ML20132E384
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| ML20132E384 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 07/12/1985 |
| From: | Fredrickson P, Garner L, Hicks T, Ruland W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20132E361 | List: |
| References | |
| 50-324-85-16, 50-325-85-16, NUDOCS 8508010799 | |
| Download: ML20132E384 (11) | |
See also: IR 05000324/1985016
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'o NdrLF AI. REGU LATORY COMMISSION
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Report Nos.: 50-325/85-16 and 50-324/85-16
Licensee: Carolina Power and Light Company
P. O. Box 1551
Raleigh, NC 27602
Docket Nos.: 50-325 and 50-324 License Nos.: DPR-71 and DPR-62
Facility Name: Brunswick 1 and 2
Inspection Conducted: June 1-30, 1985
Inspectors: h[
W. H .' 'Rtil a n'd-
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Date Signed
L. W'.
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Garner
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Da'te Signed
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T. E. Hicks d
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Approved by:
P. E. Fredr1ckson, Sectio Chief
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Date Signed
Division of Reactor Projects
SUMMARY
Scope: This routine safety inspection involved 300 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 Report review, followup on inspector identified
and unresolved items, plant modifications, and refueling activities.
Results: A violation was identified - inadequate surveillance test procedure for
the refueling hoist slack cable interlock.
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REPORT DETAILS
1. Persons Contacted
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 and 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. Blackman, Superintendent - Operations
J. Wilcox, Principal Engineer - Operations
W. Hogle, Engineering Supervisor
W. Tucker, Engineering 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
2. Exit Interview
The inspection scope and findings were summarized on June 28, 1985, with the
general manager. A violation described in paragraph 5 was discussed in
detail. The licensee acknowledged the findings without exception. The
licensee did not identify as proprietary any of the materials provided to or
reviewed by'the inspectors during this inspection.
3. Followup on Previous Enforcement Matters (92702)
(0 pen) Violation 325, 324/82-10-02: Failure to Implement Independent
Verification per NUREG 0737 Item I.C.6. This item will remain open pending
inspectors' review of the licensee's present implementation of I.C.6.
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(Closed) Violation 325,324/84-35-01: Failure to Establish Adequate
Implementing Procedure for Operating Procedure OP-32.
(Closed) Violation 324/82-39-01: Procedure Does Not Contain Isolation Valve
for Low Condenser Vacuum Instrument. The inspector verified that the
subject valves are included in the current revision (No. 32) to OP-30. As
part of the operating procedure rewrite program, th licensee verified or
included as necessary similar instrument isolation valves. This program was
completed in December 1983.
(Closed) Violation 324/82-39-04: Failure to Bypass Low Condenser Vacuum
Above 500 psig.
(Closed) Violation 324/82-39-03: Failure to Follow Procedure EI-13, Mode
Switch Not Locked.
(Closed) Violation 325/83-30-01 and 324/83-30-01: Surveillance Test Method
To Time Standby Gas Treatment System Inlet and Outlet Dampers Is Inadequate.
The licensee's response, dated October 12, 1983, to the Notice of Violation
committed to: (1) revise PT-15.7 to use MCC position indication or visual
observation of valve travel, (2) revise OP-10 to provide a caution note that
the control room position lights do not reflect actual valve position and
such can be obtained from MCC and, (3) review to determine if similar
conditions exist on other valves.
The inspector verified that the current revisions, revision 14 to PT-15.7,
revision 5 to Unit 1 OP-10 and revision 24 to Unit 2 OP-10 contain changes
as committed. The review disclosed no additional similar conditions on
other valves.
(Closed) Violation 325/82-10-05 and 324/82-10-05: Failure to Implement
Maintenance Procedure MI3-3A34. The licensee failed to perform corrective
actions as described in their response (dated May 24,1982) to the Notice of
Violation. Another. Notice of Violation was issued in report 325, 324/82-45.
Corrective action will be inspected as part of the followup on the latter
violation. This item is considered closed for administrative purposes.
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.
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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:
Work Request and Authorization (WR&A) No.1-M-85-2109, IC Residual Heat
Removal (RHR) Service Water Booster Pump, Damaged Bearing.
WR&A No. 1-M-85-2199, 1C RHR Booster Pump High Vibration, High Bearing
Temperature.
WR&A No. 2-M-85-2384, Core Spary Minimum Flow Bypass Valve Repairs,
2E21-F031A.
WR&A No. 0-E-85-1793, Scram Solenoid Valve Replacement Unit 1.
No violations or deviations were identified.
5. Surveillance Observation (61726)
The inspectors observed surveillance testing required by Technical Specifi-
cations. Through observation and record review, the inspectors verified
that: tests conformed to Technical Specification requirements; administra-
tive controls were followed; personnel were qualified; instrumentation 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:
*1MST-RP622R, Main Steamline Isolation Valve Closure Channel Calibration.
PT-12.3.1, Emergency Diesel Generator Annual Inspection.
PT-12.4, Diesel Generator Alarms, Trips and Trip Bypass Test.
PT-85-071, Special Procedure for Response Time for Relays E41A-K4 and
E41A-K5.
PT-12.20, No. 4 Diesel Generator Monthly Load Test.
. IMST-RHR21R, Residual Heat Removal, Low Pressure Coolant Injection, Core
Spray System, High Pressure Coolant Injection (HPCI) High Drywell Pressure
Trip Unit Channel Calibration.
PT-16.2-2, Primary Containment Volumetric Average Temperature, Rev.1.
* Detailed Review
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a. HPCI Response Time Testing
On June 21, 1985, the Maintenance Surveillance Test (MST) procedure
writing groups discovered a discrepancy in the current High Pressure
Coolant Injection (HPCI) System initiation response time test,
Periodic Test (PT) 45.3.4. This PT failed to adequately calculate the
response time for the HPCI System initiation logic as required by
Technical Specification 4.3.3.3.
PT-45.3.4, HPCI initiation response time test was undergoing an upgrade
process by the MST rewrite group (see LER 1-85-03). The procedure
covered Technical Specification 4.3.3.3, which states that the
Emergency Core Cooling System (ECCS) response time of each ECCS
function shall be demonstrated to be within the required limits at
least once per 18 months. The definition of ECCS response time is
"that time interval from when the monitored parameter exceeds its ECCS
actuation setpoint at the channel sensor until the ECCS equipment is
capable of performing its safety function."
The current test method adds two partial response times to obtain the
total time. One partial response time test is run for the sensor and
associated logic response times. (There should be two trains tested,
one for low low reactor water level and one for high drywell pressure.)
The second test is a single HPCI autostart response time test. This
section uses a simulated signal injection at an appropriate overlap
point with the low low reactor water level sensor logic. However,
there was not an adequate overlap point with the high drywell pressure
logic train to consider the response time of all its associated relays.
The response time of the E41-K4 and E41-K5 and E41-K5 relays (high
drywell pressure initiation relays) was not considered in the total
high drywell pressure response time test.
The licensee conducted a Plant Nuclear Safety Committee (PNSC) meeting
concerning the implications of this problem. The PNSC concluded
that: (1) The design response time of the individual relays in
question as compared to the total response time required by Technical
Specifications was minimal. The requirement is less than or equal to
30 seconds. The last HPCI system response time test was 29.64 seconds.
The licensee had no history of this type relay failing a response time
test. The design response time of these relays was .08 seconds. Based
on this information, the HPCI system was not considered inoperable.
(2) Plant conditions were: Unit 2 power level at approximately 90%,
'A' loop of Residual Heat Removal (RHR) System under Limiting Condition
for Operations (LCO), No. 3 Diesel Generator under LCO for maintenance.
To response test the relay, wires would be lifted and HPCI declared
inoperable. This would have put the unit outside its LCO action
statement and into LCO 3.0.3, which requires the reactor shutdown to
hot standby in 6 hours. The 'A' RHR loop was expected back in service
that afternoon, and No. 3 Diesel Generator returned Monday, June 24,
1985. (3) Plant management decided to test HPCI once a special
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procedure (SP-85-071) was written and No. 3 Diesel Generator was
returned to service.
Technical Specification 6.8.1.c requires that adequate procedures be
implemented covering surveillance and test activities of safety related
equipment. Technical Specification 4.3.3.3. requires an ECCS response
time test to be conducted every 18 months. Contrary to this require-
ment, the licensee did not establish an adequate procedure for
Technical Specification 4.3.3.3., in that the testing procedure,
PT-45.3.4., HPCI Initiation Response Time Test, did not test all the
relays in the high drywell pressure initiation logic. This violation
of NRC requirements was identified by the licensee and meets the
requirements of 10 CFR Part 20, Appendix C Section V. A. A Notice of
Violation will not be issued.
b. Refuel Hoist Slack Cable Interlock
On June 8, 1985, defueling of the Unit I core was halted following
continued problems with the main hoist refuel grapple. The problems
resulted from slack cable interlock actuations during normal refuel
grapple operations. While investigating the interlock malfunction and
conducting corrective maintenance, PT 18.1, Refueling Position Inter-
lock Check, was found to be inadequate.
Technical Specification Surveillance Requirement 4.9.6.d states that
each crane or hoist used for the movement of fuel be demonstrated
operable by insuring operation of the slack cable cutoff when the load
was less than 50 plus or minus 25 pounds for the mast fuel gripper.
Technical Specification 6.8.1.a. requires the licensee to establish
implementing procedures recommended in Appendix 'A' of Regulatory Guide
1.33, November 1972. Item H.2 of the guide specifies that procedures
are required for each surveillance test, inspection and calibration
listed in the Tcchnical Specification.
Contrary to the above, PT-18.1 did not demonstrate that the slack cable
cutoff occurred within the required tolerance. Step 7.3.5 of PT-18.1
only functionally checked the operation of the slack cable cutoff but
did not verify the setpoint of the interlock. This inadequacy
constitutes a violation 325,324/85-16-01; Inadequate Surveillance Test
Procedure for the Refueling Hoist Slack Cable Interlock. The licensee
has revised the procedure to include a setpoint verification and
completed the test satisfactorily prior to resuming defuel operations.
This procedure deficiency was also identified in 1983 during a
Technical Specification review by the Onsite Nuclear Safety Group, but
an unsatisfactory resolution of the issue left the procedure as is.
The failure to resolve the issue properly appears to have resulted from
a lack of understanding of the Technical Specification and the fuel
grapple operation. Onsite Nuclear Safety is currently reviewing
additional comments generated during the 1983 review to identify
similar problems.
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c. Diesel Generator Rocker Arm Assembly Nuts
During observation of PT-12.3.1, for Emergency Diesel Generator No. 4,
the inspector observed the some of the nuts which attach the rocker arm
assembly to the cylinder head appeared to be cracked. Inspection by
the licensee revealed 21 nuts which were suspect and were replaced.
During a subsequent performance of PT-12.3.1, for Diesel Generator
No. 3, the licensee replaced 30 similar nuts. The licensee has sent
several nuts to the Harris Energy Center for metallurgical examination.
Preliminary results indicate that, if the nut does not fail during
installation, it will not fail during diesel generator operation. The
inspector will review the final report when issued. The licensee plans
to inspect diesel generators 1 and 2 during July and replace nuts as
necessary.
6. Operational Safety Verification (71707)
The inspectors verified conformance with regulatory requirements by direct
observations of activities, facility toars, discussions with personnel,
review 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 shif t 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 a proper
lubrication and cooling waster 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 procedures were
followed. This included a review of area surveys, radiation work permits,
posting, and instrument calibration.
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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 clearances, and verified
the operability of onsite and offsite emergency power sources.
No violations or deviations were identified.
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 actins was completed.
No violations or deviations were identified.
8. Onsite Review of Licensee Event Reports (92700)
The listed Licensee Event Report (LER) was reviewed to verify that the
information provided met NRC reporting requirements. The verification
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 it was
concluded that necessary corrective actions had been taken in accordance
with existing requirements, licensee conditions and commitments. The
following report is considered closed:
(Closed) LER 2-83-35; Reactor Water Cleanup differential flow indicator
was Indicating high because instrument had a low output signal.
No violations or deviations were identified.
9. Followup on Inspector Identified and Unresolved Items (92701)
(0 pen) IFI 325,324/84-35-02; Post-Trip Review. The inspectors reviewed
01-22, Plant Incident and Post-Trip Investigation, Rev.10, to ensure that
an adequate post-trip review program was established. 01-22 was also
reviewed as part of the Generic Letter 83-28 inspection (85-14). No trips
have occurred since the latest revision to 01-22. This item will remain
open pending implementation review of 01-22.
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(Closed) IFI 324/82-08-07 and 325/32-08-07, Post Potentially Contaminated
Areas Until Survey Shows Otherwise. The event was reviewed with the
appropriate personnel at the time of the event. The inspector verified that
step 8.6.4 of the current revision (No. 4) to procedure E&RC, Posting of
Areas / Materials, instructs personnel as follows: " . . area that has the
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potential to be contaminated from occurrences (... leak from a...potentially
contaminated system...) should be posted as a Contaminated Area until a
survey. . .can be performed. . .". This procedure adequately addresses the
inspector's concerns.
No violations or deviations were identified.
10. Design, Design Changes and Modifications (37700)
The inspectors reviewed selected modifications to verify that: activities
were conducted in accordance with appropriate specifications and drawings;
appropriate administrative controls were implemented; and acceptance testing
was appropriate. The inspectors reviewed portions of the following
modifications:
Plant Modification 82-219Q "B" Loop RHR Service Water.
Plant Modification 82-287H,0 - Reactor Instrument Penetration Valve
Replacement.
MI-16-35A,C - HFA Relay Reconfiguration and Replacement.
Plant Modification 1-82-271, Level Transmitter LT-N026A&B
Replacement.
While reviewing a proposed Plant Modification 84-058, the licensee
discovered a wiring error for the RHR "20" Pump loss of Suction Trip in the
remote shutdown mode. The specific error involved u HFA relay in the
2-E11-F009 valve logic.
This error would have prevented the operation of the 20 RHR pump in the
shutdown cooling node from the remote shutdown panel. No other modes of
operation were affected. The problem was corrected immediately under a
trouble ticket.
The licensee conducted additional system logic drawing review and field
investigation of the remote shutdown systems. During this review, numerous
drawing errors, logic errors and incorrectly wired HFA relays were
discovered. Many of the drawing and logic errors had been corrected in the
field but the as-built condition was not reflected on the prints. Except
for the 2-E11-F009 valve logic error, no other problem identified to date
affected the operability of any equipment in any mode of operation.
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The problems appear to have been caused by an installation deficiency
associated with the contact numbering convention for the HFA relays,
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depending on whether the relay was flush or recessed mounted. The plant
modification installing the remote shutdown system in 1977 did not
adequately verify that: (1) the wiring was in accordance with the drawings,
l (2) the as-built condition was correct or, (3) the acceptance testing was l adequate, i Since this installation, the Plant Modification Procedure (ENP-03) has been l revised and in the inspector's judgement would preclude this situation from l occurring again.
The licensee's engineering staff has proposed the following corrective
actions:
a. Review logic and drawings associated with the remote shutdown circuitry
for wiring and drawing discrepancies.
b. Complete as-built verification of remote shutdown circuitry and
identify discrepancies between the as-built and plant drawings.
c. Initiate and perform required repairs to correct errors through the use
of plant modifications or work requests.
d. Perform acceptance testing through the use of special procedures that
will test the remote shutdown system in all modes of operation.
e. C1a' rify drawing orientation of HFA relays to distinguish between the
two relay configurations.
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Prior to this event, the licensee had already undertaken a program to test
the dif ferent modes of remote shutdown (1984 - 1985). To'date, only the
Reactor Core Isolation Cooling System had been satisfactorily tested. Plant
operating conditions prevented further testing.
Inspector Followup Item (IFI) 325,324/85-16-02; Remote Shutdown Panel Wiring
Deficiencies, will track the licensees' actions and progress in this area.
No violations or deviations were identified.
11. Refueling Activities (60710)
During the licensee's defueling operations, the inspectors verified that
surveillance testing required by Technical Specifications was current and
that the licensce's fuel handing procedures were implemented. The following
items were verified:
a. Selected fuel bundle movements and storage locations.
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b. Core monitoring during defuel operations was in accordance with
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i 10 l l c. Vessel water level was maintained in accordance with Technical l
Specifications.
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d. Reactor mode switch position was as required by Technical Specifica-
tion.
e. Continuous comunications were maintained between the refueling
! platform and the Control Room and the Control Room operators were
cognizant of the applicable procedure steps,
f. Health-Physics personnel maintained constant coverage of all fuel
moving activities, ensuring area dose rates, contamination levels and
airborne samples were within required tolerances.
No violations or deviations were identified.
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