ML20134H485
| ML20134H485 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 08/12/1985 |
| From: | Fredrickson P, Garner L, Hicks T, Paulk G, Puland W, Ruland W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20134H476 | List: |
| References | |
| 50-324-85-22, 50-325-85-22, NUDOCS 8508280435 | |
| Download: ML20134H485 (12) | |
See also: IR 05000324/1985022
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UNITED STATES
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NUCLEAR REGULATORY COMMISSION
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REGloN 11
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101 MARIETTA STREET,N.W.
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ATLANTA, GEORGIA 30323
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Report Nos. 50-325/85-22 and 50-324/85-22
Licensee: Carolina Power and Light Company
P. O. Box 1551
Raleigh, NC 27602
Docket Nos. 50-325 and 50-324
License Nos. OPR-71 and DPR-62
Facility Name:
Brunswick 1 and 2
Inspection Conducted: July 1 - 31, 1985
Inspectors:
O M /-8[
W.
. Rula dS
Date Signed
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12. Av6 85
G. L.'_PauT'
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Date Signed
.L2AG&95
L.'W. Garner
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Date Signed
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W .
E.' Hicks
Date Signed
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Approved By:
11. /f ()(r- j[
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P. E. Fredrichs6ff,' Section Chief
Date Signed
Division of Reactor Projects
SUMMARY
Scope:
This routine safety inspection involved 237 inspector-hours on site in
the areas of followup on previous enforcement matters, maintenance observation,
surveillance observation,
operational
safety verification, onsite review
committee, onsite Licensee Event Reports review, plant modifications, and
inadvertent core spray initiation.
Results:
Two violations were identified: Inadequate Corrective Action Relating
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To Annunciator Procedures and Hydraulic Control Units (HCU's) Not Installed As
Per Drawing; two unresolved items, Drywell Temperature Calculation and Unusual
Event Due to Fuel Pc31 Overflow.
F508280435 850813
ADOCK 05000324
O
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SUMMARY DETAILS
1.
Persons Contacted
Licensee Employees
P. Howe, Vice President - Brunswick Nuclear Project
C. Dietz, General Manager - Brunswick Nuclear Project
T. Wyllie, Manager - Engineering and Construction
G. Oliver, Manager - Site Planning and Control
J. Holder, Manager - Outages
E. Bishop, Assistant to General Manager
'L. Jones, Director - QA/QC
M. Shealy, Acting Director - Training
M. Jones, Acting Director - Onsite Nuclear Safety - BSEP
J. Chase, Manager - Operations
J. O'Sullivan, Manager - Maintenance
G. Cheatham, Manager - Environmental & Radiation Control
K. Enzor, Director - Regulatory Compliance
B. Hinkley, Manager - Technical Support
L. Boyer, Director - Administrative Support
V. Wagoner, Director - IPBS/Long Range Planning
C. Blackmon, Superintendent - Operations
J. Wilcox, Principle Engineer - Operations
W. Hogle, Engineering Supervisor
W. Tucker, Eagineering Supervisor
B. Wilson, Engineering Supervisor
R. Creech, I&C/ Electrical Maintenance Supervisor (Unit 2)
J Moyer, I&C/ Electrical Maintenance Supervisor (Unit 1)
R. Kitchen, Mechanical Maintenance Supervisor (Unit 2)
R. Poulk, Senior NRC Regulatory Specialist
D. Novotny, Senior Regulatory Specialist
W. Dorman, QA - Supervisor
W. Hatcher, Security Supervisor
W. Murray, Senior Engineer - Nuclear Licensing Unit
Other licensee employees contacted included construction craftsmen,
engineers, technicians, operators, office personnel, and security force
memoers.
NRC Resident Inspector
G. Paulk, Senior Resident Inspector, Brown's Ferry
2.
Exit Interview (30703)
The inspection scope and findings were summarized on August 7,
1985, with
the general manager.
Two violations, described in paragraph six, were
discussed in detail.
The licensee acknowledged the findings without
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exceptinn.
The licensee did not identify as proprietary any of the
materials provided to or reviewed by the inspectors during the inspection.
3.
Followup on Previous Enforcement Matters (92702)
(CLOSED) Violation 325, 324/85-03-02: Inadequate Procedure, Operating
Procedure (0P) 6.12, Condensate Phase Separator Operating Procedure.
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The inspector verified that:
(1) ops 6.12, 6.13, 6.14, 6.15 and 6.16 were
changed to include cautions to direct operating personnel to close loading
dock isolation valves from the radwaste control room upon indication of
unusual circumstances or conditions; (2) PT-45.1, Loading Dock Transfer
Lines Leak Test, was revised to incorporate necessary precautions to
preclude line freeing; (3) Radwaste operating personnel were trained on the
procedural changes and this event.
Also, the radwaste loading dock was
illuminated and the flex hose drained when not in use.
No violations or deviations were identified.
4.
Maintenance Observation (62703)
The inspectors observed maintenance activities and reviewed records to
verify that work was conducted in accordance with approved procedures,
Technical Specifications, and applicable industry codes and standards. The
inspectors also verified that:
redundant components were operable;
administrative controls were followed; tagouts were adequate; personnel were
qualified; correct replacement parts were used; radiological controls were
proper; fire protection was adequate; QC hold points were adequate and
observed; adequate post-maintenance testing was performed; and independent
verification requirements were implemented.
The inspectors independently
verified that selected equipment was properly returned to service.
Outstanding work requests and authorizations (WR&A) were reviewed to ensure
that the licensee gave priority to safety-related maintenance.
The inspectors observed / reviewed portions of the following maintenance
activities:
WR&A 1-M-85-2431, SGTS ( for PT-15.1.2)
MI-16-528, Fisher Butterfly Valves
PM-84-195, N2 Backup System
PM-84-299, Service Water Phase II Inspect / Repair / Replacement
No violations or deviations were identified.
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5.
Surveillance Observation (61726)
The inspectors observed surveillance testing required by Technical
Specifications.
Through observation and record review, the inspectors
verified that:
tests conformed to Technical Specification requirements;
administrative controls were followed; personnel were qualified; instru-
mentation was calibrated; and data was accurate and complete.
The
inspectors independently verified selected test results and proper return to
service of equipment.
The inspectors witnessed / reviewed portions of the following test activities:
2MST-RHR21M, Rev. 0
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- PT 16.2-2, Primary Containment Volumetric Average Temperature
- Daily Surveillance Requirements
a.
Primary Containment Average Air Temperature Determination
The licensee has not yet found any record which supports the use of
certain coefficients used to calculate primary containment average
temperature. Technical Specification 4.6.1.6 requires the licensee to
determine primary containment volumetric average air temperature at
least every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. PT-16.2-2 implements T.S. 4.6.1.6.
Thermocouple
readings between certain elevations are averaged and multiplied by a
volumetric coefficient for the specific containment volume monitored.
Values from five volumes are added together to obtain the volumetric
average temperature. The licensee has been unable to produce records
to support the values used for the volumetric coefficients in
PT-16.2-2.
The licensee continues to interview current and former
employees and search records for supporting information for the
coefficients. Until the licensee can support the calculations and the
coefficients used in PT-16.2-2, this item is Unresolved:
Drywell
Temperature Volumetric Ccafficients, (325, 324/85-22-03).
b.
Daily Surveillance Requirements Review
During a tour on July 1,1985, the inspector noted that the 1600-2400
hours shift foreman failed to review and initial the Daily Surveillance
Requirements (DSR) log for June 30, 1985.
On July 17, 1985, the
inspector noted that the steam jet air ejector radiation monitor
readings (012-RM-K601A and B) were not taken between 2200-2400 hours
on July 16,1985. The reactor operator also failed to initial the page.
These omissions were discussed with the shift operations supervisor and
plant management, the identified omissions were corrected.
No violations or deviations were identified.
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6.
Operational Safety Verification (71707 and 71710)
The inspectors verified conformance with regulatory requirements by direct
observations of activities, facility tours, discussions with personnel,
reviewing of records and independent verification of safety system status.
The inspectors verified that control room manning requirements of 10 CFR 50.54 and the Technical Specifications were met.
Control room, shift
supervisor, clearance and jumper / bypass logs were reviewed to obtain
information concerning operating trends and out of service safety systems to
ensure that there were no conflicts with Technical Specifications Limiting
Conditions for Operations.
Direct observations were conducted of control
room panels, instrumentation and recorder traces important to safety to
verify operability and that parameters were within Technical Specification
limits. The inspectors observed shift turnovers to verify that continuity
of system status was maintained.
The inspectors verified the status of
selected control room annunciators.
Operability of a selected ESF train was verified by insuring that:
each
accessible valve in the flow path was in its correct position; each power
supply and breaker, including control room fuses, were aligned for
components that must activate upon initiation signal; removal of power from
those ESF motor-operated valves, so identified by Technical Specifications,
was completed; there was no leakage of major components; there was proper
lubrication and cooling water available; and a condition did not exist which
might prevent fulfillment of the system's functional
requirements.
Instrumentation essential to system actuation or performance was verified
operable by observing on-scale indication and proper instrument valve
lineup, if accessible.
The inspectors verified that the licensee's health physics policies /proce-
dures were followed. This included a review of area surveys, radiation work
permits, posting, and instrument calibration.
The inspectors verified that: the security organization was properly manned
and that security personnel were capable of performing their assigned
functions; persons and packages were checked prior to entry into the
protected area (PA); vehicles were properly authorized, searched and
escorted within the PA; persons within the PA displayed photo identification
badges; personnel in vital areas were authorized; effective compensatory
measures were employed when required; and security's response to threats or
alarms was adequate.
The inspectors also observed plant housekeeping controls, verified position
of certain containment isolation valves, checked a clearance, and verified
the operability of onsite and offsite emergency power sources.
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a.
Inadequate Annunciator Procedures.
During a review-of the Plant Operating Manual Annunciator Procedures
(APs), a generic deficiency was identified.
Contained in the action
statements for many of - the procedures are references to Emergency
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Instructions (EIs) which were designed to provide the operator with
followup actions and recovery steps.
However the Els had been
- completely replaced over one year earlier (approximately May 1984) with
either Emergency Operating Procedures (E0P's) or Abnormal Operating
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Procedures (A0Ps) depending on the emergency. The licensee's plan was
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to update the APs sometime thereafter. In the interim period, a cross
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reference was generated and provided to the operators in the control
room.
The cross reference would be used until the APs could be
revised.
However, this document had not been incorporated into~ an
approved procedure and was inadvertently removed from the control room.
If one of the annunciator procedures in question was then used, the
operator would have to identify the referenced EI with a new procedure
.by reviewing the A0P, E0P procedure index and determining which 'new
procedure was applicable. Since the titles of the new procedures did
not necessarily match the old procedure titles, this type of evolution
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could be time consuming and allow for errors.
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Consequently this program failed to be adequately implemented in that
most of the procedures reviewed, which required changes, were not yet
updated nor did the operators have a readily available means to
icross-reference the old EI's with the new E0P's and AOP's.
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Examples of this problem are as follows:
Action Statement
Annunciator Panel
Description
Reference
A-03; 1-7
RHR System II Actuator
EI-1.2 Rupture
Inside Drywell,
EI-08 Abnormal
Reactor Water Level,
EI-5.2 Loss of
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A-03; 3-4
Reactor Core Isolation
EI-07 Reactor Core
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Cooling Pump Discharge
Isolation Cooling
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Flow Low
System Failure
A-05;.3-5
Reactor Vessel Pressure
EI-4.1 MSIV Closure,
High
EI-31 Reactor Scram
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UA-03; 6-1
High Activity Process Off
EI-26 Of f Gas High
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Gas Vent Pipe
Radiation, EI-27.3
Abnormal Release of
Radioactivity
Airborne
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UA-03; 6-6
Area Radiation Stack
EI-23.4 High
Filter House High
Radiation in
Accessible Areas
UA-04; 1-4
Reactor Feed Pump
EI-09 Condensate
Turbine Tripped
and Feedwater System
Failure
A-06; 4-6
Steam Tunnel High Temp
EI-31 Reactor
System B
Scram, EI-20 Main
Steam Line Leaks
VA-15; 2-1
El Bus Undervoltage
EI-15.1 Station
Blackout Operation,
EI-15.2 Degraded
Auxiliary Electrical
Power Operation
10 CFR 50 Appendix B, Criterion XVI, as implemented by FSAR Section
17.2.16, Corrective Action, requires measures be established to assure
that conditions adverse to quality (i.e. , deficiencies) are promptly
identified and corrected.
Technical Specification 6.8.1.c requires
that the licensee maintain and implement procedures specified in Reg.
Guide 1.33, November 1972.
Item
"E"
of the guide requires that
procedures for correcting abnormal, offnormal or alarm condition be
implemented.
Contrary to the above, a condition adverse to quality was not
adequately corrected in that most annunciator procedures which required
changes, caused by the introduction of Emergency Operating and Abnormal
Operating Procedures and the elimination of the Emergency Instructions,
were not updated and corrected or an alternate means adequately
provided
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clarify reference discrepancies contained in the
procedures. This is a violation, inadequate corrective action relating
to annunciator procedures (325, 324/85-22-01) of NRC requirements. The
licensee has since provided the operators with a readily accessible
cross-reference list while the annunciator procedures are changed.
Also, ANSI 18.7, 1976, Administrative Controls and Quality Assurance
for the Operational Phase of Nuclear Power Plants, Section 5.2.15,
Review, Approval and Control of Procedures, requires that plant
procedures be reviewed no less frequently than every two years to
determine if changes are necessary or desirable.
The licensee's
Administrative Procedures, Volume I Book I, Section 5.6,
implements
this ANSI requirement and specifies that the reviewer " Attest that the
procedure remains accurate, effective, and useful for its intended
purpose; or otherwise, revisions are initiated to correct identified
deficiencies." The licensee is committed to comply with ANSI 18.7,
1976.
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The licensee did conduct a review (completed in April 1985), as
required, but failed to make any procedure changes as a result of it.
One reviewer did identify several deficiencies in three of the
annunciator panels and submitted 01-28, Preparation and Review of
Operating Procedures, changes. At the time of the inspection, none of
the changes had been implemented.
b.
Hydraulic Control Unit Problems
A routine inspection of the Control Rod Drive (CRD) Hydraulic Control
Units for Unit 2,
revealed the following items, which were not in
accordance with plant design drawing G. E. 9190615:
1)
HCU racks Nos. 18-51, 14-19, 02-27 and 06-31 had support to
foundation bolts and/or nuts disengaged.
2)
HCU rack No. 30-43 had 2 of the 4 rack support to foundation bolts
missing.
3)
All bolts, lockwashers and washers on the HCU rack supports did
not appear to be cadmium plated as required.
4)
HCU rack No. 18-35 support to foundation bolt had what appeared to
be a welding ground pigtail attached under it.
In addition caps were missing from directional control valves on HCU's
Nos. 18-07, 34-31, 18-31 and 42-11.
The area also exhibited poor
housekeeping in that miscellaneous materials were in, on or between the
HCU racks.
These items included:
parts of valves, a lead brick, a
stainless steel bar, rusty washers, nuts and bolts, rolls of duct tape
and trash.
Items 1) and 2) constitute a violation of 10 CFR 50 Appendix B,
Criterion V (325, 324/85-22-02), hydraulic control units not installed
per drawings.
Subsequent inspections by the licensee revealed similar
discrepancies on Unit 1.
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c.
Diesel Generator Walkdown
During a detailed walkdown on Diesel Generator No.
1,
prior to
post-maintenance testing, the inspector found four valves which had no
tags on them and were not contained in the Operating
Procedure OP-39
valve check list. Two of these were valves associated with calibration
of the pressure switch which provides for actuation of the shutdown
cylinder to close the fuel racks during engine shutdown. These three
valves are addressed in the appropriate maintenance procedures.
A
similar condition existed on the other three diesel generators.
The
remaining valve was installed in parallel with an air regulator valve
in the starting circuit.
The other diesel generators have a check
valve in this application as shown in the technical manual.
The
licensee is evaluating this "as found" condition.
The licensee has
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indicated that OP-39 will be revised to include these valves as
appropriate. This is an Inspector Followup Item: OP-39 Revision (325,
324/85-22-04).
d. Hurricane Bob
On July 24, 1985, the remnant of Hurricane Bob, downgraded to a tropical
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storm, past approximately 100 miles inland of the Brunswick site. Only
periods of heavy rain were experienced at the site.
Plant operations were
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unaffected. Unit I was in refuel and Unit 2 was operating near full power.
The licensee had taken preparatory action in case the hurricane did approach
the site. This included tracking of the hurricane and establishing criteria
for activation of the technical support center and shutdown of Unit 2.
Unit
2 would have begun shut down if hurricane force winds were expected at the
site within four hours. No such action was required.
7.
Onsite Review Committee (40700)
The inspectors attended selected Plant Nuclear Safety Committee meetings
conducted during the period. The inspectors verified that the meetings were
conducted in accordance with Technical Specification requirements regarding
quorum membership, review process, frequency and personnel qualifications.
Meeting minutes were reviewed to confirm that decisions / recommendations were
reflected in the minutes and followup of corrective actions was completed.
No violations or deviations were identified.
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8.
Onsite Review of Licensee Event Reports (92700 and 90712)
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The listed Licensee Event Reports (LERs) were reviewed to verify that
the information provided met NRC reporting requirements.
The verification
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included adequacy of event description and corrective action taken or
planned, existence of potential generic problems and the relative safety
significance of the event. Onsite inspections were performed and concluded
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that necessary corrective actions have been taken in accordance with
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existing requirements, licensee conditions and commitments.
The following
reports are considered closed:
(CLOSED)
LER 1-83-01; Pipe sides of weld B32 showed pin hole cracks
attributed to IGSCC.
Future action addressed in response to IEB 82-03.
This defect was identified during 82-03 inspections.
Bulletin 82-03 was
closed for Unit 1 in IE inspection report 85-08.
(CLOSED) LER 1-83-04; Two crack indications in the heat affected zone on
the pipe side of weld downstream of the loop discharge valve. These defects
were identified during IEB 82-03 insrections.Bulletin 82-03 was closed for
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Unit 1 in IE inspection report 85-08.
(CLOSED) LER 1-83-49; Two crack indications exist in the heat affected zone
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on the pipe side of weld B32-RECIRC-28-A-14 and B32-RECIRC-28-B-8 due to
These defects were identified during IEB 83-02 inspections.
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Further licensee and NRC actions concerning IGSCC are addressed in Generic Letter 84-11.
(CLOSED) LER 1-85-024; Manually initiated isolation of Units 1 and 2 common
control building heating ventilating air conditioning system.
(CLOSED) LER 2-83-38; An inoperative and rod block signal was received due
to defective multiplexer cards.
(CLOSED) LER 2-83-40; Residual Heat Removal System flow transmitter had no
output response to an applied test signal.
No violations or deviations were identified.
9.
Design, Changes and Modifications (37700)
On July 1, 1985, a construction engineer working on Unit 1 suppression
chamber modifications discovered the suppression chamber spray nozzles were
not installed.
The unit was in cold shutdown undergoing a refueling outage.
The suppression chamber spray header system is a subsystem of the contain-
ment spray system, and is an operational mode of Residual Heat Removal
System (RHR). With the RHR system in containment cooling mode of operation,
the RHR pumps are aligned to pump water from the suppression pool through
the RHR system heat exchangers where cooling takes place by transferring
heat to the unit service water system. Flow returns to the suppression pool
via the full flow test line.
Under post-accident conditions, the containment cooling subsystem provides
additional redundancy to the core standby cooling systems. Approximately 5
percent of the flow from the heat exchangers may be directed to the
suppression chanber spray ring to cool any noncondensible gases collected in
the free volume above the suppression pool. Analysis shows (refer FSAR
Section 6.2.1.1.3.2.1), that containment spray is not necessary to provide
adequate containment protection during the design basis accident. There-
fore, containment spray failure was not a safety problem (refer FSAR Section
6.2.2.2).
The licensee determined that the suppression chamber spray nozzles have
never been installed.
A review of startup testing turnover packages
revealed no apparent reason for the deficiency.
New nozzles have been
ordered and will be installed prior to suppression chamber closecut and
plant startup.
This corrective action will be verified during subsequent
routine inspections.
No violations or deviations were identified,
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10.
Core Spray Initiation and Overflow of Spent Fuel Pool (93702)
On July 30, 1985 at 2236 hours0.0259 days <br />0.621 hours <br />0.0037 weeks <br />8.50798e-4 months <br />, a spurious low vessel water level LOCA
signal initiated available ECCS systems on Unit 1.
This resulted in
over-filling of the spent fuel pool and subsequent release of approximately
25,000 gallons of water into the Reactor Building.
Safety systems which
automatically actuated included three emergency diesel generators, core
spray loop 1A and group I isolation. Other systems which would normally
have started were under clearances for either maintenance or modification.
Unit I was in an outage with the vessel defueled, fuel pool gates removed
and the vessel cavity flooded up.
Full power operations of Unit 2 were
unaf fected by the event. Description of the sequence of events, root cause
and preliminary corrective actions, damage assessment and cleanup status
follows:
6-15-85
Clearance No. 886 boundary changed to allow venting and
hydrostatic testing of instrument 1-821-LT-N026A as directed
by plant modification 82-271.
Clearance designated No. 886A.
7-01-85
Clearance tags for 1-B21-LT-N026A removed from No. 886A
to allow testing on another modification.
7-30-85
Clearance tags for 1-821-LT-N026A not rehung prior to
resuming venting of instrument.
2236 Venting of 1-821-LT-N026A causes slight depressurization of
variable instrument leg containing 1-821-LT-NO31A and C.
These latter instruments initiate a low level 2 group I
isolation signal and a low level 3 LOCA signal. The control
operator (CO) observes the group I isolation annunciator and
auto starting of diesel generators 1, 3 and 4. The shift
foreman thought radiography in the main streamline isolation
valve pit may have commenced.
A senior control operator
(SCO) went to the backpanel to check radiation monitor
status.
2237 SCO reports fire in backpanel. Fuel pool high level alarm is
received. C0 requests radwaste to maximize reject from fuel
pool.
2238 CO begins control board walkdown.
Group I is reset. Core
spray logic system failure annunciator is in alarm.
Health
physicist on refuel floor reports fuel pool level is at
ventilation ducts which surround the upper portion of the
fuel pool walls.
2239 C0 trips running CRD pump.
Core spray pump 1A is found
running and is manually tripped.
2240 Extinguishment of the backpanel fire commences.
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2245 Fire is reported out in the core spray logic panel. Two HFA
relays had smoked.
No flaming had occurred.
No other
components were damaged by the fire.
7-31-85
At 0903 hours0.0105 days <br />0.251 hours <br />0.00149 weeks <br />3.435915e-4 months <br />, the Licensee determined that they were in an
unusual event based upon their emergency guideline procedure.
Per the Shift Operating Supervisor judgement, it was deter-
mined that plant conditions exist that warrant increased
awareness on the part of the plant operating staff. This was
predicated on the fact that a large area of the reactor
building had become contaminated and that if the water dried
out, there was a potential for the areas to become airborne.
8-01-85
At 0830 the unusual event was terminated based upon the
progress being made by the decontamination teams.
The root cause of the event was determined to be a problem with restarting a
modification procedure after it had been interrupted.
In addition, its
effects were amplified by another problem.
Installation of the nitrogen
backup supply to the drywell modification had inadvertently installed AC
type HFA relays into the core spray system logic which is powered by DC.
Thus, when the spurious LOCA signal occurred, these relays burned up causing
loss of power to the core spray logic. With the logic de-energized, all
initiation logic lights and annunciators associated with the core spray
initiation were inoperable.
Hence, the operator was not immediately
notified of the core spray injection. Another possible annunciator, Core
Spray /RHR Pump Running, was already lit since the RHR pump was being used
for shutdown cooling.
Interim measures taken by the licensee until long term corrective action can
be developed, include: (1) double sign-on of clearances on modifications to
assure proper tags are in place; (2) engineers will review test procedures
to identify untested devices such as the HFA relays which may have already
been placed in service and 3) reverification of clearances on tests which
are interrupted.
Final corrective actions will be included in the LER
submittal.
Overflowing of the fuel pool into the ventilation ducts resulted in: damage
to the duct work including approximately 150 feet of duct which fell onto
the floor next to the standby gas treatment trains; water on the -17', 20'
and 50' elevations of the reactor building; non-safety related MCC 1XJ
requiring de energization; partial loss of reactor building lighting; and
malfunctioning of the E11-F017A valve (outboard low pressure coolant
injection valve). When the ducting fell, it bent one safety related cable
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tray; however, no cables were damaged in the tray.
The problem with the
E11-F017A valve is still being determined. The Licensee has decontaminated
l
the floors, inspected the inside of panels and MCC's and taken actions
'
necessary to resume outage work. Outage work was restarted on August S.
This event is considered an unresolved item pending further NRC review of
,
l
the event and contributing circumstances (325/85-22-05).
No violations or deviations were identified. One unresolved item is noted.
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