factor from the point of emission of
1/50 is applied.
For a release path in any other direction, a 1/100
dilution factor is applied for conditions at the boundary. The
inspector compared these assumptions with the DBA dose calculations
provided by FSAR Section 14 and found them in agreement with the
computer based dilution projections.
The inspector reviewed the Appendix A - Table I information to
verify:
all ARMS useful for dose projection were incorporated;
listings for ARM full scale readings and conversions to source
terms were accurate; and, projected boundary dose rates were
accurate.
Findings are as follows:
(1) Table I values for dose projections at the 1/50 and 1/100
boundaries provide conservative dose estimates. Using the
Stack Gas I/II monitors as an example, the full scale reading
of IE+6 cpm was found to represent a source term of 0.75 ci/sec
release rate at the stack, based on a empirically derived
correlation of monitor efficiency. The full scale reading
represents a concentration of 1E-2 uci/cc ive a 156,000 cfm
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35
ventilation air flow and assuming a mix of isotopes provided
by EPA-520/1-75-001. A Chi-over-Q calculation based on this
source term, assuming Class E stability and a 5 m/sec wind
speed, yields 50 mR/hr and 25 mR/hr at the 1/50 and 1/100
boundaries, respectively. The Table I values of less than
60 mR/hr and less than 30 mR/hr, respectively, are then
conservative.
(2) ARMS listed in Table I cover three levels of the Turbine Building,
two levels of the Reactor Building and the A0G Building. The
listing provides most of the ARMS available that would be useful
for initial dose assessments.
The instructions _provided
in Table I were sufficient to get the dose assessment completed.
The inspector noted, however, a few discrepancies in the tabulated
infonnation, related to designated ARM number and full scale
readings. Turbine Building ARMS were listed as instrument numbers
20, 22, 26 and 27, whereas the appropiate designators are 13, 21
and 24, for the moisture seperator, main steam valve and T/G inlet
area monitors, respectively.
Full scale readings for the monitors
were listed as 1000 mR/hr, whereas the actual value is 10,000 mR/hr.
The insoector also noted that ARM #14, located on the West Refuel
Floor and has a full scale reading of lE+6 mR/hr, should also be
included in Table I.
>
(3) The inspector noted Appendix A Table I also contains references
for Iodine dose determinations and accident level classification
limits based on radiciodines.
No information immediately available
in the control room provides radioiodine concentration or dose
information and thus, a recommendation for protective actions
based on radiciodines could r.ot be made during the initial assessment.
As such, references / instructions to conduct an iodine dose assessment,
which could be a cause for confusion, should be deleted in the
instructions to control room personnel.
The inspector had no further comment on this item at the present.
Dis-
i
crepancies noted in paragraphs (2) and (3) above will be corrected in
<
a subsequent update of OP 3013. This item is open pending completion
of licensee action in the area and subsequent review by the inspector
(IFI 50-271/80-17-06).
d.
Review of NUREG 0578 Short Term Lessons Learned Category A Items
Implementation
During the inspection period the inspectors completed a review
of licensee implementation of NUREG 0578 Short Term Lessons Learned
. _ _ - -
,
.
36
Category A Items. The review consisted of establishing licensee
committments to fulfill the Category A requirements and a followup
inspection to detennine the status of licensee implementation. The
following references were used during the course of this inspection:
(1)
NUREG 0578, Published July 1979, TMI-2 Lessons Learned Task
Force Status Report and Short Term Recommendations
(ii)
NUREG 0660, Published May 1980, Revised August 1980, NRC
Action Plan Developed as a Result of the TMI-2 Accident
(iii) WVY 80-135, September 29, 1980, Shift Technical Advisor
Implementation Schedule
(iv)
WVY 80-7, January 8, 1980, Vermont Yankee Responses to NUREG 0578 Recommendations
(v)
WVY 79-130, November 20, 1979, Followup Actions Resulting from
the NRC Staff Review Regarding the TMI-2 Accident
(vi)
NRC (DENTON) letter, October 30, 1979, to ALL OPERATING NUCLEAR
POWER PLANTS, Discussion of Lessons Learned Short Term
Requirements
(vii) WVY 79-135, November 15, 1979, Long Term Questions for B&O
Task Force
(viii) NRC letter, April 1,1980, Staff Evaluation of VY Actions
on Category A Items of NUREG 0578
(ix)
WVY 80-131, September 12, 1980, Proposed Technical Specification
Change
(x)
WVY 80-141, October 7, 1980, Proposed Technical Specification
Change
(xi)
WVY 80-151, October 23, 1980, Interim Criteria for Shift Staffing
(xii) NRC letter, July 31, 1980, Interim Criteria for Shift Staffing
(xiii) WVY 80-069, April 29,1980, Containment Hydrogen Monitoring
(xiv) WVY 80-052, April 1, 1980, Containment Hydrogen Monitoring
Note that in the listings that follow, the NUREG 0578 item number is
given followed by the NUREG 0660 TAP number in parentheses.
.
.
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37
(1)
Item 2.2.1.b (I.A.1.1) Shift Technical Advisor
Requirements:
Reference (i)and(vi)
+
STA on Duty by January 1, 1980.
+
STA shall have a bachelor's degree or equivalent and receive
plant specific training in the response and analysis of the
plant for transients and accidents.
Licensee Commitment:
Reference (iv)
+
An STA will be available at the plant at all times starting
January 1, 1980, and assigned to shift duty.
+
A pool of 15 graduate engineers from the VY staff is to
fill the position on an interim oasis.
Inspection Findings
An interim group of STA's have been assigned to shift duty since
January 1, 1980. Members of the STA group are staff engineers
who have received STA specific training.
Sleeping accommmodations
have been provided at the site such that the STA is at all times
available to the control room within 10 minutes.
VY procedure
AP 0150, Revision 13, issued July 11, 1980, defines the duties,
responsibilities and authorities of the STA.
.
Licensee letter dated September 29, 1980, (WVY 80-135) to NRC
notes that the schedule for having fully trained STA's in place
by January 1, 1981, will not be met.
The estimated completion
date for having fully trained STAS is June 1, 1981.
By letters
dated September 12, 1980 andOctober7,1980(referencesixandx),
proposed Technical Specification changes were submitted to the
NRC to incorporate the assi " ment of SYAs.
The inspector had no further comments on this item.
(2)
Item 2.2.1.a (I. A.1.2) Shift Supervisor Responsibilities
Requirements:
Reference (i)and(vi)
Shift supervisor responsibilities and authority defined to
+
maintain broad perspective.
.
.
38
+
Comand function delineated and transfer of comand defined.
+
Non-safety related duties delegated.
Licensee Comitments:
Reference (iv)
'
VY agreed with NRC position and issued a management directive
+
before January 1, 1980, to clearly define shift supervisor
responsibilities and authorities.
Inspection Finding
VY procedure AP 0150, Revision 13, dated July 11, 1980, was re-
viewed and found to implement the requirements defined by the
staff position.
The inspector had no further coment on this item.
(3)
Item - - -
(I.A.1.3) Shift Manning-Overtime Limits
Requirements:
Reference (ii) and(xii)
'
+
Specified minimum number of operations personnel on shift
and defined availability of personnel to man shifts.
Licensee Comitment:
Reference (xi)
+
VY intends to comply with the requirements of this item as
specified in a letter dated October 23, 1980, to the NRC.
Inspection Finding
By letter dated October 23, 1980, the licensee stated that the
interim staffing criteria were evaluated. VY found that all
adjunct requirements except d and e of reference (xii) were
met. Plans in progress for additional licensed operator
training will bring VY into compliance with all the revised
criteria by July 1, 1982.
VY is reviewing the shift overtime limits defined by reference (xii)
and IEC 80-02 and intends to comply with the criteria. VY formal
response to the NRC on this item is expected by November 20, 1980.
The inspector had no further coment on this item.
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.
39
(4)
Item - - -
(I.C.1) Small Break LOCA Procedures
Requirements: Reference (i)and(ii)
+
Develope guidelines and procedures for coping with small
break LOCAs.
+
Retrain operations staff under new procedures.
Licensee Commitments:
Reference (v)
+
VY agreed to the NRC Staff position and worked with the
BWR Owners Group to develope accident procedure guidelines.
Inspection Findings
NRC Region I Inspection Report 50-271/80-04 documents inspector
review of procedures developed pursuant to the NRC staff approved
BWR guidelines, and review of operator training on the revised
procedures. No inadequacies were identified in regard to
procedures and training.
It should be noted that Inspection Report 50-271/80-04 identified
one unresolved item (80-04-02) concerning the power supplies for
torus and CST level instruments, and the availability of this
level information assuming the loss of the single most limiting
instrument bus. The subject item is still open.
The inspector had no further comment on this item.
(5)
Item 2.2.1.c (I.C.2) Shift and Relief Turnover
Requirements: Reference (i)and(vi)
+
Checklists to be provided to assure adequate shift turnover
of plant status information.
+
Checklists / logs to be provided to note equipment either out
of service and/or degraded.
+
System established to monitor effectiveness of shift turnover
procedure.
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40
Licensee Comitment:
Reference (iv)
+
By letter dated January 8, 1980, VY stated that operating
procedures were reviewed and revised as required to meet
the requirements of this item.
Inspection Findings
Inspector review of procedures AP 0150 dated July 11, 1980, and
AP 0152 dated December 31, 1979, found the applicable requirements
had been implemented.
The inspector had no further comment on this item.
(6)
Item 2.2.1.a (I.C.3) Shift Supervisor Responsibilities
Requirements: References (i)and(vi)
+
Shift supervisor responsibilities and authority specified.
+
Comand function delineated.
'
+
Non-safety related duties delegated.
Licensee Comitment:
Reference (iv)
+
VY stated their intent to comply with these requirements
by letter dated January 8, 1980.
Inspection Finding
VY procedure AP 0150, Revision 13, dated July 11, 1980, was re-
viewed and found to implement the requirements defined by the
staff position.
'
The inspector had no further coment on this item.
(7)
Item 2.2.2.a (I.C.4) Control Room Access
Requirements:
Reference (1), (ii) and (vi)
+
Develope administrative policy to establish that person having
control room comand function has authority to limit access.
+
Establish line of succession of control room command function
and chain of comunication.
)
. .
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.
_
_
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_
_
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41
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Licensee Connitment: Reference (iv)
+
By letter dated January 8,1980, VY stated that the authority
,
of the shift supervisor to limit control room access had been
re-affirmed and procedures were modified to establish control
'
room access policy.
Inspection Finding
!
VY procedure AP 0150, Revision 13, dated July 11, 1980, was found
to implement the requirements on control room access, lines of
authority and transfer of command functions.
l
The inspector noted that NRC ldtter of September 11, 1980 to VY,
t
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j
reference (viii), states that a change to AP 0152 satisfies this
requirement. AP 0150 is the applicable reference.
The inspector had no further comment on this item.
(8)
Item 2.1.8 a (II.B.3) Post-Accident Sampling
Requirements:
Reference (i),(ii)and(vi)
t
+
Conduct design review and implement interim measures to allow
'
capability to promptly obtain an RCS and containment air
sample under accident conditions without exceeding 10 CFR 20
!
exposure limits assuming a RG 1.3 or 1.4 release of fission'
[
products; install additional shielding as required.
,
+
Conduct design / operational review and implement interim
,
measures to allow conduct of radiological spectrum analyses
i
I
for indicators of core damage following an accident; include
assessment for the effects of direct and airborne radiation
!
levels.
+
Provide procedures that allow the prompt performance of a
f
boron and chloride chemical analyses assuming a RG 1.3 or 1.4
l
source tenn.
j
Licensee Commitment:
Reference (iv), (v), (xiii) and (xiv)
+
By letter dated January 8, 1980, the licensee stated that the
[
piant sampling capability had been reviewed in light of the
i
new criteria.
Capability for containment air sampling and
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-.
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42
hydrogen analysis is provided by the containment air
dilution (CAD) system, which has a sample connection
available outside the reactor building.
Insotopic
analysis of the gas sample can also be performed.
+
A tap for RCS samples is located in'.the Reactor
Building, which may not be habitable under 10CFR 20
restrictions assuming a RG 1.3/1.4 source term.
Procedures were revised and measures were taken to make
it possible to obtain an RCS sampie containing several
mci /ml activity, convey it to a laboratory and analyze
it without exceeding 10 CFR 20 limits.
+
Modifications have been proposed (EDCR 79-51) that would
allow analysis of samples with existing laboratory equip-
ment as well as on-line analytical equipment.
Selection
of the most suitable equipment and methods is expected to
meet the Category B requirements of NUREG 0578
(January 1, 1980).
Inspection Findings ,
Procedure OP 3530, Post Accident Sampling, Revision 0, inclusive
of DI 80-21 dated September 24, 1980, was reviewed and found to
address licensee commitments in this area.
Through discussions
with the Chemistry and Health Physics Supervisor, review of OP 3530
and other operating procedures, and review of facility records,
the following was determined.
OP 3530 was developed as a result of the licensee's design / opera-
tional review of containment and RCS sample and analysis capabili-
ties.
Protective measures instituted oer OP 3530 are based on an
RCS sample activity of several mei/ml.' Results of the licensee's
preliminary evaluation of post accident radiation shielding surveys
were documented in a February 2, 1980, internal memorandum (TMI
TECH FILE).
Sample bomb dose calculations for 10 cc and 40 cc
bombs using 1 inch and 1.5 inch lead shielding were documented in
internal . memoranda dated April 2,1980 and August 11, 1980.
Containment gas sampling and hydrogen analysis capability is pro-
vida by the CAD system in conjunction with the MSA and Delphi
monitoring systems. The MSA system, which is mounted outside the
Reactor Building, provides hydrogen analysis capability over the
range of 0 to 4 volume percent. The MSA unit is a backup for the
Delphi Unit. The Delphi unit located in the Reactor Building on
l
.
-- ---
- - - - - - -
-
"
i
.
.
43
the 280 foot elevation, provides hydrogen analysis capability
over the range of 0 to 10 volume percent. Obtaining drywell
samples under pressurized containment atmosphere conditions
is available under nonnal operation of the CAD system. The
CAD system also provides for containment air sampling under
negative pressure conditions up to several inches of mercury.
OP 3530 contains instructions to obtain and analyze containment
gas samples.
Instructions for RCS sampling and analyses for activity levels
up to 3 mei/ml are also provided by OP 3530.
Capabilities for
sampling and analysis of higher activity samples will be provided
by design modifications completed under EDCR 79-51. For isotopic
analysis of RCS sampics once collected per OP 3530, a serial
dilution on a 1 ml volume is performed to reduce radiation levels
to the point where standard counting techniques can be employed
using OP 0631. The sample dilution will produce a sample with
activity levels within the capability of the onsite multi-channel
analyzer.
Within the capabilities of existing equipment, unpressurized RCS
samples can be taken and analyzed for baron, chloride, total
dissolved gas and oxygen. The capability does not currently
exist for taking pressurized RCS samples or for performing a
dissolved hydrogen analysis. Analysis sensitivity was specified
as falling within the range of 1.0 micro ci/gm up to the high
range limit. Licensee evaluation of sample analysis capability
assumed releases from the fuel at equilibrium core inventories,
consisting of 100% noble gas, 25% iodine and 1% particulates.
Other measures accounted for and/or incorporated in OP 3530 include
considerations for: personnel exposures for conducting the sample
operations, including a requirement for calculating a dose commit-
ment prior to undertaking the operation; personnel monitoring and
the use of TLDs and high range survey instruments; use of shielding
around the interim stack gas monitor, RM-16 detector; use of
shielding in the transport of samples; use of sample shielding and
ventilation (hood) systems to reduce background levels during sample
analysis; and, purging of sample lines to reduce plate-out and
accumulated buildup of contaminants.
In that the licensea imple-
mented measures for sample taking and analyses for activities up
to only 3 mci /ml, no otherportable shielding was used nor deemed
necessary, based on expected direct radiation and airborne dose
rates for the assumed source term.
\\
l
\\
l
l
l
.\\
.
- -
.
.
.
44
.
Licensee action to demonstrate sample and analysis capability
under the assumed high activity conditions was limited to sample
dose rate calculations.
The inspector had no further questions on this item.
(9)
Item 2.1.3.a(II.D.3)SV/SRVPositionIndication
Requirement: Reference (i)and@i)
+
Positive indication of SV/SRV open status.
+
Safety grade, unambiguous indication in the control room
with annunciator / alarm functions.
+
Seismic qualification provided or schedule for qualifying.
Licensee Commitment:
Reference (iv) and (v)
+
By letter dated January 8, 1980, VY stated that modifications
had been completed to meet the above requirements.
Pressure
switches were installed in the SRV discharge piping and
accoustic accelerometers were installed on the SV discharge
Both position indication systems have control
room readout and alarm functions.
+
Pressure switches used on the SRVs are not seismically
qualified. The licensee committed to qualify the switches
by participation in a vendor program or replace the switches
with a qualified indicator by January 1, 1981.
Inspection Findings
NRC Region I Inspection Report 50-271/80-02 provides the results
of previous NRC inspection of the position indication for the
safety values.
No inadequacies were identified in regard to the
design and installation of the SV position indication system.
However, one item left open during that review concerned the
seismic qualification certain components in the system. Discussions
with licensee personnel indicated that the seismic qualification
i
for the subject components had not been completed and further,
j
that completion of the qualification may not occur by January 1,1981.
This item is addressed further below.
..
_ _
.
_ - - -
.
_
-_
.
.
45
The inspector reviewed the design package and the physical
installation of position indicators for the safety relief
valves. The modification was completed under PDCR 79-22,
Safety Relief Valve Open-Close Monitor.
The installation
and test procedures for the pressure switches were completed
,
on December 31, 1979. A two-out-of-three logic is used for
the valve open inidcation and power for the circuit is pro-
vided from a vital AC bus. An open-close indication for each
SRV is mounted on CRP 9-3 and a system annunciator / alarm
function is provided on CRP 9-3.
Except for the environmental
qualification of the pressure switches, the inspector had no
further comment on this item.
The inspector stated that if delays are expected beyond
January 1, 1981, to complete environmental qualification for
either the SV accoustic accelerometers or the SRV pressure
switches, the qualification program status and schedule should
be documented in a letter to the NRC.
This item is considered
open and will be followed on subsequent inspections
(IFI 50-271/80-17-07).
(10) Item 2.1.7.a (II.E.1.2) Auxiliary Feed System
Requirement
This item is specific to PWR plants and does not apply to VY.
(11) Item 2.1.1(II.E.3.1)PressurizerHeaterPowerSupply
Requirement
This item is specific to PWR plants and does not apply to VY.
(12) Item 2.1.5.c ( - - - ) Recombiner Procedure Review and Upgrade
Requirement
,
This item is specific to plants that have hydrogen recombiners
and does not apply to VY.
(13) Item 2.1.4 (II.E.4.2) Isolation Dependability
Requirements:
References (1),(ii)and(vi)
+
PCIS design shall comply with SRP 6.2.4 in diversity of
parameters needed for isolation.
>
_
-
_ - - . -
,
-
--
, _ . _ , . - _ . . _
.
.
46
+
Identify all essential and non-essential process lines
penetrating the drywell and modify PCIS logic as required
to ensure proper isolation.
+
Ensure all non-essential lines are automatically isolated.
+
Ensure the PCIS reset feature would not result in inadvertent
loss of containment isolation.
Licensee Commitment: References (iv) and (v)
+
By letter dated January 8,1980, VY reported the results
of reviews in regard to diversity of parameters, non-essential /
essential system identification and isolation of non-essential
systems. VY concluded that sufficient PCIS initiation diversity
existed in accordance with SRP 6.2.4; and, all essential /
non-essential systems were found to respond appropriately
under PCIS actuation.
+
During VY review of the PCIS logic, several valves were found
that would automatically reopen when the PCIS logic was reset.
Interim administrative controls were instituted to require
the operator to place the control switch for the subject
valves in the " CLOSED" position prior to resetting the PCIS.
A design change would be installed on a subsequent plant
shutdown to inhibit automatic opening of the valves following
PCIS reset.
Inspection Findings
Licensee conclusions under the first three items above were re-
viewed by the inspector.
No inadequacies were identified.
Modifications to the PCIS logic were completed during a February,
1980, plant shutdown.
Inspector review and findings of the
modifications completed under EDCR 79-35 are documented in
NRC Region I Inspection Report 50-271/80-02.
No inadequacies
were identified.
The inspector had no further comment on this item.
(14) Item 2.1.3.b (II.F.2) Instrumentation for Inadequate Core Cooling
Requirement:
References (ii) and (vi)
+
Use of a subcooling meter.
i
.
.
.
47
+
Design / analyze / install instrumentation to provide
unambiguous indications of inadequate core cooling.
Licensee Commitment:
Reference (.iv).,(v)and(vii)
+
Use of a subcooling meter is a PWR specific item and
does not apply to VY.
+
VY evaluations and actions in response to the staff positions
will be forwarded through the BWR Owners Group for evaluating
by the Bulletins and Orders Task Force.
+
Potential reactor vessel level instrumentation problems
identified by GE SIL 299 have been incorporated into VY
Operating Procedures and the operator training program.
NRC review of this item is documented in NRC Region I
Inspection Report 50-271/80-04.
No inadequacies were
identified.
The inspector had no further comment on this item.
(15) Item 2.1.1 (II.G.1) PRV Power Supplies
Requirements
This item is specific to PWR plants and does not apply to VY.
(16) Item 2.2.2.L (III.A.1.2.) Emergency Support Facilities
Requirements:
References (1), (ii) and (vi)
+
Establish interim Technical Support Center (TSC).
+
Upgrade to pemanent status per Category B schedule.
+
Develope procedure to describe TSC.
+
Designate individual responsible for activating TSC.
+
Incorporate references to TSC in emergency procedures.
Licensee Commitment:
References (iv)and(v)
.
By letter dated January 8, 1980, VY agreed to meet the requirements
of the staff position, provided descriptions of existing and planned
facilities and established schedule dates.
-
._
s
O
48
.
Inspection Findings
The inspector toured the TSC and reviewed related implementing
procedures. The inspector found that emergency procedures
OP 3001, 3002 and 3003 were revised to delineate actions to
activate the TSC and define how its function will integrate
with other emergency response centers.
Procedure AP 3014
dated December 31, 1979, defines the administrative require-
ments for the TSC, its set up and maintenance. OP 3006, Revision
9, dated November 7, 1979, provides for the periodic calibration
of TSC equipment. No inadequacies were identified.
The inspector had no further comments on this item.
(17) Item 2.2.2.C (III.A.1.2) Operational Support Center
Requirements:
References (i), (ii) and (vi)
+
Interim Operations Support Center (OSC) established.
Licensee Commitment:
References (iv) and (v)
+
By letter dated January 8, 1980, VY stated that an interim
OSC had been established. The area designated for the OSC
was the ground floor of the Service / Administration Building,
with the HP control point used as the communications center.
Inspection Findings
The inspector reviewed applicable plant procedures that established
the OSC and integrated its function with other emergency response
centers. AP 3015 dated December 31, 1979, established the OSC
and defined its functions and designated responsibilities for its
activation. Functions of the OSC were incorporated in procedures
OP 3001, OP 3002, OP 3003 and AP 3014
No inadequacies were
identified.
The inspector had no further comment on this item.
(18) Item 2.1.6.a (III.D.1.1) Primary Coolant Outside Containment
,
Requirements:
References (i),(iv),(vi)and(viii)
+
Implement program to reduce leakage from plants systems
outside of containment to as-low-as practical levels, for
j
those systems that could contain highly radioactive fluids
following an accident.
.
O
49
+
For immediate leak reduction, implement leakage reduction
measures and measure actual leakage rates with systems in
operation and report the results to the NRC.
+
Establish and implement a program of preventive maintenance
to maintain leakage to as-low-as-practical levels; program
should include periodic integrated leak tests.
+
Include considerations for a North Anna type release path.
Licensee Comitment: References (iv) and (v)
+
Systems outside containment that could contain high levels of
radioactivity following an accident were identified and
examined for leakage under operating conditions.
Systems
excluded from the program were also identified.
For those
systems included in the program, steam and water systems
were visually inspected and gasious systems were leak tested
with helium while operating under positive pressures.
Results
of these inspections and a listing of systems in each category
were reported in a January 8, 1980, letter to the NRC.
+
" Benchmark" samples of airborne activity were taken in plant
areas not rcutinely visited by plant operators. The " Benchmark"
activity levels will be used for comparison whenever increases
in leakage are suspected.
+
A leakage reduction program was instituted which will result
'
in the visual inspection (and repair as necessary) of selected
systems each month in conjunction with the Technical Specifica-
tion Surveillance operability tests.
Systems included in this
<
program include:
the RHR, HPCI, RWCU, CS, RCIC systems; and,
the RHR, RWCU and recirculation sample systems.
+
Based upon a review of the North Anna event, VY detennined
that all tanks containing radioactivity vent into filtered
ventilation systems prior to release to the environment,
and thus, no modifications were required.
Inspection Findings
The inspector reviewed the results of the base line leakage measure-
ments performed on the standby gas treatment system (SGTS) as re-
ported in a December 17, 1979, Test Report to the Operations
,
1
. - -
-
.
.
.
.
50
Supervisor. Testing was conducted under special test procedures
STP-79-05, Helium Leak Testing, dated December 10, 1979.
The
HPCI gland seal exhauster was also tested.
No leakage was found.
The inspector also reviewed the results of baseline leakage
measurements completed on systems that contain radioactive materials.
The measurements were made by visual examination of piping with
the plant operating at full power, during a walkdown of the systems
over the period of November 27-December 31, 1979.
No leakage was
found other than the flange leak on the RWCU system.
Flange' leakage on the suction side of the RWCU pumps, identified
during the base line leakage program, was repaired under
MR-79-1139 on January 9, 1980.
The " Benchmark" air activity sample results for areas not
routinely visited by the operator were also reviewed. These
areas include the steam tunnel (3.3E-0 uci/cc), the RWCU heat
exchanger room (7.6E-10 uci/cc), and the Holdup Pump Room in the
Radwaste Building (2.3E-9 uci/cc).
Implementation of the monthly leakage monitoring and reduction
program was confirmed by rsview of completed data sheets, for the
procedures listed below, for the period of February, 1980 to
September, 1980. The system covered by each procedure is also
listed.
OP 4120.01
--
OP 4121.05
--
OP 4123.01
--
OP 4124.04
--
RHR Sample
AP 0150.02
--
,
RWCU Sample
AP 0150-02
L
--
The AP 0150-02 data sheets are the auxiliary operator #2 round sheets
and are completed once per shift.
Instructions to the auxiliary
operator, in general, require that observations for leakage be made
,
in all areas toured. Additionally, specific entries on the round
l
shcet require that certain areas be specifically examined as part of
the leakage reduction program.
'
l
,
o
j
1
51
i
Based on review of the AP 0150.02 forms and discussions with the
Operations Supervisor, the inspector noted that no provisions
existed to record the results of leakage monitoring on the
recirculation sample system. Additionally, although portions
of the RWCU system were specifically covered by the form, no
provisions existed to ensure that all portions of the RWCU
system ware examined during the shift rounds. The licensee
stated that AP 0150.02 would be changed by November 30, 1980,
to incorporate documentation of the recirculation sample system
and the RWCU system leakage monitoring results.
This item is unresolved pending completion of licensee action
on this item and subsequent review by the NRC (URI 50-271/80-17-08).
(19) Item 2.1.8.b (III.D.3.3) Inplant Radiation Moriitoring
Requirement:: References (i),(ii),(vi)and(viii)
r
Provide interim method for quantifying high level releases
+
of up to 10'+ ci/sec for noble gases from all potential
release points.
Capability for effluent monitorin'g of radiciodines shall
+
be provided with sampling conducted by absorption on
charcoal, followed by onsite laboratory analysis.
+
If control room read-out of high range monitors is not
practical for implementation of interim measures, in-situ
reading by a individual with verbal communications with the
control room is acceptable. Measures shall also then include
procedures to minimize personnel exposures and the capability
to obtain radiation readings at least every 15 minutes.
Licensee Commitments:
References (iv) and (v)
By letter dated January 8, 1980, the licensee stated interim
+
procedures and equipment were provided to quantify high level
releases. A dedicated RM-16 installed at the base of the stack,
used in conjunction with stack flow rates, can be converted
to a release rate. Techniques for taking measurements, per-
forming analyses and minimizing personnel exposures are incor-
porated in newly developed procedures. Analysis can be per-
formed in the plant counting laboratory, with backup capability
at Yankee Rowe and the Westborough facility.
.
o
52
.
Inspection Findings
Modifications in progress to meet the long term requirements
for augmented radiation monitoring are being done in accordance
W.th EDCR 80-28, Gaseous Radiation Monitor, dated September 25,
1980. The new system will provide monitoring for stack gas
effluents over the range of 1E-7 uci/cc to 1E+5 uci/cc. A new
ion chamber will be installed in the existing stack gas effluent
monitor line, upstream of the existing lower range monitor, in the
stack house at the base of the stack.
One decade overlap with
existing monitors will be provided, with control room readout
in the range of 0.1 mR/hr to IE+7 mR/hr.
Discussions with
licensee personnel indicate that current schedules for completing
this item by January 1, 1981, may not be met.
Procedure OP 3530, Post Accident Sampling, Revision 0, dated
December 31, 1979, contains the necessary instructions for
obtaining samples with the interim equipment. The capability
for measuring radiciodines using portable instrumentation
(SAM II) is described in section 4 of OP 3530, as well as in
OP 3013, for use by the offsite monitoring teams.
Fe310 wing review of plant systems and structures, the only release
point considered for the source of high level releases was the
plant stack. A dedicated RM-16 was installed in the stack house
with the HP 210 probe of the monitor positioned to measure the
dose rate along a 1 foot section of the existing gas effluent
monitor sample return line. The detector probe and portions of
the effluent monitor return line are shielded by eight inches of
lead bricks. The RM-16 is powered normally by connection to
panel LP1AE which is powered from MCC 8A. MCC 8A is powered from
4160V bus No. 3 through station service transformer T-8 and 480V
bus No. 8.
Bus No. 3 is carried by the B Diesel generator on
loss of normal power. The RM-16 monitor also has battery power
as a backup supply.
Two batteries are supplied with each battery
capable of supplying power for two days.
The read-out range of the RM-16 was verified as 0.2 mR/hr to 2000
mR/hr, corresponding to a stack release rate in the range of
26 ci/sec to 147,000 ci/sec.
Comparison with the existing stack
gas monitors shows that a gap exists in the ranges of the
instruments, between 0.75 ci/sec to 26 ci/sec.
(Themonitors
installed under EDCR 80-28 will eliminate this discrepancy).
Instructions and curves
in OP 3530 also allow conversion of
RM-16 readings to effluent release concentrations (uci/cc), with
considerations for isotopic mix and time after reactor shutdown
accounted for. The inspector reviewed the bases for the RM-16
'
_ _
o
o
53
release conceritration conversions curvesInich Wire ~ derived
~
--
~
,
.
from shielding calEuiitions o5 Fi~ foot section of staihEss
steel sample line.
'
The inspector noted that a Gai-tronics unit is available at
the stack house to allow direct comunication with the control
room.
Backup means of comunications is also available through
the use of walkie-talkies.
Calibration of the RM-16 is provided for by OP 4560, Calibration
of RM-16, Revision 2, dated April 16, 1980.
Check sources are
used to verify check points of 1 mR/hr, 10 mR/hr and 100 mR/hr
along the detector range.
Calibration frequency for the RM-16
is specified as semi-annual by 0P 4540.
'
During inspector review of the stack facilities on November 4, 1980,
water was noted dripping through a stack house wall penetration
onto the top of the RM-16 electronics unit. This information
was imediately reported to plant personnel for corrective
action.
No inadequacies were identified. The inspector had no further
coment on this item.
(20) Item 2.1.8.c (III.D.3.3) Iodine Measurements
Requirements: References (i),(ii),(vi)and(vii)
+
Provide interim method for measuring radiciodines following
an accident using portable sampling equipment with a single
'
channel analyzer.
Licensee Comitment:
References (iv) and (v)
+
By letter dated January 8, 1980, VY stated equipment and
procedures exist to measure radiciodines in the concentrations
of interest following an accident. MCAs are available to
monitor a charcoal sampling medium.
The analyzers can detect
,
iodine in the presence of noble gases.
Plant procedures
!
describe methods in the presence of gross activity levels,
which involve clearing the samples of noble gases by purging
with clean air.
Inspection Findings
The inspector found that instructions for obtaining and analyzing
radioiodine samples were provided in procedures OP 3530, OP 3013,
!
.
. .
.
_
.
. _
+
v
54
OP 3010 and OP 2511,
In addition to use of the onsite MCA
and counting facilities, instructions were provided in OP 3530
for the use of portable single channel analyzers (SAM II) units.
Set-up, calibration and use of the SAM II detectors were discussed
with licensee personnel.
No inadequacies were identified.
Instructions and precautions for limiting personnel exposures
were given in the referenced procedures.
Previous inspector review of this item is documented in NRC
Region I Inspection Reports 50-271/80-09 and 50-271/80-13.
The inspector had no further comment on this item.
14. , Unresolved Items
Unresolved items are items about which more information is required to
ascertain whether thev are acceptable items, items! of noncompliance, or
deviations. Unresolved items are discussed in paragraph 12ea, 13.b and
13.d of this inspection report.
15. Management Meetings
During the period of the inspection, licensee management was periodically
notified of the preliminary findings by the resident inspectors. A summary
was also provided at the conclusion of the inspection and prior to report
issuance. Additionally, the resident inspectors attended the exit interview
on October 31, 1980, conducted by a region-based inspector in regard to an
inspection of the licensee's inservice inspectior, and outage modification
programs,
l
.