ML20137Q551
| ML20137Q551 | |
| Person / Time | |
|---|---|
| Site: | LaSalle  |
| Issue date: | 04/07/1997 |
| From: | Grant G NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | Subalusky W COMMONWEALTH EDISON CO. |
| References | |
| EA-96-392, EA-96-393, NUDOCS 9704110022 | |
| Download: ML20137Q551 (2) | |
See also: IR 05000373/1996011
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April 7, 1997
EA 96-392-
EA 96-393-
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' Mr. W. T. Subalusky, Jr.
Site Vice Prasident_
LaSalle County. Station-
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Commonwealth Edison Company
2601 North 21st Road
Marseilles, IL 61341
SUBJECT:
SYSTEM OPERATIONAL PERFORMANCE INSPECTION (SOPl! REPORT
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50-373/374/96011(DRS) AND NOTICE OF VIOLA. TION
. Dear Mr. Subalusky:
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This will acknowledge receipt of your December 20,1996 letter and your
February ~24,1997 letter in response to our November 15,1996 letter transmitting a
Notice of Violation associated with inspection Report 50-373/374/96011(DRS). We have
reviewed your corrective actions and have no further questions at this time. These
corrective actions will be examined during future inspections.
Sincerely,
l
/s/ G. E. Grant
Geoffrey E. Grant, Director
Division of Reactor Safety
Docket Nos. 50-373, 50-374
Enclosures:
1. Ltr 12/20/96 W. T. Subalusky, Jr.
Comed, to US NRC w/enci
2. Ltr 2/24/97 W. T. Subalusky, Jr.
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Comed, to US NRC w/enci
' See Attached Distribution
DOCUMENT NAME: G:\\DRS\\LAS96011.RS2
TD receive a copy of this document Indicate in the box: "C" = Copy w/o attachment /onckgre
"E" = Copy with attachment / enclosure
"N" = No copy
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April 7, 1997
W. T. Subalusky :
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cc w/o encts:
T. J. Maiman, Senior Vice President,
Nuclear Operations Division
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D. A. Sager, Vice President,
Generation Support
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H. W. Keiser, Chief Nuclear
Operating Officer
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F. Dacimo, Plant General Manager
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P. Barnes, Regulatory Assurance
Supervisor
1. Johnson, Acting Nuclear
Regulatory Services Manager
Document Control Desk - Licensing
cc w/encls:
Richard Hubbard
Nathan Schlon, Economist,
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Office of the Attorney General
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State Liaison Officer
Chairman, Illinois Commerce Commission
Distribution:
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SRis, LaSalle, Dresden,
Rlll Enf. Coordinator w/enct
Docket File w/ encl __J,
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.JE4Lw/onclG
Quad Cities w/enci
TSS w/enci
/LFDCB w/ encl
LPM, NRR w/enci
J. Lieberman, OE w/ encl
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DRP w/ enc!
A. B. Beach, Rlll w/enci
J. Goldberg, OGC w/enci
DRS w/enci
C. D. Pederson, Rlli w/enci
R. Zimmerman, NRR w/enci
Rlli PRR w/ encl
R. A. Capra, NRR w/ encl
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December 20,1996
United States Nuclear Regulatory Commission
Attention: Document Control Desk
Washington, D.C. 20555
Subject:
NRC INSPECTION REPORT NO. 50-373/96011;
50-374/96011 (DRP) AND NOTICE OF VIOLATION
References:
G. E. Grant Letter to W. T. Subalusky, dated
November 15,1996, Transmitting NRC Inspection
Report 373/374-96011
The enclosed attachment contains taSalle County Station's response to the
Notice of Violation, that was transmitted in the Reference letter and four
additional unresolved items.
Attachment 1 to this letter contains the immediate corrective actions taken
as well as long term corrective actions to preclude recurrence of the cited
violations. Attachment 2 provides our response to the unresolved items.
Based on a telephone discussion with Ms. Patricia Lougheed of the
Region lli staff, the due date for the response was extended to
December 20,1996 Additionally, the subject inspection Report identified
four apparent violatim for which a response was requested. Per a
December 13,1996, telephone discussion with Mr. Mark Ring of the Region
lll staff, the due date for the response of these four apparent violations was
extended to January 10,1997.
If there are any questions or comments conceming this letter, please refer
them to me at (815) 357-6761, extension 3600.
Respectfully,
hdd
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W. T. Subalusky
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Site Vice President
LaSalle County Station
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Enclosure
cc:
A. B. Beach, NRC Region lll Administrator
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M. P. Huber, NRC Senior Resident inspector - LaSalle
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D. M. Skay, Project Manager - NRR - LaSalle
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DCD - Licensing (Hardcopy:
Electronic:
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Central File
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ATTACHMENT 1
LaSalle County Generating Station
Response to Notice of Violation
in Inspection Report No. 50 373/96011 (DRS); 50-374/96011 (DRS)
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Violation A (96011-01 &96011-17):
10 CFR Part 50, Appendix B, Criterion lil, " Design Control," requires, in part,
that measures be established to ensure that applicable regulatory
requirements and the design basis are correctly translated into
specifications, drawings, procedures, and instructions. It further requires
that design changes be subject to design controls commensurate to those
applied to the original design and that the changes be approved by the
responsible design organization.
Contrary to the above:
1.
On March 31,1996, for Unit 1 and on May 31,1996, for Unit 2,
the fuel pool emergency makeup pumps were removed from
service in order to be modified by adding a stainless steel weld
overlay to the carbon steel pump casing and this design
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change was not subject to design controls commensurate to
those applied to the original design. Furthermore, the design
change was not approved by the responsible design
organization because it was performed as a maintenance
activity.
2.
As of September 24,1996, the design basis temperature of the
high pressure coolant system was incorrectly translated into
calculations VY. 14, " Unit 1, Division l ECCS Equipmeni
Cooling Water System," Revision 0, ATD-0375,"ECCS Pump
Room Temperature During Shutdown With Area Coolers
Inoperable," Revision 0, and 3C7-089-001, "ECCS Room
Temperature Transient Following LOCA Concurrent With Loss
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of Area Cooler," Revision 1, Revision 0. This was due to a
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1985 design change which modified the suction of the HPCS
system from the condensate storage tank to the suppression
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pool and increased the design basis temperature.
This is a Severity Level IV violation (Supplement 1).
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Response to item 1 (96011-01):
The reason for the violation:
Comed agrees that described repair activities should have been controlled
as a design change.
The FC Emergency Make-up (FCEM) Pumps (Safety Related & ASME Code
Related) were to be disassembled and inspected as part of investigating
high vibration levels. Corrosion internal to the pump was discovered and
necessitated corrective action. It was decided to perform weld repair in
accordance with ASME Section XI. To preclude future corrosion problems it
was decided to overlay the high corrosion areas with stainless steel.
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Engineering issued NDIT No. LS-0300 (Approved on June 5,1996) to
provide the Repair Program. The NDIT states "This work is considered to
be an ASME Section XI repair." However, Engineering failed to recognize
that this action constituted a design change to the pump.
The work was performed for 2 of the 4 pumps,1FC03PA & 2FC03PB, under
Work Requests (WR) 950110761 and 950019472. During the repair,
questions mose as some warpage occurred. The warping necessitated: 1)
machining to ensure that critical dimensions (clearances) were maintained,
and 2) additional welding to ensure that wall thicknesses were maintained.
Additional upgrades (revisions) to NDIT No. LS-0300 were issued to resolve
questions on use of alternate NDE methods, to increase the amount of
acceptable undercutting, to allow welding on the backside of the pump
casing to restore the required wall thickness and to require a hydrostatic test
on the pump casing. Upgrades 1 through 5 were issued (approved between
June 121996 and September 19,1996).
This work was not identified as a design change because it was incorrectly
considered routine maintenance. At the time no Safety Evaluation was
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performed nor was the UFSAR reviewed.
The corrective steps that have been taken and the results achieved:
1.
A 10CFR50.59 Safety Evaluation was performed to address
the weld repairs (On Site Review Number 96-080 approved
September 19,1996). No unreviewed safety question was
identified.
2.
Calculation No. L-000709 was performed which verified that
the as-left conditions of the pump casings comply to ASME
design requirements.
3.
A revision to UFSAR section 9.2.1.2 was prepared (included
with the 10CFR50.59 Safety Evaluation).
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A hydrostatic test on the pump casings was performed which
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verified their structural integrity.
5.
An as-built DCR 960146 was completed to clearly identify the
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weld repairs to the pumps. Vendor Drawings No. DP14450-6
Sheets 1 & 2 now reference NDIT No. LS-300.
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The corrective steps that will be taken to avoid further violations:
Procedure l_AP-1300-1 " Action Request Processing" has been revised to
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provide guidance on when weld repairs should be considered to be design
changes.
The Site Vice President and Station Manager met with the Maintenance
Masters to reinforce the expectation that the Maintenance Masters are
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responsible and accountable.for the work accomplished in their area. To
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that end, Maintenance held a training session for first line supervisors and
work analysts on what constitutes a modification and that a critical review be
made of each work package to ensure that it does not result in an
unauthorized modification. Any questionable work package is returned to
Engineering for disposition.
The date when full compliance will be achieved:
Full compliance was achieved upon completion on the Safety Evaluation
including the UFSAR change (Approved on September 19,1996) and on the
issuance of the changes to the ASME Section XI Repair Program (per NDIT
No. LS-0300, Upgrades 0 - 5, the last upgrade being Approved on
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September 19,1996).
Response to item 2 (96011-17):
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The reason for the violation:
Comed agrees that calculation VY-004, "HPCS Pump Cubicle Cooler
Ventilation System," Revision 0, did not properly address the heat load from
the HPCS Piping. This calculation was performed in 1976. Based on our
review of the calculation, it appears that the preparer failed to consider the
HPCS piping heat load. This is a human performance error.
The corrective steps that have been take.n_,and the results achieved:
1.
Calculation VY-004, " HPCS Pump Cubicle Cooler Ventilation
System," Revision 1, was approved on December 6,1996, to
address the higher cubicle heat load due to the HPCS Piping.
The fan and coolers for the HPCS cubicles have adequate
capacity for the increased heat loads.
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Calculation ATD-0375,"ECCS oump Room Temperature
During Shutdown With Area Covers Inoperable," Revision 0,-
was prepared to determine if the ama coolers can be taken out
of service during an outage without declaring the appropriate
ECCS pumps inoperable. During an outage, the temperature
of the HPCS piping will not be elevated; therefore, the
calculation does not require revision.
3.
Calculation 3C7-089-001, "ECCS Room Temperature
Transient Following LOCA Concurrent With Loss of Area
Cooler," Revision 1 does not require revision to reflect the
increased heat load. This calculation was prepared as input to
a feasibility study to examine ECCS equipment operation
without area cooler operation. The purpose of the study was
to determine if the testing / inspection requirements of Generic Letter 89-13, Service Water Problems Affecting Safety-Related
Equipment," could be waived for the VY Coolers by
demonstrating tiist ECCS operation without area coolers will
al!cw the current qualification status of equipment inside the
ECCS cubicles to be met. The results of the study was that the
VY cooler operation in each ECCS cubicle is necessary.
Therefore, Calculation 3C7-089-001, Revision 1 is not part of
the design basis and has been voided as Revision 2.
The corrective steps that will be taken to avoid further violations:
All ECCS Corner Room heat loading calculations will be reviewed and
revised as nece':,ary. Any calculations that used these heat loads as
design input will be checked and revised as necessary. These calculation
reviews and revisions will be completed prior to restarting Unit 1 and 2 from
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L1F35 and L2R07 respectively.
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Comed is in the process of performing System Functional Performance
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Reviews for systems important to safe and reliable operation, and has
initiated preparation of selected Design Basis Documents (DBD). These
activities include a review of the design basis of the system including
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calculations, UFSAR commitments, and procedures. Any inconsistencies
will be identified and resolved in accoroance with Station Procedures.
The date when full compilance will be achieved:
Full compliance was achieved when Calculation VY-004, " Unit 1, Division 1
ECCS Equipment Cooling Water System," Revision 1, was Approved on
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December 6,1996, to address the higher cubicle heat load due to the HPCS
Piping.
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Violation B (96011-10 & 96011-11):
10 CFR Part 50, Appendix B, Criterion XI, " Test Control," requires, in part,
that tests be performed in accordance with written test procedures which
incorporate the requirements and acceptance limits contained in applicable
design documents.
It further requires that test results be evaluated to ensure that test
requirements have been satisfied.
Contrary to the above:
1.
As of September 24,1996, surveillance test procedure
LTS 200-3, "RHR Heat Exchanger Tubeside DP Test,"
Revision 3, did not contain acceptance limits contained in the
design equipment specification for the residual heat removal
heat exchanger differential pressure.
2.
As of September 24,1996, the results of tests on the 2B
residual heat removal heat exchanger had not been
adequately evaluated in that an increase in differential
pressure within the tubes by approximately 22 percent over a
three year period from 1992 to 1995 was not detected or
evaluated to ensure test requirements had been satisfied.
This is a Severity Level IV violation (Supplement 1).
Response:
The reason for the violation:
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Comed agrees that the review of the subject test results was not timely, and
the results are important to assessing the overall material condition and
functionality of the residual heat removal heat exchanger. The purpose of
LTS-200-3 is to obtain the differential pressure across the tubesides of the
RHR heat exchangers. The test data is used to determine if gross
differences from design conditions exist or if significant trends in differential
pressure had occurred. The specific functional characteristic being
monitored is (1) whether excessive leakage is occurring across the baffle in
the heat exchanger water box and (2) whether major fouling of the tube side
of the heat exchanger has occurred. The heat exchanger design flow rate
and tubeside dP values were included in LTS-200-3 procedure as were the
potential causes for both high and low differential pressure. Resolution of
the discrepancies with test data is the responsibility of the Test Director.
The Test Director did review the data for these purposes, but did not
document his evaluation.
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Procedure LTS-200-3 "RHR Heat Exchanger Tubeside dP Test", is not used
to determine operability of the heat exchanger. Therefore, LTS-200-3 does
not include specific acceptance limits. Procedure LOS-RH-Q1 "RHR(LPCI)
& RHR Service Water Pump & Valve Inservice Test For Tube Side
Operational Conditions 1,2,3,4, and 5" is used to verify RHR heat exchanger
tube side flow for operability. It includes the appropriate acceptance criteria
to compare test results to determine operability.
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The corrective steps that have been taken and the results achieved:
Problem Identification Form 96-5282 was written on the inadequate
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documentation of LTS-200-3 test results. As part of the corrective action
program review, the performance of the heat exchanger has been evaluated
as operable for the current plant condition. The variation in pressure drop
documented in the referenced corrective action program is within
instrumentation accuracy.
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The corrective steps that will be taken to avoid further violations:
Procedure LTS-200-3 has been enhanced to include clear prerequisites, to
state that the results are used for engineering evaluation, and to provide
better direction to the Test Director on the need for timely data evaluation.
Additionally, we will be reviewing all applicable surveillance procedures for
systems important to safe and reliable operation as part of the ongoing
System Functional Performance Review program, and will ensure that these
procedures include adequate prerequisite requirements and acceptance
criteria, or in lieu of acceptance criteria, the specific actions to be taken to
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review the data and whether any immediate actions are required.
The date when full compliance will be achieved:
Full compliance was achieved on December 19,1996, when procedure
LTS 200-3 was revised.
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Violation C (96011-14):
Technical Specification surveillance 4.7.1.3.c requires, at least once per 18
months, determination that sediment deposition anywhere within the lake
screen house behind the bar grill is not greater than one foot in thickness.
Contrary to the above, the following portions of the circulating water bays,
within the lake screen house behind the bar grill, were not determined to
have sediment depositions of no greater than one foot in thickness at least
once in an 18 month period:
1.
Between November 12,1992, and February 9,1996, the
northwest and southeast corners of the three Unit 1 circulating
water bays were not inspected.
2.
Between January 8,1992, and February 28,1996, the
northwest and southeast corners of the Unit 2A circulating
water bay were not inspected.
3.
Between December 6,1991, and February 28,1996, the
northwest and southeast corners of the Unit 2B circulating
water bay were not inspected.
4.
Between February 18,1992, and March 15,1995, the
northeast and southwest corners of the Unit 2C circulating
water bay were not inspected.
5.
Between September 27,1993, and February 28,1996, the
northwest and southeast corners of the Unit 2C circulating
water bay were not inspected.
This is a Severity Level IV violation (Supplement I).
Response:
The reason for the violation:
LaSalle acknowledges that the Technical Specification surveillance 4.7.1.3.c
was implemented such that sediment deposition was not determined
anywhere within the lake screen house behind the bar grill at least once in
an 18 month period. Tech Spec 3.7.1.3 surveillance requirement 4.7.1.3.c is
performed by LTS-1000-4, CSCS Pond Surveillance. The surveillance
procedure had required inspecting only half of each of the Circulating Water
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(CW) Pump inlet bays (suction bays) during each 18 month surveillance
interval. The cause of this inadequate surveillance was human error in
preparation and review of the detailed implementing procedure.
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The corrective stcos that have been taken and the results achieved:
All four quadrants of the Unit 1 CW pump inlet bay were inspected during
L1R07 (February 1996) and found to be satisfactory.
All four quadrants of the Unit 2 CW pump inlet bay were inspected on
August 26,1996, and found to be satisfactory.
Procedure LTS-1000-4 was revised to require inspection of all four
quadrants of a CW pump inlet bay.
The corrective steps that will be taken to avoid further violations:
LaSalle is pursing the transition to Improved Technical Specification (ITS)
and expect to implement during the Spring of 1998 Preparations for
implementation will be underway during 1997. We , vill expand the scope of
ITS implementation to include a verification that the associated surveillance
procedures satisfy the literal wording of the proposed Technical
Specification Surveillance Requirements. This will be accomplished by
June 30,1997.
The date when full compliance will be achieved:
Full compliance was achieved on August 26,1996 with the completion of the
Unit 2 CW pump inlet bay inspections.
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Violation D (96011-13):
10 CFR Part 50, Appendix B, Criterion V, " Instructions, Procedures, and
Drawings," requires, in part, that activities affecting quality be performed
using documented instructions or procedures of a type appropriate to the
circumstances.
Commonwealth Edison Quality Assurance Manual, Revision 65a, dated
April 17,1995, Section 5, " Instructions, Procedures, and Drawings,"
requires, in part, that activities governed by the quality assurance program
be performed using documented instructions, procedures, and drawings
appropriate for the activity.
Contrary to the above, in February 1996, the licensee first leveled the
sedimentation sui that it would comply with technical specifications and
then removed the sediment from the Unit 1 circulating water bays without
any documented instructions or procedures.
This is a Severity Level IV violation.
Response.
The reason for the violation:
Comed agrees that removal of the subject sedimentation was not
adequately controlled by formal documentation.
The Unit 1 Circulating Water (CW) traveling screen repairs were started
the week of February 5,1996 by Scott Diving Services. The same week the
surveillance of the sediment level of Unit 1 CW pump bays to satisfy the
requirements of LTS-1000-4 was also performed. The results were
unsatisfactory and a Limiting Condition for Operation (LCO) was entered for
Unit 2 (Unit 1 was in a defueled status). On February 9, a redistribution of
the sediment was made by the divers and the surveillance was completed as
satisfactory. An Action Request (AR) was prepared by the System
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Engineer to remove the sedimentation prior to returning to service the Unit 1
CW pumps. The AR was converted to a Work Request (WR) that was
scheduled to be implemented by February 18,1996.
Between Febe.ny 9 and /6,1996, the divers had been repairing CW
traveling screens. The Construction Supervisor understood that the System
Engineer would want to have the CW bays cleaned as part of his
surve!! lance and directed the divers, as part of their cleanup, to remove the
sediment deposits in the Unit 1 CW bays while the CW pumps were out of
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service. The results of this activity were not documented in the WR
package. When the WR initiated by the System Engineer came up, it was
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identified that the work had been completed and the WR was canceled.
This error is a result of inadequate communication between the System
Engineer and the Construction Supervisor.
The corrective steps that have been taken and the results achieved:
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Both the Construction Supervisor and the System Engineer were counseled
on the need for effective communication in the performance of daily work.
The System Engineer was counseled on procedural adherence and his
responsibility to confirm as correct any information he receives that affects
the safe operation of the plant. He has recently attended a training session
on October 1,1996, where Senior Engineering Management emphasized
the use of quality, rigor, and safety focus in the performance of daily work.
Also, the importance of clearly communicating expectations to personnel
performing surveillances under his cognizance, maintaining adequate
follow-up of activities under his responsibility, and the operating philosophy
of conservative decision making were emphasized by his supervisor. The
decision to level the sediment in the bays to meet the acceptance criteria did
not demonstrate conservative decision making.
The decision to level the sediment instead of having the sediment removed
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prior to changing operational conditions was not a conservative decision.
The Operations Manager discussed with the Shift Managers the expectation
of conservative decision making.
The corrective steps that will be taken to avoid further violations:
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Standard pre-approved work packages for the Lake Screen House have
been developed and will be implemented by January 10,1997. An aspect of
theses work packages will be to ensure that the System Engineer is
contacted prior to sediment cleaning in the CW bays.
The date when full compliance will be achieved:
Full compliance was achieved on October 1,1996.
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Violation E (96011-18):
10CFR50.71(e) requires, in part, that licensees update the Final Safety
Analysis Report periodically to reflect modifications to the plant. Subsection
(4) requires such updates to be no more than 24 months apart and to reflect
all changes made up to a maximum of six months prior to the update.
Contrary to the above, as of September 24,1996, the LaSalle Updated Final
Safety Analysis Report had not been updated to reflect the change in initial
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and maximum suppression pool temperatures approved by License
Amendments 67 (Unit 1) and 49 (Unit 2), issued in July 1989. This period
exceeds 24 months.
This is a Severity Level IV violation (Supplement 1).
Response:
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The reason for the violation:
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Comed agrees that the subject upgrade was improperly implemented and
untimely. When LaSalle processed the request for a Technical Specification
change prior to the submittal to the NRC in October 1988, the originator of
the change identified potentially affected UFSAR sections (incompletely).
Although the sections were relevant to the primary containment and
suppression pool cooling functions, the sections identified did not include
the supprossion pool temperature value.
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Upon receipt of the license amendment in July 1989, and prior to the next
UFSAR update, the UFSAR was again reviewed as part of preparation for
the UFSAR update. The review incorrectly determined that no UFSAR
changes were deemed necessary because the sections which were
identified as part of the Technical Specification change package did not
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need updating.
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This was a human performance error due to inadequate search of the
UFSAR during both reviews. The reviewers failed to perform an adequate
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search for all affected portions of the UFSAR.
The corrective steps that have been taken and the results achieved:
The Technical Specification Amendment has been re-reviewed and a search
of applicable sections of the UFSAR has been completed. The 10CFR50.59
evaluation is in the approval process. This is scheduled to be completed by
January 10,1997.
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Procedure LAP-1200-12 " License Amendments" was revised in
September,1996, to include UFSAR changes (marked up on copies of the
applicable UFSAR pages). This assures that the UFSAR impact is
specifically included in the Onsite Review for each License Amendment
request. The ability to do computer searches on UFSAR text aids in
performing a thorough search of affected documents.
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The corrective steps that will be taken to avoid further violations:
As part of the LaSalle Upgraded Operational Plan, each section of the
UFSAR will be assigned an owner by January 15,1997. The intent of this
action is to improve accountability for UFSAR accuracy. This will also
provide a resource to other personnel performing Technical Specification
and other plant changes which could effect the UFSAR.
A sample of other Technical Specification changes will be reviewed to
determine if the UFSAR was properly updated. Any UFSAR update
problems will expand the sample. -This review will be completed by
June 30,1997.
The date when full compliance will be achieved:
.
Full compliance will be achieved no later than January 10,1997, when the
safety evaluation of the applicable changes to the UFSAR are approved.
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ATTACHMENT 2
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LaSalle County Generating Station
Response to Unresolved items
in Inspection Report No. 50-373/96011 (DRS); 50-374/96011 (DRS)
Enr.esolved item 96011-12:
Flow through the safety-related room coolers was not balanced and that the
effect of the RHRSW system on the coolers had not been adequately tested
or analyzed. We request that you provide more information on how the
maximum flow through the 1(2)WO4A room cooler was determined and a
more structured review of the effects of the RHRSW back pressure on the
room coolers to ensure adequate flow through all the room coolers under all
conditions where they would be required to operate.
,
Part 1 - M-3.4:
The inspectors observed that the " integrated tests" performed during the
preoperational testing were tests of a single loop (i.e., pump and heat
exchanger). No true integrated testing was performed. This resulted in an
untested system interaction being identified in that the RHRSW shared a
common discharge line with the DGCW. As the RHRSW pumps had a
larger capacity than the DGCW pumps (8000+ gpm RHRSW per division
versus 2000 gpm DGCW), the inspectors surmised that back pressure from
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RHRSW could adversely affect the flow through the W coolers.
.
The inspectors questioned the licensee whether this interaction was ever
tested (see Comments 8 and 14). In response, the licensee stated that the
'
Interaction was tested in July 1996. The inspectors reviewed the results of
this testing and noted that RHRSW was not identified as being running
during the testing. The licensee formally responded that RHRSW was
confirmed to have been running for Division 1 by review of operating logs.
For Division 2, the licensee noted that the effect of RHRSW on the coolers
was determined analytically. The inspectors determined that the July testing
was not intended to examine the system interaction and that the running of
the RHRSW pumps during the Division 1 test was fortuitous. The inspectors
independently reviewed the latest W cooler testing and determined that the
cooler operability was not affected at the time of the inspection.
Conclusions : The inspectors concluded that the pre-operational testing did
not identify a potentially significant interaction between the RHRSW and the
DGCW. While this irn. action did not appear to affect room cooler
3
operability at the time '!i the inspection, it had the potential to so do, if not
properly taken into account, especially if flow balancing was done to resolve
j
the cooler velocity concerns expressed in Section M2.10. Determination of
the effect of this interaction on the W coolers is considered part of
1
unresolved item 50-373/96011-12(DRS); 50-374/96011-12(DRS).
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Response:
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Comed agrees that flow through the safety-related room coolers was not
!
balanced during pre-operational testing, and that the effect on the flow
- imbalance had not been adequately tested or analyzed.
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The Diesel Generator Cooling Water (DGCW) system supplies cooling
4
water to the Core Standby Cooling System Ventilation (W) room coolers.
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When Residual Heat Removal Service Water (RHRWS ) is operated.
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simultaneously with the operation of the DGCW, additional pressure drop
~
occurs as a result of the higher flow rates in portions of the common piping.
.
Calculation L-000679, Rev 0, Approved September 19,1996, titled
t
" Determination of Flow Correction Factors for Evaluating the Performance of -
Core Standby Coolant System - Equipment Cooling Water (CSCS-ECWS)
!
Pump Operation," addressed the effects of simultaneous operation of
RHRSW on the room cooler performance. Subsequently this calculation
.
,
was updated to account for the " Keep-Fill" cross connections (refer to
!
Unresolved item 96011-19 concerning RHR Heat Exchanger Water
Hammer) and Revision 1 was Approved on November 1,1996.
.
This calculation demonstrates that adequate flow goes to the various room
coolers (1/2WO1 A,1/2WO2A,1/2WO3A and 1/2WO4A) under the
'
bounding conditions listed below. Certain conditions exist under the design
4
- basis configuration of the Core Standby Cooling System (CSCS) (when it
must be capable of supplying design basis flow to each CSCS load) that are
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not duplicated under normal or special surveillance test conditions. The
,
t
purpose of this calculation is to determine the correction factors to be
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applied to the CSCS pump flow Acceptance Criteria to ensure that the test
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results are valid and comparable to the flow required under design
'
conditions. The conditions that were evaluated are as follows:
1
1.
Difference in lake level at the time of the test versus the design
basis of 690 feet above mean sea level assuming loss of the
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main dike, leaving only the Ultimate Heat Sink.
,
2.
Suction pressure considerations due to the use of the 54 '
CSCS bypass line around the traveling screens with all CSCS
pumps operating (versus the test condition supply to the
,
service water tunnel through the traveling screens and the six
.
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36" service water tunnel inlet lines).
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3.
Suction pressure considerations due to additional CSCS
Equipment Cooling loads 'on the train being tested that would
be running during and after an accident and thd are not -
running during the test.'
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While the test is conducted with clean strainers, those
strainers could be partially plugged during design conditions.
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5.
Discharge pressure considerations (due to additional CSCS
Equipment Cooling loads on the tested train, plus those on the
4
same train of the opposite unit from the one being tested), that
-
. would be running under design conditions (but not during the
,
test), and that would be discharging into the common
discharge line with the train being tested;
- 6.
Operation with Strainer Backwash flow in operation.
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7.
This calculation also evaluates the impact of Design Change
1
Packages (DCP) 9600195 and 9600198 on the Division 2
CSCS. These DCPs provide a keep fill line connecting each
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Unit's Division 2 DGCW system to it's respective Division 2
RHR WS system piping.
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Also, LaSalle is conducting a design review of the RHRWS system as part
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of the System Functional Performance Review program. This review began
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on November 12,1996, and is performed by a team of senior industry
'
- experts. This review is to confirm the consistency of the design basis,
technical specifications, UFSAR, procedures, design documentation,
surveillances and the physical plant. This will be completed by
January 31,1997. LaSalle will implement any required design changes
,
identified by this self initiated review prior to restarting the Units from L2R07
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and L1F35.
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Part 2 - M2.10:-
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The inspectors reviewed the results for the safety-related 'VY" room coolers.
'
The inspectors observed that the flow rates through the coolers were
considerably above the design flow rate (the worst case, for the 4A coolers
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on Unit 1, was 2.4 times the design flow). As discussed in Section E1.10,
,
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- the inspectors reviewed the pump curves and determined that two of the
pumps (the 0 DGCW and the high pressure coolant system (HPCS) DGCW
pumps) were operating at the end of the pump curve (i.e., in a condition of-
i
high flow and low pressure). The test procedure provided a method to
equate the dPs obtained back to the design flow rate, and the plotted dPs
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- were compared to determine if any trends were developing.
L
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Thc inspectors discussed with the system engineer a concern regarding
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maximum flow through the 1 A and 4A room coolers for both units. Because
,
all four room coolers receive. cooling water from the O DGCW pump, the
,
inspectors were concerned that unbalanced flows could result in (1) less
than design flow through the 1 A coolers and (2) tube erosion in the 4A'
coolers. For the first concern, the inspectors noted that the most recent
surveillances demonstrated that flows through both 1 A coolers were above
design; therefore, this was not an immediate concern. In response to the
,
'
second concern, the licensee responded that the manufacturer specified a
flow velocity limit of 12 feet per second and calculation VY-12 demonstrated
that tube velocity was below that value.
The inspectors reviewed calculation W-12, " Evaluation of W Cooler Tube
Velocity Based on Test Data." As the name implied, this calculation
evaluated the maximum velocity in the tubes using the highest flow rates
'obtained as of September 1993. The inspectors noted that higher flow rates
,
were seen on at least one cooler during its 1995 surveillance test. The
,
inspectors asked the licensee if any bounding calculation had been
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performed to determine the maximum flow through the coolers which would
not exceed the manufacturer's velocity limits. The licensee replied that no
bounding calculation had been performed.
.
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Using the standard formula for determining flow (area times velocity), the
inspectors determined a maximum flow value at a velocity of 12 feet per
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second. The inspectors then confirmed that none of the coolers had -
e
exceeded this value. The inspectors confirmed the validity of the formula by
[
calculating the velocity for the flows used in the licensee's calculation and
comparing them with the results of the calculation. For coolers 1 A,2A, and
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3A, the velocity calculated by the inspectors agreed with the value obtained
by the computer program used in the licensee's calculation.
For the 4A coolers, the inspectors noted that the calculation treated them as
,
two separate coolers, with half tbs flow going to each "sub" cooler. The
,
velocity through each "sub" cooler was then calculated. Therefore, the
- inspectors calculated the velocity for each 4A cooler using half the total flow.
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The inspectors' calculated value, however, was exactly double what the
licensee's calculation determined. The system engineer, when questioned,
could not explain why this was the case. The engineer stated that one of the
"sub" coolers was identical to the 1 A coolers.
Conclusions: The inspectors concluded that the accuracy of the calculated
velocitie 'or the 4A coolers was questionable. The inspectors further
questioned the calculation's conclusion that the maximum velocity would not
be exceeded even if all the flow went through one of the 4A "sub" coolers.
The licensee was requested to provide additional information about the 4A
cooler and the formula used to calculate the velocity to support the
calculation's results. This is an unresolved item
dependent upon NRC review of the calculations' formula for the 4A cooler
and determination as to whether the maximum flows for the 4A cooler were
acceptable
(50-373/96011-12(DRS); 50-374/96011-12(DRS)).
Response:
The 1(2)W01 A and 1(2)WO2A coolers consist of 2 coils each having a fujl!
_
serpentine coil arrangement with 8 tubes in the airflow direction and 20
tubes per row. This results in a total of 20 cooling water flow circuits per coil
and since the coils are connected in parallel, this results in a total of 40
cooling water flow circuits per cooler.
The 1(2)WO4A coolers consist of 4 coils each having a double serpentine
coil arrangement. Two of the coils have 8 tubes in the airflow direction and
20 tubes per row. Due to the double serpentine arrangement, this results in
a total of 40 cooling water flow circuits per coil. The other two coils have 4
tubes in the airflow direction and 20 tubes per row. Due to the double
serpentine arrangement, this results in a total of 40 cooling water flow
circuits per coil. Since all 4 coils are connected in parallel, this results in a
total of 160 cooling water flow circuits per cooler.
The 8 row coil for the 1(2)WO4A coolers have the same physical
dimensions as the 1(2)WO1 A and 1(2)WO2A coolers. However, since the
1(2)WO4A coolers are of the double serpentine coil arrangement, it has
twice the number of cooling water flow circuits as does the 1(2)WO1 A and
1(2)WO2A coolers which have a fu!! serpentine coil arrangement.
Calculation W-12 accurately models the W cooler configurations and
determines the correct cooling water tube velocity for the assumed 50% flow
distribution between the 4 row and the 8 row coils of the 1(2)WO4A coolers
to be 4.4 fps. This is well under the 12 fps maximum allowable tube velocity.
The calculation did not determine the exact cooling water flow distribution
between the 4 row and the 8 row coils of the 1(2)WO4A coolers, but the
calculation allowed for this variation by concluding that even if 100% of the
measured flow went to either of the 4 row or to the 8 row coil, the maximum
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calculated cooling water tube velocity (8.8 fps) would still be under the 12
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fps maximum allowable tube velocity.
- We have independently verified the results of Calculation W-12 via
separate analysis.
4
The following document is available for review at LaSalle County Generating
Station:
1.
Calculation VY-12, Rev. O, approved September 13,1996,
titled: " Evaluation of W Cooler Tube Velocity Based on Test
Data."
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Unresolved item 96011-16:
The inspectors noted that surveillances did not measure or otherwise
account for lake level, which normally was around an elevation of 700 feet.
This appeared to mean that an indicated value of 7400 gpm during
.
'
surveillances would actually be below the design basis requirement. The
inspectors did not have an operability concern because the recorded
2
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measured flow rates have consistently been above 7800 gpm. However the
inspectors were concerned that surveillance tests, such as LTS-200-3,
"RHR Tubeside DP Testing," which verified the design flow of 7400 gpm,
might be inadequate, because they did not account for lake level. This is
considered an unresolved item, awaiting the licensee determining the effect
of the lake level on the surveillance procedures (50-373/96011-16(DRS);
50-374/96011-16(DRS)).
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Response:
Correction factors for cooling lake level have not been included in
surveillance procedures. This approach has been determined to be
incorrect and is being evaluated within our corrective action program. A
Problem identification Form has been initiated. For example, LOS-RH-Q1
"RHR (LPCI) & RHR Service Water Pump & Valve inservice Test For Tube
Side Operational Conditions 1,2,3,4, and 5" verifies RHR heat exchanger
tube side flow exceeds 7400 gpm and verifies that the RHRWS pumps meet
ASME Section XI requirements but does not either correct for cooling lake
,
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level or specify a flow rate which would be satisfactory regardless of lake
<
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level.
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We will be reviewing all applicable surveillance procedures for systems
'
important to safe and reliable operation as part of the ongoing System
Functional Performance Review program, and will ensure that these
procedures include adequate prerequisite requirements and acceptance
criteria, or in lieu of acceptance criteria, the specific actions to be taken to
review the data and whether any immediate actions are required.
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Unresolved item 96011-19:
,
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The review indicated that generally, the CSCS contained adequate
,
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provisions to preclude multiple division failures resulting from a single
source failure. However, two instances were identified where this did not
appear to be the case; one of which was resolved prior to the end of the
inspection.
j
The first potential single failure was a possible water hammer event in the
RHR heat exchangers which could result in tube damage. The heat
.
exchangers were normally lined up to allow water from RHR into the sheIl
,
.
,
side of the heat exchanger. Because RHRSW was manually initiated and
did not normally run, the tube side would depressurize below atmospheric
.
pressure as a result of the relative elevations of the tubes versus the
ultimate heat sink elevation. If the lake was at the design basis low level of
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690 feet, voiding would be present in the tubes under normal operating
.
conditions. If the lake were at its normal level of 700 feet, boiling would
occur in the heat exchanger within seconds of RHR being initiated in its
,
injection mode. Once RHRSW was manually started, the steam voids would
rapidly collapse as they.were condensed by the cold RHRSW, causing a
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water hammer which could break tubes in both heat exchanger tubes in both
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RHR divisions. This could have rendered both trains of RHR inoperable.
The licensee responded that a water hammer would occur as postulated by
the inspectors. As of the end of the inspection, the licensee had not
determined the effect of the water hammer on the tubes. This is considered
i
an unresolved item, pending completion of the licensee's determination and
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. associated operability analysis (50-373/96011-19(DRS);
50-374/96011-19(DRS)).
.
{
Response:
The configuration of both the Division 1 and the Division 2 RHR heat
exchangers is essentially the same. However, the configuration of the
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Division 1 RHRWS piping is different from the Division 2 RHRWS piping for
,
both Units. Because of these differences, the affect of a postulated water
]
hammer in the system is different, as described below:
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Division 1
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Due to the physical configuration of the Unit 1/2 Division 1 Residual Heat
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Removal Service Water (RHRWS) systems, the only location within the .
system where the postulated water hammer event can occur is in the upper
elevation of the RHR heat exchanger tubes. Since the pressure in the top of
-
the highest elevation tube is slightly greater than the fluid pressure at
,
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normal conditions with the RHRWS pumps off, voiding and subsequent
' water hammer will not typically occur in the Division 1 RHRWS systems.
However if the RHR heat exchanger tubes are heated prior to starting the
,
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.RHRWS pumps, the vapor pressure could be higher than the fluid pressure
8
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in the top of the RHR heat exchanger tubes. Such heating could occur
during the initial stages of the LPCI injection when the suppression pool
water has been heated up due to a LOCA or SRV blowdown. The situation
could be aggravated if the lake level dropped, for example following a dike
failure. In these cases the voiding could occur in the tube high points.
To ensure that the Division 1 RHRWS systems meet their design function in
the unlikely event of a water hammer in the tubes of the RHR heat
exchanger, a series of analyses have been completed:
A. General Electric (GE) performed an analysis in October 1996, to
develop conservative water hammer pressure pulses resulting from a
worst case water hammer event in the RHR heat exchanger tubes.
Actual pressure pulse values resulting from any water hammer within
the heat exchanger tubes are expected to be significantly lower than
that calculated in the,GE bounding analysis. Additionally, GE
evaluated the impact of the conservative water hammer pressures on
the RHR heat exchanger.
t
GE concluded that the bounding water hammer pressures which
could occur in the RHR heat exchanger tubes and water box were
sufficiently low that they will not exceed the heat exchanger design
allowables. Use of the more realistic water harnmer pressures would
further strengthen this conclusion.
B. Sargent & Lundy (S&L) performed an analysis which provided further
confirmation of the adequacy of the RHR heat exchanger following a
postulated water hammer in the heat exchanger tubes. Again,
conservative water hammer pressure pulses were utilized. Actual
water hammer loadings are expected to be significantly less than that
considered.
The conclusion of this analysis was that the stresses in the RHR heat
exchangers are within design basis code allowables for the increase
in pressure due to the potential water hammer in the RHR heat
exchanger tubes.
C. S&L performed evaluations of the impact on the piping, equipment
and supports of the Unit 1 and 2 Division 1 RHRWS system as a
result of the conservative water hammer event in the RHR heat
,
exchanger tubes. This evaluation concluded that the stresses in the
system piping, valves, penetration, strainer and pumps and supports
are within applicable Code allowables.
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In addition to the above, an operability evaluation will be completed prior to
startup to document that Division of RHRWS will remain operable in all
'
reactor modes in its current condition. The RHRWS is operable in the -
,
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current shutdown condition.
l
A series of analyses have been completed which are available onsite for
review and include-
1
1.
GE (F. Moody, B. Hughes) to Comed (J. Rommel) Letter,
October 1,1996. Subject: LaSalle RHR Heat Exchanger
'
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Postulated Water Hammer
2.
NDITLS-0397 Upgrade 2, October 24,1996, " Potential for
Water Hammer in the Tubes of the RHR Heat Exchanger and
the Associated. Forces"
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3.
LAS-ENDIT-0270, November 7,1996, "RHR Heat Exchanger
"
Water Hammer Assessment"
4.
LAS-ENDIT-0275, December 6,1996, " Assessment of Effects
of Postulated RHR Heat Exchanger Water Hammer on Units 1
'
and 2 Division 1 Piping, Equipment and Supports - Non Design
'
Basis"
5.
Calculation L-000715, Rev 0 dated November 14,1996 & Rev.
1 dated December 5,1996, " Evaluation of Potential Water
Hammer Event on RHR Heat Exchanger Service Water
(CSCS) Piping Subsystems in Units 1 & 2"
6.
Calculation L-000857, Rev. O dated December 2,1996 & Rev.
,
1 dated December 5,1996, " Assessment of Pipe Supports and
RHR Heat Exchanger Support, Strainer Foundation, Sleeves
and Buried Pipe for Water Hammer Loads - Units 1 & 2"
7.
Calculation L-000731, Rev. O dated November 12,1996, "
-
Evaluation of RHR Heat Exchanger for Water Hammer Effect"
8.
- Calculation L-000854, Rev. O dated November 12,1996 &
Rev.1 dated December 5,1996," Evaluation of RHR Heat
Exchanger, Strainer, Pumps, Valves and Penetrations for
Nozzle Load due to Postulated Water Hammer in Heat
Exchanger"
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Division 2
The physical configuration of the Units 1 and 2 Division 2 RHRWS system
,
allows for the potential for a water hammer event to occur in the inlet piping
to the heat exchanger as well as the heat exchanger tubes. The Division 2
piping has a loop in which the piping has a vertical rise and drop before
terminating at the RHR heat exchanger inlet nozzle. This loop exists to
provide a straight run of pipe necessary to assure the accuracy of flow
measuring instrumentation. The piping / pipe supports have not been shown
analytically to be able to withstand (within design allowables) water hammer
originating in the piping. A keep fill system with cross ties to both WS and
DGWC has been designed for both Division 2 RHR-WS systems to maintain
the piping system full and thus eliminate the potential for a water hammer
during design basis events. These design changes are documented in
DCPs 9600195 (Unit 1) and 9600198 (Unit 2) and will be implemented prior
to restart from L1F35 and L2,R07 respectively.
DCPs 9600195 and 9600198 have been initiated to add two cross ties to
'
each Division 2 RHRWS system to ensure that it is kept filled and
pressurized. One cross tie is from the Service Water (WS) system, the
other is from the DGCW system. This modification will prevent the formation
of voids by keeping the Unit 1 and Unit 2 Division 2 -WS systems filled and
4
pressurized to above the saturation pressure. Two cross ties are required
because the WS system is non-safety-related and cannot be relied upon in
the event of an accident, Loss of Offsite Power (LOOP), or seismic event.
The DGCW system is safety-related, but does not operate continuously. It
operates whenever the emergency diesel generators are running or when
the ECCS pumps (including RHR) are running. Therefore, the cross tie from
WS will keep the RHRWS system filled during normal operation, while the
cross tie from DGCW will keep it filled in the event of an accident or LOOP.
Additional design or operational changes are being implemented during
L1F35 and L2R07 respectively, to ensure the RHRWS system is not
depressurized below water saturation pressures include:
1.
An annunciator alarm will provide notification to the control
room operators if the keep fill cross tie is not keeping the
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Division 2 RHRWS system pressurized and filled.
'
2.
Should the periodic (every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />) RHRWS strainer
backwash cycle auto initiate while the RHRWS pumps are in
standby, the backwash discharge valve would open, which
would allow the keep fill flow to be diverted out the backwash
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discharge line instead of keeping the RHRWS system filled
and pressurized. Therefora, an interlock will be added to the
control logic of the RHRWS strainer backwash to permit
initiation of the periodic (once every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />) automatic
backwash cycle only if the RHRWS pumps are running.
3.
The pump startup procedures will be revised to ensure that a
RHRWS pump is started before valve 1(2)E12-F0688 is
opened. Should the RHRWS pumps be started after the
1(2)E12-F0688 valve is open, the keep fill system would not
be able to maintain the RHRWS system filled and voiding
could occur. The piping will begin to void when the flow rate
across valve 1(2)E12-F0688 exceeds the keep fill rate plus
the pump flow rate (the pump flow rate is initially zero). To
preclude the possibility of water hammer, it is necessary to
ensure that a F3HRWS pump is running before the flow across
the valve exceeds the keep fill flow rate.
Following the addition of the above changes, the Division 2 RHR-WS will
meet the required design function and be operable during all reactor modes.
Prior to operability of the keep fill cross ties, the Division 2 RHR-WS system
remains operable for operating conditions 4,5 and defueled. The
determination that the design of Division 2 was not consistent with design
basis in Modes 1,2 and 3 was reported to the NRC by 10CFR50.72 on
December 17,1996.
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Unresolved item 96011-20:
The inspectors noted an issue open from 1987 to July 1996. The issue
related to a potential fire in a corridor where control panels for all three
EDGs were located. The fire could render all three division EDGs
inoperable. The action taken in 1987 was initiation of an hourly fire watch
and origination of a modification request to install physical protective
barriers. However, due to concerns with fire retardant materials, the
modification package was put on hold in 1991 and was canceled in
September of 1996.
The basis for canceling the modification was establishment of an alternative
shutdown path: core cooling by the reactor core isolation cooling system,
which did not require EDG operation. Other longer term actions, such as
cooling the suppression pool, would be handled by cross-tying the
emergency busses to the other unit. This assumption and the analysis was
previously approved by the NRC for the Station Blackout issue.
The inspectors questioned the licensee on the adequacy of the
compensatory actions in place from 1987 to 1996 and what guidance would
have been available to the operators had a fire occurred during this nine-
year period. The focus of the inspectors' concerns was on why the licensee
required the EDGs to operate, as 10 CFR Part 50, Appendix R, did not
require a licensee to assume that offsite power was lost, unless the fire
caused it to be. The licensee stated that assuming loss of offsite power was
a conservative measure. However, neither the original (1987) fire hazard
analysis contained in Appendix H of the UFSAR, nor the revision proposed
in 1996, stated that a conservative assumption of loss of offsite power had
been applied. Therefore, the inspectors inquired whether the licensee had
confirmed that offsite power cables either would or would not be affected by
a fire in the zone.
Conclusions: The lack of compensatory actions for a nine-year period could
be a significant failure to take adequate corrective actions. The
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significance, however, depended on whether offsite power would be affected
for a fire in the EDG corridor. Although the licensee claimed that loss of
offsite power was a conservative assumption, this was not reflected in either
the original fire hazards analysis nor in the 1996 revision. The inspectors
requested that the licensee respond in writing providing evidence to support
the assertion that a fire in the EDG corridor would not result in loss of
normal power to the affected components. This is considered an unresolved
item, pending the licensee's response (50-373/96011-20(DRS);
50-374/96011-20(DRS)).
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Response:
The design basis for postulating a fire simultaneously with a LOOP is
documented in the SAFE Shutdown Analysis, Section H.4.1.5.c.
UFSAR Section H.4.2.57 (Safe Shutdown Analysis for Fire Zone SC11) and
associated tables were recently revised to add a new safe shutdown path
that has been established for use in the event that there is a fire in Fire
Zone SC11. This satisfies the requirements of Appendix R to 10 CFR Part 50. Procedures were in place for Operations to establish unit crossties
to either Unit for offsite power. In the event a fire in either Unit 1 or Unit 2
diesel generator corridors, caused by a loss of auxiliary power, operating
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procedures were available to direct operators in the restoration of offsite
power sources. Specifically, LOA-AP-101 (Unit 1) and LOA-AP-201 (Unit 2)
are used to establish unit crossties which can be implemented within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />
of the initial event.
,
Procedures LOA-AP-07, " Loss of Auxiliary Electrical Power," and
LOA-AP 08, " Total Loss of AC Power," (which were superseded by
Procedures LOA-AP-101 and LOA-AP-201) were available prior to 1987.
They provided direction to ertablish unit crossties to either Unit for offsite
power and to initiate RCIC in case of loss of all AC power.
Normal (offsite) power is supplied from the System Auxiliary Transformers
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(SAT) to the safety related 4.16-kV Buses 141Y,142Y,143, 241Y,242Y and
243.
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For the purpose of determining whether normal offsite power is affected by i
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fire in the diesel generator corridors, it is also necessary to identify all
electrical connections that are needed in providing power to the subject
divisional buses. These electrical connections include,1) the 4.16-kV non-
segregated phase bus ducts that supply power from the SAT's to the
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divisional buses; 2) the cables that are required to control and protect the
feed circuit breakers from the SAT's to the divisional buses; 3) the cables
required to maintain operability for the SAT's. Specifically, these cables
!
primarily makeup the protective relaying circuits and transformer cooling
systems for the SAT's.
The results of this evaluation, as documented in LAS-ENDIT-0297, conclude
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that there are no canes (or instruments) routed in these areas that are
required to maintain offsite power to the divisional buses.
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Vertical Burner Flame Test per IEEE 383-1974. Therefore, an
' electrically initiated fire in these exposed cable trays will not
propagate.
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In addition, the exposed cable trays in the Unit 2 DG corridor
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are located approximately 1 foot above and approximately 5
~ feet across (parallel) from the SAT non-segregated phase bus
ducts. In the Unit 1 DG corridor, the exposed cable trays are.
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located approximately 6 inches above and approximately 2 feet
across (parallel) from the SAT non-segregated phase bus
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ducts. The entire corridor areas are provided with an early
warning fire detection and automatic sprinkler systems. The
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fire detectors and automatic sprinklers are optimally located to
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detect and suppress fires. They are located in the higher
elevations of the corridors in close proximity to the cable trays.
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Therefore, the impact of a fire in an exposed cable tray
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relative to the bus ducts is minimized by the physical location
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of the exposed cable trays to the bus ducts, in addition to the
automatic detection and suppression systems
in summary, normal offsite power will not be affected by a fire in these areas
primarily attributed to having no cables (or instruments) routed in these
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areas associated with providing offsite power from the SAT's to the
divisional buses. In addition, these areas have a minimal amount of
combustibles to support a sustained fire. In the unlikely event of a fire, both
diesel generator corridors are provided with fire detection and suppression
systems available to detect and mitigate the consequences of a fire.
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Although the 4.16-kV SAT power feeds to the divisional buses are routed in
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this area, this equipment is non-combustible, and is expected to perform its
function in the event of a fire and its subsequent detection and suppression.
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in addition, exposed cables meet the requirements of IEEE 383-1974 and
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the physical orientation of the exposed cable trays to the bus ducts minimize
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the impact of a cable tray fire relative to the bus ducts.
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February 24,1997
1
United States Nuclear Regulatory Commission
Attention: Document Control Desk
Washington, D.C. 20555
Subject:
NRC INSPECTION REPORT NO. 50-373/96011;
50-374/96011 (DRS) AND NOTICE OF VIOLATION
,
References:
1.
G. E. Grant Letter to W. T. Subalusky, dated
November 15,1996, Transmitting NRC Inspection
Report 373/374-96011
2.
W. T. Subalusky Letter to U.S. NRC, dated
December 20,1996, Transmitting Response to
NRC inspection Report 373/374-96011 and
Reference 1 transmitted US NRC inspection Report 373/374-96011 and
reference 2 transmitted LaSalle County Station's response. The enclosed
attachment supplements LaSalle County Station's response to the Notice of
Violation item 1. If there are any questions or comments concerning this letter,
please refer them to me at (815) 357-6761, extension 3600.
Respectfully,
,
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W. T. Subalusky
.
Site Vice President
LaSalle County Station
Enclosure
~g7g3c gygg gy,
cc:
A. B. Beach, NRC Region til Administrator
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M. P. Huber, NRC Senior Resident inspector - LaSalle
D. M. Skay, Project Manager - NRR - LaSalle
F. Niziolek, Office of Nuclear Facility Safety -lDNS
DCD - Licensing (Hardcopy:
Electronic:
).
Central File
ElH. EIEll:I.M. H. . H.
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ATTACHMENT 1-
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LASALLE COUNTY GENERATING STATION
SUPPLEMENTAL RESPONSE TO NOTICE OF VIOLATION
lN INSPECTION REPORT NO. 50-373/96011 (DRS); 50-374/96011 (DRS)
e
Violation A (96011-01 & 96011-171-
Subsequent to the exit for NRC Inspection Report 96019 on January
3,1997, at LaSalle County Station, Comed held discussions with the NRC
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regarding additional corrective actions being taken in response to the subject
Notice of Violation in Inspection Report 96011. The following corrective
actions regarding the Nuclear Design Information Transmittal (NDIT) process
have been or will be taken.
The corrective stens that have been taken and the results achieved:
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1.
On January 4,1997, NEP-12-03LA, Revision 2, LaSalle Nuclear
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Design Information Transmittal (NDIT) Site Appendix, was volded.
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This revision was volded because the procedure contained
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instructions which were misinterpreted as allowing minor modifications
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to be authorized by the NDIT procedure.
2.
All NDITs issued under NEP-12-03LA, Revision 2 have been
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reviewed to determine if other NDITs had been inappropriately used
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to make design changes. Three occurrences of inappropriate use of
the NDIT procedure were identified. The first provided generic
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approval to modify valve packing. This NDIT was veided. A design
drawing was issued to control the use of valve packing. The second
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involved a material substitution for an unavailable original material for
non-safety related damaged soil drain piping. A safety evaluation
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screening has been performed and the material specification for the
piping has been updated. The third NDIT, involving a material type
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change in valve guides, was supplemented with a parts evaluation, a
safety evaluation and update of the valve drawings in accordance wid
applicable station procedures.
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3.
On January 3,1997, the Site Engineering Manager required that all
NDITs be approved by an Engineering Department Head prior to
issue. On February 6,1997, for other reasons, a stop work order was
issued by Site Quality Verification on use of NEPs subject to
completion of independent technical reviews, Onsi?e Review and
Station Manager approval in accordance with the station Technical
Specifications. NEP-12-03 and a new revision to NEP 12-03LA,
which resolves the deficiencies with Revision 2, are currently
scheduled for this review process. Use of NDITs is suspended until
the full review and approval process is completed for these two
- procedures.
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The corrective steps that will be taken to avoid further violations:
1.
Revision 3 of NEP-12-03LA was written to (1) clarify the scope of use
of this procedure, (2) specifically prohibit the use of an NDIT for
transmittal of a design change, (3) specifically prohibit the use of an
NDIT to circumvent the temporary alteration procedure and (4) require
a 10CFR50.59 screening for repairs or upgrades of an NDIT dealing
with the same repair. As noted above, an independent technical
review and Onsite Review will be performed for this revision of the site
appendix along with NEP-12-03, prior to their implementation. This
process will be complete before March 14,1997. Training on those
procedures will be conducted by March 28,1997.
2.
All NDITs issued by Engineering to all revisions of NEP-12-03LA will
be reviewed to determine if additional NDITs had been inappropriately
used to make design changes. If an inappropriate use of an NDIT is
identified, immediate corrective action will be taken. This effort will be
complete by April 4,1997.
2