ML040300067
| ML040300067 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 01/29/2004 |
| From: | Casto C Division of Reactor Safety II |
| To: | Rosalyn Jones Duke Energy Corp |
| References | |
| EA-04-018, IR-03-002 IR-04-007 | |
| Download: ML040300067 (15) | |
See also: IR 05000269/2004007
Text
January 29, 2004
Duke Energy Corporation
ATTN: Mr. Ronald A. Jones
Vice President
Oconee Site
7800 Rochester Highway
Seneca, SC 29672
SUBJECT:
OCONEE NUCLEAR STATION - NRC INSPECTION REPORT NO.
05000269/2004007, 05000270/2004007, AND 05000287/2004007
Dear Mr. Jones:
On January 21, 2004 the U.S. Nuclear Regulatory Commission (NRC) completed an in-office
and site inspection to resolve a previously identified issue at your Oconee Nuclear Station. The
purpose of the inspection was to review Unresolved Item 05000269,270,287/2003003-002,
High Energy Line Break (HELB) Accident Scenario Review that was identified in an inspection
performed during the week of June 16 - 20, 2003. The enclosed report documents the results
of this inspection which were discussed on January 27, 2004, with your staff.
This inspection was an examination of 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. Within these areas, the inspection consisted of selected examinations of records,
documents, discussion with NRC staff, and interviews with licensee personnel.
This report documents an apparent violation which 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 Web site at www.nrc.gov; select What We Do, Enforcement,
then Enforcement Policy. The apparent violation involved the application of 10 CFR 50.59 for
a May 2001 revision to the Oconee Updated Final Safety Analysis Report for the HELB analysis
in which the licensee failed to identify Unreviewed Safety Questions and changes involving
more than minimal increase in risk which required prior NRC approval. 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.
2
An open predecisional enforcement conference to discuss this apparent violation will be
scheduled at a future date. The NRC will contact you regarding this date. The decision to hold
a predecisional enforcement conference does not mean that the NRC has determined that a
violation has occurred or that enforcement action will be taken. This conference is being held
to obtain information to assist the NRC in making an enforcement decision. This may include
information to determine whether a violation occurred, information to determine the
significance of a violation, information related to the identification of a violation, and information
related to any corrective actions taken or planned. The conference will provide an opportunity
for you to provide your perspective on these matters and any other information that you believe
the NRC should take into consideration in making an enforcement decision.
You will be advised by separate correspondence of the results of our deliberations on this
matter. No response regarding the apparent violation is required at this time.
In accordance with 10 CFR 2.790 of the NRCs "Rules of Practice," a copy of this letter and its
enclosure 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).
Sincerely,
\\\\RA\\\\
Charles A. Casto, Director
Division of Reactor Safety
Docket Nos. 50-269, 50-270, 50-287
License Nos. DPR-38, DPR-47, DPR-55
Enclosure:
Inspection Report No. 05000269/2004007, 05000270/2004007, and
cc w/encl:
Noel Clarkson
Compliance Manager (ONS)
Duke Energy Corporation
Electronic Mail Distribution
(cc w/encl contd - See page 3)
3
(cc w/encl contd)
L. E. Nickolson
Safety Assurance Manager (ONS)
Duke Energy Corporation
Electronic Mail Distribution
Lisa Vaughn
Duke Energy Corporation
Mail Code - PB05E
422 South Church Street
P.O. Box 1244
Charlotte, NC 28201-1244
Anne Cottingham
Winston and Strawn
Electronic Mail Distribution
Beverly Hall, Acting Director
Division of Radiation Protection
N. C. Department of Environmental
Health & Natural Resources
Electronic Mail Distribution
Henry J. Porter, Director
Div. of Radioactive Waste Mgmt.
S. C. Department of Health and
Environmental Control
Electronic Mail Distribution
R. Mike Gandy
Division of Radioactive Waste Mgmt.
S. C. Department of Health and
Environmental Control
Electronic Mail Distribution
County Supervisor of
Oconee County
415 S. Pine Street
Walhalla, SC 29691-2145
Lyle Graber, LIS
NUS Corporation
Electronic Mail Distribution
(cc w/encl contd - See page 4)
4
(cc w/encl contd)
M. T. Cash, Manager
Regulatory Issues & Affairs
Duke Energy Corporation
526 S. Church Street
Charlotte, NC 28201-0006
Peggy Force
Assistant Attorney General
N. C. Department of Justice
Electronic Mail Distribution
Enclosure
U. S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos:
50-269, 50-270, 50-287
License Nos:
Report No:
05000269/2004007, 05000270/2004007 and 05000287/2004007
Licensee:
Duke Energy Corporation
Facility:
Oconee Nuclear Station, Units 1, 2, and 3
Location:
7800 Rochester Highway
Seneca, SC 29672
Dates:
June 20, 2003 - January 21, 2004
Inspectors:
M. Scott, Senior Reactor Inspector
Approved by:
Mark S. Lesser, Chief
Engineering Branch 2
Division of Reactor Safety
Enclosure
SUMMARY OF FINDINGS
IR 05000269/2004-007, 05000270/2004-007, 05000287/2004-007; 06/20/2003 - 01/21/2004;
Oconee Nuclear Station, Other Activities.
The inspection was conducted by a senior reactor inspector. An apparent violation was
identified for making a change to the facility in 2001 that involved Unreviewed Safety Questions
and more than a minimal increase in risk, without prior NRC approval pursuant to
10 CFR 50.59. With completion of the Updated Final Safety Analysis Report a (UFSAR)
change, the licensee accepted the attendant, non-conforming safety issues contained therein.
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.
NRC Identified Findings
Cornerstone: Mitigating Systems
Apparent Violation: The inspectors identified an apparent violation of 10 CFR 50.59
(a)(1) (1999 version of 10 CFR) which states, in part, that the licensee may make
changes in the facility as described in the safety analysis report without prior
Commission approval, provided the proposed change does not involve an unreviewed
safety question (USQ). 10 CFR 50.59 (a)(2) states, in part, that a proposed change
involves an USQ if the probability of occurrence or malfunction of equipment important
to safety previously evaluated in the safety analysis report may be increased, or if it may
create an accident different from any previously evaluated.
On May 17, 2001, the licensee made a change to the facility, as described in the
Updated Final Safety Analysis Report, Section 3.6.1.3, associated with the High Energy
Line Break (HELB) analysis, which involved unreviewed safety questions, and failed to
obtain prior NRC approval. The UFSAR Section was changed to increase the maximum
initiation time following HELB of Emergency Feedwater from 15 to 30 minutes and of
High Pressure Injection from 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> (based on referenced reports and
analysis). The analysis discussed an increased cycling of pressurizer Safety Relief
Valves on steam and water, boiler condenser mode of decay heat removal, and an
unapproved computer code for application to HELB, but failed to recognize that such
changes may increase the probability of occurrence or the consequences of a
malfunction of equipment important to safety or may create an accident different from
any previously evaluated. In addition, the change resulted in more than a minimal
increase in risk. (Section 4OA5)
This is an Apparent Violation pending results of an enforcement conference.
Enclosure
REPORT DETAILS
Other Activities
4OA5 Other Activities
(Closed) URI 50-269, 270, 287/2003003-02, HELB Accident Scenario Review
Introduction. An apparent violation was identified for making a change to the facility in
2001 that involved Unreviewed Safety Questions and more than a minimal increase in
risk, without prior NRC approval pursuant to 10 CFR 50.59.
Description. URI 05000269,270,287/2003003-002, HELB Accident Scenario Review,
was identified concerning Oconee Updated Final Safety Analysis Report (UFSAR)
Section 3.6.1.3 that was changed on May 17, 2001. The change was made prior to
licensee implementation of the revised 10CRF50.59 rule, and therefore was evaluated
as to whether or not it involved an unreviewed safety question (USQ). The inspectors
determined that the change involved some USQs.
The UFSAR change was associated with the licensees high energy line break (HELB)
analysis for main feedwater piping. The escaping water/steam is assumed to disable
the 4160 Volt breakers for at least the motor driven emergency feedwater (EFW) pumps
and for the high pressure injection (HPI) pumps, and the automatic initiation of the
turbine driven EFW pump. The change was to evaluate a delay in the time allowed for
manual restoration of EFW from 15 minutes to 30 minutes and HPI from 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> to 8
hours. The EFW time to initiation was extended when it was recognized through
operator action validation timelines, that it took longer than 15 minutes to provide EFW
from other manual sources. The time extension for HPI injection appeared to be related
to the licensees desire to reduce site manning established to support HPI cable
switching to an alternate power source. The resulting effect on plant equipment is that
the pressurizer safety relief valves (SRV) are required to cycle an additional 15 minutes
for up to 30 minutes until EFW is started and will change from relieving steam to
relieving water, reactor coolant system (RCS) subcooling is lost, significant RCS voiding
occurs, natural circulation cooling is lost, and decay heat is removed by the boiler
condensing mode (BCM) for up to eight hours. Delaying EFW initiation may effect the
thermally induced compressive and tensile stresses on the Once Through Steam
Generator (OTSG) tubes resulting from refilling a dryed out steam generator. Extended
reliance on BCM has several implications which have not been reviewed by the NRC,
including computer modeling assumptions, cyclical stresses on the RCS resulting from
pressure spikes and vibration, and a possible reactivity excursion upon reinitiating of
RCS flow due to diluted boron concentration in the cold leg. The inspectors determined
that delaying the initiation of safety systems beyond the existing licensing basis time
requirements may increase the probability or consequences of a malfunction of
equipment (SRV, RCS boundary) and may create the possibility of an accident or
malfunction of a different type than previously evaluated and therefore is a USQ that
requires NRC approval.
2
Enclosure
Safety Relief Valve Concern
The licensees calculation, OSC-7299, revision 0, and referenced report (Duke Power
MDS Report No. OS-73.2) was the basis for the previous recovery times for EFW and
HPI (15 minutes and 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, respectively). Revision 1 to the calculation introduced the
increased recovery times. The 10 CFR 50.59 evaluation indicated that one of the key
assumptions was that the SRVs would lift and reseat with water passing through the
valves. Originally, the SRVs would be challenged and would undergo 5 cycles on steam
in 15 minutes. With the longer recovery times associated with the May 2001 change,
the licensees calculation indicted that SRVs would undergo 6 challenges on steam and
8 additional challenges with water in 30 minutes. The licensees safety evaluation
stated, Increasing the time allowed to re-establish these flows has no significant effect
on the operation of the associated pumps and fluid systems. It additionally stated, As
described in the Safety Review, this activity only allows additional time before equipment
is required to be placed in operation following a postulated HELB. The equipment will
be operated in the same manner as it previously was, so there are no new alignments
associated with this change. Since the equipment is utilized in the same way as it
previously was, the consequences of a malfunction of equipment will not increase.
The inspectors were concerned that the licensees assumption that the SRVs
successfully reseat each time is critical to recovery without core damage. With a stuck
open valve and no safety injection, core damage would result. The inspectors
determined that the licensees assumption did not have adequate basis. The SRVs
were not designed to function in this manner and have not been adequately
demonstrated to perform in this manner. The licensees evaluation did not address that
the increased number of cycles of these valves on steam and the change in medium to
water may increase the probability of a malfunction (i.e., sticking open or closed) and
create the possibility of an accident of a different type (loss of coolant or overpressure).
The evaluation added no more technical content to the discussion on malfunctions.
In the OSC-7299 calculation the two actual SRVs are modeled as one valve. The
calculation does not address the impact on the risk importance of this modeling. NRC
review of the risk indicates that each SRV lift, and the change of medium from steam to
water, has a certain probability of failure. With the increased number of challenges, the
overall probability that the SRV(s) will fail open during the event increases. With a failed
open SRV, and no HPI, core damage will result. Given an increased SRV failure
probability, the delta core damage frequency for the applicable core damage accident
sequences stemming from the HELB initiating event was evaluated by the NRC as
greater than 1E-6. NEI Guidance 96-07 (paragraph 4.3.1, Example three) indicates
that a change to the plant that causes an increase in event frequency exceeding 1E-6
per year would require NRC approval prior to making the change.
The licensee provided additional information to support their position. The licensee
considered the SRVs adequate based upon NRC acceptance of the Electric Power
Research Institute (EPRI) test program on SRVs, which was completed as part of a
Three Mile Island Action Plan item, and a letter from Dresser, the SRV vendor. NRC
3
Enclosure
Safety Evaluation (SER) Report for NUREG-0737, Item II.D.1, Performance Testing of
Relief and Safety Valves for Oconee Unit 1, 2, and 3 (TAC 44600, 44601, 44602) dated
July 19, 1989, accepted SRV performance for UFSAR Chapter 15 accident and
transient scenarios. Reference 8, (EPRI document NP-2628-SR, PWR and Relief
Valve Test Program: Safety and Relief Valve Test Report, December 1982) is the
performance test report on power operated relief valves and SRVs. The report states
that: The objective of the ... Program was to perform full scale operability tests on a set
of primary system relief and safety valves representative of the those utilized in or
planned for use in PWRs ..... The test conditions were selected to be representative of
those expected in participating PWRs based on consideration of limiting UFSAR, cold
overpressrization, and extended high pressure liquid injection events.
The EPRI study was conducted in 1981 and included a Dresser model 31739A SRV
found at Oconee. The Oconee equivalent SRV was tested with several (4) water lifts
and did reseat. It is noted that the valves in the EPRI test had not been exposed to a
containment harsh environment for some portion of a fuel cycle prior to being tested,
which could influence real valve lifts. Although the Oconee similar valve was tested with
consecutive lifts, it had been rebuilt prior to the water lifts. NRC staff opinion is that the
testing was very limited and not sufficient to demonstrate the valves would successively
re-close with multiple actuations of the subject postulated event beyond the limited lifts
addressed in the above-mentioned SER. In the EPRI study, the number of valves
tested is not sufficient from a quality assurance standard to demonstrate high reliability.
The small EPRI sample size could not reasonably provide justification for valve
confidence during consecutive challenges as modeled in the loss of 4160 Volt HELB
scenario unique to Oconee.
The inspectors determined that the SRV performance during the HELB scenario is not
bounded by the EPRI test program, nor by the SER. The SER accepts the Dresser
31739A safety valve blowdown results because it does not impede natural circulation
due to hot leg voiding. Limiting transients are identified as Loss of Main Feedwater
(LOFW) and Feedwater Line Break (FWLB) (Reference 22 of the SER). Generic plant
transients are listed but do not include the loss of 4160 Volt power and TDEFW in a
HELB. The limiting transients assumptions indicate a single failure of one emergency
feedwater pump, a Loss of Offsite Power (LOOP), no credit for PORV actuation among
other things, but does not assume loss of 4160 Volt power, therefore the original
scenarios did not address the unique Oconee vulnerability - loss of 4160 Volt power
resulting in the loss of HPI. With a LOOP, the standard emergency power is sequenced
on and pump injection occurs within a very short time. With these limiting transients, the
RCS/pressurizer fills within several minutes and decay heat is being effectively removed
a short time thereafter. Natural circulation loss is not jeopardized by the scenarios.
With these limiting transients, there is a very unlikely chance of core damage, because
even with an SRV failure, HPI and EFW is promptly available. During these scenarios,
the SRVs lift 3 to 4 times as opposed to the Oconee unique UFSAR change of May
2001, which challenges the SRVs 14 times, eight of which are with water. The change
to Section 3.6.1.3 transient contrasts sharply with above generic limiting scenarios. The
SER does not accept SRV performance as the licensee proposed in the HELB
evaluation.
4
Enclosure
The licensee provided a valve vendor memorandum (dated 9-19-03). The licensee did
not have this information available for the creation of the May 2001 UFSAR change.
Although the memo did provide some information regarding testing on similar valves
under various conditions, the various testing information did not represent the revision 1
HELB transient. The new vendor information did not provide a failure rate on the
subject SRVs and did not address probabilistic reliability of the valves under water lifts.
The vendor information did indicate the valve was capable under two phase lifts
(saturated steam, not saturated water). However, the information stated that there has
been no cycle testing for the Oconee type valve, outside of the EPRI testing. The
inspectors determined the changes in performance required by the SRVs represent a
USQ because the probability of occurrence or a malfunction may be increased, or an
accident of a different type (loss of coolant) may be created.
Delayed EFW Initiation Concern on Steam Generator Tubes
The inspectors questioned the delayed EFW initiation effects on the once through steam
generators (OTSG) under the HELB scenario. The long straight tubes in a Babcock &
Wilcox OTSG have existing axial loading analysis, described in the UFSAR (such as
Section 3.9), due to temperature differences between the OTSG components (tubes to
shell), when refilling a dryed out OTSG. The Oconee Emergency Operating
Procedures have limits on temperature changes (stated to be +100 and -60 degree F
differential temperatures, tensile and compression, respectively for Units 2 & 3). These
limits are assumed to be manageable with immediate injection capability, but with
delayed injection timing could be critical to prevent exceeding the limits. In the loss of
4160 Volt HELB scenario, EFW flow would be delayed for up to 30 minutes instead of
15 minutes and HPI injection is further delayed. With delayed injection, cold to hot leg
temperature differences are driving this divergence combined with other cooling effects.
Thus, the differential temperature across the OTSGs would be a potential
concern/consideration in the scenarios evaluation. Excessive stresses could cause
OTSG tubes to crack or rupture. The inspectors were concerned that these issues had
not been addressed in the licensees evaluative documents. From this the inspectors
concluded that this is a USQ because of the possibility that an accident different from
any previously evaluated may be created, such as a steam generator tube rupture or
excessive accident induced tube leakage concurrent with a HELB.
Boiler Condenser Mode Concern
The introduction of BCM was a new mode of long term (8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />) decay heat removal
added to the UFSAR via the May 2001 change. Per Revision 1 to OSC-7299
calculation, enough volume will be lost from the RCS via the SRVs and Reactor Coolant
Pump (RCP) seals leakage such that, significant voiding will occur, natural circulation
and subcooling is lost, and BCM is relied upon after 30 minutes into scenario. BCM
cooling comes from core decay heat and steam rising up the hot leg and condensing in
the OTSG tubes. This condition or mode could persist up to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> under the scenario
until RCS is under some form of pressure and temperature control. The licensee used
RELAP5 software to model the RCS response, which was different than the model
previously used. This computer code has not been approved for use in HELB by the
5
Enclosure
NRC, nor has the NRC been afforded the opportunity to review the licensees
assumptions. The inspectors were unable to conclude that the RELAP5 modeling
reasonably reflected actual conditions, timeline/chronology, and magnitude of changes
in the plant during the scenario. The calculation generally indicated that results were
very sensitive to EFW initiation timeline and other model/scenario facets.
Within the scenario, the reactor coolant significantly boils and chugs as steam is
condensed in the reactor coolant components under saturated RCS and increased
voided volume conditions, thus creating potential component vibration and multiple
pressure spikes that constitute mechanical cycles. There is no practical industry
experience with this mode of cooling or impact discussion of the possible induced stress
and fatigue to plant equipment. The UFSAR (chapters 3 and 5) addresses dynamic
loading and fatigue analysis of primary piping and components. The inspectors were
concerned that the licensees evaluation did not address the challenges to the
mechanical components of the plant with many more dynamic cycles present for up to
eight hours. For example, UFSAR Sections 3.9.1.1 and Table 5.2 indicate cycle
transients that the RCS has been designed to withstand and the HELB/BCM is not
indicated. Additionally, Section 3.9.3 discusses design and dynamic loads to meet
Section 3.1.33 RCS pressure boundary capability criterion. The 10 CFR 50.59 review of
the UFSAR and support documentation did not recognize this potential problem. The
inspectors could not determine the effects of operation in the BCM for an extended
period on plant equipment. From this the inspectors concluded that this is a USQ
because of the possibility that an accident different from any previously evaluated
(structural failures and loss of coolant) may be created.
The inspectors questioned the potential for recriticality with BCM. Babcock and Wilcox
Nuclear Technologies (BWNT) submitted a potential 10 CFR Part 21 report to the NRC
on July 31, 1995. Report number 1995-186 contained a potential safety concern on
post small break loss of coolant accident (SBLOCA). The document was not discussed
in the 10 CFR 50.59 evaluation. The report provided preliminary information on the
potential for core recriticality caused by a reactivity insertion due to moderator dilution
while in BCM. The report reads in part, "During the course of a small break LOCA and
any other transients that involve the partial loss of reactor coolant system (RCS)
inventory, the steam generators may provide an energy sink for part or all of the core
decay heat via boiler/condenser operation. In this mode, steam generated in the core
through boiling is passed through the hot legs to the steam generators and condensed.
The condensate is returned to the core through the cold legs. Because boron volatizes
at a concentration substantially below that of the source, the concentration of boron
carried with the steam is greatly reduced with the result that the boron concentration
downstream from the steam generator is gradually reduced. Evaluation of the boron
carryover fraction with the MULTI-Q code shows that the fraction is temperature
dependent and limited to ten percent for the conditions of interest." In the report, BWNT
had indicated that they would provide additional information at a later date. When asked
by the inspectors, the licensee produced a Framatome document, 77-5002260-00
Evaluation of Potential Boron Dilution Following Small Break Loss-of-Coolant Accident.
This September 1998 document indicated that with HPI and EFW injection from the
onset of small break that a cold leg reactivity insertion on the bump of a RCP would
6
Enclosure
cause a recriticality of 15 to 35 percent with some core damage possible. The
document did not discuss the possible mechanical effects of cool, deborated water in
the core during recriticality (e.g., potential prompt criticality with steam expansion/rapid
core voiding). The inspectors were concerned that due to the timeline differences,
injection pump availability variances, and the potential for natural circulation recriticality,
the conditions of the 1998 document appear to be sufficiently different than those of the
May 2001 HELB transient, that documentation of those differences and the exact
potential for recriticality and potential damage must be evaluated. The licensees
evaluation did not address recriticality potential with the HPI return at eight hours. The
licensees stated position was that although the occurrence of BCM can result in an
addition of positive reactivity under natural circulation, the risk of a significant core
power excursion leading to core damage is low. The 10 CFR 50.59 Rule in effect at the
time the May 2001 evaluation was written did not allow any increase in risk in a facilty
change without prior NRC approval. From this the inspectors concluded that this is a
USQ because of the possibility that an accident different from any previously evaluated
may be created.
Analysis. The finding is not suitable for evaluation using the SDP. The SRV concern
alone was evaluated by separate probabilistic risk analysis. Given the increased SRV
failure probability alone (assumed failure probability with water medium of 0.1), the delta
core damage frequency for the applicable core damage accident sequences stemming
from the HELB initiating event was greater than 1E-6. NEI Guidance 96-07 indicates
that a change to the plant that causes an increase in event frequency exceeding 1E-6
per year would require NRC approval prior to make the change. The significance of this
finding, based on the increase in risk associated with the SRV change alone is low to
moderate.
Enforcement. 10 CFR 50.59 (a)(1) (1999 edition) states in part, that the licensee may
make changes in the facility as described in the safety analysis report without prior
Commission approval, provided the proposed change does not involve an USQ.
10 CFR 50.59 (a)(2) states, in part, that a proposed change involves a USQ if the
probability of occurrence or the consequences of a malfunction of equipment important
to safety previously evaluated in the safety analysis report may be increased or if the
possibility for an accident or malfunction of different from any previously evaluated may
be created.
On May 17, 2001, the licensee made a change to the facility, as described in the
Updated Final Safety Analysis Report, Section 3.6.1.3, associated with the High Energy
Line Break (HELB) analysis, which involved unreviewed safety questions, and failed to
obtain prior NRC approval. Specifically, calculation OSC-7299 was changed to increase
the maximum initiation time following HELB of Emergency Feedwater from 15 to 30
minutes and of High Pressure Injection from 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. The analysis discussed
increased cycling of pressurizer Safety Relief Valves on steam and water and, boiler
condenser mode of decay heat removal, and an unapproved computer code for
application to HELB, but failed to recognize that such changes may increase the
probability of occurrence or the consequences of a malfunction of equipment important
to safety or may create an accident different from any previously evaluated.
7
Enclosure
The licensee has not placed this issue into the corrective action program, or
acknowledged this as a performance deficiency.
This is being treated as an apparent violation (AV), 50-269, 270, 287/2004007-01,
Failure to Obtain Prior NRC Approval to a Change to the Facility involving Unreviewed
Safety Questions on High Energy Line Break Analysis.
4OA6 Meetings, including Exit
The NRC presented the inspection finding to Mr. Noel Clarkson on January 27, 2004 via
a telephone conversation. The licensee acknowledged the finding presented.
Proprietary information is not included in this inspection report.
8
Attachment
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee:
N. Clarkson, Regulatory Compliance Manager
D. Garland, Operations Senior Engineer
L. Nicholson, Safety Assurance Manager, Oconee Nuclear Station
G. Swindlehurst, Nuclear Engineering Manager
NRC personnel:
NRR personnel
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
50-269, 270, 287/2004007-01
Failure to Obtain Prior NRC Approval to a Change
to the Facility Involving Unreviewed Safety
Questions on High Energy Line Break Analysis
Closed
50-269, 270, 287/2003003-02
HELB Accident Scenario Review