ML20133J206
| ML20133J206 | |
| Person / Time | |
|---|---|
| Site: | Arkansas Nuclear  |
| Issue date: | 01/14/1997 |
| From: | Dyer J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | Hutchinson C ENTERGY OPERATIONS, INC. |
| References | |
| NUDOCS 9701170438 | |
| Download: ML20133J206 (4) | |
See also: IR 05000313/1996006
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AR LINGToN, T E X AS 76011-8064
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C. Randy Hutchinson, Vice President
Operations
Arkansas Nuclear One
Entergy Operations, Inc.
1448 S.R. 333
Russellville, Arkansas 72801-0967
SU8 JECT: NRC INSPECTION REPORT 50-313/96-06:50-368/96-06
Thank you for your letter of December 12,1996,in response to our letter and '
Notice of Violation dated November 12,1996. We have reviewed your reply and find it
responsive to the concerns raised in our Notice of Violation. We will review the
implementation of your corrective actions during a future inspection to determine that full
compliance has been achieved and will be maintained.
Sincerely,
C
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J.
. Dyer, Director
Division of Reactor Projects
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Docket Nos.: 50-313
50-368
License Nos.: DPR-51
NPF-6
cc:
Executive Vice President
& Chief Operating Officer
Entergy Operations, Inc.
P.O. Box 31995
Jackson, Mississippi 39286-1995
Vice President
Operations Support
Entergy Operations, Inc.
P.O. Box 31995
Jackson, Mississippi 39286
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9701170438 970114
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ADOCK 05000313
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Entergy Operations, Inc.
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Manager, Washington Nuclear Operations
ABB Combustion Engineering Nuclear
Power
12300 Twinbrook Parkway, Suite 330
Rockville, Maryland 20852
County Judge of Pope County
Pope County Courthouse
Russellville, Arkansas 72801
Winston & Strawn
1400 L Street, N.W.
Washington, D.C. 20005-3502
Bernard Bevill, Acting Director
Division of Radiation Control and
Emergency Management
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4815 West Markham Street, Slot 30
Little Rock, Arkansas 72205-3867
Manager
Rockville Nuclear Licensing
Framatone Technologies
1700 Rockville Pike, Suite 525
Rockville, Maryland 20852
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Entergy Operations, Inc.
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Project Engineer (DRP/C)
DRS-PSB
Branch Chief (DRP\\TSS)
Leah Tremper (OC/LFDCB, MS: TWFN 9E10)
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DOCUMENT NAME: R:\\_ANO\\AN606AK.KMK
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"E" = Copy with enclosures "N" = No copy
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Entsrgy oporttions,Inc.
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RusuMic. AR 72301
To 501 B58-5000
December 12,1996
OCAN129602
U. S. Nuclear Regulatory Commission
Document Control Desk
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Mail Station P1-137
M1'
Washington, DC 20555
Subject:
Arkansas Nuclear One - Units 1 and 2
Docket Nos. 50-313 and 50-368
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Response To Inspection Report
50-313/% -06;50-368/96-06
Gentlemen:
Pursuant to the provisions of 10CFR2.201, attached is the response to the notice of violations
identified during the inspection activities associated with a Reactor Coolant System level
perturbation and a hydrogen burn during welding activities.
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Should you have any questions or comments, please call me at 501-858-4601.
Very truly yours,
W4
Dwight C. Mims
Director, Licensing
DCM/ajs
Attachments
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U. S. NRC
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December 12,1996
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cc:
Mr. Leonard J. Callan
Regional Administrator
U. S. Nuclear Regulatory Commission
RegionIV
611 Ryan Plaza Drive, Suite 400
Arlington, TX 76011-8064
NRC Senior Resident Inspector
Arkansas Nuclear One
1448 S. R. 333
Russellville, AR72801
Mr. George Kalman
NRR Project Manager Region IV/ANO-1 & 2
U. S. Nuclear Regulatory Commission
NRR Mail Stop 13-H-3
One White Flint North
11555 Rockville Pike
Rockville, MD 20852
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Attachment to
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During an NRC inspection conducted on August 18 through September 28,1996, two
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violations of NRC requirements were identi6ed.
In accordance with the "Gerwal
Statement of Policy and Procedure for NRC Enforcement Actions," NUREG-1600, the
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violations are listed below:
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A. Technical Specification 6.8.1.a states, in past, that written procedures be established,
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implemented, and maintained covering the applicable procedures reconunended in
Appendix A of Regulatory Guide 1.33, November 1972.
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Paragraph H.2.a.1 of Regulatory Guide 1.33, November 1972, states that speci6c
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procedures should be written for containment leak rate tests. Procedure 1305.018,
Revision 9, " Local Leak Rate Testing - C," is the procedure for testing containment
penetrations. Step 10.2.5 of Procedure 1305.018 states to " vent and drain the system
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inside the local leak rate test (LLRT) boundaries in accordance with radiological work
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permit requirements."
Penetration 14 is the letdown line penetration through
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containment and the LLRT boundary is between the first outside valve CV-1221 and
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the two parallel inside valves CV-1214 and CV-1216.
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Contrary to the above, Penetration 14 was not vented and drained within the LLRT
boundaries, but wu vented and drained into the Reactor Coolant System, which
resulted in the introduction of air into the Reactor Coolant System during reduced
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inventory and caused a level indication change.
This is a Severity Level IV violation (Supplement I) (Violation 50-313/9606-01).
B. Unit 1 Technical Specification 6.8.1.f states, in part, that written procedures shall be
established, implemented, and maintained covering fire ' protection program
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implementation.
Appendix 9A.4 of the Unit 1 Safety Analysis Report describes that the ANO Fire
Protection Program is controlled and maintained by various plant procedures that
include, but are not limited to, maintenance procedures for control ofignition sources.
Step 5.1.1 of Procedure 1003.006, Revision 3, " Control of Ignition Sources," states
that it is the responsibility of the cognizant supervisor for maintenance activities to
determine the fire and explosion precautions necessary for the performance of safe
work.
Contrary to the above, on September 21,1996, the licensee did not determine the fire
and explosion precautions necessary for safe work in that welding was performed on
a pressurizer relief valve tailpipe without having sampled and purged the line of
hydrogen. As a result, a hydrogen burn occurred.
This is a Severity Level IV violation (Supplement I) (Violation 50-313/9606-02).
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Response to Notice Of Violation 313/9606-01
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(1) Beason for the violation:
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Following a hot spot flush of the letdown coolers on September 18,19% Unit 1
operations personnel were draining the letdown line in preparation for a local leak rate
During this evolution, Unit I was in reduced inventory with Reactor Coolant
test.
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System (RCS) level steady at 371.5 feet and about 80% complete with the draining of
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the RCS cold legs. The core side of the RCS was no longer hydraulically coupled to
the cold legs and, therefore, no longer hydraulically coupled to the reactor building
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drain header. The same drain was being used to remove water from the primary side
of the Once Through Steam Generator (OTSG) and to remove water used in
performing
the
previous
hot
spot
flush
of
the
letdown
coolers.
(See attached drawing 1)
In order to ensure complete venting and draining of the letdown penetration,
pressurized service air was used as a motive force. During the evolution, control room
operators observed an unexpected RCS level increase of approximately 0.7 feet.
When the operations personnel draining the letdown line became aware of the RCS
level increase, they immediately secured service air and informed the control room.
The RCS level rise stopped when the service air was secured and quickly returned to
its previous value. The elapsed time from the start of the RCS level rise to RCS level
stable at its previous value of 371.5 feet was approximately ten minutes.
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Air introduced into the cold leg from the letdown line collected in the air volume
between the top of the water level and the Reactor Coolant Pump (RCP) seal. Water
in the cold leg between the RCP and the reactor vessel acted as a seal between the
RCP and the head vents. This allowed for venting of the introduced air to occur only
from the RCP seal vent. The volume of air tlat this vent path could pass was
insufficient in comparison to the amount of air bdng introduced inte the system;
therefore, the buildup of air pressure below the RCP seal vent displaced a small
amount of water from the cold leg into the reactor vessel. This displaced water caused
the reactor vessel level indication to increase approximately 0.7 feet. (See attached
drawing 2)
The cause of this event was that an adequate assessment of the vent capabilities of the
RCS cold legs in association with the high volumes of service air being introduced into
the RCS via the letdown system was not performed. Additionally, the lack of a
procedure for draining systems connected to the RCS contributed to this event.
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(2) Corrective steos that have been taken and the results achieved:
Service air was secured immediately upon identification ofit as the cause of the RCS
levelincrease.
Unit 1 Operations Manager briefed operations personnel on the details and causes of
the event during shiA turnover meetings following the occurr'ence.
(3) Corrective steos that will be taken to avoid further violations:
The Unit 1 and Unit 2 Operations Managers will discuss this event with Operations
Department personnel prior to the next refueling outages which are currently
scheduled for the Spring of 1998 for Unit 1 and the Spring of 1997 for Unit 2.
Ensuring proper and adequate venting prior to manipulating RCS level and utilizing
caution when performing an evolution on an RCS interconnected system during
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draindown conditions will be stressed.
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A procedure for draining systems that are or may be interconnected to the RCS will be
developed by February 28,1998.
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(4) Date when full comoliance will be achieved:
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Full compliance was achieved on September 18,1996 when the introduction of service
air was secured and the RCS level returned to its previous value.
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Att:chment to
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Response to Notice Of Violation 313/9606-02
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(1) R**=an for the violation:
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On September 21,1996 while welding a cap on a recently cut one-inch pipe, a loud
noise was heard by personnel working in the Unit 1 Reactor Building. The noise is
believed to have been caused by a small hydrogen burn in the Pressurizer Code Safety
Valve ten-inch discharge line to the Quench Tank. The one-inch line is connected to
the top center of a horizontal run of the ten-inch discharge piping making it a potential
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high point location. It is believed that a small amount of hydrogen, came out of
solution from the primary coolant in the Quench Tank, and migrated to the or.e-inch
capped line.
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The presence of hydrogen gas was considered during the pre-job brief. However, the
decision was made not to sample for combustible gasses prior to welding because it
was determined that hydrogen gas should not collect since the RCS had been
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previously degassed, purged, vented, and was open to the atmosphere. It was also
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believed that sampling for combustibles after cutting the pipe was unnecessary since
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hydrogen, if present, would be vented when the pipe was cut.
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While completing the Ignition Source Permit, the personnel involved with this job
failed to identify that the work being performed involved welding on enclosed
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equipment. Examples of enclosed equipment, as identified by the Ignition Source
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Permit, included tanks, containers, ducts, dust collectors, etc. Because piping was not
included in the list of examples it was not considered enclosed equipment. Moreover,
this section of the form was viewed as being applicable only when work was
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performed from within enclosed equipment.
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The cause of this event was welding operations unknowingly conducted in the
presence of a combustible hydrogen level. Knowledge of the hydrogen level present in
the tank and the line prior to the start of welding is necessary to determine the exact
origin of the hydrogen. It is believed that hydrogen came out of solution in the
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primary coolant present in the Quench Tank and concentrated at the newly capped
A combustible gas sample was not obtained from the Quench Tank prior to
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vent.
performing the welding.
However, had the personnel involved with this job
recognized that hydrogen may continue to be expelled following depressurization and
degassification of the RCS, the need for purging of the Quench Tank and associated
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piping would have been more apparent.
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(2) Corrective steos that have been taken and the results achieved:
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Work was stopped in the area and a walkdown was conducted to verify conditions
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were safe.
The Quench Tank and associated piping were purged with nitrogen and combustible
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gas samples were obtained Sunples obtained during the purge indicated hydrogen
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levels as high as 3.6%.
Upon completion of purging the hydrogen level was
insignificant.
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The incident was discussed with supervisory personnel at shift outage meetings.
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Supervisors of personnel responsible for welding were directed to more closely
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scrutinize welding packages for proper identification of work conditions.
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Work groups involved in the planning, conduct, approval, supervision, or monitoring
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of activities involving spark / heat generating evolutions were alerted to the hazards
and potential generation of hydrogen in systems associated with the Reactor Coolant
System.
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Walkdowns of the Quench Tank and affected piping were performed. The rupture
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disk on the tank was examined and found intact. It was concluded by the evidence of
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this event that the design limits for the Quench Tank were :mt exceeded and that the
tank's ability to perform its intended function was unaffected by this event.
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A walkdown of the pressurizer code safety valve discharge piping, supports, guides,
and snubbers was also performed. The results of this evaluation indicated no damage
resulted from this event.
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(3) Corrective steos that will be taken to avoid further violatigg
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A warning statement will be added to the Ignition Source Permit (Form 1003.006A) to
identify that any spark / heat generating work on any system associated with the RCS or
any system where potential for combustible gasses is present requires special attention.
Additionally, piping will be identified as an example of enclosed equipment. This
procedure revision will be completed by January 15,1997.
The cause and lessons teamed from this event will be reviewed in pre-outage briefings
prior to the start of the next refueling outages for both Unit I and Unit 2 which are
currently scheduled for the Spr!ng cf 1998 and 1997, respectively.
The cause and lessons learned fron, this event will be incorporated into contract
welder training presented prior to each refueling outage by April 1,1997.
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The cause and lessons learned from this event will be reviewed with maintenance
personnel qualified to perform welding at ANO by April 1,1997.
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(4) Date when full comoliance will be achieved:
Full compliance was achieved on September 22,1996 when the Quench Tank and
associated piping were purged, vented, and sampled.
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Drain down in progress; water level stable in
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reactor core; cold leg level going down; cold
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leg drain water and letdown system flush
water going to reactor building drain header.
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Drah Header
Drawing 2
Drain down in progress; air assisted draining
ofletdown system in progress; air goes into
cold leg RCP area; RCP seal vent can not
vent all the air, and pressure builds up in
this area; water level rises in reactor core to
372.2'.
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