ML18152B374

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Forwards Preliminary Accident Sequence Precursor Analysis of Operational Condition Which Was Discovered at Surry Power Station,Unit 1 on 980509 & Reported in LER for Review & Comment
ML18152B374
Person / Time
Site: Surry 
Issue date: 08/11/1999
From: Edison G
NRC (Affiliation Not Assigned)
To: Ohanlon J
VIRGINIA POWER (VIRGINIA ELECTRIC & POWER CO.)
References
NUDOCS 9908160116
Download: ML18152B374 (25)
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e UNITED S rATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555--0001 Mr. J.P. O'Hanlon Senior Vice President - Nuclear Virginia Electric and Power Company 5000 Dominion Blvd.

Glen Allen, Virginia 23060 August 11, 1999

SUBJECT:

REVIEW OF PRELIMINARY ACCIDENT SEQUENCE PRECURSOR ANALYSIS OF OPERATIONAL EVENT AT SURRY POWER STATION, UNIT 1

Dear Mr. O'Hanlon:

Enclosed for your review and comment is a copy of the preliminary Accident Sequence Precursor (ASP) analysis of an operational condition which was discovered at Surry Power Station, Unit 1, on May 9, 1998 (Enclosure 1 ), and was reported in Licensee Event Report (LER) No. 280/98-009. This analysis was prepared by our contractor at the Oak Ridge National Laboratory (ORNL). The results of this preliminary analysis indicate that this condition may be a precursor for 1998. In assessing operational events, an effort was made to make the ASP models as realistic as possible regarding the specific features and response of a given plant to various accident sequence initiators. We realize that licensees may have additional systems and emergency procedures, or other features at their plants that might affect the analysis.

Therefore, we are providing you an opportunity to review and comment on the technical adequacy of the preliminary ASP analysis, including the depiction of plant equipment and equipment capabilities. Upon receipt and evaluation of your comments, we will revise the conditional core damage probability calculations where necessary to consider the specific information you have provided. The object of the review process is to provide as realistic an analysis of the significance of the event as possible.

In order for us to incorporate your comments, perform any required reanalysis, and prepare the final report of our analysis of this event in a timely manner, you are requested to complete your review and to provide any comments within 30 days of receipt of this letter. We have streamlined the ASP Program with the objective of significantly improving the time after an event in which the final precursor analysis of the condition is made publicly available. As soon as our final analysis of the condition has been completed, we will provide for your information the final precursor analysis of the condition and the resolution of your comments.

We have also enclosed several items to facilitate your review. Enclosure 2 contains specific guidance for performing the requested review, identifies the criteria which we will apply to determine whether any credit should be given in the analysis for the use of licensee-identified additional equipment or specific actions in recovering from the event, and describes the specific information that you should provide to support such a claim. Enclosure 3 is a copy of LER No.

280/98-009, which documented the condition.

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9908160116 990811 PDR ADOCK 05000280 S

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'L J. P. O'Hanlon August 11, 1999 Please contact me at 301-415-1448 if you have any questions regarding this request. This request is covered by the existing 0MB clearance number (3150-0104) for NRG staff followup review of events documented in LERs. Your response to this request is voluntary and does not constitute a licensing requirement.

Docket No:-;.: 50-280

Enclosures:

As stated Distribution:

(D.o.clreLEile-ili PUBLIC PDll-1 R/F CHawes GEdison OGG ACRS Sincerely, ORIGINAL SIGNED BY:

Gordon E. Edison, Senior Project Manager, Section 1 Project Directorate 11 Division of Licensing Project Management Office of Nuclear Reactor Regulation LPlisco, RII SMays, RES PO'Reilly, RES DOCUMENT NAME: G:\\PDll-1\\SURRY\\sps198st.wpd To receive a copy of this document, indicate in the box C=Copy w/o attachment/enclosure E=Copy with attachment/enclosure N = No co OFFICE PDll-1/PM NAME GEdison:cn REmch DATE 81 b /99 I

/99 OFFICIAL RECORD COPY

J. P. O'Hanlon \\~

Please contact me at 301-415-1448 if you have any questions regarding this request. This request is covered by the existing 0MB clearance number (3150-0104) for NRC staff followup review of events documented in Lf:Rs. Your response to this request is voluntary and does not constitute a licensing requirement.

Docket No. 50-280

Enclosures:

As stated Sincerely, Gordon E. Edison, Senior Project Manager, Section 1 Project Directorate II Division of Licensing Project Management Office of Nuclear Reactor Regulation

Mr. J. P. O'Hanlon Virginia Electric and Power Company cc:

Mr. Donald P. Irwin, Esq.

Hunton and Williams Riverfront Plaza, East Tower 951 E. Byrd Street Richmond, Virginia 23219 Mr. E. S. Grecheck Site Vice President Surry Power Station Virginia Electric and Power Company 5570 Hog Island Road Surry, Virginia 23883 Senior Resident Inspector Surry Power Station U. S. Nuclear Regulatory Commission 5850 Hog Island Road Surry, Virginia 23883 Chairman Board of Supervisors of Surry County Surry County Courthouse Surry, Virginia 23683 Dr. W. T. Lough Virginia State Corporation Commission Division of Energy Regulation P. 0. Box 1197 Richmond, Virginia 23209 Robert B. Strobe, M.D., M.P.H.

State Health Commissioner Office of the Commissioner Virginia Department of Health P.0. Box 2448 Richmond, Virginia 23218 Surry Power Station Office of the Attorney General Commonwealth of Virginia 900 East Main Street Richmond, Virginia 23219 Mr. J. H. McCarthy, Manager Nuclear Licensing & Operations Support Innsbrook Technical Center Virginia Electric and Power Company 5000 Dominion Blvd.

Glen Allen, Virginia 23060 Mr. W. R. Matthews Site Vice President North Anna Power Station

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e LER No. 280/98-009 Event

Description:

Unisolable reactor coolant system leak Date of Event:

May 9, 1998 Plant:

Surry Power Station, Unit 1 Event Summary LER No. 280/98-009 Surry Power Station, Unit 1 (Surry 1), was shut down after personnel discovered an unisolable 0.25-gal/min leak in the reactor coolant system (RCS) seal injection line to the C reactor coolant pump (RCP). The leak was at the RCP thermal barrier and was caused by thermal fatigue coupled with vibration stress acting on a preexisting fault in the toe of a pipe weld. The vibration stress was the result of a loose rod hanger. The estimated conditional core damage probability (CCDP) associated with this event is 1.4 x 10-5*

Event Description On May 9, 1998, with Surry I at I 00% power, operators noted an increase in the RCS leak rate. The leakage was within Technical Specification (TS) limits [0.25 gal/min (Ref. I) vs. 1.0 gal/min (TS)]. Operations personnel entered containment and reported a leak near the 1.5-in. seal injection line to the C RCP at the thermal barrier. Operators reduced the power level to 50% to reduce radiation levels in the containment building so that personnel could determine the exact location of the leak. A weld leak on the seal injection line near the C RCP thermal barrier was confiIIIled. Surry I proceeded to cold shutdown and an Unusual Event was declared. 2 The C RCP seal injection line was removed from the RCP thermal barrier. The failed weld was excavated and a new line was welded in place. A root cause evaluation determined that a preexisting flaw existed in the toe of the failed weld. The most probable causes for the weld failure were a lack of fusion of the weld material or thermal fatigue coupled with vibration stress. A loose rod hanger that supports the seal injection line may have contributed to the vibration stress.2 Additional Event-Related Information Each RCS loop contains a vertical single stage centrifugal pump with a controlled leakage seal assembly. The controlled leakage seal assembly (primary seal) restricts leakage along the pump shaft. A second seal directs leakage past the primary seal and out of the pump. A third seal minimizes the leakage of water and vapor from the pump into the containmt..1t atmosph(;re. Some hii:,:1-pressure water from the charging pumps is injected into the RCP between the impeller and the controlled leakage seal. [The charging pumps also serve as the high-pressure injection (HPI) pumps when required.] Part of the charging water flow enters the RCS through a

  • labyrinth seal in the lower pump shaft to serve as a buffer to keep hot reactor coolant from entering the upper portion of the pump. The remainder of the seal injection flow is directed along the drive shaft through the 1

LER No. 280/98-009 primary seal and back to the charging system through the seal-water heat exchanger. Component cooling water is supplied to cooling coils around the labyrinth seal (thermal barrier) in the lower pump shaft. This thermal barrier heat exchanger serves to remove heat from any RCS coolant that may leak up the RCP shaft if the seal injection flow is interrupted.3 The reported leak was in a weld on the 1.5-in. seal injection line just above the thermal barrier. A catastrophic failure of the seal injection line at this weld would allow high pressure RCS coolant to leak past the thermal barrier and out the failed seal injection line. This RCS loss of coolant could not be isolated. Hence, a break in the seal injection line would be an unisolable small-break LOCA.

Emergency Diesel Generator (EDG) #2 was unavailable during this event because of maintenance. This EDG is dedicated to Unit 2 and would not affect this event unless further complications from a loss of offsite power (LOOP) were to occur during a LOCA.

Modeling Assumptions This event was modeled as a potential small-break LOCA in the seal injection line to the C RCP. In the actual event, the pipe crack developed slowly and began to leak. This leakage was detected, and the plant was shut down while the seal injection line remained substantially intact. It is possible, however, that the crack could have developed differently, resulting i, catastrophic failure of the injection line before detection. NUREG/CR-6582, Assessment of Pressurized Water Reactor Primary System Leaks4, shows those leak types with the highest potential for relatively rapid growth include leaks through thermal fatigue cracks in branch lines, such as existed in this case.

The probability of a "rupture-before-leak" failure mode was estimated using service-based piping,reliability data developed by the Swedish Nuclear Power Inspectorate (SKI). 5 The probability of pipe rupture represents the likelihood that a defect could have progressed to a rupture. The conditional probability of a seal injection line rupture was estimated using data related to thermal-fatigue-induced piping failures included in the recently developed SKI piping failure database. 5 The SKI database currently includes more than 2300 pipe failure records that represent about 4300 reactor-years of operating experience. For failures due to thermal fatigue, 18 cracks and leaks, but no ruptures, were observed in stainless steel piping 1 to 2 in. in diameter. Using Bayesian statistics with a noninformative prior", a conditional probability of rupture because of thermally induced fatigue of2.4 x 10-2 was estimated.b Because no ruptures have occurred because of this mechanism, "The use of a noninformative prior is described on page 5-36 of the PRA Procedures Guide, NUREG/CR-2300, Januacy 1983. A number of alternate estimators have been proposed for the case where no failures have been observed.

See, for example, Section 5.5 ofNUREG/CR-2300 and R. T. Bailey's article "Estimation from Zero-Failure Data" in RiskAnalysis, Vol. 17, No. 3, June 1997.

h An alternative to the "data-driven" model that constitutes the SKI effort is the application of probabilistic fracture mechanics models. These models enable the calculation of failure probabilities assuming that *piping is susceptible to anticipated degradation mechanisms especially those that develop over a long period. Ref. 5 notes that under a similar set ofboundary conditions, the two approaches tend to produce similar (i.e., the same order of magnitude) results.

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LER No. 280/98-009 this estimate is uncertain. If a much larger experience base were available, it is possible that the estimated probability for a rupture-before-leak failure occurring would be lower. However, several thermal fatigue-induced failures also included cyclic f~tigue (vibration-induced fatigue) as a contributing factor (as noted in the Event Description, this may have been the case in this event as well). Among the 78 failures reported in the SKI data base, two cyclic fatigue-related ruptures have been observed. Again, using a Bayesian statistic with a noninformative prior,.an estimated conditional probability of cyclic fatigue-related ruptures of3.2 x 10-2 was estimated. This is approximately the same conditional probability as the 2.4 x 10-2 estimate for thermally induced fatigue-related ruptures. These values are consistent with the average number of piping failures that are ruptures estimated in 1981 by Thomas (Ref 6) 8 and are about a factor of 4 smaller than the break-before-leak probability developer! by the Electric Power Research Institute (EPRI) in 1992 (Ref 7).b Because a 1.5-in. break would be a small-break LOCA, the initiating frequency was adjusted from 2.3 x 10-6 to 2.4 x 10-2 for this leak event to account for the increased likelihood of a fatigue-related rupture. Because the leak location was not isolable, the basic event representing the probability of failure to isolate a small-break LOCA in the short-term (SLOCA-XHE-NOREC) was adjusted from 4.3 x 10-1 to 1.0 (TRUE).

The Accident Sequence Precursor (ASP) model for Surry was also revised to address the probability of rapidly depressurizing the RCS and using the low-pressure injection (LPI) system to cool the core ifHPI were to fail.

. The Surry individual plant examination (IPE) report7 states that the operators are direct<td to use secondary heat removal capabilities to depressurize the RCS until LPI flow is sufficient to cool the c5re. The probability of the operators failing to depressurize the RCS and initiating LPI was assumed to be 0.31, consistent with Ref

8.

A seal line rupture would also reduce injection flow to the other two RCPs. This would allow warmer RCS coolant to leak through the primary seal of the unaffected RCPs; warmer RCS coolant could affect the life of these RCP seals. This effect was not modeled as part of this analysis. Furthermore, a seal line rupture would offer less resistance to coolant flow than nominal RCS backpressure and would allow more injection flow to exist in the seal injection line. Because charging flow and HPI flow are provided by the same pumps, a seal line rupture would reduce the amount of available HPI flow to the core. Because any reduction in HPI flow was not expected to be significant compared to nominal HPI flow, this effect was also not modeled as part of this analysis.

Analysis Results The CCDP for a postulated small-break LOCA associated with the leaking seal injection line weld is estimated to be l.;4 x 10-5_ The dominant sequence, sequence 13 in Fig. 1, involves "Reference 6 estimated that between 2 and 45% (on average, -6%) of piping failures were catastrophic, depencfr1g on the failure cause.

  • Unfortunately, piping failures caused by high-cycle fatigue were not separately enumerated.

Reference 6 further estimates that with respect to catastrophic failures, 3% were low-cycle fatigue failures, 20% were vibration-related fatigue failures, and 20% were associated with "thermal shock."

bReference 7 estimated that the probability of a break-before-leak varied from 0.09 to 0.11, depending on pipe size.

3

LER No. 280/98-009 a postulated seal injection line break (small-break LOCA) given the weld leak, successful reactor trip and secondary side cooling, failure to isolate the small-break LOCA in the short tenn, failure ofHPI, and failure to rapidly cool down and depressurize to LPI pressures.

The dominant sequence accounts for one-half (50%) of the total contribution to the CCDP. The dominant cut sets in this sequence involve an operator failure to cool down and depressurize the RCS in a timely manner following a failure ofHPI.

The next most dominant sequence, sequence 4 in Fig. 1, involves a postulated seal injection line break (small-break LOCA) given the weld leak, successful reactor trip and secondary side cooling, failure to isolate the small-break LOCA in the short tenn, successful HPI and primary cooldown to RHR. entry conditions,

  • failure of RHR, successful containment spray recirculation (CSR), and failure of high-pressure recirculation (HPR).

This sequence accounts for an additional 42% of the total contribution to the CCDP. The dominant cut sets in this sequence involve failures of 4160-Y ac buses lH and lJ. These individual bus failures affect, among others, the following components:

RHR suction valves MOY 1700 (powered from bus HI) and MOY 1701 (powered from bus lJ); because these valves are in series and both valves have to open in order to have successful RHR, the loss of either bus will result in a loss of RHR, RWST supply valves MOY 1115B (powered from bus IH) and MOY l l 15D (powered from bus lJ);

because these valves are in parallel and both valves have to close in order to have successful HPR, failure to close either valve will result in a loss ofHPR.

Hence, the failure of bus IH or bus lJ will result in the failure ofRHR and HPR.

Substantial uncertainty is associated with the CCDP estimated for this event, primarily because of uncertainty in the conditional probability of pipe rupture. In addition to the uncertainty related to zero-event data described in Modeling Assumptions, Ref. 5 describ~s, among others, the following sources of uncertainty: coverage and completeness of the SKI data collection effort, data aggregation and exposure time estimation issues, identification of appropriate reliability attributes (e.g., pipe diameter, piping material) and influence factors (such as design and operating practices), plant-to-plant differences, and in-plant differences.

In one probabilistic fracture mechanics study" cited in Ref. 5, a three orders of magnitude difference existed in the "Probabilistic Pipe Fracture Evaluations for Leak-Rate Detection Applications, NUREG/CR-6004, 1995.

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LER No. 280/98-009 conditional rupture probability for leaking 100-800 mm pipe (10*4 ~ p ~ 10*1), depending on (1) the materr~J, (2) whether the crack was in the base metal, or (3) if the crack was in a weld (as it was for this event). For stainless steel, the conditional probability for weld cracks was about two orders of magnitude higher than for cracks in base metal.

Definitions and probabilities for selected basic events are shown in Table 1. The conditional probabilities associated with the highest probability sequences are shown in Table 2. Table 3 lists the sequence logic associated with the sequences listed in Table 2. Table 4 describes the system names associated with the dominant sequences. Minimal cut sets associated with the dominant sequences are shown in Table 5.

Acronyms accident sequence precursor conditional core damage probability

. containment spray recirculation emergency diesel generator Electric Power Research Institute high-pressure injection high-pressure recirculation individual plant examination ASP CCDP CSR EDG EPRI HPI HPR IPE IRRAS LOCA LOOP LPI LPR MDP MOV RCP RCS RHR.

RWST SKI Integrated Reliability and Risk Analysis System loss-of-coolant accident loss of offsite power low-pressure injection low-pressure recirculation motor-driven pump motor-operated valve reactor coolant pump reactor coolant system residual heat removal refueling water storage tank Swedish Nuclear Power Inspectorate TS technical specifications References

1.

10 CFR 50, Part 50. 72 report # 34200.

2. LER 280/98-009, Rev. 0, "Nonisolable Leak of Reactor Coolant Pump Seal Injection Line Weld," June 3, 1998.
3. Surry Power Station Units 1 & 2, Updated Final Safety Analysis Report.

5

LER No. 280/98-009

4.

Shah, V. N., et. al., Assessment of Pres::urized Water Reactor Primary System Leaks, NUREG/CR-6582, December 1998.

5. R. Nyman, D. Hegedus, B. Tamie, and B. Lydell, Reliability of Piping System Components, Framework for Estimating Failure Parameters from Service Data, SKI Report 97:26, December 1997.
6. H. M. Thomas, "Pipe and Vessel Failure Probability," Reliability Engineering, 2:83 (1981).
1. Pipe Failures in U.S. Commercial Nuclear Power Plants, EPRI TR-100380, July 1992.
8. Virginia Electric and Power Company, Probabilistic Risk Assessment for the Individual Plant Examination, Final Report, Surry Units 1 and 2, August 1991.

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Event name IE-LOOP IE-SGTR IE-SLOCA IE-TRANS ACP-BAC-LP-lH ACP-BAC-LP-IJ EPS-DGN-FC-2 FRCI-XHE-XM HPI-CKV-CC-DIS HPI-CKV-CC-SUCT HPI-MDP-CF-RUN HPI-MOV-CF-DIS HPI-MOV-CF-SUCT HPI-MOV-CF-VCT HPI-MOV RWSTA e

LER No. 280/98-009 Table 1. Definitions and Probabilities for Selected Basic Events for LER No. 280/98-009 Base Current Description probability probability Type Initiating Event-LOOP (Excludes 1.6 E-005 I O.OE+OOO the Probability of Recovering Offsite Power in the Short Term)

Initiating Event-Steam Generator 1.6 E-006 O.OE+OOO Tube Rupture Initiating Event-Small-Break 2.3 E-006 2.4 E-002 LOCA Initiating Event-Transient 3.2 E-004 O.OE+OOO Division 1HacPower4160VBus 9.0E-005 9.0 E-005 Fails Division lJ ac Power 4160V Bus 9.0 E-005 9.0 E-005 Fails EDG2Fails 3.0 E-002 1.0 E+OOO TRUE Operator Fails to Cool Down and 3.1 E-001 3.IE-001 NEW Depressurize the RCS in a Timely Manner Following HPI Failure Failure ofHPI Discharge Check 1.0 E-004 1.0 E-004 Valves Failure ofHPI Suction Check 2.0E-004 2.0E-004 Valves From RWST Common-Cause Failure ofHPI 2.2E-005 2.2 E-005 Pumps to Run Common-Cause Failure ofHPI 2.6E-004 2.6E-004 Discharge Motor-Operated Valves (MOVs)

Common-Cause Failure ofHPI 2.6E-004 2.6 E-004 Suction MOVs From the Refueling Water Storage Tank (RWST)

Common-Cause Failure ofHPI 2.6 E-004 2.6E-004 Suction MOVs From the Volume Control Tank HPI/RWST Isolation MOV 1115B 3.0 E-003 3.0 E-003 Fails 8

Modified for this event Yes Yes Yes Yes No No Yes No No No No No No No No

e LER No. 280/98-009 Table 1. Definitions and Probabilities for Selected Basic Events for LER No, 280/98-009 (Continued)

Event Base Current name Description probability probability Type HPI-MOV HPI /RWSTisolation MOY 1115D 3.0 E-003 3.0 E-003 RWSTB Fails HPR-XHE-XM Operator Fails to initiate the HPR 1.0 E-003 1.0 E-003 System LPI-MDP-CF-AB Common-Cause Failure ofLPI 5.6 E-004 5.6 E-004 Motor-Driven Pumps LPR-MOV-CF-HPR Common-Cause Failure of Cross-2.6 E-004 2.6 E-004 Tie MOVs to HPR LPR-MOV-CF-RWST Common-Cause Failure ofLPR 2.6 E-004 2.6 E-004 RWST Isolation Valves LPR-MOV-CF-SUMP Common-Cause Failure of Sump 2.6 E-004 2.6E-004 Isolation Valves PCS-VCF-HW Turbine Bypass Valves/ Condenser/

3.0 E-003 3.0 E-003 Circulating Water Failures PCS-XHE-XM-Operator Fails to Initiate Cool Down 1.0 E-003 1.0 E-003 CDOWN RHR-MOV-CC-RHR Suction MOV 1700 Fails 3.0 E-003 3.0 E-003 SUCA RHR-MOV-CC-RHR Suction MOY 1701 Fails 3.0 E-003 3.0 E-003 SUCA RHR-XHE-XM Operator Fails to Activate the RHR 1.0 E-003 1.0 E-003 System SLOCA-04-NREC SLOCA Sequence 04 1.0 E+oOO 1.0 E+OOO Non-Recovery Probability - Failure to Recover HPR SLOCA-07-NREC SLOCA Sequence 07 1.0 E+OOO 1.0 E+OOO Non-Recovery Probability-Failure to Recover HPR SLOCA-10-NREC SJ.OCA Sequence 10 8.4 E-001 8.4 E-001 Non-Recovery Probability-Failure to Recover HPI SLOCA-XHE-Operator Fails to Recover From an 4.3 E-001 1.0 E+OOO TRUE NOREC SLOCA in the Short-Term 9

Modified for this event No No No No No No No No No No No No No No Yes

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e e

LER No. 280/98-009 Table 2. Sequence Conditional Probabilities for LER No. 280/98-009 Conditional Event tree Sequence core damage Percent name number probability contribution (CCDP)

SLOCA 13 7.2 E-006 49.9 SLOCA 04 6.0 E-006 41.7 SLOCA 07 8.4 E-007 5.8 Total (all.sequences) 1.4 E-005 Table 3. Sequence Logic for Dominant Sequences for LER No. 280/98-009 Event tree name Sequence Logic number SLOCA 13

/RT, /AFW, SLOCA-NR, HPI, COOL-LPI SLOCA 04

/RT, /AFW, SLOCA-NR, /HPI,

/COOLDOWN, RHR, /CSR,.HPR SLOCA 07

/RT, /AFW, SLOCA-NR, /HPI, COOLDOWN,

/CSR,HPR 10

e e

LER No. 280/98-009 Table 4. System Names for LER No. 280/98-009 System name Logic AFW No or Insufficient Flow From the Auxiliary Feedwater System COOL-LPI Rapid Cool Down and Depressurization to LPI Pressures

e LER No. 280/98-009 Table 5. Conditional Cut Sets for Higher Probability Sequences for LER No. 280/98-009 Cut set Percent number contribution CCDP" Cut sehh SLOCA Sequence 13 7.2 E-006 1

22.9 1.6 E-006 SLOCA-XHE-NOREC, HPI-MOV-CF-VCT, FRC 1-XHE-XM, SLOCA-10-NREC 2

22.9 1.6 E-006 SLOCA-XHE-NOREC, HPI-MOV-CF-DIS, FRCI-XHE-XM, SLOCA-10-NREC 3

22.9 1.6 E-006 SLOCA-XHE-NOREC, HPI-MOV-CF-SUCT, FRC 1-XHE-XM, SLOCA-10-NREC 4

17.4 1.2 E-006 SLOCA-XHE-NOREC, HPI-MOV-CC-SUCT, FRCl-XHE-XM, SLOCA-10-NREC 5

8.7 6.2 E-007 SLOCA-XHE-NOREC, HPI-MOV-CC-DIS, FRC 1-XHE-XM, SLOCA-10-NREC 6

1.9 1.4 E-007 SLOCA-XHE-NOREC, HPI-MDP-CF-RUN, FRCl-XHE-XM, SLOCA-10-NREC SLOCA Sequence 04 6.0 E-006 1

35.9 2.2 E-006 SLOCA-XHE-NOREC, ACP-BAC-LP-lH, SLOCA-04-NREC 2

35.9 2.2 E-006 SLOCA-XHE-NOREC, ACP-BAC-LP-lJ, SLOCA-04-NREC 3

3.6 2.2 E-007 SLOCA-XHE-NOREC, RHR-MOV-CC-SUCA, HPI-MOV-00-RWSTA, SLOCA-04-NREC 4

3.6 2.2 E-007 SLOCA-XHE-NOREC, RHR-MOV-CC-SUCB, HPI-MOV-00-RWSTA, SLOCA-04-NREC 5

3.6 2.2 E-007 SLOCA-XHE-NOREC, RHR-MOV-CC-SUCA, HPI-MOV-00-RWSTB, SLOCA-04-NREC 6

3.6 2.2 E-007 SLOCA-XHE-NOREC, RHR-MOV-CC-SUCB, HPI-MOV-00-RWSTB, SLOCA-04-NREC 7

1.2 7.2 E-008 SLOCA-XHE-NOREC, RHR-XHE-XM, HPI-MOV-00-RWSTA, SLOCA-04-NREC 8

1.2 7.2 E-008 SLOCA-XHE-NOREC, RHR-XHE-XM, HPI-MOV-00-RWSTB, SLOCA-04-NREC 9

1.2 7.2 E-008 SLOCA-XHE-NOREC, RHR-MOV-CC-SUCA, HPR-XHE-XM, SLOCA-04-NREC 12

e e

LER No. 280/98-009 Table 5. Conditional Cut Sets for Higher Probability Sequences for LER No. 280/98-009 ( continued)

Cut set number 10 Percent contribution 1.2 SLOCA Sequence 07 1

25.8 2

25.8 3

8.6 4

8.6 5

8.6 6

4.8 7

2.9 8

2.3 9

2.3 10 2.3 11 1.6 Total (all sequences)

CCDP" 7.2 E-008 8.4 E-007 2.2 E-007 2.2 E-007 7.2 E-008 7.2 E-008 7.2 E-008 4.0 E-008 2.4 E-008 1.9 E-008 1.9 E-008 1.9 E-008 1.3 E-008 1.4 E-005 Cut setsb SLOCA-XHE-NOREC, RHR-MOV-CC-SUCB, HPR-XHE-XM, SLOCA-04-NREC SLOCA-XHE-NOREC, PCS-VCF-HW, HPI-MOV-00-RWSTA, SLOCA-07-NREC SLOCA-XHE-NOREC, PCS-VCF-HW, HPI-MOV-00-RWSTB, SLOCA-07-NREC SLOCA-XHE-NOREC, PCS-VCF-HW, HPR-XHE-XM, SLOCA-07-NREC SLOCA-XHE-NOREC, PCS-XHE-XM-CDOWN, HPI-MOV-00-RWSTA, SLOCA-07-NREC SLOCA-XHE-NOREC, PCS-XHE-XM-CDOWN, HPI-MOV-00-RWSTB, SLOCA-07-NREC SLOCA-XHE-NOREC, PCS-VCF-HW, LPI-MDP-CF-AB, SLOCA-07-NREC SLOCA-XHE-NOREC, PCS-XHE-XM-CDOWN, HPR-XHE-XM, SLOCA-07-NREC SLOCA-XHE-NOREC, PCS-VCF-HW, LPR-MOV-CF-HPR, SLOCA-07-NREC SLOCA-XHE-NOREC, PCS-VCF-HW, LPR-MOV-CF-SUMP, SLOCA-07-NREC SLOCA-XHE-NOREC, PCS-VCF-HW, LPR-MOV-CF-RWST, SLOCA-07-NREC SLOCA-XHE-NOREC, PCS-XHE-XM-CDOWN, LPI-MDP-CF-AB, SLOCA-07-NREC "The conditional probability for each cut set is determined by multiplying the probability of the initiating event by the probabilities of the basic events in that minimal cut set. The probability of the initiating events are given in Table 1 and begin with the designator "IE."

The probabilities for the basic-events also are given in Table 1.

~asic event, SLOCA-XHE-NOREC, is a TRUE type event which is not normally included in the output of fault tree reduction programs but has been added to aid in understanding the sequences to potential core damage associated with the event.

13

Background

GUIDANCE FOR LICENSEE REVIEW OF PRELIMINARY ASP ANALYSIS The preliminary precursor analysis of an operational event that occurred at your plant has been provided for your review. This analysis was performed as a part of the NRC's Accident Sequence Precursor (ASP) Program. The ASP Program uses probabilistic risk assessment techniques to provide estimates of operating event significtance in terms of the potential for core damage. The types of events evaluated include actual initiating events, such as a loss of off-site power (LOOP) or loss-of-coolant accident (LOCA), degradation of plant conditions, and safety equipment failures or unavailabilities that could increase the probability of core damage from postulated accident sequences. This preliminary analysis was conducted using the information contained in the plant-specific final safety analysis report (FSAR), individual plant examination (IPE), and the licensee event report (LER) for this event.

Modeling Techniques The models used for the analysis of 1998 events were developed by the Idaho National Engineering Laboratory (INEL). The models were developed using the Systems Analysis Programs for Hands-on Integrated Reliability Evaluations (SAPHIRE) software. The models are based on linked fault trees. Four types of initiating events are considered: (1) transients, (2) loss-of-coolant accidents (LOCAs), (3) losses of offsite power (LOOPs), and (4) steam generator tube,ruptures (PWR only). Fault trees were developed for each top event on the event trees to a supercomponent level of detail. The only support system currently modeled is the electric power system.

The models may be modified to include additional detail for the systems/ components of interest for a particular event. This may include additional equipment or mitigation strategies as outlined in the 'FSAR or IPE. Probabilities are modified to reflect the particular circumstances of the event being analyzed.

Guidance for Peer Review Comments regarding the analysis should address:

Does the "Event Description" section accurately describe the event as it occurred?

Does the "Additional Event-Related Information" section provide accurate additional information concerning the configuration of the plant and the operation of and procedures associated with relevant systems?

Does the "Modeling Assumptions" section accurately describe the modeling done for the event? Is the modeling of the event appropriate for the events that occurred or that had the potential to occur under the event conditions? This also includes assumptions regarding the likelihood of equipment recovery.

~1;,--.,

Appendix G of Reference 1 provides examples of comments and responses for previous ASP analyses.

Criteria for Evaluating Comments Modifications to the event analysis may be made based on the comments that you provide.

Specific documentation will be required to consider modifications to the event analysis.

References should be made to portions of the LER, AIT, or other event documentation concerning the sequence of events. System and component capabilities should be supported by references to the FSAR, IPE, plant procedures, or analyses. Comments related to operator response times and capabilities should reference plant procedures, the FSAR, the IPE, or applicable operator response models. Assumptions used in determining failure probabilities should be clearly stated.

Criteria for Evaluating Additional Recovery Measures Additional systems, equipment, or specific recovery actions may be considered for incorporation into the analysis. However, to assess the viability and effectiveness of the equipment and methods, the appropriate documentation must be included in your response.

This includes:

normal or emergency operating procedures.*

piping and rnstrumentation diagrams (P&IDs),*

electrical one-line diagrams,*

results of thermal-hydraulic analyses, and operator training (both procedures and simulator),* etc.

Systems, equipment, or specific recovery actions that were not in place at the time of the event will not be considered. Also, the documentation should address the impact (both positive and negative) of the use of the specific recovery measure on:

the sequence of events, the timing of events, the probability of operator error in using* the system or equipment, and other systems/processes already modeled in the analysis (including operator actions).

For example, Plant A (a PWR) experiences a reactor trip, and during the subsequent recovery, it is discovered that one train of the auxiliary feedwater (AFW) system is unavailable. Absent any further information regrading this event, the ASP Program would analyze it as a reactor trip with one train tJf AFW unavailable. The AFW modeling would be patterned after information gathered either from the plant FSAR or the IPE. However, if information is received about the use of an additional system (such as a standby steam generator feedwater system) in recovering from this event, the transient would be modeled as a reactor trip with one train of AFW unavailable, but this unavailability would be mitigated by the use of the standby feedwater system. The Revision or practices at the time the event occurred.

mitigation effect for the standby feedwater system would be credited in the analysis provided that the following material was available:

standby feedwater system characteristics are documented in the FSAR or accounted for in the IPE, procedures for using the system during recovery existed at the time of the

event, the plant operators had been trained in the use of the system prior to the event, a clear diagram of the system is available (either in the FSAR, IPE, or supplied by the licensee),

previous analyses have indicated that there would be sufficient time available to implement the procedure successfully under the circumstances of the event under analysis,

' the effects of using the standby feedwater system on the operation and recovery of systems or procedures that are already included in the event modeling. In this case, use of the standby feedwater system may reduce the likelihood of recovering failed AFW equipment or initiating feed-and-bleed due to time and personnel constraints.

Materials Provided for Review The following materials have been provided in the package to facilitate your review of the preliminary analysis of the operational event.

The specific LER, augmented inspection team (AIT) report, or other pertinent reports.

A summary of the calculation results. An event tree with the dominant sequence(s) highlighted. Four tables in the analysis indicate: (1) a summary of the relevant basic events, including modifications to the probabilities to reflect the circumstances of the event, (2) the dominant core damage sequences, (3) the system names for the systems cited in the dominant core damage sequences, and (4) cut sets for the dominant core damage sequences.

Schedule Please refer to the transmittal letter.for schedules and procedures for submitting your comments.

References

1.

R. J. Belles et al., "Precursors to Potential Severe Core Damage Accidents: 1997, A Status Report," USNRC Report NUREG/CR-4674 (ORNUNOAC-232) Volume 26, Lockheed Martin Energy Research Corp., Oak Ridge National Laboratory, and Science Applications International Corp., Oak Ridge, Tennessee, November 1998.

.-4.. *, 'I e

10CFR50.73 Virginia Electric And Power Company June 3, 1998 U. S. Nuclear Regulatory Commission Attention: Document Control Desk

\\Nashingtcm, D. C. 20555

Dear Sirs:

Surry Power Station 5570 Hog Island Road Surry, Virginia 23883 Serial No.:

98-330.

SPS: JCS Docket No.: 50-280 License No.: DPR-32

/

Pursuant to 1 OCFR50. 73, Virginia Electric and Power Company hereby submits the following Licensee Event Report applicable to Surry Power Station Unit 1.-

Report No. 50-280/1998-009-00 This report has been reviewed by the Station Nuclear Safety and Operating Committee and will be forwarded fo the Management Safety Review Committee for its review.

Very truly yours,

~JcCL___

D. A. Christian Site Vice President Enclosure Commitments contained in this letter:

j

1.

The Unit 2 piping and supports will be inspected during the next refueling outage to verify proper installation and adjustment.

/

2.

-k,2-z Approved RCE recommendations that are needed to prevent a recurrence of this event will be implemented.

cc:

U.. S. Nuclear Regulatory Commission Region II Atlanta Federal Center 61 Forsyth Street, SW, Suite 23T85 Atlanta, Georgia 30303 Mr. R.

  • A. Musser NRC Senior Resident Inspector Surry Power Station

e e

NRC FORM366 U.S. NUCLEAR REGULATORY COMMISSION APPROVED BY 0MB NO. 316CM>104 (4-95)

EXPIRES 4130/98 ESTIMlB> BURDEN PER REllPON8e TO COIIPLY WITH THIS IIMNlllTORY N'ORIIATIOII COUECTION REQUEST: 50.0 ~S.

LICENSEE EVENT REPORT (LER)

REPOR1B> LES80NII LEARNED ME. INCORPORA 1B> INTO nE UCEH81NO PROCESS /HJ FED IIACK TO NlUIITRY. FORWARD

~

Rl!QAIIDNJ IIIRJl!N -Tl! TO nE INFORIIATIOII IHJ RECORDS IWWISENT BRANCH (T-4 '33),

(See reverse for required number of digits/characters for each block)

U.S. l<<JCI.EAR RE<IU.ATORY ~

-.<<n0N. DC

-1.

/HJ TO 1IE P-REDUc110N PRO.E:T (3150-41°')0 OFRCe Of' IIANAGl!IENT /HJ BUDGET.

WASHNJTON.DC2050:I.

FACIUTY NAME (11 DOCKET NUMBER (2)

PAGE(3)

SURRY POWER STATION, Unit 1 05000-280 1 OF3 TITLE(4)

Nonlsolable Leak of Reactor Coolant Pump Seal lnlection Line Weld EVENT DATE (5 LER NUMBER (6)

REPORT DATE (7)

OTHER FACILITIES INVOLVED (8)

MONTH DAY 8EQUENTW.

REVl8ION MONTH DAY YEAR FACILITY NAME DOCUMENT NUMBER YEAR YEAR 05000-

"IUM8ER NUMBER

\\

OS 09 98 1998

-009-00 06 03 98 FACIUTY NAME DOCUMENT NUMBER 05000-OPERATING THIS REPORT IS SUBMITTED PURSUANT TO THE REQUIREMENTS OF 10 CFR I: (Check one or more) (11)

MODE(9)

NA 20.2201(b) 20.2203(a)(2)(v)

X

50. 73(a)(2)(1)
50. 73(a)(2)(viii)

POWER 20.2203(8)(1) 20.2203(8)(3)(1)

50. 73(a)(2)(11)
50. 73(a)(2)(X)

LEVEL(10) 100%

2C.2203(a)(2)(i) 20.2203(a)(3)(1i)

50. 73(a)(2)(11i) 73.71

.2203(a)(2)(il) 20.2203(*)(4)

50. 73(a)(2)(1v)

OTHER

.,., 34

)(ill) 50.38(c)(1)

50. 73(a)(2)(v)

Spacfy In Abancl below 20 50.36 :1(2

"'34a)(2)(vll) or In NRC Farm 368A LICENSEE CONTACT FOR THIS LER f12)

'\\~""

NAME I

NUMBER (h:ule kN Code)

D. A. Christian, Site Vice President (757) 365-2000

~OMPLe l; ONE L ~E FOR EA(',H COMPONENT FAU.um: o-scA IB~D IN THIS IRT (13)

CAUSE SYSTEM COMPONENT MANUFACllJRER REPORTASLE CAUSE SYSTEM COMPONENT MANUFACTURER REPORTABLE TONPAOS

  • TONPROS SUPPLEMENTAL REPORT EXPECTED (14)

EXPECTED M.... 1~rlH IA YEAR YES X

NO SUBMISSION (If yes, complete EXPECTED SUBMISSION 0-'TE).

DATE ABSTRACT (Limit to 1400 spaces, I.e., approxlmately 15 single-spaced typewritten lines) (1&)

On May 9, 1998, with Unit 1 at 100% power, an increase was noted in Reador Coolant System (RCS) leakage. Operations personnel entered the containment to investigate and discovered a leak in the area of the 1 Yz" seal injedion line to the "C" Reador Coolant Pump (RCP) at the pump thermal barrier. A subsequent containment entry confirmed that a weld or pipe through-wall non-isolable leak existed at the seal injection line of the RCP. The unit was placed at cold shutdown as required by TS 3.1.C.4. On May 9, 1998, a Notice of Unusual Event was declared and, at 2316,- the NRC was notified in accordance* with

  • 10CFR50.72(a)(1)(i) and 10CFR50.72(b)(1)(i)(A). The seal injection line was repaired e~d the unit was prepared for start-up and the unit was returned to service on May.25, 1998. A Root Cause Evaluation (RCE) was initiated to verify the cause of the leaking "C" RCP seal injection weld. The cause has preliminarily been determined to be from a pre-existing indication at the toe of the weld. The most probable cause for the weld failure was a lack of fusion or thermal fatigue coupled with vibration stress due to a loose rod hanger. This event is reportable pursuant to 1 OCFR50. 73(a)(2)(i)(B).

e NRC FORM 366A

(... 95)

U.S. NUCLEAR REGULATORY COMMISSION LICENSEE EVENT REPORT (LER)

TEXT CONTINUATION DOCKET YEAR LER NUMBER (6)

I SEQUENTIAL I REVISION NUMBER NUMBER PAGE (3)

FACILITY NAME (1)

Surry Power Station, Unit 1 05000-280 1998

- 009 -

00 2 OF 3 TEXT (If more space is required, use additional copies of NRC Form 366A) (17)

1.0 DESCRIPTION

OF THE EVENT On May 9, 1998, with Unit 1 at 100% power, an increase was noted in Reactor Coolant System (RCS) leakage. The leakage was within Technical Specification (TS) limits and monitoring revealed that the leakage rate had increased only slightly. Operations personnel entered the containment to investigate and discovered a leak in the area of the 1 %" ~eal injection line to the "C" Reactor Coolant Pump (RCP) [EIIS-AB-P] at the.

pump thermal barrier. A unit ramp down to 50% power was commenced to reduce dose in the area of the leak so that a second containment entry could be made to further examine the leak. The second containment entry confirmed that a weld or pipe through-wall non-isolable leak existed at the seal injection line of the RCP. As a result, the unit was placed at cold shutdown as required by TS 3.1.C.4. On May 9, 1998, a Notice of Unusual Event was declared and, at 2316, the NRC was notified in accordance with 10CFR50.72(a)(1)(i) and 10CFR50.72(b)(1)(i)(A). The seal injection line was repaired and the unit was returned to service on May 25, 1998. This event is reportable pursuant to 10CFR50.73(a)(2)(1)(B) as a condition prohibited by Technical Specifications.

2.0 SIGNIFICANT SAFETY CONSEQUENCES AND IMPLICATIONS RCS leakage is quantified daily including unidentified leakage. The leakage from the seal injection line to the RCP thermal barrier was detected by the daily leakage evaluation and was confirmed by visual inspection. The leak rate was less than the unidentified leakage limits specified in TS 3.1.C.2. A catastrophic failure of the weld is unlikely, but if it were to occur, the resultant loss of RCS inventory would be bounded by existing accident analyses. Therefore, the health and safety of the public were not affected.

3.0 CAUSE A Root Cause Evaluation was initiated to verify the cause of the leaking "C" RCP seal injection weld.. The cause ha_, preliminarily been determined to be from a pre-existing indication at the toe of the weld. The most probable cause for the weld failure was a lack of fusion or thennal fatigue coupled with vibration stress due to a loose rod hanger [EIIS-AB-H].

4.0 IMMEDIATE CORRECTIVE ACTION(S)

Th~ RCP seal injection line was removed from the RCP thermal barrier. The failed weld was excavated and a new line was welded in place in accordance with approved procedures.

NRC FORM 311M (4-86}

NRC FORM ;366A (4--%)

e FACILITY NAME (1)

Surry Power Station, Unit 1 LICENSEE EVENT REPORT (LER)

TEXT CONTINUATION DOCKET 0500~ -280 TEXT (If more space is required, use additional copies of NRC Form 366A) (17) 5.0 ADDITIONAL CORRECTIVE ACTIONS The rod hanger for "Cn RCP seal injection line was adjusted.

6.0 ACTIONS TO PREVENT.RECURRENCE e

U.S. NUCLEAR KEGULATORY COMMISSION YEAR 1998 LER NUMBER (6)

I SEQUEHTIAL l REVISION NUMBER NUMBER

-009-00 PAGE (3) 3 OF3 The corresponding welds for "A" and "Bn RCP seal injection lines were nondestructively tested with no indications noted. The associated pipe supports were inspected to ensure proper installation. No deficiencies were identified.

The piping and support configurations for the Unit 2 RCP seal injection lines were evaluated by Engineering.

bue to hanger differences between the two units, the evaluation concluded that a similar event on Unit 2 is not likely.

However, the'Unit 2 piping and supports will be inspected during the next refueling outage to verify proper installation and adjustment.

Approved RCE recommendations that are needed to prevent a recurrence of this event will be implemented.

7.0 SIMILAR EVENTS S-1-93-010-00, "Operation with a Non-isolable Leak on a "B" Steam Generator Channel Head Drain Line.*

S-1-95-007-01, "Operation with Non.. isolable Leak in Pressurize Instrumentation Nozzles.n S-1-98-006-00, "Unisolable Through Wall Leak of RCP Thermowell."

8.0 MANUFACTURER/ MODEL NUMBER NA 9.0 ADDITIONAL INFORMATION Unit 2 was operating at 100% and was not affected-by this event.

.. /

NRC FORM 31111A (4-4161

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