ML031060288
| ML031060288 | |
| Person / Time | |
|---|---|
| Site: | Nine Mile Point  (DPR-063) |
| Issue date: | 04/15/2003 |
| From: | Lanning W Division of Reactor Safety I |
| To: | Conway J Nine Mile Point |
| References | |
| -nr, EA-03-053 IR-03-003 | |
| Download: ML031060288 (30) | |
See also: IR 05000220/2003003
Text
April 15, 2003
Mr. John T. Conway
Vice President Nine Mile Point
Nine Mile Point Nuclear Station, LLC
P.O. Box 63
Lycoming, NY 13093
SUBJECT:
NINE MILE POINT NUCLEAR STATION - NRC SPECIAL INSPECTION
REPORT 50-220/03-003 - PRELIMINARY WHITE FINDING
Dear Mr. Conway:
On March 7, 2003, the NRC completed a special inspection of the Nine Mile Point Nuclear
Station, Unit 1. The enclosed report documents the inspection findings which were discussed
at the completion of the inspection with you and other members of your staff during an exit
meeting on March 7, 2003.
This inspection examined activities conducted under your license as they relate to safety and
compliance with the Commissions rules and regulations and with the conditions of your license.
The team reviewed selected procedures and records, observed activities, and interviewed
personnel. In particular, the inspection reviewed event evaluations, including technical
analyses, root cause investigation, relevant performance history, and extent of condition to
assess the significance and potential consequences of the degraded condition of the reactor
building closed loop cooling (RBCLC) system.
This report discusses a finding that appears to have low to moderate safety significance. As
described in Section 4OA3 of this report, this finding involves inadequate implementation of
corrective actions for significantly degraded piping in the RBCLC system. There were
numerous prior opportunities to identify and correct this problem. This finding was assessed
using the reactor safety Significance Determination Process (SDP) as a potentially safety
significant finding that was preliminarily determined to be White (i.e., a finding with some
increased importance to safety, which may require additional NRC inspection). The finding has
low to moderate safety significance because a pipe rupture in the RBCLC system could result in
an initiating event and loss of certain equipment necessary to mitigate plant transients and
accidents.
Following identification of the degraded piping, you implemented appropriate corrective actions
by replacing most of the RBCLC system piping located in the drywell with improved hardware
and design. With these compensatory measures in place while long term corrective actions are
being developed, our inspectors determined that an immediate safety hazard does not exist.
John T. Conway
2
The finding also appears to be an apparent violation of NRC requirements and is being
considered for escalated enforcement action in accordance with the General Statement of
Policy and Procedure for NRC Enforcement Actions (Enforcement Policy), NUREG-1600. The
current Enforcement Policy is included on the NRCs Website at http://www.nrc.gov/what-we-
do/regulatory/enforcement.html.
We believe that we have sufficient information to make our final risk determination for the
performance issue regarding inadequate corrective action for the degraded RBCLC system.
However, before the NRC makes a final decision on this matter, we are providing you an
opportunity to either submit a written response or to request a Regulatory Conference where
you would be able to provide your perspectives on the significance of the finding, the bases for
your position, and whether you agree with the apparent violation. If you choose to request a
Regulatory Conference, we encourage you to submit your evaluation and any differences with
the NRC evaluation at least one week prior to the conference in an effort to make the
conference more efficient and effective. If a Regulatory Conference is held, it will be open for
public observation. The NRC will also issue a press release to announce the Regulatory
Conference.
Please contact Mr. James M. Trapp at (610) 337-5186, within 10 business days of the date of
this letter to notify the NRC of your intentions. If we have not heard from you within 10 days, we
will continue with our significance determination and enforcement decision and you will be
advised by separate correspondence of the results of our deliberations on this matter.
Since the NRC has not made a final determination in this matter, no Notice of Violation is being
issued for this inspection finding at this time. In addition, please be advised that the number
and characterization of the apparent violation described in the enclosed inspection report may
change as a result of further NRC review.
In accordance with 10 CFR 2.790 of the NRC's "Rules of Practice," a copy of this letter and its
enclosures will be available electronically for public inspection in the NRC Public Document
Room or from the Publicly Available Records (PARS) component of NRCs document system
(ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-
rm/adams.html (the Public Electronic Reading Room).
If you have any questions, please contact Mr. Trapp at (610) 337-5186.
Sincerely,
/RA/
Wayne D. Lanning, Director
Division of Reactor Safety
Docket No.
50-220
License No.
Enclosures:
1) Inspection Report 50-220/03-003 w/Attachment: Supplemental Information
2) NRC Special Inspection Team Charter
John T. Conway
3
cc w/encl:
M. J. Wallace, President, Nine Mile Point Nuclear Station, LLC
M. Wetterhahn, Esquire, Winston and Strawn
J. M. Petro, Jr., Esquire, Counsel, Constellation Power Source, Inc.
P. D. Eddy, Electric Division, NYS Department of Public Service
C. Donaldson, Esquire, Assistant Attorney General, New York
Department of Law
J. V. Vinquist, MATS, Inc.
W. M. Flynn, President, New York State Energy Research
and Development Authority
Supervisor, Town of Scriba
C. Adrienne Rhodes, Chairman and Executive Director, State Consumer Protection Board
T. Judson, Central NY Citizens Awareness Network
John T. Conway
4
Distribution w/encl:
H. Miller, RA/J. Wiggins, DRA
F. Congel, OE (RidsOeMailCenter)
W. Kane, DEDR (RidsEdoMailCenter)
B. Borchardt, NRR (RidsNrrAdip)
D. Dambly, OGC (RidsOgcMailCenter)
S. Figueroa, OE (RidsOeMailCenter)
D. Holody, ORA
R. Urban, ORA
J. Trapp, DRP
T. McGinty, RI EDO Coordinator
R. Laufer, NRR
D. Skay/T. Colburn, PM, NRR (Backup)
G. Hunegs, SRI - Nine Mile Point
B. Fuller, RI - Nine Mile Point
N. Perry, DRP
K. Kolek, DRP
Region I Docket Room (with concurrences)
W. Lanning, DRS
R. Crlenjak, DRS
R. Lorson, DRS
S. Pindale, DRS
DOCUMENT NAME: G:\\PEB\\PINDALE\\NMP2003003.WPD
After declaring this document An Official Agency Record it will be released to the Public.
To receive a copy of this document, indicate in the box: "C" = Copy without attachment/enclosure "E" = Copy with attachment/enclosure "N" = No copy
OFFICE
RI/DRS
RI/DRS
RI/DRS
RI/DRP
RI/ORA
NAME
SPindale
RLorson
ECobey
JTrapp
RUrban
DATE
03/27/03
04/15/03
03/27/03
03/27/03
03/27/03
OFFICE
RI/DRS
NAME
WLanning
DATE
04/15/03
04/ /03
04/ /03
04/ /03
04/ /03
OFFICIAL RECORD COPY
ENCLOSURE 1
U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Docket No:
50-220
License No:
Report No:
50-220/03-003
Licensee:
Nine Mile Point Nuclear Station, LLC (NMPNS)
Facility:
Nine Mile Point, Unit 1
Location:
P. O. Box 63
Lycoming, NY 13093
Dates:
February 10, 2003 - March 7, 2003
Inspectors:
S. Pindale, Senior Reactor Inspector (Team Leader)
S. Chaudhary, Reactor Inspector
E. Cobey, Senior Reactor Analyst
E. Knutson, Resident Inspector
Approved by:
James M. Trapp, Chief
Projects Branch 1
Division of Reactor Projects
ii
SUMMARY OF FINDINGS
IR 05000220/2003-003; 02/10/2003 - 03/08/2003; Nine Mile Point, Unit 1; Special Inspection
Team of Degraded Piping in the Reactor Building Closed Loop Cooling System.
The inspection was conducted by two regional inspectors, one resident inspector, and one
regional senior reactor analyst. One preliminary White finding was identified. The significance
of most findings is indicated by their color (Green, White, Yellow, Red) using IMC 0609,
Significance Determination Process (SDP). Findings for which the SDP does not apply may
be Green or be assigned a severity level after NRC management review. The NRCs program
for overseeing the safe operation of commercial nuclear power reactors is described in
NUREG-1649, Reactor Oversight Process, Revision 3, dated July 2000.
A.
Inspector Identified and Self-Revealing Findings
Cornerstones: Initiating Events and Mitigating Systems
Preliminary White. An apparent violation of 10 CFR 50, Appendix B,
Criterion XVI, Corrective Action, was identified by the team associated with the
failure to evaluate significant conditions adverse to quality involving degraded
piping in the reactor building closed loop cooling (RBCLC) system. The failure to
adequately identify and evaluate equipment problems, and correct deficiencies,
resulted in repetitive and continued degraded piping conditions in the RBCLC
system. Specifically, a RBCLC system piping leak occurred on May 15, 2002,
due to significant pipe corrosion, primarily as a result of inadequate piping
design, application and operation. Additionally, numerous RBCLC system leaks
occurred during several preceding years. However, the cause for these leaks
was not determined and appropriate corrective actions were not implemented.
This led to further degradation of the RBCLC system piping such that additional
significant leaks occurred on December 5, 2002, and again on December 12,
2002. These significant leaks in December 2002 were accompanied by a
significant reduction in the pipe wall which degraded the structural integrity of the
affected piping sections.
This finding has low to moderate safety significance, based on the results of the
phase three SDP analysis, because the degraded RBCLC piping resulted in an
increase in the likelihood of the loss of the RBCLC system due to piping failure,
which directly affected the initiating events cornerstone. The loss of the RBCLC
system would also result in the loss of cooling to several other risk significant
systems (e.g., feedwater/condensate pumps, recirculation pumps, shutdown
cooling heat exchangers, etc.) following a loss of coolant accident or a loss of all
AC power event where AC power is recovered prior to core damage, which
directly affected the mitigating systems cornerstone. (Section 4OA3.4; AV 50-
220/03-03-01)
REPORT DETAILS
Summary of Plant Status
The reactor building closed loop cooling (RBCLC) system provides cooling for various reactor
auxiliary equipment, as well as balance of plant equipment. Major components supplied by the
system included the drywell air coolers, reactor recirculation pump coolers, reactor building
equipment drain tank cooler, fuel pool heat exchangers, shutdown cooling system, control room
air conditioning equipment, instrument air compressors, and the high pressure injection system
(i.e., feedwater pumps, feedwater booster pumps, and condensate pumps). The RBCLC
system is a safety-related, risk-significant system that is required to operate during normal plant
operations and accident conditions.
In May 2002, and again on December 5 and 12, 2002, the licensee experienced substantial
leaks in RBCLC small bore (less than 2" diameter) piping. Following evaluation and analysis of
these leaks, the licensee discovered notable and widespread wall thinning in RBCLC piping
sections, which were most severe at threaded mechanical connections (where piping thickness
was the smallest due to the thread roots). This reduction in wall thickness was ultimately
attributed to a combination of general corrosion, flow-assisted corrosion, and galvanic
corrosion.
Prior to 2002, there had been numerous additional small bore piping leaks within the RBCLC
system at threaded mechanical joints. Repair methods for these leaks varied, and included
tightening the connection or fittings, replacing components (such as flow switches), seal
welding the threaded connections, and replacing affected pipe sections. Around May 2000,
chloride and sulfate concentrations in the RBCLC system were found to be elevated. Near the
same time, RBCLC system oxygen levels were found to be significantly below normal levels,
and iron particulate levels were high. These parameters indicated an increased corrosion rate,
however, efforts to identify the cause and correct the abnormal chemistry parameters were
unsuccessful.
The NRC teams review of the event details determined the root and contributing causes for the
degraded RBCLC piping included: inadequate system design, inadequate corrective actions,
and degraded RBCLC system water chemistry. Subsequent to the December 12, 2002, leak,
several immediate corrective actions were implemented, including extensive RBCLC small bore
piping and fitting replacement with improved piping material and design. Longer term similar
actions were also in progress for the remaining RBCLC piping sections that had not been
replaced. In addition, the licensee was continuing their efforts to determine the cause and
corrective actions for the unexpected and unexplained chemistry parameters.
The performance deficiency was the failure, prior to December 12, 2002, to determine the
cause of a significant condition adverse to quality and implement appropriate corrective actions
to prevent further degradation of the RBCLC system. The NRC team determined that the
licensees structural analysis did not provide evidence that the as-found condition of the
degraded piping in the RBCLC system retained sufficient strength, and consequently, the
structural integrity of the affected RBCLC system piping may not have been maintained when
subjected to design loading conditions. The safety significance of the inspection finding, based
on the increase in core damage frequency due to internal and external initiating events, was
determined to be White, which represents a finding of low to moderate safety significance.
2
4.
OTHER ACTIVITIES (OA)
4OA3 Event Followup
1.
Degraded RBCLC Piping Due to Corrosion
a.
Inspection Scope
This inspection was conducted in accordance with NRC Inspection Procedure 93812,
Special Inspection, to assess the licensees actions associated with the December 5
and 12, 2002, discovery of two instances where portions of the RBCLC piping were
significantly corroded such that leaks occurred in the system. The licensee conducted
event evaluations following each incident to determine the root cause and corrective
actions. The team reviewed the associated design basis documents, calculations, and
other related documents. A list of the documents reviewed by the team is provided as
Attachment 1 to this report.
The team reviewed aspects of the historical performance of the RBCLC system relative
to prior leaks and associated licensee actions and evaluations. The team also
examined portions of degraded RBCLC piping that had been removed from the system,
walked down portions of the system, and interviewed licensee personnel.
Chronology of System Leakage
The RBCLC system piping was designed and installed in accordance with the B31.1-
1955 Code for Pressure Piping. The pipe was Schedule 40 carbon steel and threaded
connections were used for many of the small bore piping connections. The nominal wall
thickness for 1-1/2 inch diameter Schedule 40 and 80 pipe is 0.145 and 0.200 inches,
respectively. The use of threaded connections reduces the nominal wall thickness as
the threads are cut into the pipe, thereby further reducing the pipe wall thickness at the
root of the threads. In addition, the system also contained several dissimilar metal joints
(e.g., carbon steel to stainless steel; and carbon steel to bronze) at several of the piping
connections. While this was not prohibited by the piping design code, direct connection
(without insulating barriers) of dissimilar metals can lead to galvanic corrosion.
The team reviewed documentation of RBCLC system leaks dating back to 1991. In July
1991, the unit was shut down to investigate increased drywell leakage. The source of
the leakage was RBCLC from the recirculation pump seal coolers. At that time, a total
of seven out of ten recirculation pump seal cooler threaded pipe connections were found
to be leaking. These connections consisted of threaded pipe joints, as opposed to
welded pipe sections. The licensee attributed the leakage, as documented in deviation
event report (DER) 1991-0560, to thermal expansion and vibration which caused the
mechanical connections to loosen. The licensee determined the root cause of the event
to be an inadequate system design.
3
In February 1992, DER 1992-0480 documented that the long term corrective actions of
DER 1991-0560 had not been implemented. The corrective action in this DER
recommended that the long term corrective actions from DER 1991-0560 should be
implemented prior to closing DER 1992-0480. Despite continuing issues with
recirculation pump seal cooler leaks through the 1990s (as documented in DER 2002-
2383), this recommendation was not implemented, and modification N1-80-83 was
subsequently canceled in 1994.
In September 2000, two recirculation pump seal cooler leaks were identified and
documented in DER 2000-3268. Both leaks were from threaded connections between
the RBCLC piping and the coolers. The cause of the leaks (i.e., whether the leakage
was through the mechanical joints or through-wall degradation of the piping) was not
positively identified. However, the DER noted that attempts to stop the leak by
tightening the connections were unsuccessful. Both leaks were repaired by seal
welding.
During a mid-cycle outage in May 2002 to investigate drywell leakage, two significant
RBCLC leaks were identified in the drywell, as documented in DER 2002-2383. One
leak was from a recirculation pump seal cooler mechanical joint. Again, the cause of the
leak was not positively identified, although attempts to tighten the joint did not stop the
leakage. This leak was repaired by seal welding. The other leak was from the
downstream threaded connection to a flow switch in RBCLC piping to the 14
recirculation pump. This leak was repaired by replacing the flow switch and the
immediate upstream and downstream piping. Subsequent vendor analysis identified the
apparent cause of the flow switch leak as galvanic corrosion of the downstream pipe,
due to dissimilar metals in the flow switch and the piping. Flow turbulence downstream
of the flow switch continually exposed fresh metal and allowed the galvanic action to
progress to failure. Although the results of the vendor analysis results were available in
July 2002, they were not factored into the corrective action process and, consequently,
were not addressed until after the subsequent RBCLC leaks were identified in
December 2002.
On December 5, 2002, Unit 1 shut down to investigate an increase in unidentified
drywell leakage. The source was found to be RBCLC system leakage from the
threaded joint on the downstream side of the outlet check valve from the 11 drywell
equipment drain tank cooler. The apparent cause, as identified in DER 2002-5166, was
a combination of galvanic corrosion between dissimilar metal components (bronze
check valve, carbon steel piping) and turbulent flow downstream of the check valve.
The leak was repaired by eliminating the check valve and replacing the associated
piping. Additional actions associated with this DER included the following:
Eliminating the outlet check valve from the other (12) drywell equipment drain
tank cooler;
Replacing susceptible pipe assemblies at the outlet of the recirculation pump
motor and seal cooler lines, and eliminating check valves and dissimilar metal
joints;
4
Completing seal welding of RBCLC lines to the recirculation pump seal coolers;
and
Replacing flow switches and connecting piping for the two recirculation pumps
that had not had this done within the last four years.
One week later, on December 12, 2002, a leak was identified at the RBCLC inlet
connection to the 11 drywell cooler heat exchanger. The leak was from the threaded
connection of a pipe nipple to a threaded elbow, originating in a pinhole at the root of the
exposed portion of the threads. The licensee (DER 2002-5280) identified that the
apparent cause for this leak was general corrosion combined with the tapered threads
on the original construction Schedule 40 piping. This threaded joint was not a dissimilar
metal joint (it was all carbon steel).
In response to the most recent problem, the unit was shut down. The corrective action
for this leak was to replace all drywell air cooler inlet and outlet piping. Additional
actions associated with DER 2002-5280 included replacement of the majority of RBCLC
piping inside the drywell with Schedule 80 piping using welded (rather than threaded)
connections. The recirculation pump motor cooler piping was determined to be in good
condition and was not replaced; and the upstream piping to the equipment drain tank
was determined to be acceptable until the refueling outage scheduled for Fall 2004.
RBCLC Chemistry Control
In early 2000, unexplained changes in the RBCLC water chemistry parameters began to
occur. Over a period of several months, the dissolved oxygen concentration decreased
from its normal value of about 3000 ppb (parts per billion) to essentially zero.
Subsequently, in June 2000, DER 2000-2139 was written to document an increase in
RBCLC water conductivity, and chloride and sulfate concentrations. Typically, such
changes are the result of service water system leakage into the RBCLC system.
Attempts to identify the source of the chloride and sulfate contamination have been
unsuccessful to date. Contaminant concentrations have, for the most part, been
maintained within specification by performing system feed-and-bleeds (i.e., purging the
water volume in the system). The cause for the oxygen depletion has not been
determined. The feed-and-bleed evolution used aerated water (oxygen concentration
on the order of 3000 ppb), however, the RBCLC oxygen concentration remained
approximately zero. This indicated that some process was continuing to consume the
dissolved oxygen. The licensee had also identified elevated concentrations of soluble
and insoluble iron in the RBCLC water since the year 2000, which was consistent with
the oxygen depletion mechanism being the result of corrosion.
5
2.
Root and Contributing Causes of Degraded RBCLC Piping
a.
Inspection Scope
The team reviewed the licensees event evaluation reports and cause analyses
associated with the RBCLC system pipe leaks and degraded piping. The team also
independently assessed the root and causal factors for the event. The team reviewed
data and corrective action program documents, conducted plant tours, and interviewed
personnel, including station management.
b.
Findings
The team concluded that the licensees cause evaluations prior to the December 12,
2002, leak did not effectively evaluate the observed degraded piping. The licensees
actions, subsequent to this leak, have included a comprehensive cause investigation
and also an evaluation to determine how the organizational and cultural environment
affected previous attempts to correct this problem. The licensee appropriately identified
that general corrosion, galvanic cells, and flow-assisted corrosion degraded the RBCLC
system integrity and led to the leaks.
The licensees investigation identified several preliminary findings, including: station
personnel did not use effective problem solving techniques; weaknesses in technical
rigor/justification; high standards for thorough problem solving were not reinforced; and
personnel did not demonstrate judicial use/application of failure analysis examinations.
The NRC teams review of the event details determined the following regarding the root
and contributing causes for the degraded RBCLC piping:
Inadequate System Design: The use of threaded (vs. welded) connections with
Schedule 40 piping (nominal wall thickness of 0.145") resulted in a thin base
material at the piping connections, particularly at the roots of the threads.
Dissimilar metals in various system components resulted in galvanic corrosion
which, in some cases, accelerated the wall loss of the internal piping surface to
the point of loss of adequate structural integrity and through-wall leakage.
Inadequate Corrective Actions: In 1991, DER 1991-0560 identified threaded
connections at the recirculation pump seal coolers as a system design deficiency
and recommended corrective action to implement a previously identified
modification (N1-80-83) to redesign the connections. However, this corrective
action was initially not acted upon, as identified by DER 1992-0480, and
ultimately was canceled. Corrective actions associated with several of the leaks
consisted, in part, of seal welding at the threaded pipe joints. This action was
superficial in that it only eliminated the immediate symptom (the leak) and made
no attempt to identify the root cause of this significant condition adverse to
quality. In addition, the failure analysis for the leaking flow switch, which
identified galvanic corrosion and turbulent flow as the cause of failure, was not
factored into the corrective action program, and therefore, was not promptly
acted upon. Corrective actions associated with the December 5, 2002 leak,
while more extensive than in previous cases, were still not adequate to identify
6
the root cause of the system degradation and to prevent the additional failure,
that occurred one week later.
Degraded RBCLC System Water Chemistry: Actions over about two years have
been unsuccessful in identifying the source of chloride and sulfate
contamination, and the cause for the oxygen depletion. While the cause of
these issues remains unknown, they apparently have contributed to accelerated
system degradation through corrosion, as evidenced by the coincident increase
in soluble/insoluble iron content of the water. Attempts to identify the source of
dissolved hydrogen and nitrogen have also been unsuccessful.
While the licensees recent efforts to identify the root and contributing causes of
degraded RBCLC piping were acceptable after the December 12, 2002 leak, some of
the causes remained undetermined. In particular, the licensee has not yet been able to
identify the source of the abnormal chemistry parameters in the RBCLC system. The
licensees efforts were continuing in this area to identify and diagnose the RBCLC
system abnormal chemistry parameters.
3.
Structural Integrity of RBCLC Degraded Piping
a.
Inspection Scope
The team interviewed personnel, conducted a partial system walkdown, and reviewed
the licensees engineering evaluations associated with the structural integrity of the as-
found condition of the 1-1/2" diameter degraded piping in the RBCLC system to
independently assess the condition of the degraded RBCLC system piping. In
particular, the team reviewed the licensees preliminary evaluation of the system
structural integrity as documented in engineering report NER-1S-031, Rev. 00A. The
licensee evaluated the condition that they determined represented the worst case
condition. This evaluation considered the pipe degradation, and RBCLC system static
and dynamic loading (including additional loading potentially caused by transients
initiating in other systems).
The limiting location was the circumferential ligament adjacent to the section where the
December 5, 2002, leak occurred. It was located in the threaded area of the RBCLC
piping one thread adjacent to the leak. Engineering report NER-1S-031 documented
evaluations pertaining to the following:
Failure analysis of a section of 1-1/2" diameter pipe installed at the RBCLC
return line from the 11 drywell sump cooler (105-04) between check valve CKV-
70-362 and ball valve VLV-70-363;
7
Collapse load analysis for the above pipe to determine the collapse moment
capacities for various temperature conditions and sustained loads (dead weight
plus operating loads). The method used in calculating collapsing moment were
per Appendix F of ASME Code,Section III;
Piping analysis for pipe between line No. 105-04 and the 4" diameter header
pipe; and
A comparison of applied moments to the calculated collapsing moment
capacities for the applicable loading conditions:
-
Load Case a: Dead weight, design pressure 125 psig, normal RBCLC
system operating temperature 100F, and 0.05 maximum ground
acceleration for seismic loads.
-
Load Case b: Dead weight, design pressure 125 psig, and a drywell
temperature of 240F as a result of a small break loss of coolant
accident.
-
Load Case c: Dead weight, transient pressure of 142 psig, combined
with a drywell temperature of 215F as a result of a loss of offsite power
event.
The results of the piping analysis documented in NER-1S-031 were used as input to an
inelastic finite element analysis using the ANSYS Computer Program for the various
load conditions. This analysis was used to evaluate the structural integrity of the
existing ligament geometry in the threaded piping section.
b.
Findings
The licensee determined the collapse moment capacity and the applied moment for
each of the three load cases. The collapse moment capacity relates to the calculated
strength of the RBCLC piping, based upon material properties. Inherent in the
licensees analysis was that they assumed the remaining material in the measured
ligament (after the significant corrosion occurred), retained the properties of the original
piping/metal material. The applied moments were calculated for each of the loads that
would result in these cases. The analysis assumed that the integrity of the pipe would
not be maintained if the applied moment exceeded the collapse moment.
The calculated collapse moment capacities (criteria) and applied moments are
summarized in the following table (Note: all units are ft-lbs).
8
Load Case
Calculated collapse moment
capacity (Criterion)
Criterion, including
measurement tolerance
Applied
moment
a
37.8
36.6
37
b
42
40.7
40
c
42
40.7
38
Although the applied moment exceeded the collapse moment capacity for load case a,
the licensee stated that the applied moment was within 1% of the reduced collapse
moment capacity (criteria above).
The licensee stated that there was no leak evident at the ligament that was analyzed
(downstream of bronze check valve CKV-70-362). They concluded that this location
and configuration was a critical section and was the worst case (and bounding) for the
purpose of analysis. They also concluded that the critical piping section would retain
sufficient structural integrity to prevent collapse of the piping when subjected to the
design loading conditions. While the team did not identify a location or configuration
that would be more bounding, the team determined the absence of leak was not an
indication of structural integrity and/or loading capacity. Further, a leak can be
prevented by a barrier that does not have any significant structural capacity.
The team identified several additional concerns associated with the licensees analysis,
assumptions, and methodology. For example, the pipe wall thickness assumed in the
finite element analysis was a very thin ligament at the root of the pipe thread, and in
some cases, only a few thousandths of an inch. The material behavior in thin ligaments
may be significantly different than that assumed in the analysis. Very thin carbon steel
material may not exhibit the homogenous isotropic behavior assumed in the licensees
analysis; the grain size of the metal significantly affects the structural properties. The
material properties assumed in the analysis was based on the original certified material
test report (CMTR) supplied with the piping purchase order.
In addition to the above uncertainties in the material properties, there are potential of
negative cumulative errors in wall thickness measurements, i.e. magnification and
calibration tolerance/error in the electron microscope, and the caliper or other measuring
tools and equipment.
The removed section of the pipe was visually examined by the inspection team to
assess the material condition. The removed sections indicated a highly corroded piping
section with missing thread root. Even where the material was not missing, a flash light
illumination indicated a material ligament so thin that it appeared nearly translucent.
The team also learned that a full section of the pipe was able to be broken apart
manually following removal by maintenance personnel.
Finally, the team noted that the licensees analyses and evaluations were based on
assumptions that had not been substantiated by test and/or verifiable data. As such, the
licensees results were considered preliminary by the licensee and their consultants.
9
In summary, although the RBCLC system remained in operation and functional during
the operating cycle, the team concluded that the licensees evaluation did not provide an
adequate basis to demonstrate that the piping in the RBCLC system retained sufficient
structural strength/integrity when subjected to loading conditions during postulated
events. In addition, the team concluded that a passive failure of the degraded RBCLC
piping was a dominant failure mode, which resulted in an increased likelihood of a loss
of RBCLC initiating event.
4.
Corrective Actions
a.
Inspection Scope
The team interviewed licensee personnel, reviewed related corrective action program
documents, and reviewed associated licensee evaluations associated with the degraded
piping. The adequacy, extent and timeliness of the licensees corrective actions were
also assessed.
b.
Findings
Corrective Actions Implement for RBCLC Leakage
In December 2002, the licensee identified significant and widespread degradation of the
RBCLC system piping due to corrosion. This degradation occurred despite numerous
prior opportunities to identify, determine the root causes and correct the condition.
Leaks had occurred over the previous several years due to significant degradation of
small bore piping (less than 2" diameter), and a failure of this size line would result in
failure of the RBCLC system.
The team determined that the leaks that occurred on May 15, 2002, represented an
opportunity to recognize the potential significant degradation of the RBCLC system.
The more significant of the two leaks occurred at a threaded connection on the
downstream side of a flow switch associated with one of the five recirculation pump
coolers. The second leak at a threaded mechanical pipe connection associated with
another recirculation pump cooler was seal welded. At that time, the licensee attributed
those leaks to inherent leakage associated with threaded connections and noted that
leaks at the pipe connections for the seal cooling piping to and from the recirculation
pumps had been a chronic problem for many years. They failed to adequately evaluate
the cause and extent of the degraded condition. Further, the licensee failed to evaluate
an associated flow switch failure analysis report (performed by a vendor), which was
dated July 29, 2002, and provided relevant insights regarding the nature and extent of
the corrosion in the RBCLC system. This failure analysis was not included in the
licensees corrective action process, and therefore, was not adequately reviewed.
The December 5, 2002, leak also represented an opportunity for the licensee to perform
a detailed cause analysis and implement comprehensive corrective actions. This leak
was located adjacent to the 11 equipment drain cooler discharge check valve. The
licensee concluded that the carbon steel pipe was experiencing wall thinning on the
downstream side at and near threaded connections to either bronze or austenitic
stainless steel components, and that this degradation due to galvanic corrosion was
10
accelerated due to turbulent flow conditions. The area at the threaded connection that
showed the most severe degradation consisted of a very thin ligament of corroded
metal. Although the licensee identified several RBCLC pipe areas for further inspection
and repair, these actions failed to properly identify and characterize the cause and
extent of the degradation mechanism. Specifically, the licensee failed to recognize that
general internal pipe corrosion contributed substantially to the pipe wall thinning, and
that the inspection scope for susceptible piping areas should have extended beyond
dissimilar metal, turbulent flow interfaces.
Soon after the startup from the December 5, 2002, forced outage, another leak occurred
on December 12, 2002. The investigation of this leak revealed additional RBCLC piping
that was substantially degraded. During the extent of condition evaluation, the licensee
again identified wall thinning due to corrosion. However, in this instance, a dissimilar
metal and galvanic corrosion mechanism was not present. The licensee had not
previously considered that the carbon steel to carbon steel connections may also exhibit
significant corrosion. Further, the effect of threads on pipe wall thickness in conjunction
with the pipe wall thinning (absent a galvanic mechanism) had not been considered
during the previous evaluations.
Assessment of Corrective Actions
In evaluating the RBCLC system leak history and associated licensee corrective actions,
the team made several observations. In particular, the team determined that the
licensees efforts in response to the problems over the years were focused on fixing
symptoms (leaks) rather than identifying causes, determining extent of condition, and
implementing effective corrective actions. For example, the team observed the
following:
For the RBCLC system leaks identified in May 2002 and earlier, the apparent
causes did not consider mechanisms other than leakage across the threads.
DER 2002-2383 stated that it is expected that threaded piping connections that
are not seal welded will leak over an extended period of time. The cause
analysis was not sufficiently rigorous to identify that the Schedule 40 pipe wall
thickness at the threaded area was significantly less than the rest of the system.
Therefore, the cause analysis, extent of condition assessment and scope of
repairs were not sufficient to preclude additional RBCLC leakage.
Seal welding was proposed and implemented on threaded connections as a
housekeeping measure. This activity could potentially stop an active leak as a
temporary measure. However, because seal welding is not designed or credited
to restore structural integrity, it could also mask significant internal degradation
and allow continued internal corrosion to further degrade the structural integrity
of the pipe.
The licensee recognized the degraded chemistry parameters in the RBCLC
system (high chloride and sulfate concentration, low oxygen, high iron), existed
for over two years, however, the cause of these conditions had not been
identified. The licensees feed-and-bleed activities of the system only
temporarily and marginally improved the chemistry conditions.
11
In 1980, a modification was initiated to eliminate certain RBCLC threaded
connections in the drywell (in particular, threaded joints in recirculation pump
coolers to eliminate a possible leakage source). However, the modification was
not installed, and was canceled in 1994 based on low priority and continued
satisfactory system performance (two successful operating runs).
The team reviewed the licensees corrective actions following the December 12, 2002
leak (after the licensee fully recognized the cause and extent of condition). Several
immediate corrective actions were implemented. These activities included extensive
replacement of RBCLC piping and fittings inside the drywell. The majority of RBCLC
fittings and pipe (about 90%) was replaced with the more robust schedule 80 piping.
The remaining piping was determined to be acceptable through calculations in
combination with ultrasonic and visual inspections. Also, the new piping sections were
connected by welded joints (except in some cases, where prohibited by physical
interference problems).
Longer term similar actions are also in progress for RBCLC piping located outside the
drywell. The licensee similarly evaluated the existing condition of the RBCLC piping
outside the drywell by ultrasonic and visual inspections, and concluded that there was
sufficient pipe wall thickness and structural integrity to support interim continued
operation of the RBCLC system. Current licensee plans are to replace all 3" and
smaller diameter RBCLC system piping (inside and outside the drywell) with Schedule
80 welded joint piping within two years. The licensee performed testing and conducted
an evaluation and determined that the larger than 3" piping was not subject to a similar
type of failure mechanism. Regarding the chemistry issues, the licensee has been
developing an action plan to identify the source of loss of oxygen (oxygen injection and
detection), and the source of the other elevated parameters. The team found the
licensees completed and planned corrective actions to be appropriate.
Performance Assessment
The licensees failure, prior to December 12, 2002, to determine the cause of a
significant condition adverse to quality and implement corrective action to prevent
repetition, despite prior opportunities to do so, was a performance deficiency. This
failure allowed the RBCLC system to continue to degrade due to several factors,
including inadequate design and poor system chemistry. The system degraded
significantly due to general corrosion, galvanic corrosion, and flow-assisted corrosion.
In accordance with Inspection Manual Chapter (IMC) 0612, Appendix B, Issue
Disposition Screening, the team determined that the issue was more than minor
because the issue was associated with the equipment performance attribute of both the
initiating events and mitigating systems cornerstones. The significantly degraded
RBCLC piping resulted in an increase in the likelihood of the loss of the RBCLC system
due to piping failure, which directly affected the initiating events cornerstone. The loss
of the RBCLC system would also result in the loss of cooling to the feedwater and
condensate pumps, the recirculation pumps, the drywell coolers, the shutdown cooling
heat exchangers, and two of three instrument air compressors following a loss of
coolant accident or a loss of all AC power (SBO) event where AC power is recovered
12
prior to core damage, which directly affected the mitigating systems cornerstone.
Section 4OA3.5 discusses the risk analysis and assessment associated with this finding.
Enforcement
Title 10 to CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requires, in part,
that measures shall be established to assure that conditions adverse to quality are
promptly identified and corrected. In the case of significant conditions adverse to
quality, the measures shall assure that the cause of the condition is determined and
corrective action taken to prevent repetition. Contrary to this requirement, when
significant conditions adverse to quality occurred prior to, and on May 15, 2002,
involving degraded RBCLC system piping, the licensee failed to determine the cause
and the extent of the condition and failed to take appropriate corrective actions to
prevent recurrence. Specifically, an RBCLC system piping leak occurred on May 15,
2002, due to significant pipe corrosion, primarily as a result of a inadequate piping
design, application and operation. Additionally, numerous RBCLC system leaks
occurred during several preceding years. However, the cause of this condition was not
determined and corrective actions were not taken, and as a result, corrosion continued
to further degrade RBCLC system piping such that additional significant leaks occurred
on December 5, 2002, and again on December 12, 2002. These significant leaks in
December 2002 exhibited severe pipe wall loss and degraded the structural integrity of
the affected piping sections. This was an apparent violation of 10 CFR 50, Appendix B,
Criterion XVI. (AV 50-220/03-003-01)
5.
Risk Significance and Analysis of Event
a.
Inspection Scope
The team evaluated the licensees safety and availability assessment of the degraded
condition of the RBCLC system, including the associated assumption and evaluation
criteria, analysis methodology, and design inputs. The team also performed an
independent risk assessment of the finding related to the degraded RBCLC system.
The team evaluated the duration of the degraded condition, and the safety implications
associated with the cause of the degradation. The team also interviewed the cognizant
licensee risk, engineering, and operations personnel.
13
b.
Findings
SDP Phase 1:
In accordance with NRC IMC 0609, Appendix A, Significance Determination of Reactor
Inspection Findings for At-Power Situations, the team conducted a significance
determination process (SDP) Phase 1 screening and determined that the finding
degraded both the initiating event and mitigating systems cornerstones. Therefore, a
SDP Phase 2 evaluation was required.
SDP Phase 2:
The SDP Phase 2 process was not designed to estimate the risk significance of a
finding that resulted in an initiating event that induces a second initiating event.
SDP Phase 3:
Internal Initiating Events:
The NRCs Standardized Plant Analysis Risk (SPAR) model, Revision 3.01, was used to
evaluate the significance of this finding. The team determined that the SPAR model
needed to be revised to link the loss of RBCLC event tree and the anticipated transient
without scram (ATWS) event tree and to reflect the possibility of a recirculation pump
seal leak following the loss of the RBCLC system. This revision resulted in an increase
in the baseline core damage frequency from 7.88E-6 per year to 7.91E-6 per year.
Assumptions:
1.
The performance deficiency existed for in excess of a year. Therefore, the team
used an exposure time of 1 year.
2.
The RBCLC system piping was significantly degraded and lacked adequate
structural integrity. Therefore, the dominant failure mode of the RBCLC system
involved a passive failure of the piping which resulted in an increase in the
likelihood of a loss of RBCLC initiating event. The initiating event frequency was
determined by taking into account the existing failure modes of the system, the
lack of structural integrity of the piping, the numerous leaks from the RBCLC
piping over the years, and the likelihood of a leak before break in the piping.
Applying engineering judgement, the team concluded that the loss of RBCLC
initiating event frequency was approximately 5.0E-2 per year.
3.
Loss of coolant accidents and SBO events result in drywell temperatures that
induce thermal stresses in the RBCLC piping in excess of the structural
capability of the piping. Therefore, the team used a conditional failure probability
of 1.0 for the RBCLC system in these events.
4.
Failure of the RBCLC piping would result in the inability to remove heat from the
recirculation pump seals. Without cooling, the likelihood of a recirculation pump
seal leak increased substantially. Therefore, the team used a seal failure
14
probability of 0.5, which was based on the licensees recirculation pump seal
package test results.
5.
Failure of the RBCLC piping would result in system leakage in excess of the
automatic makeup capability for the system. Consequently, the RBCLC
expansion tank level would be lost and the operating RBCLC pumps would fail
due to inadequate net positive suction head (NPSH).
The team did not credit recovery of the RBCLC system because under certain
entry conditions, Annunciator Response Procedure N1-ARP-H1, Control Room
Panel H1, directed the starting of the standby RBCLC pump; and Annunciator
Response Procedure N1-ARP-H1, Special Operating Procedure N1-SOP-8,
RBCLC Failure, and Operating Procedure N1-OP-11, Reactor Building Closed
Loop Cooling System, did not provide guidance to secure the operating RBCLC
pumps when inadequate NPSH existed. Also, no procedural guidance existed to
isolate an RBCLC leak and recover the RBCLC system. In addition, because
each of the dominant accident sequences involved the failure of operator actions
prior to when RBCLC would have been recovered, the likelihood of the failure of
the operators to recover RBCLC would be dependent on those prior failures.
Consequently, the team considered the likelihood of the operators failure to
recover the RBCLC system too high to credit.
The team revised the SPAR model to reflect these assumptions, determined a revised
core damage frequency for the exposure period (1.32E-5 per year) and calculated the
change in core damage frequency ( CDF) for this finding due to internal initiating
events.
CDF = [(1.32E-5 per year) - (7.91E-6 per year)]
= 5.29E-6 per year (White)
15
This result was dominated by the following accident sequences.
Contributio
n
to CDF
Core Damage Sequence Description
4.03E-6
IE - Loss of RBCLC due to the degraded piping condition
Instrument air (IA) fails following the loss of RBCLC
RCS inventory is lost via either a stuck open SRV or unisolated
recirculation pump seal leaks
Condensate and feedwater fail due to loss of RBCLC
Operators successfully depressurize to low pressure
Core Spray successfully provides inventory control
Suppression Pool Cooling fails due to loss of IA
Shutdown Cooling fails due to loss of RBCLC
Containment spray fails
Containment venting fails due to loss of IA
5.71E-7
IE - Small break loss of coolant accident (SLOCA)
RBCLC fails due to the degraded piping condition following the SLOCA
IA fails following the loss of RBCLC
Condensate and feedwater fail due to loss of RBCLC
Operators successfully depressurize to low pressure
Core Spray successfully provides inventory control
Suppression Pool Cooling fails due to loss of IA
Containment spray fails
Containment venting fails due to loss of IA
5.26E-7
IE - Loss of RBCLC due to the degraded piping condition
IA fails following the loss of RBCLC
Condensate and feedwater fail due to loss of RBCLC
Emergency condensers fail
Operators successfully depressurize to low pressure
Core Spray successfully provides inventory control
Suppression Pool Cooling fails due to loss of IA
Shutdown Cooling fails due to loss of RBCLC
Containment spray fails
Containment venting fails due to loss of IA
6.80E-8
IE - Loss of RBCLC due to the degraded piping condition
IA fails following the loss of RBCLC
RCS inventory is lost via two or more stuck open SRVs
Condensate and feedwater fail due to loss of RBCLC
Core Spray successfully provides inventory control
Suppression Pool Cooling fails due to loss of IA
Shutdown Cooling fails due to loss of RBCLC
Containment spray fails
Containment venting fails due to loss of IA
16
External Initiating Events:
The Nine Mile Point Unit 1 probabilistic risk assessment (PRA) model U1PRA01B, dated
February 2002, includes external initiating events (e.g., seismic and fire initiating
events). Therefore, the team evaluated the results obtained using the licensees PRA
model to determine the risk contribution of the significantly degraded RBCLC piping due
to external initiating events.
Seismic:
The Nine Mile Point Unit 1 PRA model has six categories of seismic events. The model
uses the EPRI seismic hazards curves to estimate the frequencies of each of these
events. The baseline seismic-induced CDF is approximately 1.25E-6 per year. The
licensees PRA documentation stated that the model results using the Lawrence
Livermore National Laboratory seismic hazard curves would be higher by approximately
a factor of five.
The team concurred with the licensees conclusion that the significantly degraded
RBCLC piping would fail during any seismic event of 0.05g or greater in magnitude.
The licensee revised their PRA model to reflect this degraded condition and determined
that the increase in seismic-induced CDF was approximately 1.03E-7 per year. This
result was dominated by a seismic-induced loss of offsite power, failure of the RBCLC
piping, failure of instrument air, and failure to remove decay heat from containment.
The team reviewed the results and concluded that the results were reasonable and that
seismic events did not contribute significantly to CDF.
Fire:
The team determined that there were no fire scenarios that would result in conditions
that would fail the significantly degraded RBCLC piping. In addition, the team
determined that the significantly degraded RBCLC piping did not adversely impact the
mitigation of any fire events. Therefore, the team concluded that fire events did not
contribute significantly to CDF.
High Winds, Floods, and Other External Events (HFO):
The team determined that there were no HFO events that would result in conditions that
would fail the significantly degraded RBCLC piping. In addition, the team determined
that the significantly degraded RBCLC piping did not adversely impact the mitigation of
any HFO events. Therefore, the team concluded that HFO events did not contribute
significantly to CDF.
17
Potential Risk Contribution due to Large Early Release Frequency:
In BWR Mark I containments, only a subset of core damage accidents can lead to large,
unmitigated releases from the containment that have the potential to cause prompt
fatalities prior to population evacuation. Core damage sequences of concern for BWR
Mark I containments are inter-system loss of coolant accident, ATWS, SLOCA, and
transient sequences. Because the dominant accident sequences for the case involving
the significantly degraded RBCLC piping were transient and SLOCA sequences, the
finding was screened for its potential risk contribution to large early release frequency
(LERF). Using NRC Inspection Manual Chapter 0609, Appendix H, Containment
Integrity SDP, the team determined that the dominant accident sequences did not result
in a contribution to LERF because these sequences resulted in core damage following
containment failure due to a loss of containment heat removal. Thus, evacuation of the
population would have been carried out in sufficient time so that these accident
sequences would not have resulted in a contribution to LERF.
Licensees Risk Assessment:
The licensee performed a risk evaluation of the degraded RBCLC piping and concluded
that the CDF was 9.0E-7 per year and the LERF was 7.5E-8 per year. The team
reviewed the licensees results and concluded that the differences were primarily
attributable to a difference in three assumptions.
First, the licensee assumed that the RBCLC piping was degraded, but it retained
structural integrity for all initiating events except loss of coolant accidents, loss of drywell
cooling events, and seismic events greater than 0.05g in magnitude. The licensee did
not assume that the likelihood of the loss of RBCLC initiating event increased due to the
condition of the RBCLC piping. The team evaluated the licensees assumption and
concluded that it was not the most appropriate assumption for the condition.
Second, the licensee assumed that the RBCLC system would fail at one preferential
location and that the recirculation pump seals would be cooled by the boil off of the
water that would remain in the system following the pipe rupture. As a result, the
licensee assumed that the likelihood of the recirculation pump seal leak remained
unchanged. The team evaluated the licensees assumption and concluded that there
was no basis to assume that the RBCLC piping would fail at one preferential location
and that the remaining water in the system would adequately cool the recirculation pump
seals. As a result, the team evaluated the licensees assumption and concluded that it
was not the most appropriate assumption for the condition.
Lastly, the licensee assumed that recovery of the RBCLC and IA systems was possible
to provide long term heat removal from containment. The licensee assumed that the
likelihood of the operators failure to recover the RBCLC system was 0.1. The licensee
based this assumption largely on the time available to perform the recovery actions and
reliance on assistance from the Technical Support Center and the Emergency
Operations Facility. The team evaluated the licensees assumption and concluded that
it was not the most appropriate assumption for the condition for the reasons described
above (Phase 3 Assumption 5).
18
Analysis - Conclusion:
The safety significance of the inspection finding based on the increase in core damage
frequency due to internal and external initiating events is White ( CDF = 5.39E-6 per
year). The safety significance of the inspection finding based on the increase in large
early release frequency is Green ( LERF < 1.0E-7 per year). Therefore, the safety
significance of the inspection finding is White. A White finding represents a finding of
low to moderate safety significance.
4OA5 Other
(Closed) URI 50-220/2002-06-02: RBCLC System Piping Degradation Due to
Corrosion. This item was opened to evaluate the safety and risk significance of the
degraded condition of the RBCLC system. This NRC special inspection team performed
this evaluation, and identified associated licensee performance deficiencies as
documented in this inspection report. Therefore, this item is closed, and further tracking
and follow-up of this issue will be accomplished via the enforcement tracking/violation
open item identified in this report (See Section 4OA3.4 of this report).
4OA6 Meetings, including Exit
The inspectors presented the inspection results to Mr. J. Conway, Vice President, Nine
Mile Point, and other members of licensee management at the conclusion of the onsite
inspection on February 14, 2003, and on March 7, 2003, upon completion of the
combined onsite and in-office inspection activities. The licensee acknowledged the
findings presented. The team reviewed some proprietary documents during the
inspection, and these documents were identified and discussed by the NRC at the exit
meeting. Based upon subsequent discussions with the licensee, none of the information
presented at the exit meeting and included in this report was considered proprietary.
ATTACHMENT 1
KEY POINTS OF CONTACT
Licensee Personnel
M. Alvi, Lead Engineer, Design Structural
K. Churchill, System Engineer
K. Embry, Licensing Engineer
T. Kulczycky, Principle Engineer, Reliability Engineering
T. Kurtz, Engineering Services
B. Montgomery, Manager, Engineering Services
J. Murphy, Engineer, Mechanical Design
B. Randall, General Supervisor, System Engineering
J. Richards, Manager, Chemistry
NRC Personnel
G. Hunegs, Senior Resident Inspector, NMP
J. Trapp, Chief, Projects Branch 1, Region I
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
50-220/2003-03-01
Failure to Determine the Cause of a Significant Condition Adverse
to Quality and Implement Corrective Action to Prevent Repetition,
Associated with Severe Corrosion of the RBCLC System.
Closed
50-220/2002-06-02
RBCLC System Degradation
LIST OF DOCUMENTS REVIEWED
Drawings:
C-18011-C
Instrument Air System P&I Diagram, Sheet 1, Rev. 48
C-18018-C
Reactor Shutdown Cooling System P&I Diagram, Sheet 1, Rev. 25
C-18022-C
RBCLC System P&I Diagram, Sheet 2, Rev. 43
C-18022-C
TBCLC System P&I Diagram, Sheet 3, Rev. 30
C-18298-C
RBCLC System Piping at Drywell Air Coolers and Equipment Drain Sump Pit
Coolers, Rev. 6
C-18299-C
RBCLC System Piping at Drywell Air Coolers and Equipment Drain Sump Pit
Coolers, Rev. 5
C-26855-C
RBCLC System No. 70 Piping Isometric, Rev. 2
Attachment 1 (contd)
2
Calculations:
S13.4-70-TP15
RBCLC, Rev. 0
Licensing Documents:
Nine Mile Point Unit 1 Technical Specifications
Updated Safety Analysis Report - Nine Mile Point Unit 1 Nuclear Station
Deviation Event Reports (DER):
1991-560
1992-480
1993-339
2000-2139
2000-3268
2001-5201
2002-2383
2002-3143
2002-5166
2002-5193
2002-5193
2002-5280
2002-5305
Procedures:
N1-OP-11
Reactor Building Closed Loop Cooling System, Rev. 20
N1-MRM-REL-0104
Maintenance Rule Manual, Rev. 16
N1-MRM-REL-0105
Maintenance Performance Criteria, Rev. 14
Miscellaneous Documents:
Failure Analysis of Flow Switch from the RBCLC to Recirculation Pump 32-190 Cooling Water,
NMP-1, dated July 29, 2002
Design Change Package N1-02-219
Drywell Equipment Drain Tank Coolers RBCLC
Outlet Re-design, Rev. 0
Draft Evaluations
DER 2002-5305 Category 1 Root Cause Evaluation (Organizational and Cultural Assessment -
Unit 1 RBCLC System Events)
Safety and Availability Assessment - Unit 1 - RBCLC Pipe Leakage Inside Primary Containment
Reliability Group Technical Report - Unit 1 Drywell Heatup and RBCLC Drain Unit Cooler Piping
Temperature Response Evaluation
Safety and Availability Assessment - Unit 1 - RBCLC Leak Study
Attachment 1 (contd)
3
LIST OF ACRONYMS USED
Alternating Current
American Society of Mechanical Engineers
Anticipated Transient Without Scram
Apparent Violation
Boiling Water Reactor
Core Damage Frequency
CFR
Code of Federal Regulations
Certified Material Test Report
DER
Deviation Event Report
Electric Power Research Institute
HFO
High Winds, Floods, and Other External Events
Instrument Air
IMC
Inspection Manual Chapter
Mechanical Design Criteria
MS
NEI
Nuclear Energy Institute
Net Positive Suction Head
NRC
Nuclear Regulatory Commission
ppb
Parts Per Billion
Reactor Building Closed Loop Cooling
Station Blackout
Significance Determination Process
SLOCA
Small Break Loss of Coolant Accident
Standardized Plant Analysis Risk
Turbine Building Closed Loop Cooling
Unresolved Item
Change in Core Damage Frequency
Change in Large Early Release Frequency
ENCLOSURE 2
February 4, 2003
MEMORANDUM TO:
James Trapp, Manager
Special Inspection
Steve Pindale, Leader
Special Inspection
FROM:
A. Randolph Blough, Director
/RA/
Division of Reactor Projects
SUBJECT:
SPECIAL INSPECTION CHARTER - NINE MILE POINT
UNIT NO. 1
A special inspection has been established to inspect and assess the reactor building closed
loop cooling (RBCLC) system piping degradation that was identified at Nine Mile Point Unit 1 in
December 2002. The special inspection will be conducted onsite during the week of
February 10, 2003, and will include:
Manager:
James Trapp, Chief, Projects Branch 1
Leader:
Steve Pindale, DRS
Members:
Suresh Chaudhary, DRS
Edward Knutson, Resident Inspector at Nine Mile Point
Eugene Cobey, Senior Risk Analyst - Part Time
On December 5, Unit 1 was shut down due to unidentified system leakage inside the drywell.
Leakage was subsequently identified from the RBCLC system. The piping degradation resulted
in system leaks and potentially adversely impacted the structural integrity of the system. The
RBCLC system is cooled by service water and provides demineralized water to cool auxiliary
equipment located in the reactor, turbine and waste disposal building. The RBCLC system
provides cooling water to major components including equipment drain tank coolers, drywell air
coolers and recirculation pump coolers located in the drywell in addition to fuel pool heat
exchangers, instrument air compressors, feedwater pumps, condensate pumps and feedwater
booster pumps.
2
This special inspection was initiated in accordance with NRC Inspection Procedure 71153
Event Follow-up and NRC Management Directive 8.3, NRC Incident Investigation Program.
The decision to perform this special inspection was based largely on the postulated loss of
safety function of the feedwater coolant injection system (high pressure reactor makeup source
is dependent on RBCLC) and the increased conditional core damage probability (CCDP) for this
condition. The inspection will be performed in accordance with the guidance of NRC Inspection
Procedure 93812, Special Inspection, and the inspection report will be issued within 45 days
following the exit meeting for the inspection. If you have any questions regarding the objectives
of the attached charter, please contact James Trapp at 610-337-5186.
Attachment: Special Inspection Charter
Special Inspection Charter
Nine Mile Point Unit No. 1
Reactor Building Closed Loop Cooling System Piping Degradation
The objectives of the inspection are to determine the facts and assess the conditions
surrounding the reactor building closed loop cooling system piping degradation that occurred at
Nine Mile Point Unit 1 on December 2002. Specifically the inspection should:
a.
Assess the adequacy of the licensees root cause evaluation of the condition.
b.
Assess the adequacy of the licensees extent of condition review and corrective actions
for the condition.
c.
Assess the effectiveness of prior corrective actions for the previous leaks in the reactor
building closed loop cooling system.
d.
Evaluate the licensees assessment of the risk significance of the condition, including
evaluation of all input assumptions.
e.
Independently evaluate the risk significance of the condition.
f.
Assess the applicability/effectiveness of the licensees piping inspection program.
g.
Assess the design adequacy of the RBCLC piping material compatibility.
h.
Document the inspection findings and conclusions in a special inspection report in
accordance with Inspection Procedure 93812 within 45 days of the exit meeting for the
inspection.