ML15239A175

Forwards for Review & Comment,Preliminary Accident Sequence Precursor Analysis of Operational Event That Occurred at Oconee Nuclear Station,Unit 3,on 970503

ML15239A175
Person / Time
Site:	Oconee
Issue date:	04/24/1998
From:	Labarge D NRC (Affiliation Not Assigned)
To:	Mccollum W DUKE POWER CO.
References
NUDOCS 9805010205
Download: ML15239A175 (34)

Text

VLER No.

287/97-003 LER No. 287/97-003 Event

Description:

Two high-pressure injection pumps were damaged because of a low water level in the letdown storage tank Date of Event:

May 3, 1997 Plant:

Oconee 3 Event Summary Following an HPI nozzle weld leak and thermal sleeve failure at Oconee 2 (Ref. 1), operators began shutting down Oconee 3 on May 1, 1997, so that personnel could inspect the high pressure injection (HPI) nozzles and thermal sleeves at that unit. A low water level in the letdown storage tank (LDST), caused by the partial draining of the common reference leg in the tank level instrumentation, resulted in inadequate suction flow to the HPI pumps. Two of the three HPI pumps were damaged. All three HPI pumps were vulnerable to failure if a loss-of-coolant accident (LOCA) had occurred while the reference leg was drained. The estimated conditional core damage probability (CCDP) associated with this event for the 340-h period when the low water level in the reference leg would have impacted HPI pump operability is 3.3 x 10'. This is an increase of 3.2 x 10- over the nominal core damage probability (CDP) of 8.7 x 10'for the same 340-hour period that the condition existed.

Event Description On May 1, 1997, personnel at Oconee 3 started to shut down the reactor to inspect the HPI nozzles and thermal sleeves in response to an HPI nozzle weld leak and failed thermal sleeve at Oconee 2 (Ref. 2) and reassessment of earlier Unit 3 radiographs that indicated the potential degradation ofa Unit 3 thermal sleeve. By the morning of May 3, the decay heat removal (DHR) system had been placed in operation, reactor coolant system (RCS) temperature and pressure were at 240F and 270 psig, respectively, and a slow cooldown (100F/h) was in progress. HPI pump 3B was running and pump 3A was in standby.

At 0913, control room alarm 3 SA-2/C-2 indicated that the discharge pressure for the HPI pump was low. The alarm was cleared and then alarmed two more times during the next minute. HPI discharge pressure was indicating -2,000 psig. While reactor coolant pump (RCP) seal injection flow indicated normal, the RCP seal injection control valve (3HP-3 1) position was observed to be varying and, in response, the operators placed the valve controller in "manual." At 0915, the 3A HPI pump auto-started on a low RCP seal injection flow signal. The control room operators stopped the 3A HPI pump within a minute, but when its control switch was placed in "automatic" it again started on low RCP seal injection flow.

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LER No. 287/97-003 The 3A HPI pump-motor current was fluctuating at levels above normal (70-120 A) and the 3B pump motor current was about 10 A. The 3A pump was placed in the "run" mode and the 3B pump was secured. Eight minutes after the initial low HPI discharge pressure alarm both the RCP seal injection flow and HPI pump discharge pressure were indicating low. The operators realigned the HPI pump suction flow path to the borated water storage tank (BWST) by opening suction valve 3HP-24. The water level in the LDST began increasing and the pump-motor current for the 3A HPI pump-motor stabilized at 10 A. At 0928, with HPI pump discharge pressure still low and no indication of RCP seal injection flow, operators closed BWST suction valve 3HP-24.

Two minutes later the operators observed that the LDST chart recorder had been indicating a constant level of 55.9-in for the last 1.75 h. The operators recognized that the HPI pump problems could be associated with erroneous LDST level indication, although the precise cause and nature of the problems were unknown. At 0931 the 3A HPI pump was secured and valve 3HP-5 was closed to isolate RCS letdown. It was subsequently discovered that the 3A and 3B HPI pumps had been damaged when they were operated without an adequate suction source. Inadequate suction resulted from a low net positive suction pressure (NPSH) and possible hydrogen entrainment. The 3A and 3B pumps had operated with inadequate NPSH for about 15 min and 4 min, respectively.

RCS makeup and RCP seal injection were not immediately required and a decision was made not to start the 3C HPI pump (if pump operation was required, the BWST could have been used as its suction source). A Notice of Unusual Event was declared at 1504 because ofthe expected delay in restoring RCS normal makeup.

At 1515, the water level in the LDST level instrumentation common reference leg was found to be -49 in instead of its normally filled level of > 100 in. The partially drained reference leg produced a high water level indication for the LDST. At the time that the HPI pumps were damaged the tank level indicated 56 in, but the tank.was actually empty.

A small amount of boric acid buildup was noted around a test tee cap on the reference leg side of the No. 2 level transmitter. A subsequent laboratory examination concluded that the reference leg leak resulted from either (1) scratches on seating surfaces of the test tee and plug or (2) a slight expansion of the tee nipple, probably from over tightening the cap sometime in the past. The licensee also noted that the reliance of the operators on the LDST low level alarm to cue LDST makeup, instead of LDST status monitoring to determine when makeup was needed, contributed to the HPI pump failures. The LDST low level alarm set point is 55-in, one inch below the lowest tank level that could be indicated with the partially drained reference leg.

At -2130, personnel began to develop procedures to flush, fill, vent, and start the 3C HPI pump without using the LDST. A contingency plan was also developed to support Unit 3 shutdown without any HPI pumps running, if that was necessary. Following approval of the procedures and contingency plan, the 3C HPI pump was successfully started at approximately 1140 on May 4, 1997, and the Unit 3 cooldown continued.

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LER No. 287/97-003 Additional Event-Related Information The HPI system at Oconee provides both normal RCS makeup and RCP seal injection, as well as HPI for small-and medium-break LOCA mitigation. During normal operation, the HPI system "A" header, using either the 3A HPI pump or the 3B HPI pump, supplies RCS makeup and RCP seal injection (-80 gpm combined flow). The LDST is used as a surge tank and normal (non-emergency) suction source for the HPI pumps. During operation, a hydrogen atmosphere is maintained in the LDST to promote oxygen scavenging.

The "B" HPI header, supplied by the 3C HPI pump, is for emergency injection only. The HPI pumps effectively share a common suction because the suction cross-connect valves are normally open (Fig. 1).

Two channels of level indication are provided for the LDST. The operators can select either channel for display on a control room chart recorder. The level transmitters for the two channels utilize common process piping and a common reference leg that is vented back to the LDST.

Normally, the water level in the LDST ranges between 60 and 80 in. The low LDST level alarm set point is 55 in. When the LDST level is at 100 in (full), and the reference leg of the transmitter is full, there is zero differential pressure across the transmitter. This indicates a full tank. When LDST level indicates "0 in", there are about 690 gals remaining in the tank. A continuous fill line, which would have maintained the reference leg filled, was included in the original LDST instrumentation design. The licensee did not consider the fill line to be a part of the instrumentation, and it was isolated at the time of the event.

The HPI pumps are normally isolated from the BWST by normally-closed motor-operated valves (MOVs) HP 24 and -25. In the event of a safety system actuation, MOVs HP-24 and -25 open. The elevation head pressure in the BWST will overcome the pressure caused by the LDST level and hydrogen over-pressure, opening check valves HP-101 and -102 and closing the LDST outlet header check valve HP-97, and providing flow from the BWST to the HPI pumps. As the water level in the BWST drops, the available pressure from the LDST could exceed the available pressure from the BWST, allowing flow from the LDST when its check valve opens. The hydrogen gas in the LDST could then expand and fill the suction piping, resulting in damage to the HPI pumps. The procedural operating limit curve for LDST hydrogen pressure and volume is intended to assure that LDST pressure does not exceed available BWST pressure, even as the water level in the BWST is drawn down during a LOCA. (A 1991 operational event at Oconee 1, 2, and 3 involving incorrect LDST hydrogen pressure/volume curves was analyzed as an accident sequence precursor. 3)

The HPI pumps at Oconee are 24 stage vertical centrifugal pumps that develop 3,000 psi discharge pressure with a capacity of about 500 gpm each. The pumps will typically only operate for 1-2 min without an adequate suction source, before they are damaged.

Additional information concerning this event is included in an NRC Augmented Inspection Team report.4 3

LER No. 287/97-003 Modeling Assumptions If an initiating event involving a loss of RCS inventory had occurred while the LDST was nearly empty, all three HPI pumps could have failed as a result of hydrogen gas binding. This analysis assumes the HPI system was vulnerable to failure as a result of the LDST common reference leg leak between February 22, 1997-when the LDST level instrumentation was calibrated, and May 3, 1997-when the two HPI pumps failed while shutting down. The potential effect of a loss of all HPI pumps following an initiating event without RCS inventory loss, such as a transient with successful primary relief valve closure, was not addressed. The limited RCS makeup required following such an event could be provided by the safe shutdown facility (SSF) RCS makeup pump.

If an initiating event involving a loss of RCS inventory had occurred when the LDST common reference leg water level was low, the potential for HPI pump failure would have depended on the actual water levels that were reached in the LDST and the BWST.

This analysis assumed the LDST reference leg was leaking continually. The LDST reference leg level was assumed to have decreased linearly with time, from 100 in (full) on February 22, 1997, to 49 in on May 3, 1997. Although the LDST was refilled daily to compensate for minor RCS leakage and to maintain level within the operational range, the gradual reduction in reference leg level resulted in an effective, albeit unrealized, reduction in tank level. Based on a simplified model of LDST level and pressure as a function of LDST reference leg level during BWST drawdown, the HPI pumps were estimated to be vulnerable to failure during (approximately) the final 20% of the time between February 22 and May 3, or 340 h. During this period, hydrogen gas would enter the pump suction piping and fail the HPI pumps if, following a LOCA, BWST level decreased to near the level at which switchover to high-pressure recirculation was required.

A new branch (HPI-LATE) was added to the event trees used in the accident sequence precursor (ASP) analysis to address the potential failure of HPI due to low water level in the LDST late in the injection phase.

The fault tree associated with this branch consists of one basic event, LDST-LVL-LOW, that is nominally false but set to true during the 340-h period when unacceptably low LDST water level existed. The ASP event trees for transients, loss of offsite power events, small-break LOCAs (SLOCAs), and steam generator tube rupture events (IE-SGTR) were also enhanced to address the potential use of rapid RCS depressurization and low pressure injection (LPI) in the event that HPI failed and secondary side cooling was available by adding branches to address fast depressurization, LPI, and low-pressure recirculation (LPR). The Oconee Individual Plant Examination (IPE) states that following a small-break LOCA with a loss ofHPI, the emergency operating procedures direct the operators to use secondary heat removal systems to depressurize the RCS until LPI flow is greater than 100 gpm per header. The probability of the operators failing to depressurize the RCS and initiating LPI was assumed to be 0.1, consistent with Ref. 5. Two operator actions associated with cooldown and depressurization are included in the SLOCA model. PCS-XHE-XM-CDOWN addresses the failure of the operators to cooldown and depressurize the unit and initiate RHR following a SLOCA. This action is initiated early following the SLOCA. PCS-XHE-XM-FDEPR addresses the failure of the operators to depressurize to LPI pressure following a loss of HPI. In this event this occurs close to the time when sump recirculation 0

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LER No. 287/97-003 must be initiated, 4-6 h after the SLOCA. Because of this separation in time between the two actions, they were considered independent in this analysis.

If the water level in the BWST did not decrease to near the sump switchover level, then HPI pump operability would not be expected to be impacted. This could happen if, instead of proceeding to high-pressure recirculation, the operators successfully cooled down and depressurized the RCS during the injection phase, and initiated decay heat removal using the DHR system. This is the preferred response following a small-break LOCA (SLOCA), since it avoids sump recirculation (the ASP models include this potential action). Limited BWST drawdown is expected in this case.'.

HPI is also required to mitigate a medium-break LOCA (MLOCA) at Oconee. If an MLOCA occurred during the 340-h period when the LDST reference leg level was unacceptably low, the HPI pumps would have failed due to hydrogen entrainment before sump recirculation was initiated. The Oconee IPE' notes that the time available before switchover to high-pressure recirculation (90 min) is too short to allow RCS depressurization to the point that low pressure recirculation can be used. Recovery from a failure of HPI by depressurizing and using LPI is therefore not possible following an MLOCA.

The ASP Program typically considers the potential for core damage following four postulated initiating events in pressurized-water reactors: transient, loss of offsite power, SLOCA, and steam generator tube rupture.

Supercomponent-based linked fault tree models are available for each of these postulated initiating events. A linked fault tree model was developed to address the impact of a low water level in the LDST on a medium break LOCA. Consistent with the Oconee IPE, this model assumed a reactor trip (RT) and one train of HPI and piggy-back cooling (high pressure recirculation) are required for core cooling following an MLOCA. The fact that the RT, HPI, and piggy-back cooling success criteria were the same as that used in the Oconee ASP model for an SLOCA allowed the existing fault trees to be used, in conjunction with the event tree shown in Fig. 2, in describing MLOCA accident sequences. The event tree includes the following branches:

Initiating Event-ALOCA (MLOCA).

The frequency of a medium-break LOCA is estimated to be 5.0 x 10/year [8.2 x 10-/h, assuming the unit is at power 70% of the time (6,132 h)], based on a survey of medium-break frequencies performed in support of the analysis of Turkey Point LER No. 250/94-005 in the 1994 precursor report (see Appendix H to Ref. 8 for additional information).

Reactor Trip (RT). Failure ofthe reactor to trip is assumed to result in core damage following a medium-break LOCA.

High-Pressure Injection (HPI). Failure of injection using the HPI system results in a loss of short-term RCS makeup and core damage following a medium-break LOCA. Flow from one HPI pump is assumed to provide success.

aThis expectation is supported by the limited BWST drawdown that occurred following a 350-gpm reactor coolant pump seal failure in 1980 at Arkansas Nuclear One, Unit 1 (Ref 6).

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LER No. 287/97-003 HPIInjection Phase Successful (HPI-LATE). Failure of HPI late in the injection phase results in the loss of RCS makeup and core damage following a medium-break LOCA. As described previously, this top event specifically addresses the potential failure of HPI due to low LDST level (other late injection phase failures, such as a common cause failure of the HPI pumps to run, are imbedded within HPI). A failure probability of 1.0 is assumed for this branch when LDST level is unacceptably low.

Piggy-Back Cooling (PB-COOL). Failure of piggy-back cooling results in a failure of long-term injection and decay heat removal and is assumed to result in core damage. PB-COOL utilizes the DHR pumps, which take suction on the reactor building sump and provide water via the DHR heat exchangers to the suctions ofthe HPI pumps. Flow from one HPI pump (supplied by one DHR train) provides PB-COOL success.

As with the other ASP linked fault tree models, the medium-break LOCA model was solved using the Saphire computer code to identify combinations of basic events (cut sets) that would result in core damage.

Analysis Results The CCDP estimated for the potential HPI system unavailability because of the leaking LDST common reference leg is 3.3 x 10s. This is an increase of 3.2 x 10 -' over the nominal CDP of 8.7 x 10-7 for the same 340-hour period that the condition existed. The dominant sequence, highlighted as sequence 3 in Fig. 2, contributes about 96% to "he increase in the CCDP and involves

• a postulated MLOCA,

• successful reactor trip, initial HPI success, and

• failure of HPI late in the injection phase as a result of the low water level in the LDST.

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.

In addition to an assessment of the effect of a loss of HPI following a potential initiating event at Unit 3, a sensitivity analysis considered the affect if the Unit 3 LDST reference leg leak and the Unit 2 HPI injection nozzle weld leak (see the analysis of LERNo. 270/97-001) had instead occurred at the same unit. As described in the analysis of LER No. 270/97-00 1, subsequent inspections of the thermal sleeve and injection line nozzles at Units 1 and 3 determined that Unit 3 was also affected by nozzle cracking. Assuming the leaking LDST common reference leg could have occurred at any of the three units, there is a 0.33 probability that the two events could have occurred together at Unit 2 or 3. The CCDP estimated for a leaking HPI injection line (as described in the analysis ofLERNo. 270/97-001) with HPI potentially unavailable because of a drained LDST common reference leg (as described herein) is 2.4 x 10'. The CCDP estimated for the observed HPI injection nozzle leak at Unit 2 (assuming nominal HPI system performance) is 1.0 x 10-5. Weighting these conditional 6

LER No. 287/97-003 probabilities by the probability that the events could have occurred at the same unit (0.33) results in an overall estimated CCDP for the combined events of 2.4 x 10' x 0.33 + 1.0 x 10-' x (1.0 - 0.33), or 8.6 x 10'.

Acronyms ASP accident sequence precursor BWST borated water storage tank CCDP conditional core damage probability CDP core damage probability DHR decay heat removal HPI high-pressure injection IPE individual plant examination LDST letdown storage tank LOCA loss-of-coolant accident LPI low pressure injection LPR low-pressure' recirculation MLOCA medium-break loss-of-coolant accident MOVs motor-operated valves NPSH net positive suction head RB reactor building RCP reactor coolant pump RCS reactor coolant system RT reactor trip SGTR steam generator tube rupture SLOCA small-break loss-of-coolant accident References

1. Licensee Event Report 287/97-003, "High Pressure Injection System Inoperable due to Design Deficiency and Improper Work Practices," June 2, 1997.

2. Licensee Event Report 270/97-001, "Unisolable Reactor Coolant Leak due to Inadequate Surveillance Program," May 21, 1997.

3. Precursors to Potential Severe Core Damage Accidents: 1991, A Status Report, NUREG/CR-4674, Vol.

16, September 1992, p B-47.

4. "NRC Augmented Inspection Team Report 269/97-06, 270/97-06, 287/97-06," May 30, 1997.

5. Oconee Nuclear Station Units 1, 2, and 3, IPE Submittal Report, December 1990, p. 5.7-22, Rev. 1.

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LER No. 287/97-003

6. Precursors to Potential Severe Core Damage Accidents: 1980-1981, A Status Report, NUREG/CR 3591, Vol. 2, February 1984, p. B-126.

7. Oconee Nuclear Station Units 1, 2, and 3, IPE Submittal Report, December 1990, pp 2.3-8, -9, Rev. 1.

8. Precursors to Potential Severe Core Damage Accidents: 1994, A Status Report, NUREG/CR-4674, Vol.

21, December 1995.

LER No. 287/97-003

/R W110H Fig. 1. Flow diagram of the emergency core cooling system at Oconee 3.

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LER No. 287/97-003 Fig. 2. Dominant core damage sequence for LER No. 287/97-003.

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LER No. 287/97-003 Table 1. Definitions and Probabilities for Selected Basic Events for LER No. 287/97-003 Modified Event Base Current for this name Description probability probability Type event IE-LOOP Initiating Event-Loss of Offsite 2.8 E-006 2.8 E-006 No Power IE-MLOCA Initiating Event-MLOCA 2.7 E-005 2.7 E-005 NEW Yes IE-SGTR Initiating Event-Steam Generator 1.3 E-006 1.3 E-006 No Tube Rupture IE-SLOCA Initiating Event-SLOCA 6.5 E-007 6.5 E-007 No IE-TRANS Initiating Event-Transient 7.7 E-004 7.7 E-004 No LDST-LVL-LOW Low Water Level in the LDST 0.0 E+000 1.0 E+000 TRUE Yes Fails the HPI Pumps PCS-VCF-HW Failure of Secondary System 3.0 E-003 3.0 E-003 No Hardware PCS-XHE-XM-CDOWN Operator Fails to Initiate 1.0 E-002 1.0 E-002 No Cooldown PCS-XHE-XM-FDEPR Operator Fails to Initiate Fast 1.0 E-00 1 1.0 E-00 I NEW Yes Depressurization for LPI 11

LER No. 287/97-003 Table 2. Sequence Conditional Probabilities for LER No. 287/97-003 Conditional Event tree Sequence core damage Core damage Importance Percent name number probability probability (CCDP-CDP) contribution" (CCDP)

(CDP)

MLOCA 03 2.7 E-005 0.0 E+000 2.7 E-005 96.4 SLOCA 10 8.8 E-007 0.0 E+000 8.8 E-007 3.0 Total (all sequences) 3.3 E-005 8.7 E-007 3.2 E-005

'Percent contribution to the total importance.

Table 3. Sequence Logic for Dominant Sequences for LER No. 287/97-003 Event tree Sequence Logic name number MLOCA 03

/RT, /HPI, HPI-LATE SLOCA 10

/RT, /EFW, /HPI, COOLDOWN, HPI-LATE, FASTDEPR Table 4. System Names for LER No. 287/97-003 System name Logic COOLDOWN RCS Cooldown to DHR Pressure Using Turbine-Bypass Valves, etc.

EFW No or Insufficient Emergency Feedwater System Flow FASTDEPR RCS Cooldown to LPI Pressure Using Turbine-Bypass Valves, etc.

HPI No or Insufficient HPI System Flow HPI-LATE HPI Fails Late 12

LER No. 287/97-003 System name Logic RT Reactor Fails to Trip During Transient Table 5. Conditional Cut Sets for Higher Probability Sequences for LER No. 287/97-003 Cut set Percent number contribution CCDP Cut setsb MLOCA Sequence 03 2.7 E-005 2

1 100.0 2.7 E-005 LDST-LVL-LOW SLOCA Sequence 10 8.8 E-007 1

75.0 6.6 E-007 PCS-VCF-HW 2

25.0 2.2 E-007 PCS-XHE-XM-CDOWN, PCS-XHBE-XM-FDEPR Total (all sequences) 3.3 E-005 i'

'The CCDP is determined by multiplying the probability that the portion of the sequence that makes the precursor visible (e.g., the system with a failure is demanded) will occur during the duration of the event by the probabilities of the remaining basic events in the minimal cut set. This can be approximated by 1 - e*, where p is determined by multiplying the expected number of initiators that occur during the

.duration of the event by the probabilities of the basic events in that minimal cut set. The expected number of initiators is given by Xt, where A is the frequency of the initiating event (given on a per-hour basis), and t is the duration time of the event (340 h). This approximation is conservative for precursors made visible by the initiating event. The frequencies of interest for this event are:

4,,m,

= 8.15 x 10 /h, and A.oc, = 6.52 x 10 /h. The importance is determined by subtracting the CDP for the same period but with plant equipment assumed to be operating nominally.

t Basic event LDST-LVL-LOW is a type TRUE event. This type of event is not normally included in the output of the fault tree reduction process but has been added to aid in understanding the sequences to potential core damage associated with the event.

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GUIDANCE FOR LICENSEE REVIEW OF PRELIMINARY ASP ANALYSIS

Background

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 significance 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 1995 and 1996 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.

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

Criteria for Evaluating Coments 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 instrumentation 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 of 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 Revision or practices at the time the event occurred.

mitigated by the use of the standby feedwater system. The 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.

L. N. Vanden Heuvel et al., Precursors to Potential Severe Core Damage Accidents: 1994, A Status Report, USNRC Report NUREG/CR-4674 (ORNL/NOAC 232) Volumes 21 and 22, Martin Marietta Energy Systems, Inc., Oak Ridge National Laboratory and Science Applications International Corp.,

December 1995.

U Duke Power Company J R' HmPTOS Oconee Nuclear Site Vice President P 0. Box 1439 (864)885-3499 Office Seneca SC 29679 (864)8853564 Fax DUKE POWER June 2, 1997 U.S. Nuclear Regulatory Comission Document Control Desk Washington, D.C. 20555

Subject:

Oconee Nuclear Station Docket Nos. 50-269, -270, -287 Licensee Event Report 287/97-03, Revision 0 Problem Investigation Process No.: 0-097-1428 Gentlemen:

Pursuant to 10 CFR 50.73 Sections (a) (1) and (d),

attached is Licensee Event Report 287/97-03, concerning an inoperability of the High Pressure Injection System.

This report is being submitted in accordance with 10 CFR 50.73 (a) (2) (ii) (B).

This event is considered to be

.of no significance with respect to the health and safety of the public.

Very truly yours, J. W. Hampton, Vice President

' A Oconee Nuclear Site

/fts Attachment PDR ADOCK 05000287 \\o u6 3 3 E 43 Pmten on MCWPWEnclosure 3

Document Control Desk June 2, 1997 Page 2 cc:

Mr. Luis A.

Reyes Administrator, Region II U.S. Nuclear Regulatory Commission 61 Forsyth Street, S. W.; Suite 23T85 Atlanta, GA 30303 Mr. D. E. LaBarge U.S. Nuclear Regulatory Commission Office of Nuclear Reactor Regulation Washington, D.C. 20555 INPO Records Center 700 Galleria Parkway, NW Atlanta, GA 30339-5957 Mr. M. A. Scott NRC Resident Inspector Oconee Nuclear Station

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Oconee Nuclear Station, Unit Three 05000 287 1 of 16 TITLE (4) High Pressure Injection System Inoperable Due to Design Deficiency and Improper Work Practices EVENT DATE (5)

LER NUMBER (6)

REPORT DATE (7)

OTHER FACILITIES INVOLVED (8)

MONTH DAY YEAR YEAR SEUENTIAL REVISON MONTH DAY YEAR FACIUTY NAME DOCKET NUMBER(S) 05000 05 03 97 97 00 06 02 9105000 O

P ERAING0 3

THIS REPORT IS SUBMITTED PURSUANT TO THE REQUIREMENTS OF 10 CFR (Check one or more of the ftfaowl)

(11 M

E11N N

20.402(b) 20.405(C) 50.73(a)(2)(iv) 73.71(b) 20.405(a)(1)(i) 50.36(c)(1) 50.73(a)(2)(v) 73.71(c) 0 20.405(a)(1)(i) 50.36(c)(2) 50.73(a)(2)(vi)

OTHER (Specify in 20.405(a)(1)(ii) 50.73(a)(2)()

50.73(a)(2)(vil)(A)

Absact below and 20.405(a)(1)(iv)

X 50.73(a)(2)(ii)(B) 50.73(a)(2)(viii)(B) in Text, NRC Form 20.405(a)(1)(v) 50.73(a)(2)(iii) 50.73(a)(2)(x) 366A)

LICENSEE CONTACT FOR THIS LER (12)

NAME TELEPHONE NUMBER AREA CODE R. T. Bond, Safety Review Manager (864) 1885-3043 COMPLETE ONE LINE FOR EACH COMPONENT FAILURE DESCRIBED IN THIS REPORT (13)

CAUSE SYSTEM COMPONENT MANUFACTURER REPORTABLE CAUSE SYSTEM COMPONENT MANUFACTURER REPORTABLE TO NPRDS TO NPRDS SUPPLEMENTAL REPORT EXPECTED (14)

EXPECTED MONTH DAY YEAR SUBMISSION YES (Iyes, complet E(PECTED SUBMISSION DATE)

X NO DATE (15)

ABSTRACT (Limit to 1400 spaces ie. apprimunately fifeen singlepece typewrtifen &nes) (16)

On May 3, 1997, Unit 3 was being shutdown to verify the integrity of the High Pressure Injection (HPI) System nozzles. Unit 3 was at approximately 240 degrees and 270 psig with.a Low Pressure Injection pump and a Reactor Coolant Pump in operation. At approximately 0915 hours0.0106 days <br />0.254 hours <br />0.00151 weeks <br />3.481575e-4 months <br />, the 3A and 3B HPI pumps were damaged due to operation with an inadequate suction source. Both Letdown Storage Tank (LDST) level instruments erroneously indicated level was 55.9 inches for about one hour and forty five minutes prior to the damage to the HPI pumps. However, at the time of the failure, the tank was essentially empty. Subsequent investigation determined the reference leg of the LDST level to be partially drained. The Operators responded to the event and placed the unit in a stable condition. On May 5, 1997, an Engineering evaluation determined that the inaccurate level made the HPI system inoperable at some point between February 22, 1997 and May 3, 1997. This is significant because operation in this condition is outside the design bases of the HPI System. The root cause is a combination of a design weakness of a common reference leg for the LDST level instruments and a leaking instrument fitting due to an inadequate work practice. A contributing cause was the failure to adequately apply available operating experience. Corrective ions include a modification of the LDST level instruments.

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YEAR J

SEQUENTIAL REVISION Oconee Nuclear Station, Unit Three 287 97 NUMBER OB 2 OF 16 BACKGROUND:

The High Pressure Injection (HPI) System [EIIS:BQ] controls the Reactor Coolant System (RCS) [EIIS:AB) inventory, provides the seal water for the Reactor Coolant Pumps [EIIS:P), and recirculates RCS letdown for water quality maintenance and reactor coolant boric acid concentration control.

The HPI System is also a part of the Emergency Core Cooling System (ECCS) which mitigates the consequences of loss of coolant accidents (LOCA).

The HPI System prevents uncovering of the core for smaller break sizes, where high RCS pressure is maintained, and delays the uncovering of the core for intermediate break sizes. The HPI System, during emergency operation, supplies borated water to the RCS from the Borated Water Storage Tank (BWST).

The HPI System has three parallel HPI pumps that have the apability to take suction from the BWST. The HPI pumps have the pability to discharge through two redundant flow headers into the RCS, tilizing four injection lines (two per header).

The HPI headers are cross-connected by piping and associated valves to provide for remote manual alignment to ensure flow to the core through both HPI trains should a single failure of an HPI pump or HPI injection valve prevent automatic injection through one train.

The HPI System, during normal makeup operation, supplies borated water to the RCS from the Letdown Storage Tank (LDST) using either the 3A or 3B HPI pumps. During power operation, the LDST operates with approximately 40 psig hydrogen overpressure. The "A" HPI header supplies normal RCS makeup flow, typically 15 to 20 gpm through each of the two lines. The "B" HPI header is supplied by the 3C HPI pump and is used for emergency only.

Each Oconee Unit has two channels of level indication for the LDST. The control room chart recorder has a selector switch to align the selected transmitter to the recorder. The two transmitters have common process tubing from the LDST. The two transmitters have a common reference leg that is vented back to the LDST. The bottom level tap is about 28 inches above the bottom of the bowl shaped tank. When the LDST level is at 0 inches there is about 690 gallons of inventory available to the HPI Pumps.

al makeup flow to the RCS is 40 gpm, RCP seal injection flow is 40 gpm,

. Seal Return flow is 8 gpm, minimum recirculation flow is 30 gpm and normal letdown flow is 72 gpm. Any RCS shrinkage due to cooldown would

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YEAR SEQUENTIAL REVISION NUMBER R

NUMBER Oconee Nuclear Station, Unit Three 287 97 03 00 3 OF 16 require additional makeup from the LDST into the RCS to maintain a constant pressurizer level. Normal LDST level ranges between 60 and 80 inches. The low LDST level alarm setpoint is 55 inches. When the LDST level is 100 inches (full) and the reference leg of the transmitter is full, there is zero differential pressure which indicates a full tank.

The HPI Pumps at Oconee are 24 stage vertical centrifugal pumps that develop 3000 psi discharge pressure with a capacity of about 500 gpm each.

The pumps will typically only operate for one to two minutes without an adequate suction source. Technical Specification 3.3.1 requires three HPI pumps and two HPI flow paths to be operable when RCS temperature is greater than 350 degrees with fuel in the core. Additionally, valves HP-409 and HP-410 in the cross-connect must be operable. This is based on considerations of potential small breaks at the Reactor Coolant Pump ischarge piping for which two HPI trains (two pumps and two flow paths) re required to assure adequate core cooling. Included in the Technical Specification definition of operable is the requirement that essential auxiliary equipment, such as instrumentation and controls, be capable of performing its related support function.

EVENT DESCRIPTION:

On May 1, 1997, Oconee management made a commitment to the NRC that Unit 3 would be shut down to inspect High Pressure Injection (HPI) System nozzle thermal sleeves. The thermal sleeve problems were reported in LER 270/97

01. A power reduction from 100% was started at 1946 hours0.0225 days <br />0.541 hours <br />0.00322 weeks <br />7.40453e-4 months <br />. Cooldown to a cold shutdown condition was planned.

On May 3, 1997 at approximately 0700 hours0.0081 days <br />0.194 hours <br />0.00116 weeks <br />2.6635e-4 months <br />, Unit 3 was in the cooldown process. At this time Reactor Coolant System (RCS) temperature and pressure were about 240 F and 270 psig. The decay heat removal system had been started on the previous shift. Steam generators were still available for decay heat removal. Two Reactor Coolant Pumps (RCPs) were still in operation. A slow cooldown rate of about 10 F per hour was initiated.

There were no unusual conditions known to exist on Unit 3 at this time.

HPI Pump was running with the 3A HPI pump in standby. Both Letdown Storage Tank (LDST) levels were indicating 55.9 inches. At 0913 hours0.0106 days <br />0.254 hours <br />0.00151 weeks <br />3.473965e-4 months <br />,

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LER NUMBER BSI PAGE 3 YEAR SEQUENTIAL REVISION NUMBER NUMBE Oconee Nuclear Station, Unit Three 287 97 03 00 4 OF 16 the control room operators received statalarm 3SA-2/C-2 (HPIP DISCH PRESS LOW).

This statalarm cleared within twenty seconds but alarmed twice more during the next minute. The operators noted that HPI discharge pressure was indicating approximately 2000 psig. They also noted that RCP seal injection flow was normal but 3HP-31 (RCP Seal Injection Control Valve) position demand was swinging. 3HP-31 control was taken to manual to stop the swings. At 0915 hours0.0106 days <br />0.254 hours <br />0.00151 weeks <br />3.481575e-4 months <br />, the 3A HPI punp auto started cr low RCP seal injection flow. The 3A HPI pump was manually stopped within one minute by the control room operators. At 0916 hours0.0106 days <br />0.254 hours <br />0.00151 weeks <br />3.48538e-4 months <br />, the operator placed the control switch for the 3A HPI pump back to automatic and the 3A HPI pump restarted on low RCP seal injection flow. The 3A HPI pump motor amps were swinging above normal (70-120 amps).and the 3B HPI pump motor ammeter was indicating about 10 amps.

The control room operators placed the control switch for the 3A HPI pump to run and secured the 3B HPI pump. At 0921 hours0.0107 days <br />0.256 hours <br />0.00152 weeks <br />3.504405e-4 months <br />, with CP seal injection flow and HPI pump discharge pressure 'both indicating w, the HPI pump suction flow path was aligned to the Borated Water torage Tank (BWST) by opening 3HP-24 (suction valve from BWST).

LDST level began increasing and the 3A HPI pump motor amps settled out at about 10 amps.

With HPI pump discharge pressure indicating low and no RCP seal injection flow, 3HP-24 was reclosed at 0928 hours0.0107 days <br />0.258 hours <br />0.00153 weeks <br />3.53104e-4 months <br />. At.approximately 0930 hours0.0108 days <br />0.258 hours <br />0.00154 weeks <br />3.53865e-4 months <br />, the Operator At The Control (OATC) noticed that the LDST chart recorder had been indicating a constant level of about 56 inches for the past hour and forty five minutes. He suspected the LDST erroneous level indications were the cause for the abnormal HPI Pump conditions.

The OATC made the Control Room SRO aware of the erroneous LDST level indications. Based on interviews, some members of the operating team suspected that the LDST really had a lower level than indicated or the LDST was not vented properly and a negative pressure existed in the tank. The LDST vent was checked and found to be open to the Gaseous Waste Disposal System as expected.

OATC started makeup to the LDST from the 3A Bleed Holdup Tank. At 0931 hours0.0108 days <br />0.259 hours <br />0.00154 weeks <br />3.542455e-4 months <br />, the operators secured the 3A HPI pump and closed 3HP-5 to isolate letdown from the RCS at the direction of the Operations Shift Manager (OSM).

Both channels of LDST levels were indicating 92 inches at this me. The alarm response guides were reviewed for all alarms.

/3/A/1700/14 "Loss of HPI Makeup and Letdown" and AP/3/A/1700/16 "Abnormal Reactor Coolant Pump Ops" abnormal,procedures were entered.

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YEAR SEQUENTIAL REVISION NUMBER NUMBER Oconee Nuclear Station, Unit Three 287 97 03 00 5 OF 16 The HPI System low discharge pressure alarm was the first indication of 3B HPI Pump degradation. While the operating team was assessing the status of the 3B HPI Pump, low seal injection flow caused an automatic start of the 3A HPI Pump. The low current load for the 3B HPI Pump indicated no makeup flow was being provided to the RCS so the pump was stopped. High current load followed by low current load on the 3A HPI Pump, in addition to no makeup or seal injection flow, indicated the 3A HPI Pump was not operating properly, so that pump was stopped also.

The operating team could have started the 3C HPI Pump with the BWST as the suction source. The team determined there was no time critical reason to take a risk damaging the 3C HPI Pump. The status of the suction header was questionable. Based on interviews and observations in training, the team would have opened a suction valve from the BWST (3HP-25) prior to starting the 3C HPI Pump. This is an operating rule to ensure a reliable source of ater is available for operation of the 3C HPI Pump. The team knew this ption was available for RCS makeup if needed.

At approximately 0945 hours0.0109 days <br />0.263 hours <br />0.00156 weeks <br />3.595725e-4 months <br />, Operations initiated a work activity to have technicians assess LDST level.

Tha OSM determined that the 3A and 3B HPI Pumps were probably damaged and the cause for the damage was not obvious. The OSM determined that additional support was needed to understand the reason for the failed HPI Pumps. He activated the Emergency Response Organization at 1030 hours0.0119 days <br />0.286 hours <br />0.0017 weeks <br />3.91915e-4 months <br />, on May 3, 1997.

At approximately 1100 hours0.0127 days <br />0.306 hours <br />0.00182 weeks <br />4.1855e-4 months <br />, the Site Vice President requested a Significant Event Investigation Team (SEIT) to investigate the HPI Pump problems. Members of the SEIT arrived at Oconee during the same shift in which the damaged occurred, observed the operators, and conducted interviews.

At 1110 hours0.0128 days <br />0.308 hours <br />0.00184 weeks <br />4.22355e-4 months <br />, the Technical Support Center (TSC) and the Operational Support Center (OSC) were staffed and operational.

approximately 1504 hours0.0174 days <br />0.418 hours <br />0.00249 weeks <br />5.72272e-4 months <br />, the Emergency Coordinator declared a Notice of sual Event (NOUE) emergency classification. He determined that there was a potential degradation in the level of safety on Unit 3. The basis

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YEAR SEQUENTIAL REVISION NUMBER NUMBER Oconee Nuclear Station, Unit Three 287 97 03 31 00 6 OF 16 for this was that recovery actions for the restoration of normal reactor coolant makeup would extend beyond the current shift. An Emergency Notification message was transmitted at 1505 hours0.0174 days <br />0.418 hours <br />0.00249 weeks <br />5.726525e-4 months <br />.

At approximately 1515 hours0.0175 days <br />0.421 hours <br />0.0025 weeks <br />5.764575e-4 months <br />, Instrument and Control (I&C) technicians determined that the LDST common reference leg was approximately 49 inches.

Normal reading for a filled reference leg is > 100 inches. The reference leg was refilled and indicated level dropped from approximately 98 inches to approximately 44 inches. With a partially full reference leg, actual LDST level was approximately 54 inches lower than indicated level. When the LDST level indicated 55.9 inches, the tank was really empty at the time the 3A and 3B HPI Pumps were damaged. I&C noted a small amount of boron buildup around a test tee cap on the reference leg side of level number 2.

Level transmitter calibration showed both levels within tolerance.

erations requested the I&C technicians to check the LDST reference lag on it 1 to ensure proper LDST level indication with the unit in operation.

nit 2 was not an immediate concern because it was at cold shutdown.

At approximately 1600 hours0.0185 days <br />0.444 hours <br />0.00265 weeks <br />6.088e-4 months <br />, site management formed a Failure Investigation Process (FIP) Team.

At approximately 2130 hours0.0247 days <br />0.592 hours <br />0.00352 weeks <br />8.10465e-4 months <br />, the TSC directed Operations staff to develop a 3C HPI Pump flush, fill and vent procedure and a procedure to start the 3C HPI Pump without utilizing the LDST. A contingency plan was also to be developed to support Unit 3 shutdown without any HPI Pumps operating. The RCS should be allowed to heatup slightly, only enough to support RCP seal return losses from the RCS and to maintain pressurizer level approximately 80 inches (<80 inches is the Pressurizer Heater low level cut-off).

On May 4, 1997, at 0129 hours0.00149 days <br />0.0358 hours <br />2.132936e-4 weeks <br />4.90845e-5 months <br />, the Operations procedure for restart of the 3C HPI Pump from the BWST was approved. Flushing, venting and alignment were also authorized.

At approximately 0830 hours0.00961 days <br />0.231 hours <br />0.00137 weeks <br />3.15815e-4 months <br />, the Plant Operation Review Committee (PORC) approved, with suggested changes, the contingency plan to.continue shutdown of Unit 3 with no HPI Pumps operating.

May 4, 1997, at approximately 1140 hours0.0132 days <br />0.317 hours <br />0.00188 weeks <br />4.3377e-4 months <br />, the 3C HPI Pump was started and the Unit shutdown continued.

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PAGE 3 YER SEQUENTIAL REVISION I

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P A E 3 Oconee Nuclear Station, Unit Three 2 87 97 03.

00 7OF 16 On May 5, 1997, at approximately 1946 hours0.0225 days <br />0.541 hours <br />0.00322 weeks <br />7.40453e-4 months <br />, the Unusual Event was terminated when pressurizer cooldown was completed, and the 3C.,HPI Pump was no longer needed.

On May 5, 1997, an AIT Team was dispatched to Oconee to review the event.

Also, the NRC issued a Confirmation of Action Letter (CAL) for Oconee Units 1, 2, and 3 concerning actions that Duke Power will take as a result of the unisolable Unit 2 RCS leak identified on April 22, 1997.

In this CAL, Oconee was requested to:

• determine the cause of this event (Unit 3 HPI system degradation which delayed entry into cold shutdown on May 3, 1997)

• evaluate the findings and implement appropriate corrective actions to prevent recurrence.

The FIP investigation discovered that a fitting had leaked on one of the LDST level transmitters. The fitting was the test tee fitting on the reference leg side of the D/P transmitter. Inspection of the fitting determined that it was a Swagelok test tee fitting with a Parker test tee cap. Closer examination of the tee revealed that a scratch existed inside the fitting in an area where sealing occurs when the cap is installed. It is not known the exact cause of the scratch in the fitting. The fitting was removed and sent to the Metallurgy Lab for further analysis.

An engineering evaluation of the inaccurate LDST level determined the Unit 3 HPI system to be past inoperable at 1615 hours0.0187 days <br />0.449 hours <br />0.00267 weeks <br />6.145075e-4 months <br />, on May 5,*1997.

In the event that a SBLOCA had occurred during the period between February 22, 1997 to May 3, 1997, the potential existed for hydrogen to be drawn into the suction of the HPI pumps as the BWST volume was depleted. The Unit 3 HPI system was inadvertently being operated outside the bounds of the LDST Operating Curve (OP/3/A/1104/02, Enclosure 5.2) as a result of the 54 inch discrepancy between actual LDST level and indicated LDST level. This additional information was reported to the.NRC as a supplement to the original event notification on May 6, 1997, at 1856 hours0.0215 days <br />0.516 hours <br />0.00307 weeks <br />7.06208e-4 months <br />.

results of Duke Power's investigation of this event were discussed at a ublic restart meeting at Oconee Nuclear Station on May 16, 1997.

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YEAR SEQUENTIAL REVISION WINUMBER NUMBER Oconee Nuclear Station, Unit Three 287 97 03 00 a OF 16 CONCLUSIONS:

There are two key issues; one is the damaged High Pressure Injection (HPI) pumps and the other is the past inoperability of the HPI System. The significant aspect is the implications of past inoperability of the HPI System. The inaccurate Letdown Storage Tank (LDST) level indicator created the conditions where Unit 3 operated.for a period of time with inadequate level in the LDST. Operation in this condition is outside the design bases of the HPI System. This condition was identified during the HPI System degradation event investigation.

The 3A and 3B HPI pumps were damaged on May 3, 1997, during a Unit 3 cooldown. A Duke Power Failure Investigation Process (FIP) team and ignificant Event Investigation Team (SEIT) thoroughly investigated this ent. As a result of these efforts, two primary causes for the degradation of the HPI system event were determined. First, LDST level instruments gave erroneous indications. Second, the control room team did not properly monitor and detect the inaccurate level indications given the existing plant conditions. The Unit 3 control room team was relying on the LDST low level alarm to key them when to makeup to the LDST rather than monitor the status of the LDST and makeup before reaching the alarm setpoint. The low level alarm setpoint would have alarmed at 55 inches to warn the operators of the decreasing level, however the partially filled reference leg prevented the low level warning provided by an annunciator and a computer alarm. Improved monitoring of control room indications would minimize the potential for this type of missed opportunity. The 3A HPI pump operated with inadequate NPSH for about fifteen minutes. The 3B HPI pump operated with inadequate NPSH for about four minutes.

Based on a laboratory examination of the fitting, the instrument line leak on the LDST resulted from one of two observed conditions, or a combination thereof:

1. Scratches on seating surfaces on tee and plug body

2. Slight expansion of the tee nipple, probably due to over-tightening of the cap sometime in the past.

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YEAR lv SEQUENTIAL REVISION NUMBER NUMBER Oconee Nuclear Station, Unit Three 287 '

97 03 00 9 OF 16 A review of operating experience was conducted utilizing industry, corporate, and Duke Power Company site databases. The search objective was to locate operating experience associated with instrument failures that involved reference legs, fittings, leaks, letdown storage tank, volume control tank, and other similar qualifiers. In reviewing the plant events and responses to operating experiences, information and indicators were available prior to 1992 to determine that the common reference leg used for the LDST level was a single failure design problem with significant consequences. There were several missed opportunities to utilize industry experience especially when considering the significance of the single failure of the common reference leg of the non-safety related LDST level instruments and the significant consequences of damage to the HPI Pumps.

e root cause of the past inoperability of the HPI system, is a ombination of a design weakness of a common reference leg for the LDST level instruments and a leaking instrument fitting due to an inadequate work practice. Also, a contributing cause was the failure to adequately apply available operating experience.

From a review of plant operating experience at Oconee for the last two years there have been no similar events of HPI inoperability, therefore, it is concluded that the event is non recurring.

There were no personnel injuries, radiation releases or overexposures related to this event.

CORRECTIVE ACTIONS:

Immediate

1.

Operators stabilized the Unit.

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YEAR FM SEQUENTIAL REVISION NUMBER NUMBER Oconee Nuclear Station, Unit Three 287 97 NB03 E 10 OF 16 Subsequent

1.

Detailed (FIP) and general (SEIT) investigations were completed.

2.

Support organizations (OSC, TSC) were activated as necessary to assist in completing the Unit 3 cooldown. Activities included restoring the accuracy of the Unit 3 LDST level indication and re establishing an HPI makeup flow path. The Unit 3 cooldown and depressurization was completed.

3.

The abnormal procedure for loss of HPI makeup was improved.

4.

A heightened awareness of monitoring control room instrumentation was established.

5.

For Unit 1, the LDST reference leg is being verified as full weekly and the reference leg tubing fittings are being checked for leaks each shift. These actions will continue until the LDST level and pressure modifications described at the May 16, 1997 meeting are implemented.

6.

Modifications on Units 2 and 3 added separate reference legs for the LDST level transmitters and a redundant LDST pressure transmitter.

7.

The Unit 3 HPI System has been repaired, flushed, inspected, and tested as required to assure operability.

8.

Short-term Operations training for on-shift personnel on the event and the LDST modifications has been implemented.

9.

The applicability of this event to other tank level instruments has been evaluated.

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YER SEQUENTIAL REVISION NUMBER NUMBER Oconee Nuclear Station, Unit Three 287 97 03 00 11 OF 16 Planned

1.

Modifications will be implemented on Unit 1 to add separate reference legs for the LDST level transmitters and add a redundant LDST pressure transmitter.

2.

Applicable procedures will be reviewed and benchmarked and appropriate improvements will be implemented.

3.

The modification selection process at Oconee will be reviewed in light of this event to assure proper prioritization.

4.

Operator simulator training on loss of LDST level will be implemented.

5.

A reliability study of the HPI System will be performed.

6.

The foreign material and damage inspection work practices for tubing caps and fittings will be improved.

7.

An action plan will be developed and work practices will be modified to address fittings from different manufacturers.

8.

The removed 3A and 3B HPI pumps will be examined.

9.

A root cause of the failure to adequately apply operating experience from the 1980s will be performed.

Corrective actions 1 through 9 are NRC commitments. They are the only NRC commitments contained in this report.

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YEAR SEQUENTL REVISION NLBE NLMBER Oconee Nuclear Station, Unit Three 287 97 03 00 12 OF 16 SAFETY ANALYSIS:

The subject failure of the Letdown Storage Tank (LDST) level instrument had the potential for evolving into two general classes of scenarios of degraded plant operation. The first class of scenarios would be those for which the level instrument failure and subsequent loss of High Pressure Injection.(HPI) flow initiate the plant e-Tent.

The actual Unit 3 event falls into this class. Other events in this class would include the HPI failure occurring in other modes, such as during power operation. The second class of scenarios would be those for which the level instrument failure and subsequent loss of HPI flow occur as part of the plant response to an event. Most of the licensing basis events, such as those events in UFSAR Chapter 15, assume the availability of the HPI System to maintain or restore Reactor Coolant System (RCS) inventory. With the subject failure f the LDST level instrument the HPI System would be degraded or operable. Consequently the capability of the plant to successfully itigate and recover from an event without the HPI System would be challenged. The following discussion assesses the safety significance of the LDST level instrument failure.

Loss of LDST Level as the Initiating Event For the scenarios for which the LDST level instrument failure is the initiating event, the HPI pump in operation would be lost due to a loss of suction supply. Normally the pump in operation is either the A or B HPI pump on the A injection train. The loss of the operating pump will start the second HPI pump (A or B) on low Reactor Coolant Pump (RCP) seal injection flow. Without any suction supply the second pump would also be immediately lost. Depending on the plant operating mode, the loss of these two HPI pumps would leave either the C HPI pump or no remaining operable pumps. Technical Specifications allow one HPI pump to be inoperable at reduced power levels and lower modes, so the loss of A and B pumps may cause a total loss of the HPI System.

A loss of the A and B HPI pumps with the C pump operable still provides for high pressure injection capability from the Borated Water Storage Tank ST).

The RCS will slowly lose inventory due to RCP seal leakoff. RCP al injection is also lost, with continued seal cooling provided by the

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YEAR SEQUENTIAL REVISIONI F A NUM BER

. NUM BER 1

36 Oconee Nuclear Station, Unit Three 287 97 03 00 13 o 16 Component Cooling Water System. Pressurizer level can then be restored by the operator manually starting the C HPI pump and throttling to maintain the desired RCS inventory.

Although there is no remaining redundancy in the HPI System, a safe and controlled shutdown and cooldown of the unit can be performed.

A loss of the A and B HPI pumps with the C pump inoperable results in a loss of all normal HPI injection capability. The RCS will slowly lose inventory due to RCP seal leakoff. RCP seal injection is also lost, with continued seal cooling 'provided by the Component Cooling (CC) System. For this situation the Standby Shutdown Facility (SSF) Reactor Coolant (RC)

Makeup Pump is available within approximately ten minutes to supply borated RCS makeup flow via RCP seal injection. With this backup makeup flow ligned, the plant can be maintained in a stable hot shutdown condition.

ue to the limited flow capacity of the SSF RC Makeup Pump, proceeding to cold shutdown would be very gradual.

Depending on the plant initial conditions at the time HPI flow is lost, such as the conditions at the time of the Unit 3 event, reaching the long-term decay heat removal mode may be possible without any significant abnormal operations.

Lo3s of LDST Level.During An Event For the scenarios for which the LDST level instrument failure exists at the beginning of an event, the HPI pumps will potentially be lost due to loss of suction caused by hydrogen expanding from the LDST into the HPI suction header. A loss of all HPI injection capability will result in different levels of severity in the plant response depending on the event in progress.

If the event in progress does not involve a loss of primary coolant or RCS overcooling, then the demand for HPI injection is limited to that required to offset RCP seal leakoff. This seal injection can be supplied by the SSF RC Makeup Pump within approximately ten minutes. With the alignment of the SSF RC Makeup Pump a hot shutdown condition can be maintained and core cooling is not challenged.

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LER NUMBER 6 PAGE 3 YEAR SEQUENTIAL REViSION NUMBER NUMBER Oconee Nuclear Station, Unit Three 287 97 03 00 14 OF 16 If the event in progress involves overcooling of the RCS, such as a loss of steam generator pressure control, the inventory makeup and boration normally supplied by the HPI System will be lost.

It is likely that the overcooling will result in emptying the pressurizer and a loss of the subcooled margin. The operator will trip the RCPs on loss of the subcooled margin. Continued shrinkage of the primary inventory will result in voiding at the hottest locations in the RCS, most likely the reactor vessel head initially. For large overcooling transients the pressure will decrease to less than 600 psig and the core flood tanks will inject. This will provide both RCS inventory makeup and boron. For smaller overcooling events core flood tank injection may not occur. It is likely that the subcritical margin will be maintained despite the loss of HPI boron injection. The loss of HPI injection may result in an interruption of natural circulation. Should this occur the reheating of the RCS due to

• nterruption of primary-to-seconda.ry heat transfer will either expand the nventory and restore natural circulation, or result in a transition to two-phase natural circulation. Either evolution will establish a long-term method of decay heat removal. The SSF RC Makeup Pump can then be used to gradually refill and borate the RCS.

If the event in progress involves a loss of primary coolant inventory, such as a SBLOCA or a SGTR, the loss of HPI injection will result in a significant challenge to core cooling. The loss of inventory can only be offset by depressurizing the RCS to enable the core flood tanks and the Low Pressure injection System to inject and maintain core cooling. The station Emergency Operating Procedures include guidance to depressurize the RCS by rapidly decreasing steam generator pressure and by opening the pressurizer PORV, as necessary. These actions should be successful in cooling the core.

For large break LOCAs the HPI System is not credited in the licensing basis analyses. Therefore, there is no impact on the large break LOCA analysis from the failure of the LDST level instrumentation.

The ATWS analysis credits the HPI System to inject sufficient boron to rovide the negative reactivity necessary to shut down the reactor.

thout the HPI System to shut down the reactor, the event would be rminated only with successful insertion of a sufficient number of control rods.

The station Emergency Operating Procedures include guidance to obtain insertion of the control rods following an ATWS event.

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YEAR SEQUENTIAL REVISION NUMBER NUMBER Oconee Nuclear Station, Unit Three 287 97 03 00 15 OF 16 PRA Perspective Because of the temperature and pressure of the RCS at the time of the event and the other equipment that was still available for mitigation, the actual failure of the two HPI pumps during the event had an insignificant probability of resulting in core damage. Additionally, even if the plant had been at power when the HPI pumps failed, there would still have been a very low probability of core damage.

If the failure of the two HPI pumps occurred during power operations, the following sequence of events would have to occur to result in core damage:

• The third HPI pump would have to fail or be out of service,

" The thermal barrier cooling provided by the Component Cooling System would have to fail, The SSF RC Makeup Pump cooling of the RCP seals would have to fail,

• And depressurization.of the primary system to conditions to allow the Low Pressure Injection (LPI) System to inject would have to fail.

If an initiating event such as a steam generator tube rupture or a SBLOCA had occurred while the LDST was nearly empty, all three HPI pumps could have failed as a result of gas binding. This event would be considered

.significant with respect to core damage risk.

If this were to occur, the only way for the operators to mitigate the accident would be.to depressurize the RCS to allow injection with LPI.

If this action failed, core damage would be expected. As a result, this event would be considered an Accident Sequence Precursor.

Summary of Safety Significance For the class of scenarios beginning with a failure of the LDST level instrument and loss of the 3A and 3B HPI Pumps, the plant can be put in a safe condition without approaching any loss of core cooling or other operational limits. These scenarios could be successfully mitigated by manual operation of the 3C HPI Pump or the SSF RC Makeup Pump. However, e ability.to achieve a cold shutdown condition may be degraded or lost.

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YEAR SEQUENTIAL REVISION NUMBER NUMBER Oconee Nuclear Station, Unit Three 287 9700 16 o For the class of transients which do not empty the pressurizer due to either an overcooling transient or a loss of primary coolant, the SSF RC Makeup Pump would be able to maintain a hot shutdown condition. The ability to achieve a cold shutdown condition may be degraded or lost.

For the transients which empty the pressurizer due to overcooling, the RCS would evolve to some mode of natural circulation, although inventory control capability would be minimal. Core cooling would be maintained, but plant conditions would be abnormal and challenging.

For the accidents such as SBLOCA and SGTR which involve a loss of coolant, but which do not result in the RCS depressurizing down to LPI injection conditions (like LBLOCA), core cooling would be challenged without HPI System injection. The station Emergency Operating Procedures direct the perator to depressurize the RCS to obtain core flood tank and LPI System njection. These actions should result in maintaining core cooling, but are outside the design basis of the ECCS.

Based on the above evaluation the failure of the LDST level instrumentation has a low safety significance for the types of transients that are expected to occur during the life of the plant. For the lower probability accidents which involve a loss of primary coolant, an increased risk of core damage and offsite dose consequences would result.