ML040270203
| ML040270203 | |
| Person / Time | |
|---|---|
| Site: | Comanche Peak  |
| Issue date: | 01/27/2004 |
| From: | Chamberlain D Division of Reactor Safety I |
| To: | Blevins M TXU Energy |
| References | |
| EA-04-009, IR-02-009 | |
| Download: ML040270203 (9) | |
See also: IR 05000445/2002009
Text
January 27, 2004
Mr. M. R. Blevins, Senior Vice President
and Principal Nuclear Officer
TXU Energy
ATTN: Regulatory Affairs
Comanche Peak Steam Electric Station
P.O. Box 1002
Glen Rose, Texas 76043
SUBJECT: COMANCHE PEAK STEAM ELECTRIC STATION - SPECIAL TEAM INSPECTION
REPORT 05000445/2002-09 - PRELIMINARY WHITE FINDING
Dear Mr. Blevins:
This letter discusses a finding that appears to have low to moderate safety significance. As
described in the subject inspection report issued on January 9, 2003, the finding involved the
failure to identify and correct an indicated flaw in a steam generator tube during Refueling
Outage 1RF08. Failure to remove the tube from service resulted in a steam generator tube
leak. The finding was characterized as an Apparent Violation pending the determination of its
safety significance. As noted in the inspection report, since your staff removed the leaking tube
from service, it did not present an immediate safety concern. This finding was assessed based
on the best available information, including influential assumptions, using the applicable
Significance Determination Process (SDP) and was preliminarily determined to be a White
finding. The finding was preliminarily determined to have a low to moderate safety significance
because of the inability of the degraded tube to meet its required safety margins, as indicated
by the in-situ testing failures and the associated inability to withstand some severe accident
conditions, resulting in an increase in the large early release frequency ( LERF) for this
performance deficiency. We have provided a summary of the Phase 3 Significance
Determination as an enclosure to this report.
There were some differences between your safety assessment, as documented in your letters
to the NRC dated March 5 and April 9, 2003, and the significance determination performed by
the NRC. These differences included your use of thermal-hydraulic models that predicted much
lower steam generator tube temperatures during severe accidents than the NRC models
predict. This results in much lower tube failure probabilities than in the NRCs analysis. The
agencys models are not designed to be overly-conservative, given the current state of
knowledge. The staff considers its model results to be the best currently available basis for
risk-informing inspection efforts in this technical area. In addition, your analysis treats the flaw
as being smaller and stronger than we believe your data actually indicates. We believe that the
-2-
NRC model uses your data in a more objective manner. Finally, in the last of the models you
offered for consideration (the fully linked Level 1 and 2 logic model treatment) there appears to
be a problem with the truncation level used in the analysis. If corrected, we believe that your
model may well support a risk conclusion similar to the conclusion of the NRCs risk analysis.
The finding is also an apparent violation of NRC requirements, as discussed in Section 02.02 of
the inspection report, 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
Before we make a final decision on this matter, we are providing you an opportunity (1) to
present to the NRC your perspectives on the facts and assumptions used by the NRC to arrive
at the finding and its significance at a Regulatory Conference or (2) submit your position on the
finding to the NRC in writing. If you request a Regulatory Conference, it should be held within
30 days of the receipt of this letter, and we encourage you to submit supporting documentation
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. If you
decide to submit only a written response, such submittal should be sent to the NRC within
30 days of the receipt of this letter.
Please contact Charles Marschall at 817-860-8185 within 10 business days of the date of the
receipt 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 these inspection findings at this time. In addition, please be advised that the number
and characterization of apparent violations in the inspection report, referenced in the subject
line of this letter, may change as a result of further NRC review.
In accordance with 10 CFR 2.790 of the NRCs 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).
Sincerely,
/RA/
Dwight D. Chamberlain, Director
Division of Reactor Safety
Docket: 50-445
License: NPF-87
-3-
Enclosure: SDP Phase 3 Summary
cc w/enclosure:
Roger D. Walker
Regulatory Affairs Manager
TXU Generation Company LP
P.O. Box 1002
Glen Rose, TX 76043
George L. Edgar, Esq.
Morgan Lewis
1111 Pennsylvania Avenue, NW
Washington, DC 20004
Terry Parks, Chief Inspector
Texas Department of Licensing
and Regulation
Boiler Program
P.O. Box 12157
Austin, TX 78711
The Honorable Walter Maynard
Somervell County Judge
P.O. Box 851
Glen Rose, TX 76043
Chief, Bureau of Radiation Control
Texas Department of Health
1100 West 49th Street
Austin, TX 78756-3189
Environmental and Natural
Resources Policy Director
Office of the Governor
P.O. Box 12428
Austin, TX 78711-3189
Brian Almon
Public Utility Commission
William B. Travis Building
P.O. Box 13326
1701 North Congress Avenue
Austin, TX 78711-3326
Susan M. Jablonski
Office of Permitting, Remediation and Registration
Texas Commission on Environmental Quality
MC-122
P.O. Box 13087
Austin, TX 78711-3087
-4-
Electronic distribution by RIV:
Regional Administrator (BSM1)
DRP Director (ATH)
DRS Director (DDC)
Senior Resident Inspector (DBA)
Branch Chief, DRP/A (WDJ)
Senior Project Engineer, DRP/A (TRF)
Senior Reactor Analyst (DPL)
Staff Chief, DRP/TSS (PHH)
RITS Coordinator (NBH)
ACES Director (GFS)
Senior Reliability and Risk Analyst (SML)
JDixon-Herrity, OE (JLD)
RFranovich, NRR (RLF2)
DOCUMENT: R:\_CPSES\CP2002-09 CHOICE WHITE LETTER.WPD
RIV:DRS/EB RIV:DRS NRR:DSSA/SPSB C:DRS/EB C:DRP/A
WCSifre DPLoveless SMLong CSMarschall WDJohnson
CSM = E CSM = T CSM = E /RA/ /RA/
01/27/04 01/26/04 01/26/04 01/22/04 01/26/04
D:ACES D:DRS
GFSanborn DDChamberlain
/RA/ /RA/
01/26/04 01/27/04
OFFICIAL RECORD COPY T=Telephone E=E-mail F=Fax
ENCLOSURE
Significance Determination Process
Phase 3 Summary
A. Overview of Issue
A failure to identify and correct a clearly detectable steam generator tube flaw indication
during eddy current examinations in the 2001 refueling outage (1RF08) resulted in the
tube remaining in service until it leaked in September of 2002. The tube subsequently
failed in-situ testing, indicating that it would not have met design basis accident
requirements.
B. Significance Determination Basis
1. Reactor Inspection for IE, MS, B cornerstones
a. Phase 1 screening logic, results and assumptions
The team determined that a Significance Determination Process Phase 2 analysis
was required because the issue resulted in the failure of a reactor coolant system
barrier, specifically a steam generator tube leak.
b. Phase 2 Risk Evaluation
In accordance with Inspection Manual Chapter 0609, Appendix A, the inspectors
conducted a Phase 2 estimation using the Risk-Informed Inspection Notebook for
Comanche Peak Steam Electric Station, Unit 1, Revision 1. The dominant affected
accident sequences are provided in Table b-1. This finding increases the likelihood
of an initiating event, specifically, the Steam Generator Tube Rupture; therefore, the
initiating event likelyhood was increased by one order of magnitude in accordance
with Manual Chapter 0609, Appendix A, Attachment 2.
The Phase 2 estimation resulted in a preliminary WHITE finding. Therefore, the
analyst determined that the finding should be evaluated using the Phase 3 process.
TABLE b-1
PHASE 2 DOMINANT ACCIDENT SEQUENCES
Initiating Event Sequence Contribution
Steam Generator Tube Rupture SGTR-EQ1/ISO-SDC 8
(SGTR)
SGTR-EIHP-EQ2/ISO 7
SGTR-AFW-MKRWST 6
SGTR-AFW-FB 6
SGTR-AFW-EIHP 7
Enclosure -2-
c. Phase 3 Analysis
The analysts conducted an assessment of the Comanche Peak steam generator
tube degradation that was as independent as was feasible while using the licensees
information to make the assessment specific to Comanche Peak. By reviewing the
differences in the analysts and licensees underlying assumptions of the physical
phenomena involved in this analysis, the licensee identified some appropriate
sensitivity studies to perform on both analyses. Upon consideration of all results, the
analysts concluded that the best estimate point value of the change in large early
release frequency ( LERF) for this performance deficiency was 5.5 x 10-7/year. This
frequency range corresponds to a white finding in the significance determination
process.
The assessment of risk for this degraded tube was evaluated for the following three
types of severe accident sequences:
(1) Core Damage Sequences Initiated by Spontaneous Tube Rupture:
In this case, the in-situ test demonstrated that the tube was capable of
withstanding pressure differentials in the range encountered during normal
operation; therefore, the analysts concluded that there was no increase in risk
associated with spontaneous tube rupture sequences.
(2) Core Damage Sequences Initiated by Secondary Depressurization Events that
Induce Tube Rupture:
Because the in-situ test was not capable of reaching the pressure difference that
would be created by a design-basis secondary depressurization event, it was
necessary to use information from the eddy current inspections to estimate the
burst pressure for the flawed tube. The predicted burst pressure was greater
than the differential pressure that would be experienced during a design-basis
depressurization event. However, the predicted burst pressure also had a
significant amount of uncertainty, leaving some probability that the tube would
actually have burst if exposed to the elevated pressure differential.
A probability distribution for the burst pressure was developed based on the
in-situ test results and the predicted uncertainty in the model. The analysts
estimated the induced rupture probability as the fraction of this probability
distribution that was below the pressure difference created by the accident
sequence. The analysts increased estimated induced rupture probability as a
function of time to account for crack growth during the last operating cycle. The
analysts used a series of burst probabilities for specific time periods during the
last year of operation with the flawed tube.
As shown in Table c-1, the analyst used a frequency of 1 x 10!3 per reactor-year
for the frequency of a secondary depressurization event, a probability of 0.25
(1 out of 4) that the depressurization event affects the steam generator with the
flawed tube, and a conditional probability of 1 x 10!2 that the combined
secondary depressurization event and tube rupture will result in core damage.
The time periods in Table c-1 are based on the licensees estimated crack
Enclosure -3-
growth rate. Summing the risk contributions for all time periods in the year
produces a result of 2.35 x 10!8 per reactor-year for the increase in core damage
frequency.
The analysts adjusted these values to reflect a slower crack growth rate than
was estimated by the licensee. The analysts used the 95th percentile crack
growth rate (15% of the wall thickness per year) from a Westinghouse database,
instead of the licensees estimate of 27% per year. The slower crack growth rate
increased the risk estimate by predicting that the crack had been in a condition
susceptible to rupture for a longer period of time before it was discovered. The
adjustment in the growth rate resulted in a frequency of 4.2 x 10-8/year. Because
the tube rupture and secondary pressure boundary failure create a direct path to
the atmosphere, this result is also the LERF.
TABLE c-1
RESULTS OF STAFFS ANALYSIS FOR SECONDARY
DEPRESSURIZATION SEQUENCES
Initiating Event Core Damage
Frequency Time Period Probability Burst Frequency
(per year) (fraction of last year) SG 2 Affected Probability CCDP (per year)
1 x 10-3 3/12 1/4 0 1 x 10-2 0
1 x 10-3 4.5/12 1/4 0.004 1 x 10-2 3.75 x 10-9
1 x 10-3 1.5/12 1/4 0.009 1 x 10-2 2.81 x 10-9
1 x 10-3 1/12 1/4 0.015 1 x 10-2 3.13 x 10-9
1 x 10-3 1/12 1/4 0.024 1 x 10-2 5.00 x 10-9
1 x 10-3 0.9/12 1/4 0.039 1 x 10-2 7.31 x 10-9
1 x 10-3 0.1/12 1/4 0.072 1 x 10-2 1.50 x 10-9
TOTAL 2.35 x 10-8
(3) Core Damage Sequences Initiated by Other Phenomena that Induce
Tube Rupture by Creating Abnormally High Temperatures in the Tube
Material:
The burst pressure predicted in the previous section for the flawed tube is
based on its strength at normal operating temperatures. If a core
damage accident occurs in a manner that does not depressurize the
reactor coolant system before the reactor core melts, physical testing has
demonstrated that the hot gases from the core will reach and overheat
the steam generator tubes. The increase in temperature substantially
reduces the burst pressure of the tube. The pressure difference across
the tubes in a steam generator with a depressurized secondary side
would be sufficient to rupture this cracked tube at the higher
temperatures. Consequently, the portion of the plants baseline core
Enclosure -4-
damage frequency that produces the conditions necessary to rupture the
cracked tube becomes an additional contribution to the large early
release frequency because of the crack.
The staffs analysis for this contribution starts with the frequency of the
plant damage states (PDSs) in the licensees PRA that have the
characteristics necessary to heat the tubes with the reactor coolant
system at high pressure. This is multiplied by the probability that the
reactor coolant system will not become depressurized before the tube
ruptures and by the probability that the secondary side of the steam
generator does become depressurized. The product is further reduced
by a factor of 0.5 to account for the probability that the tube is in the part
of the steam generator tube bundle that heats up most rapidly. The next
reduction factor is the fraction of the last year of operation during which
the degradation of the tube made it susceptible to failure under these
severe conditions. Finally, the licensees baseline contribution to the
large early release frequency is subtracted from the result to produce the
incremental change caused by the flaw. An outline of the calculation is
presented in Table c-2.
The analysts total risk estimate for the subject finding is the sum of the
estimated change in risk for the three types of severe accident
sequences documented in the preceding sections. This summation is
provided in Table c-3. The result falls into the white range for the
LERF.
TABLE c-2
ANALYSIS FOR SEVERE ACCIDENT SEQUENCES
THAT INDUCE TUBE RUPTURE
Data Used: Frequency (per year)
or Probability:
Sum of Relevant PDS Frequencies: 4.0x10!5
Probability of RCS Depressurization during Core Damage Progression: x 0.5
Probability that Steam Generator Containing the Flaw is Depressurized: x 0.1
Probability that the Flaw is in Hottest Part of the Tube Bundle: x 0.5
Fraction of Last Year that the Flaw was Vulnerable to Rupture: x 0.57
Total Estimated LERF with Flaw: 5.7x10!7
IPE Baseline LERF from Severe Accident Induced Tube Rupture: - 5.6x10!8
TOTAL ESTIMATED LERF: 5.1x10!7
Enclosure -5-
TABLE c-3
STAFFS TOTAL RISK ESTIMATE
Type of Tube Rupture: LERF (per year)
Spontaneous 0
Induced by Secondary Depressurization Events + 4.2 x 10-8
Induced by Core Damage Accidents + 5.1 x 10-7
TOTAL LERF 5.5 x 10-7