ML20133H468
| ML20133H468 | |
| Person / Time | |
|---|---|
| Site: | Arkansas Nuclear  |
| Issue date: | 10/01/1985 |
| From: | Harrell P, Johnson W, Martin L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20133H460 | List: |
| References | |
| 50-313-85-22, 50-368-85-23, NUDOCS 8510170378 | |
| Download: ML20133H468 (13) | |
See also: IR 05000313/1985022
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APPENDIX B
U. S. NUCLEAR REGULATORY COMMISSION
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REGION IV
NRC Inspection Report:
50-313/85-22
Licenses:
50-368/85-23
Dockets:
50-313
50-368
, Licensee: Arkansas Power and Light Company (AP&L)
P. O. Box 551
Little Rock, Arkansas 72203
Facility Name:
Arkansas Nuclear One (ANO), Units 1 and 2
Inspection At:
ANO Site, Russellville, Arkansas
.;
Inspection Conducted:
August 1-31, 1985
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Inspectors:
/
Q.D.Johnsch,feniorResidentReactor
Date'
Inspector (pars. 2,3,4,5,6,7,
9, 10)
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F. H. Harrell, Tes(dent Reactor Inspector
Date'
(pars. 2, 4, 5, 6, 7, 8)
Approved:
A24/E.
L."EVMartin, Ch' f, Project Section 8
D(tg
Reactor Proje s Branch
8510170378 851003
ADOCK 05000313
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. Inspection Summary
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Inspection' Conducted August 1-31, 1985 (Report 50-313/85-22).
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Areas' Inspected:
Routine, unannounced inspection including operational safety
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verification, maintenance,' surveillance, design change control,
followup on previously identified items, low temperature overpressurization
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protection,-and training.
The. inspection involved 84 inspector-hours (including 16 backshift hours)
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. onsite by two NRC inspectors.
- Results: Within the seven areas inspected, one violation was identified
(failure to verify fire water valves in correct position, paragraph 4).
Inspection Summary
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Inspection Conducted August 1-31, 1985 (Report 50-368/85-23)
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Areas Inspected:
Routine, unannounced inspection including operational safety
verification, maintenance, surveillance, design change control, followup on
previously identified items, followup of onsite event, and training.
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The inspection involved 83 in'spector-hours (including 15 backshift hours)
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- onsite by'two NRC inspectors.
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Results: Within the seven areas inspected, one violation was identified (two
fire doors found open, paragraph 4).
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DETAILS
1.
Persons Contacted
- J. Levine, ANO General Manager
-B. Baker, Operations Manager
R. Blankenship, Nuclear Engineer
M. Bolanis, Health Physics Superintendent
M. Browning, Maintenance. Engineer
- P. Campbell, Licensing Engineer
H. Carpenter, I&C Supervisor
E. Corliss, I&C Supervisor
L. Dugger, Acting I&C Maintenance Superintendent
E. Ewing, Engineering & Technical Support Manager
- L. Gulick, Unit 2 Operations Superintendent
D. Hamblen, Quality Control Engineer
H. Hollis, Security Coordinator
L. Humphrey, Administrative Manager
J. Lamb, Safety and Fire Protection Coordinator
- D. Lomax, Licensing Supervisor
J. McWilli.ams, Unit 1 Operations Superintendent
J. ' Montgomery, Human Resources Supervisor
- M. Pendergrass, Acting Engineering & Technical Support Manager
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V. Pettus, Mechanical Maintenance Superintendent
'*D. Provencher, Quality Engineering Supervisor.
J. Ray, Quality Control Engineer
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E. Rice, Electrical Maintenance Supervisor
P. Rogers, Plant Licensing Engineer
'*L. Sanders,. Maintenance Manager
- L.' /Sch'empp, Nuclear Quality Control Manager
.C. Shively, Plant Engineering Superintendent
G. Storey, Safety and Fire Protection Coordinator
M. Stroud, Electrical Engineer
L. Taylor, Special Projects Coordinator
B. Terwilliger, Operations Assessment Supervisor
R. Tucker, Electrical Maintenance Superintendent
D. Wagner, Health Physics Supervisor
- R. Wewers, Work Control Center Manager
- C. Zimmerman, Operations Technical' Support.
- Present at exit interview.
The inspectors also contacted other plant personnel, including operators,
technicians, and administrative personnel.
2.
Followup on Previously Identified Items (Unit 1)
(Closed) Open Item.313/8419-03; 368/8419-03:
QC department training.
This item addressed a concern that the Manager of Nuclear Quality Control
was required to devote a considerable amount of time to the development
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and administration of the training program for quality control (QC)
inspectors and engineers and for warehouse personnel who perform receipt
' inspections. The NRC inspector found that licensee management has
reviewed this concern and shifted some responsibilities for administration
of the QC: training program to the training section.
The responsibilities
' shifted include scheduling and coordinating QC training, maintenance of QC
training records, filing and storing QC lesson plans and tests, and
> providing assistance in QC training program development.
Implementation
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of the proposed new QC trainer position in the training section would
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enable the training section to also develop and present QC training
programs.
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_ Closed) Open Item 313/8501-04: Verification _that procedure changes have
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been issued to the control room prior to heatup.
The licensee has reviewed this item and has determined the method
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. presently used is adequate. The licensee.does not intend to change the
' established system at this time.
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(0 pen)
Unresolved Item 313/8507-01:
Fire door (FD) 19 will not stay
shut.
FD 19 was previously identified as not being maintained shut due to air
flow.
Due_to high-energy line break considerations, the door does not
have a latch, but is held shut by a door closer.
In response to this
item, the licensee installed an additional door closer to provide
sufficient force to maintain the door shut.
This corrective action was
inadequace in that the NRC inspectors found the door not fully closed
during a plant tour. The licensee should provide a corrective action that
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will ensure that FD 19 will stay shut as required to provide a fire
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barrier between the south-piping penetration room and the emergency
feedwater pump room.
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3.
Licensee Event Report (LER) Followup (Units 1 and 2)
Through direct observation, discussions with licensee personnel, and
. review of records,'the following event reports were reviewed to determine
that reportability' requirements were fulfilled, immediate
corrective action was accomplished, and corrective action to prevent
recurrence has been accomplished in accordance with Technical
Specifications.
Unit 1
84-006-00
Potential degradation'of reactor building liner plate
l85-004-00
Reactor trip caused by spurious closure of reheat stop
and intercept valves
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85-005-00
Reactor trip caused by spurious anticipatory trip signal
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Unit 2
83-049-01T-0
Failure to meet electrical surveillance requirements
84-003-00
Reactor trip and main steam isolation system actuation
84-005-00
Nuclear instrument failure
85-001-00
Inadvertent recirculation actuation signal during testing
Unit 1 LER 84-006 reported a design error in the supports for the hydrogen
purge system which could have degraded the reactor building liner plate
following a loss of coolant accident.
The licensee corrected this error
and modified the affected hydrogen purge system supports with design
change package 84-1066 in December 1984.
Unit 1 LER 85-005 reported a reactor trip which was caused by personnel
error and incomplete procedures.
Appropriate procedure revisions and
training have been completed.
Unit 2 LER 83-049 resulted from a detailed Technical Specification
surveillance testing review performed by the licensee following a
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violation involving inadequate review of station battery surveillance
testing. The review identified instances in 1981 and 1982 in which
surveillance testing of containment penetration overcurrent prctection
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devices and undervoltage protection devices had not been properly
performed o, evaluated.
The necessary procedure revisions have been
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completed.
Unit 2 LER 84-003 reported a reactor trip from low power caused by low
steam generator. pressure. .The cause of the low steam generator pressure
was operator-error, complicated by a leaking boric acid. flow control
valve.
The valve was repaired and operator training was conducted.
Unit 2 LER 85-001 reported an' inadvertent recirculation actuation which
occurred during plant protection system logic matrix actuation testing at
power. 'Approximately 50,000 gallons of borated water drained from the
refueling water tank to the containment sump during the event.
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testing of logic matrix relays did not identify a specific cause of the
spurious actuation.
Inspection of the sump after processing the borated
water found one of the sump doors open.
Procedure changes have been
performed to require verification that. sump doors are shut and locked
during the containment closecut inspection at the end of an outage.
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No violatfor.s or deviations were identified.
4.
Operational Safety Verification (Units 1 and 2)
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The NRC inspectors observed control room operations, reviewed applicable
logs, and conducted discussions with control room operators.
The
inspectors verified the operability of selected emergency systems,
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reviewed tagout records, verified proper return to service of affected
components, and ensured that maintenance requests had been initiated for
equipment in need of maintenance.
The inspectors made spot checks to
verify that the physical security plan was being implemented in accordance
with the station security plan.
The inspectors verified implementation of
radiation protection controls during observation of plant activities.
The NRC inspectors toured accessible areas of the units including the Unit
1 reactor building to observe plant equipment conditions, including
potential fire hazards, fluid leaks, and excessive vibration.
The
inspectors also observed plant housekeeping and cleanliness conditions
during the tour. The spent fuel pool area was noted as needing additional
housekeeping attention.
The NRC inspectors walked down the accessible portions of the Unit 1
and Unit 2 fire water system. The walkdown was performed using
Procedure 1104.32 and Drawings M-209, 219, and 2219.
During the walkdown,
the NRC inspectors noted the discrepancies listed below:
Twenty-four valves on Unit 1 and eighty-two valves on Unit 2 are
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installed in the plant and shown on the piping and instrumentation
drawing (P&ID), but the valves are not listed on the normal fire
water system valve alignment sheets provided as Attachment A to
Procedure 1104.32.
Even though these valves are missing from the
lineup sheets, no instances were noted by the NRC inspectors where
the fire water system was inoperable.
The licensee performs a
monthly surveillance of the position of fire water valves in the flow
path as required by Technical Specifications.
It appears that this
is the reasoa the system was.not found to be inoperable, even though
a large number of valves were missing from the lineup sheets.
The licensee has agreed to include the missing valves on the normal
valve alignment sheets.
Unit 1 Technical Specification 4.20.1.b requires that at least once
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per 31 days, each valve in the fire water flow path, that is not
locked or sealed, be verified to be in its correct position.
The
licensee has issued Procedure 1104.32, Supplements IIIa and IIIc to
implement this Technical Specification requirement for Unit 1.
The
NRC inspectors noted that fire water valves FS-121 and FS-122,
isolation _ valves for the emergency diesel generator fuel oil tank
vault, were not included in Supplements IIIa or IIIc.
The NRC
inspectors found the valves open, so the system was not considered
inoperable. However, the licensee failure to verify these unsealed
valves are in their correct position every 31 days is an apparent
violation of the Unit 1 Technical Specifications.
(313/8522-01)
During tours of the plant areas, the NRC. inspectors noted that three fire
-doors (FD) were not fully closed.
FD 19 is discussed in paragraph 2 of
.this report.
The other doors were FD 210 for the Unit 2 lower south
piping penetration room and FD 186 for the Unit 2 emergency diesel fuel
oil storage tank vault.
The NRC inspectors shut the doors by hand since
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the automatic door closers were not powerful enough to overcome the air
flow through the door openings.
In NRC Inspection Report 50-368/85-13, a violation was identified
involving failure to maintain fire doors shut.
The licensee's response to
this violation indicated that a memo would be issued to all managers and
supervisors to notify all personnel in their groups of this problem and to
make all personnel aware that they should ensure fire doors are shut when
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they pass'through a door.
It appears that this corrective action did not
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have,the desired effect in that the NRC inspectors found FD 210 and FD 186
not shut and latched.
The licensee's_ failure to maintain FD 186 and 210 shut is an apparent
violation of Technical Specification 3.7.11.
(368/8523-01)
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5.
Monthly Surveillance Observation (Units 1 and 2)
The NRC inspector. observed the following Technical Specification require'd
surveillance testing:
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Unit 2 emergency diesel generator monthly test (Procedure 2104.36)
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Unit 2 boric acid heat tracing check (Procedure 2104.03, Appendix A)
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Unit 1 emergency diesel generator monthly test (Procedure 1104.36)
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The NRC inspector verified that testing was performed in accordance with
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. adequate procedures, test instrumentation was calibrated, limiting
conditions for operation were met, removal and restoration of the affected
components were accomplished, test results conformed with Technical
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Specifications and procedure requirements, test results were reviewed by
personnel other than the individual directing the test, and any
deficiencies identified during the_ testing were properly reviewed and
resolved by appropriate management personnel.
The NRC inspector also witnessed portions of the following test
activities:
Unit 2 boric acid pump monthly test (Procedure 2104.03)
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Unit 2 channel C plant protection system test (Procedure 2304.40)
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Unit 1 engineered safeguards actuation system digital subsystem test
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(Procedure 1304.45)
-Unit 2 charging pump 2P-368 monthly test (Procedure 2104.02)
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Unit I reactor building _ cooling units service water flow test
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(Procedure 1104.33, Supplement 7)
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The NRC inspector observed operation of the Unit 1 postaccident sampling
system on August 2, 1985.
A gamma isotopic -analysis was performed on a
reactor coolant system letdown sample and on a reactor building air
sample.
The-in-line dissolved hydrogen analyzer appeared to function
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properly, but the in-line dissolved oxygen analyzer was inoperable.
No violations or deviations were identified.
6.
Monthly Maintenance Observation (Units 1 and 2)
Station maintenance activities of safety-related systems and components
~ listed below were observed / reviewed to ascertain that they were conducted
in accordance with approved procedures, Regulatory Guides, and industry
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codes or' standards; and in conformance with Technical Specifications.
The following items were considered during this review:
the limiting
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conditions for operation were met while components or systems were removed
from service; approvals were obtained prior to initiating the work;
activities were accomplished using approved procedures and were inspected
as applicable; functional testing and/or calibrations were performed prior
to returning components or systems to service; quality control records
were maintained; activities were accomplished by qualified personnel;
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parts and materials used were properly certified; radiological controls
were implemented; and fire prevention controls were implemented.
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Job orders (J0) were reviewed to determine status of outstanding jobs and
to ensure that priority is assigned to safety-related equipment
maintenance which may affect system performance.
The following maintenance activities were observed / reviewed:
. Unit 2 plant protective system voltage matrix test
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(JO 700531, Procedure 2408.25)
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Change oil in Unit 1 diesel generator starting air compressor
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C4B1 (JO 700184)
Remove Unit 1 steam generator secondary handhole cover
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(JO 701073)
Adjust pressure in Unit 2 charging pump 2P-36B accumulators
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(JO 523266)
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No violations or deviations-were identified.
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7.
- Followup of'Onsite Event (Unit 2)
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On Ju19 30, August 5, and August 13, 1985, Unit 2 experienced reactor
trins.
Following each of these trips, one or both of emergency feedwater
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(EFW). system valves 2CV-1037-1 and 2CV-1039-2 failed to shut on demand
from the control room.
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Valves 2CV-1037-1 and 2CV-1039-2 are in the EFW flow path from the
steam-driven EFW pump to the 'A'
and 'B' steam generators.
The valves in
the redundant EFW flow path from the motor-driven EFW pump to the steam
generators functioned normally.
Valves 2CV-1026-2 and 2CV-1076-2 remained
operable, providing steam generator isolation capability.
When the valves failed to operate normally after the trip on July 30, a
review by the licensee indicated that the closing coils in the valves were
burnt out.
The coils were replaced and testing was performed or, both
valves to verify the valves operated properly.
No problems were noted.
When 2CV-1039-2 failed to operate normally after the trip on August 5, the
licensee investigated the cause of the failure.
The licensee discovered
that an internal breaker _ jumper was placing a 125 VDC signal from an
external annunciator circuit on the closing coil.
The jumper was removed
and the coil was replaced.
Testing was performed on the valve and it
operated satisfactorily.
After a reactor trip on August 13, 2CV-1039-2 again failed to operate
properly.
This time an electrical engineer performed a wire check of
the internal breaker wiring using the vendor print as a reference.
During
this review, the engineer found that the contactor was wired to the wrong
set of auxiliary contacts and that this wiring was not shown on the vendor
print.
The licensee rewired the closing coils for both valves and
' replaced auxiliary contacts.and the closing coil for 2CV-1039-2.
The
valves were tested and performed satisfactorily.
On August 16, following another reactor trip, both valves functioned
no rmally.
The licensee established a program to cycle both valves daily
to establish a baseline of operational assuredness.
No additional
problems were noted after the daily cycling program was initiated, and the
cycling frequency was reduced to twice weekly on August 26, 1985.
The NRC inspectors reviewed the procurement documentation associated with
th? valve breakers.
The breakers are 125 VDC, full-voltage reversing
combination starters with circuit breakers supplied by Gould,
Incorporated.
The purchase order (PO) issued by AP&L required that a
certificate of conformance be supplied by Gould that certified the
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breakers met all conditions and specifications of the AP&L P0.
Gould
supplied a certificate of conformance and a copy of the report of test and
inspection performed in the factory.
The documents state that the breaker
met P0 requirements and tested satisfactorily in the factory.
In addition, Gould supplied a drawing of the internal wiring of the
breaker.
The NRC inspector reviewed the vendor-supplied drawing, the
breaker installation, and discussed the internal wiring problems with a
licensee electrical engineer.
Based on these' reviews, it appears that the
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problems encountered with the valve breakers were caused by the vendor
providing an inadequate drawing of the internal breaker wiring and by the
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miswiring of the auxiliary contacts either at the factory or during
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installation. .This matter has been sent to the NRC's Vendor Program
Branch for followup at the vendor's facility.
.No violations or deviations were identified.
8.
Design Change Control (Units 1 and 2)
The NRC inspector. performed a review of the design change program.
This
review was performed to verify that design changes were made in accordance
with Technical Specifications, industry guides and standards,10 CFR, and
plant . procedures.
The design change packages (DCPs) listed below were reviewed by the
inspector:
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Unit 1
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81-1016
Addition of Isolation Valves for Emergency Hatch for
use During LLRT
81-1023
Modification of Decay Heat Unit Coolers
VUC-1A, IB, IC, and ID
81-1080
Emergency Diesel Generator Field Winding Shutdown
Shorting
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82-1077
Y-11 Inverter Seismic Analysis for Transformer
Replacement
82-1088
Replacement of the RCP Seal Pressure Sensing Lines
82-1098
Modification of RCP Seal Water Return Valves
83-1014
Addition of Thermal Insulation to CV-2617 and CV-2667
84-1066
Modification of Hydrogen Purge System Pipe Supports
Unit 2
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80-2086
Spent Fuel Storage Rack Modifications
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80-2115
Addition of Manual Isolation Valves Upstream of
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2SV-1585-2 and 2SV-1589-2
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81-2057
Addition of Mechanical Seals for EFW Pumps
82-2075
Upgrade Refueling Machine Hoist
82-2160
Installation of DC Breakers for Valves 2CV-1037-1
and 2CV-1039-2
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83-2009
Addition of Thermal Insulatio'n to 2CV-1000-1
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and 2CV-1050-2
83-20451 ESFh5 Start Alarm Modifications on the Service
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Water Pumps
83-2084
Replacement of Existing Handswitches for
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-Containment Purge Valves
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In addition to the above. listed DCPs, the NRC inspector also reviewed a
sampling of non-Q DCPs to verify that the work performed by the DCP was
correctly classified.
No instances.were noted where improper
' classification was used.
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The' safety-related DCPs listed above were reviewed for the following, as
appropriate:
Review and approval was in accordance with the requirements of
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10 CFR Part 50.59 and the reviews were technically adequate.
Review and approval was in accordance-with Technical Specification,
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quality assurance (QA), and quality control (QC) requirements.
Postmodification test records were reviewed by the licensee and an
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evaluation of the test results was performed.
Acceptance criteria was provided and test results met the established
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criteria.
-Test deviations were resolved and retesting performed, if required.
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Appropriate changes were made to operating and surveillance
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procedures.
Drawings were revised to reflect the DCP changes.
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Field change notices received the proper reviews and approvals.
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QA and/or QC reviews of the completed DCPs had been performed.
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The NRC inspector also reviewed plant procedures to verify that procedures
properly implemented the requirements of the Technical Specifications,10
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- CFR, industry codes and standards, and the Quality Assurance
Manual-Operations.
No problems were noted in this area.
The inspector
noted that a large backlog of DCPs awaiting closecut'has developed.
Closeout activities that need to be finished include updating of drawings
other than piping and instrumentation drawings, review of DCP for
completeness, and verification of proper completion of each DCP
requirement.
The licensee stated that a consultant has been hired to
assist in catching up on the backlog of DCP closeouts.
The licensee
- intends to eliminate the backlog of DCPs by January 1986.
The licensee
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should take whatever steps are necessary after the backlog is eliminated
to keep the backlog to a minimum.
The inspector also noted that a large number of field change notices (FCN)
were issued for many of the DCPs reviewed.
The large number of FCNs tend
to make installation of DCPr unnecessarily difficult for the person in the
field installing or testing the design change. With this added level of
difficulty in understanding the requirements, the probability of an
incorrect installation increases. .The large number of FCNs is due in part
to many DCPs being prepared by engineers in the Little Rock general
offices who do not routinely visit the site to verify that the proposed
modifications can be installed as intended by the design.
No violations or deviations have been noted tnus far.
This inspection
will be continued during.the next inspection period.
9.
Low Temperature Overpressurization Protection (Unit 1)
On August 23, 1985, the NRC inspectcr noted that valve CV-1000, the pilot
operated relief valve (PORV) isolation valve, on Unit 1 was shut.
The
unit was in cold shutdown with a steam bubble in the pressurizer, and the
PORV controls were set for the reduced setpoint of 525 psig for low
temperature overpressurization protection (LTOP).
For automatic LTOP,
CV-1000 must'be open, although neither the Technical Specifications nor
plant procedures required this valve to be open during cold shutdown.
Upon notification, the licensee opened the valve and initiated a change to
Procedure 1102.10, " Plant Shutdown and Cooldown," to require opening
CV-1000 during a cooldown when reactor coolant system (RCS) pressure is
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less.than or equal tn 475 psig and RCS temperature is between 350 degrees
Fahrenheit and 280 degrees Fahrenheit.
The licensee also initiated a
procedure change to require checking the operability of the LTOP
annunciator alarm during cooldown.
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The NRC inspector discussed this issue with the NRC Office of Nuclear
' Reactor Regulation (NRR) project manager for ANO-1.
The project manager
stated that LTOP operability on plants with a single PGRV was a generic
concern which is being addressed by NRR.
This is an open item pending NRR
resolution'of LTOP operability requirements for ANO-1. (0 pen Item-
313/8522-02)
No violations or deviations were identified.
10.
Operator Training on the Davis Besse Transient of June 9,1985 (Unit 1)
The.NRC' inspector attended a training seminar for Unit 1 operations
department personnel on August 26, 1985.
The primary ~ subject of this
seminar was the Davis Besse transient of June 1985.
The trainer and
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operators discussed the initial conditions, sequence of events and
operator actions during the _ loss of all feedwater transient.
Emphasis was
placed on comparison of plant equipment at Davis Besse and ANO-1 and
discussing how equipment and operators would respond to a similar set of
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circumstances at ANO-1.
This was the second training session on the Davis
Besse transient conducted for ANO-1 operators.
The first session was held
shortly after the event and was based on preliminary information available
at that time.
The second session was based on information in NUREG-1154.
11.
Nonlicensed Staff Training (Units 1 and 2)
The NRC inspector reviewed training administrative procedures and
discussed nonlicensed staff training with various licensee personnel.
This inspection effort will continue during the next inspection period.
No violations or deviations were identified.
12.
Exit Interview
The NRC inspector met with Mr. J. M. Levine (ANO General Manager) and
other members of the AP&L staff at the end of this inspection.
At this
meeting, the inspector summarized the scope of the inspection and the
findings.
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