ML20195H168

Forwards Copy of Preliminary ASP Analysis of Operational Condition Discovered at Ons,Units 1,2 & 3 on 980212 & Reported in LER 269/98-004,for Review & Comment

ML20195H168
Person / Time
Site:	Oconee
Issue date:	06/10/1999
From:	Labarge D NRC (Affiliation Not Assigned)
To:	Mccollum W DUKE POWER CO.
References
NUDOCS 9906160295
Download: ML20195H168 (30)

Text

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.j k UNITED 81'ATES

] NUCLEAR REGULATORY COMMISSION

. WASHINGTON, D.C. 30086 0001

%*,,***+$o

/ June 10,' 1999 i

V -

Mr. W. R. McCollum, Jr.

L l Vice President, Oconee Site

, Duke Energy Corporation.

j ' P. O. Box 1439 Seneca, SC 29679 l-l

SUBJECT:

. REVIEW OF PRELIMINARY ACCIDENT SEQUENCE PRECURSOR ANALYSIS l

= OF OPERATIONAL CONDITION AT OCONEE NUCLEAR STATION, UNITS 1,2, l ' AND 3 -

t

Dear 'Mr. McCollum:

' Enclosed for your review and comment is a copy of the preliminary Accident Sequence Precursor (ASP) analysis of an operational condition that was discovered at Oconee Nuclear Station, Units 1,2, and 3 (Oconee 1,2, and 3) on February 12,1998 (Enclosure 1), and was l

reported in Licensee Event Report (LER) No. 269/98-004. 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 l realize that licensees may have additional systems and emergency procedures, or other l features, at their plants that might affect the analysis. Therefore, we are providing you an L opportunity to review and comnient 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 re-analysis, and prepare the l

final report of our analysis of this event in a timely manner, you are requested to complete your 1

' 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 f' l event in which the final precursor analysis of the condition is made publicly available. As soon i

as our final analysis of the condition has been completed, we will provide for your information L the final precursor analysis of the condition and the resolution of your comments.

l- We have also enclosed several items to facilitate your review. Enclosure 2 contains specific L guidance for performing the requested review, identifies the criteria that we will apply to determine whether any credit should be given in the analysis for the use of licensee-identified NRCIU CSITER C8PY

! , 9906'160295 990610 PDR l-8 ADOCK 05000269 J

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Mr. W. R. McCollum, Jr. June 10, 1999 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. 269/98-004, which documented the condition.

Please contact me at (301) 415-1472 if you have any questions regarding this request. This request is covered by the existing OMB clearance number (3150-0104) for NRv staff followup review of events documented in LERs. Your response to this request is voluntary and does not constitute a licensing requirement.'

Sincerely, ORIGINAL SIGNED BY:

David E. LaBarge, Senior Project Manager, Section 2 Project Directorate ll Division of Licensing Project Management Office of Nuclear Reactor Regulation Docket Nos. 50-269,50-270, and 50-287

Enclosures:

(1) ASP Analysis (2) Licensee Review Guidance (3) LER 269/98-04 cc w/encis: See next page Distribution: OGC e Docket FileE ACRS PUBLIC C. Ogle, Ril PD ll-1 R/F J. Zwolinski/S. Black S. May, RES P. O'Reilly, RES Document Name: G:\PDil-1\OCONEE\ ASP ANA.LTR.WPD To receive a copy of this document, Indicate in the box:

"C" = Copy without attachment / enclosure "E" = Copy with attachment / enclosure "N" = No copy ' M OFFICE PM:PQll/$1/A LA:PDil/S1 l6 SC:PDil/S1 NAME DLaBd6tidin CHawes Of#j REmch M DATE & / /C/99 (0 / li) /99 6 //0/99 OFFICIAL RECORD COPY

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l Mr. W. R. McCollum, Jr. 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. 269/98-004, which documented the condition.-

Please contact me at (301) 415-1472 if you have any questions regarding this request. This fequest is covered by the existing OMB clearance number (3150-0104) for NRC staff followup

' review of events documented in LERs. Your response to this request is voluntary and does not t' constitute a licensing requirement. j I

Sincerely,  !

I 1

David E. LaBarge, Senior Project Manager, Section 2 Project Directorate ll Division of Licensing Project Management ,

Office of Nuclear Reactor Regulation l Docket Nos. 50-269, 50-270, and 50-287

Enclosures:

(1) ASP Analysis (2) Licensee Review Guidance (3) LER 269/98-04 cc w/encis: See next page l

i

Oconee Nuclear Station .

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cc:

- Ms. Lisa F. Vaughn Mr. J. E. Burchfield Legal Department (PBOSE) . Compliance Manager Duke Energy Corporation Duke Energy Corporation 422 South Church Street Oconee Nuclear Site

- Charlotte, North Carolina 28201-1006 P. O. Box 1439 Seneca, South Carolina 29679 Anne Cottington, Esquire -

Winston and Strawn Ms. Karen E. Long 1400 L Street, NW. Assistant Attorney General Washington,DC 20005 North Carolina Department of Justice Mr. Rick N. Edwards P. O. Box 629

- Framatome Technologies Raleigh, North Carolina 27602 Suite 525 1700 Rockville Pike L. A. Keller Rockville, Maryland 20852-1631 Manager- Nuclear Regulatory Licensing Manager, Lls Duke Energy Corporation NUS Corporation 526 South Church Street 2650 McCormick Drive,3rd Floor Charlotte, North Carolina 28201-1006 Clearwater, Florida 34619-1035 Mr. Richard M. Fry, Director Senior Resident inspector Division of Radiation Protection I U. S. Nuclear Regulatory North Carolina Department of i Commission Environment, Health, and 78128 Rochester Highway Natural Resources  ;

Seneca, South Carolina 29672 3825 Barrett Drive  :

Raleigh, North Carolina 27609-7721 Virgil R. Autry, Director - ,

Division of Radioactive Waste Management Mr. Steven P. Shaver -

Bureau of Land and Waste Management Senior Sales Engineer l I

Department of Health and Environmental Westinghouse Electric Company Control 5929 Carnegie Blvd.

2600 Bull Street Suite 500 Columbia, South Carolina 29201-1708 Charlotte, North Carolina 28209 l i

County Supervisor of Oconee County Walhalla, South Carolina 29621 4

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l LER No. 269/98-004 l

6 LER No. 269/98-004 i

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Event

Description:

Calibration and calculational errors compromise emergency j core cooling system transfer to emergency sump

[ Date of Event: February 12,1998 1

Plant: Oconee Nuclear Plant, Units I,2, and 3 l Event Summary .

At the Oconee Nuclear Plant, Units 1,2, and 3 (Oconee 1,2, and 3), incorrect calibration of the borated water

, storage tank (BWST) level instruments, failure to address potential errors in reactor building emergency sump (RBES) indicated level, and incorrect estimation of expected RBES level resulted in (1) the potent,ial for emergency core cooling system (ECCS) pump loss ofnet positive suction pressure (NPSH) and vortexing, and (2) a situation where the emergency operating procedure (EOP) requirements for BWST-to-RBES transfer would never have been met. This would have required ad-hoc operator action to maintain post-loss-of-coolant

. accident (LOCA) core cooling. The estimated conditional core damage probability (CCDP) associated with 4 4 these conditions is 2.0 x 10'8 at Oconee 1 and 2 and 1.9 x 10 at Oconee 3. This is an increase of 1.7 x 10 4

at Oconee I and 2 and 1.4 x 10 at Oconee 3 over the nommal core damage probability (CDP) in a 1-year period of 1.8 x 104.

Event Description On February 12,1998, Oconee I was at 65 percent power and Oconee 2 and 3 were at 100 percent power.

During an investigation of a Self-Initiated Technical Audit (SITA) issue, personnel at Duke Power determined that the BWST level instruments were miscalibrated by as much as 18 in lower than assumed in the 4 calculations supporting EOP actions. Because of the calibration error, the indicated water level in the BWST was higher than the actual water level. Consequently, during the drain-down of the BWST following a postulated LOCA, unacceptable ECCS and reactor building spray pump NPSH and vortex formation may occur before the operators, while complying with the EOPs, transfer pump suction from the BWST to the  !

reactor building (RB) sump (Ref.1).

The BWST level calibration errors occurred when three new level transmitters were installed in 1989, replacing two older pneumatic level instrument trains. The field installation drawings specified that the new transmitters l be mounted at elevation "799-1 or below." As a result, the new calibration test tees for each instrument were typically located ~1 ft below the elevation of the impulse line tap into the system, but in the worst case the elevation difference was -1.5 feet, as shown in Fig. I and Table 1. (Level transmitters LT 2A and LT 6 are the primary indicators of the water level in the BWST following a LOCA.) A review of the drawings for the original pneumatic instruments indicated an elevation difference of approximately 4 in. Although the

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Enclosure 1

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r LER No. 269/98-004 )

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calibration procedure was revised aRet the new transmitters were installed, the revision did not address the elevation differences

• l l Table 1. BWST Level Transmitter Test Tee -Impulse Line Elevation Errors ,

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Elevation Error in BvyST Level Transmitters (R) .

Unit LT 2A LT 6 LT 132 l Unit 1 -0.776 -1.01 6 -0.94 6  !

Unit 2 -0.976 -1.106 -1.08 6 Unit 3 -1.36 -1.40 -1.46 A second potential source of calibration error, the relative height of the calibration test instrument compared to the calibration test tee, while also missing from the calibration procedure, was determmed to not j l

substantially impact instrument calibration because the calibration test instrument elevation is adjusted at j Oconee to match the elevation of the test tee.

In 1986, a series of instrument error calculations, which addressed the BWST level instruments, were performed to determine the appropriate procedural setpoints for BWST-to-RBES transfer in order to satisfy  !

ECCS pump NPSH requirements and to avoid vortexing in the pump suction lines. These calculations assumed that the zero reference elevation for the BWST level instruments was the elevation of the impulse line tap. In January,1988, these calculations were designated OSC-2820, " Emergency Procedure Guidelines Setpoints,"

to document the sources and derivation of nurnerical values used as EOP setpoints.

l Although these calculations were updated on several occasions aAer the BWST level instruments were replaced in 1989, the assumed zero reference point was not changed. Therefore, because calibration was to the test tee elevation rather than to the impulse line tap elevation, the error between the water level in the BWST assumed in the EOP calculations and the indicated water level differed by 1-1.5 A in the nonconservative direction. This l crror is a significant fraction of the 6 ft and 2 A BWST level setpoint action statements included in the EOPs. j All BWST level transmitters were recalibrated to address the test tee elevation errors by 0431 on February 13, 1998, the day after the problem was discovered.

One week after the BWST level instrumentation miscalibration was found, personnel identified another problem related to the BWST-to-RBES transfer. The Oconee EOPs at the time of this event required the operators to ,

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~ ' Current Oconec practice in 'other instrument calibration procedures is to include a "zero offset" on the calibration data sheet to account for the difference between the instrument test tee and impulse line tap elevations.

6 NRC staff, ASP program staff, and personnel from Duke Power, telecon, January 28,1999.

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LER No. 269/98-004

( begin the BWST-to-RBES transfer when the water level in the BWST was less than 6 ft and the water level L in the RBES was greater than 4 A (Ref. 2). He failure to consider instrument errors when the EOP muumum RBES level was specified, plus the incorrect calculation ofthe expected water level in the reactor building when the water level in the BWST dropped to 6 ft, resulted in the potential for the indicated water level in the RBES to never reach the 4 ft level required for transfer.

De original 1973 emergency procedure for transferring ECCS pump suction from the BWST to the RBES specified that the transfer should occur upon receipt of the low-low BWST level alarm, then set at 3 ft. No t RBES level requirement was included in the original procedure.

In 1985, the ECCS pump suction transfer procedure was revised to require the water level in the BWST to be less than 6 A and the water level in the RBES to be more than 2 ft. He 2-ft RBES level was included as a precaution to ensure an adequate water level in the sump followmg pipe breaks that could be located outside I the contamment. De RBES level instruments in place at the time had a range of 0 to 3 ft. Between December 1984, and December 1986, as part ofpost-Dree MileIsland accident upgrades, two wide-range RB water level transmitters were installed at each of the three Oconee units. These instruments provide RBES level indication of 0 to 15 ft.

! When OSC-2820, " Emergency Procedure Guidelines Setpoints" was issued in January 1988 (as described previously), the results of calculations performed one month earlier that addressed the potential error in the new RBES water level instruments were used as inputs in determinmg the nummum pump NPSH requirements during the recirculation mode. An RBES setpoint of 3.5 ft was established to ensure a minimum sump inventory for all accidents (the intent was to confirm that inventory of water in the BWST had been transferred to the RB rather than to a location outside containment). He supporting analysis for the 3.5-ft setpoint included an allowance of +8.8 in for instrument error to account for the possibility that the level transmitters might read high, but did not recognize the possibility that the RBES level indication might read low and never reach the EOP setpoint.

In February 1988, the RBES level instrumentation calculation was revised to address current leakage. His l calculation estimated the " worst-case" instrument error to be +8.8/-21'in. At the time the calculation was

! revised, the water level in the RB was estimated to be 5.3 ft (64 in) when the water level in the BWST reached 6 ft. Assuming a worst-case instrument error (- 21 in), the actual water level in the RBES (43 in) was greater than the 3.5 ft (42 in) water level required for the BWST-to-RBES transfer, but only marginally. In April 1988, the EOP was revised to incorporate the 3.5 ft mimmum RBES water level prior to transfer.

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In July 1989, OSC-2820 was revised to require a muumum indicated RBES water level of 3.75 ft to assure mimmum NPSH requirements would be met. Because the calculation did not evaluate the potential impact of j

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'the RBES level instruments reading low, the fact that the 3.75-ft level (45 in, or 2-in greater than the 43 in lowest indicated level considering maxunum instmment error) might not be reached was not recognized. He EOPs were not revised to reflect the changes to OSC 2820 at that time.

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• I"ne wwst-case negative instrument error was revised in 1996 to - 18.1 in.

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.- . 1 LER No. 269/98-004 At the end of May 1994, the EOPs were revised to reflect a higher minimum water level in the RBES before the BWST-to-RBES transfer is made. For instrument readability reasons, the mimmum indicated water level in the RBES was established at 4 ft, which met the 3.75-A level documented in OSC-2820. Again, this revision failed to consider the potential for the RBES level instruments reading low. Once the EOP change was made, the potential existed for the RBES level to indicate 5 in below that which was procedurally specified when the operators were oW to begin actions required for transferring ECCS suction from the BWST to the RBES. I His is based on an estimated water level in the RBES of 64 in when the water level in the BWST was at 6 ft.

His problem was further impacted by another calculational error discovered in November 1997 (Ref. 3). The calculation of the inventory ofwater in the RBES (that had previously been used to estimate a water level depth of 64 in. in the RBES when the water level in BWST was at 6 ft) was found to incorrectly account for the following trapped water volumes that would reduce the expected water level in the RBES following a LOCA:

. water trapped in the reactor vessel cavity and in the deep end of the fuel transfer canal, water needed to make up for reactor coolant system shrmkage during cooldown, a water needed to refill the pressurizer, water needed to fill the reactor building spray piping inside containment, and a water needed to account for the vapor content maintaining containment pressure.

Ref. 3 noted that the reactor vessel cavity and the fuel transfer canal could trap a large quantity of water and significantly reduce the inventory in the RBES - thereby reducing the RBES water level. He reactor vessel '

cavity is the volume between the reactor vessel and the primary shield (Fig. 2). Reactor coolant piping, core l- flood / decay heat removal piping, and incore instrument tubing pass through the reactor vessel cavity. In addition, a drain line from the deep end of the fuel transfer canal empties into the casity. The bottom of the l

reactor vessel cavity contains a 4-in line which drains the cavity to the RB normal sump. However, the drain line was covered with a flange that contained a 3/4-in pipe nipple that provided very limited drainage (this <

flange was discovered to be missing at Unit 3).

'Ibe deep end of the fuel transfer canal could also trap a large quantity of water. Two lines are provided to drain the fuel transfer canal to the RB normal sump. Instead of perforated drain covers, the drain lines contained " basket strainers" that were believed to be much more likely to be blocked by debris, which would prevent the fuel transfer canal from draining. (An additional drain line, located I ft above the bottom of the l fuel transfer canal, provides an alternate drain path to the reactor vessel cavity; however, drainage through the

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reactor vessel cavity was essentially blocked by the 3/4-in restriction discussed previously.) ne basket strainers had been installed for ALARA purposes during an outage about 10 years ago and had been allowed

' to remain during operation without a proper station modification evaluation.

l An evaluation considering the effects ofwater being trapped in the reactor vessel cavity and in the fuel transfer j canal concluded that the expected water level in the RBES was 3.07 ft instead of the 5.3 ft (64 in) used in  !

calculations for determining when the water level in the BWST reached 6 ft. This revised value would apply particularly to large- and medium-break LOCAs, when building spray would collect in the fuel transfer canal.

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LER No. 269/98-004 Following the removal of the basket strainers and the flange on the reactor cavity drain in November 1997, the expected water level in the RBES was estimated to be ~4.5 ft.

In conclusion, three conditions that degraded the potential for BWST-to-RBES transfer were reported in Refs.

I and 3. Incorrectly calibrated BWST level transmitters (1989-1998) could have resulted in ECCS pump loss of NPSH and vortexing when the operators performed the EOP steps required to place a unit on sump recirculation following a LOCA. Failure to consider potential RBES level instrument error when developing '

procedures for the BWST-to-RBES transfer, combined with the incorrect estunation ofthe expected water level

in the RBES (1985-1998), could have resulted in a condition where EOP requirements for initiatmg BWST-to-RBES transfer would not have been met. His would have required ad-hoc operator action to maintain post-LOCA cooling.

Additional Event-Related Infor nation De Oconee ECCS (Fig. 3) consists ofg high-pressure injection (HPI) and low-pressure injection (LPI) syrtem, as well as a core flood system. He HPI system includes three 24-stage vertical centrifugal pumps that develop 3000-psi discharge pressure with a capacity of 500 gpm each. The HPI system provides both normal niakeup and reactor coolant pump seal injection, as well as makeup to the RCS for small and medium-break LOCAs.

HPI pump A or B is normally in operation; HPl pump C is for emergency use only, ne HPI pumps will typically operate for 1-2 min without an adequate suction source before they are damaged.

%e Oconee LPI system also includes three pumps. Rese high-capacity, low head pumps provide RCS makeup for removing decay heat during normal shutdown operations or following a large-break LOCA. When the RCS is not depressurized below the LPI pump shutoff head, the LPI pumps also proside the suction source for the HPI pumps during the recirculation phase following a small- or medium-break LOCA. Two of the LPI

. pumps are automatically started for LOCA mitigation; the third pump is manually started ifrequired. De LPI pumps are more tolerant of reduced NPSH than the HPI pumps, and can operate for greater periods of time with reduced NPSH. [While no information is available concerning the expected Oconee LPI pump performance at reduced NPSH, Ref. 4 provided this infonnation for another low-pressure, high-capacity pump-the containment spray pump at Maine Yankee. He manufacturer ofthat pump indicated that the pump

, could operate indefinitely at 95% of required NPSH and for 15 min at 75% of required NPSH. He pump manufacturer also stated that similar pumps are routinely operated for 1-3 min at 50% of required NPSH without sustaining damage.]

The Ownee BWSTs provide 350,000 gal for injection when drawn down from the minimum Technical Specification level (46 ft) to 6 ft. Because the same BWST level channels are used to measure maximum and minimum water level, the BWST level calibration error did not impact the volume of water delivered to the RCS during the injection phase.

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LER No. 269/98-004 Modeling Assuinptions

~ This analysis addressed the combined impact of(1) water trapped in the reactor vessel cavity and the fuel transfer canal, (2) the potential for RBES level instruments to indicate low due to instrument error, and (3) incorrectly calibrated BWST level transmitters that increase the probability that the operators would fail to transfer the ECCS pump suctions to the RBES once the inventory in the BWST is depleted. An event-specific mcdel was developed to depict the potential combinations ofinstrument and operator errors that, following a I OCA or other condition requiring sump recirculation, could result in failure to transfer ECCS pump suction from the BWST to the RBES and result in the unavailability oflong-term core cooling. This model, shown in Figs. 4 and 5, was used to estimate the importance of this event. The Oconee Standardized Plant Analysis Risk (SPAR) models developed for use in the ASP Program were used to determine the nommal CDP in a 1-year period. The event tree model includes the followmg banches:

Sump Recirculation Required (RECIRC1 De initiating events necessary to analyze this event consist of the set of sequences that require sump recirculation. Because of differences in timmg, large, medium and small- .

break LOCAs and transients (including a loss ofoffsite power) requiring feed-and-bleed cooling were addressed ]

separately. Utilizing a 1-year time period (the longest interval analyzed in the ASP Program) and revising the j initiating event frequencies to be consistent with Ref. 5, the probabilities of requiring sump recirculation were i estimated using the Oconee SPAR model. nese are shown in Table 2.

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Table 2. Probability of Requiring Sump Recirculation During a 1-year Period

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Probability of requiring  !

Initiating event sump recirculation Large-break LOCA 5.0 E-006 I

Medium-break LOCA 4.0 E-005 Small-break LOCA 9.2 E-005 l Feed-and-bleed (transients) 2.4 E-005 )

RBESLevel > 4ft when BWSTLeve! = 6ft (RBES-OK). Success for this branch implies that the water level

. in the RBES is at least 4 A when the water level in the BWST is drawn down to 6 ft. If the water level in the RB is at least 4 ft when the water level in the BWST reaches 6 ft, this analysis assumes the operators will begin to transfer the ECCS pump sucts ms to the RBES as specified in the EOP (Ref. 2). If the water levelin the RB  !

. is less than the 4 ft required by ti; 3 EOP, the potential exists for the operators to delay transfer until the ECCS pumps are damaged and can no longer be used for core cooling. He probability that the RBES level will not indicate 4 ft t;.ium the water lev,1 in the BWST reaches 6 ft (i.e., when the EOP requires the operators to 6 l l

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i LER No. 269/98-004 l

l transfer ECCS pump suction to the RBES) depends on the actual water level in the RB and the RB water level instrument error.

a. . Impact of t.apped water in reducing expected RBES level. Two RB volumes were the primary contributors to the reduced RBES inventory reported in Refs. I and 3: the deep end of the fuel transfer canal and the reactor vessel cavity. At Units 1 and 2, the reactor vessel cavity drain line included a flange with a 3/4-in pipe nipple that effectively prevented the reactor vessel cavity from draining to the RB sump.

At Unit 3, the pipe flange was found to be missing. His would have allowed water that entered the Unit 3 reactor vessel cavity to drain to the RB sump.

He deep end of the fuel transfer canal drained to the RB sump tidough basket strainers at each of the units. He potential existed for these strainers to become clogged, thereby preventing the fuel transfer canal from draining. However, when the strainers were inspected, they were found to be clean at each .

unit,' and would have allowed the fuel transfer canal to drain to the sump. The water drained fr om the fuel transfer canal would increase the calculated RB sump level an additional 0.75 A, to 3.8 R, for Units 1 and

2. He missing reactor vessel cavity drain flange at Unit 3 would have allowed that unit's reacto/ vessel cavity to drain as well, resulting in a calculated RB sump level of 4.5 ft-this is the same as the calculated water level after the basket strainer and reactor vessel drain flange issues were resolved. These sump levels assume the BWST was initially at the Technical Specification (TS)-required level of 46 ft, and was drained to 6 ft at the time the ECCS pump suctions were transferred to the RBES. In actuality, the BWST is maintained at a level of 48.5 ft about 90% of the time, which would increase the water level in the sump at the time operators transfer to the sump?

b. Potential RBES level instrument error. He estimated error for the RBES level channels is +8.8/- 18.1 in, includirq current leakage. Based on information provided by personnel at Duke Power following the January 28,1999, telephone conversation with NRC and ASP program staff, this error is assumed to represent the *2a values of an approximately normal distribution. Using this assumption and the expected water levels in the RB described above, the probability that both RBES level channels will read less than 4 ft can be estimated.6 Using the +8.8-in and - 18.- in values, the mean error (due to current leakage) is calculated to be -4.7 in and the standard deviation (c)is calculated to be 6.7 in. For Oconee 1 and 2, with a calculated water level in the RB sump of 3.8 ft (45.6 in), the probability that an RB level channel will not read 4 ft (48 in)is estimated to be

$[(48 in - mean level)/o] = @[(48 - (45.6 - 4.7)) / 6.7] = 0.86,

' Personal communication, J. W. Minarick (S AIC) and R. L Oakley (Duke Power), hhtch 1,1999.

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! During the January 28,1999, telephone conversation, personnel at Duke Power stated that the Oconce operators would take action when the first RBES level channel indicated that the water level in the RB was 4 A.

Failure to take action would therefore require failure of both channels to indicate a 4-ft level.

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LER No. 269/98-004  :

where @[ ] is the cumulative normal probability distribution. The probability of not exceeding 4 ft on either channel can be estimated using the independent failure probability (0.86) and the correlatio : in the errors in the two channels. Unfortunately, essentially no information exists concerning the expected correlation between the two channels. As a surrogate for this information, data developed in conjunction with an NRC reactor protection system reliability study (Ref. 6) was used to estimate a p-factor for the ,

common cause failure of the two level channels.' The resulting estimate ( = 0.024) implies a very limited l' correlation between the two channels. Using this estimate for p, the probability that the RB water level indicators will not indicate that the level is at least 4 ft on either channel is estimated to be 0.735. Because ,

of the limited correlation between channels, this compares to a probability of 0.732 if the channels were independent. '

The probability (to two significant figures) of not indicating 4 ft on either RB level channel for initial BWST l levels of 46 ft and 48.5 ft at a BWST drain-down to 6 ft (the EOP-specified level to begin transferring ECCS j pump tuctions to the RBES) is shown in Table 3.

Table 3. Probability that Neither RB Water Level Channel will Indicate 4 ft.

i Probability that neither RB i Unit and initial BWST level water level channel indicates 4 ft Oconee I and 2,46 ft initial BWST level (10% of the time) 0.74 Oconee I and 2,48.5 ft initial BWST level (90% of the 0.55 l time)  ;

1 Oconee 3,46 ft initial BWST level (10% of the time) 0.18 l l

Oconee 3,48.5 ft initial BWST level (90% of the time) 0.064 )

Cold-Leg Break (CLBREAK). Success for this branch implies that the LOCA occurred in one of the cold legs. l Based on information provided in Ref.1, operator action to open the sump isolation valves will transfer ECCS j 1

pump suction to the RBES following a cold-leg break. This is because containment pressure is high enough to overcome the elevation head of the BWST. For a hot leg break, however, the lower expected containment pressure requires the operators to also isolate the BWST before the ECCS pumps take suction from the RBES.

Closure of the BWST isolation valves occurs later in the transfer sequence and requires additional time. The difference in timing is important, primarily for large- and medium-break LOCAs, and therefore cold- and hot-leg breaks must be distinguished in the model. To recognize the greater likelihood of a break in a cold leg

• Personal communication, J. W. Minarick (SAIC) and D. M. Rasmuson (NRC), March 15,1999.

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LER No. 269/98-004 because of the greater number ofcold leg pipe segments and welds,' this analysis assumes a probability of 0.6 that a LOCA will occur in a cold leg.

~ RBES = #f of BWSTMinimum Lew/ (RBES-M7N). If transfer to the RBES is delayed, the water level in the

, BWST will ultimately decrease to the point where the ECCS pumps are damaged by vortexing or unacceptable NPSH. Success for this branch implies that the water level in the RB reaches 4 R, satisfying the EOP BWST-to-RBES transfer requirement, in time for the operators to effect RBES transfer before ECCS pump damage occurs. 'Ihe incorrectly calibrated BWST level transmitters at the three units effectively raised the indicated level at which vortexmg would begin. The level a which vortexing is expected to begin was chosen as the .

BWST level associated with unacceptable LPI pump operation, because the impact of vortexmg on pump performance is expected to conunate. Based on the information included in Additional Event-Related Information, the impact of the slight reduction in NPSH caused by a 1-A reduction in BWST level is expected to be relatively minor. However, once vortexing begins it is expected to completely develop with only a slight additional reduction in the water level in the BCT (see, for example, the description of the loss of residual heat removal capabilities at Diablo Canyon on April 10,1987, in Ref. 8).

Attachment A to Ref.1 indicates that vortexing is expected to begin at a BWST water level of 0.85 ft.

Considering the calibration errors described in Table I, vortexmg is expected to begin, unknown to the operators, at an indicated BWST level ofapproxunately 1.8 A for Units 1 and 2, and 2.3 ft for Unit 3. In order

, to complete the transfer from the BWST to the RBES before vortexing impacts the LPI pumps, the operators must begin the transfer process at an indicated BWST level greater than 2 ft (the level specified in the EOP at which the BWST must be isolated).

Based on ECCS flowrates and valve cycle times,' plus additional assumptions concerning initiator-specific flowrates, the time to perform an intermediate EOP step and unit-specific average BWST calibration errors,6 the estimated BWST indicated levels at which the RBES transfer must begin in order to prevent vortexing are shown in Table 4.

"Ref. 7 prmides a discussion of the factors that influence the likelihood of pipe break.

• Personal conununication, J.W. Mi'iarick (SAIC) and B. Abellana (Duke Power), March 10,1999. For a large-break LOCA, an LPI flowrate of 6000 gpm (two trains), a building spray flowrate of 3000 gpm (two trains),

and an HPI flowrate prior to operator termination of 1400 gpm are estimated. Cycle times for the RBES and BWST isolation valves are 70 and ~30 sec, respectively.

. % following flowrates were assumed in the analysis at the time of switchover: 9000 gpm [large-break LOCA (LPI plus building spray)],4400 gpm [ medium-break LOCA (HPI plus building spray)] and 1400 gpm

, [small-break LOCA and feed and bleed (HPI)]. For cold leg breaks, the analysis assumed the RBES valves must be I opened 50% for the RBES to become the pump suction source For hot leg breaks, the analysis assumed the BWST isolation valves had to completely close before the sump prmided suction flow. In addition, an intermediary step in the EOP requiring building spray throttling was assumed to require 1 min. The average BWST calibration error was assumed to be -1.0 A for Units I and 2 and 1.4 ft for Unit 3.

9 f 9 l 1 l 1 O

" 4 u- _ _

LER No. 269/98-004 De conditional probability that RB water level on both level transmitters is still less than 4 A when the BWST reaches the minimum acceptable levels listed in Table 4, given the RBES level indication was less than 4 A when the water level in the BWST was 6 A, were estimated using the same approach as for branch RBES-OK.

These conditional probabilities are also included in Table 4.

- Operators Switch to RBESat BWSTMinimum Lewi(OPS-MIN). Success for this branch implies a decision l

on the part of the operators to transfer the ECCS pumps to the RBES before pump damage occurs, even though j the water level in the RB was less than 4 A. If the water level in the RB is less than 4 A when the water level i in the BWST is drawn down to 6 A, the operators will find themselves outside their procedural bases-action j to effect transfer to the RBES would techmcally be a violation of the EOP (Ref. 2) as written at the time the condition was discovered However, the operators would be aware medly of the need to transfer to the sump before the BWST depletes, and would know that the procedure required the transfer to be completed by  ;

the time the BWST level indicated 2 A. This knowledge is expected to result in an increasing urgency (initially l tempered by the understandmg that some mimmum RB water level was required for the pumps to operate in l {

the recirculation mode) to transfer the ECCS pumps to the RBES as the water level in the BWST dropr, '

ultimately resulting in such a decision.- Degraded ECCS pump performance, if observed, would serve to ,

reinforce the decision to t ansfer (operator burden, the n(ed for rapid response, plus annunciator noise, particularly following a large- or medium-break LOCA, would be expected to compromise such an observation). De Technical Support Center (TSC) would be fully operational at the time for small-break LOCAs and would also be expected to reinforce the decision to transfer.

The probability of not transferring the ECCS pumps cannot be rigorously estimated using contemporary Human Reliability Analysis (HRA) methods because the action is outside the procedure basis and is, in part, ad-hoc. For the purposes of this analysis it was assumed that, without TSC assistance, the operators would not begin to transfer the ECCS pumps to the RBES at an indicated BWST level of 6 A. However, around an  !

indicated BWST level of 4 A, it was assumed that there was an even chance that the operators would begin transferring the ECCS pumps to the RBES rather than waiting further for indication that the water level in the RB had risen to 4 A, and that at an indicated level of 2 A the operators would likely transfer the pumps to the ,

l sump. A value of 0.5 was therefore assigned to the probability that the operators would begin to transfer at i 4 A and a value of 0.1 was assigned to the probability that the operators would begin to transfer at an indicated level of 2 A. .For small-break LOCAs, the TSC would also be available to aid the operators. A moderate  !

dependency is assumed between the operators and the TSC for a decision at 4 A and greater and a low i l Mcy is assumed for the decision at 2 A, resulting in probability estimates of 0.9,0.3, and 0.01, at 6 A, l 4 A, and 2 R, respectively?

l l The probability that the operators, with and without support from the TSC, would fail to begin transferring the suction for the ECCS pumps to the RBES by the time the water levels in the BWST given in Table 4 were l

'Small-break LOCAs do not measurably contribute to the significance of this event. Assumptions concerning the probability of operator error following a small-break LOCA have little impact on the analysis results. l 10 i

O L j

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. , j i

LER No. 269/98-004 l Table 4. Minimum Acceptable BWST Levels to Initiate RBES Transfer and i Conditional Probability that RB Level will Not Indicate 4 ft. l l

l

. Minimum Conditional Con.ditional acceptable probability that RB probability that RB BWST level to level will not indicate level will not indicate initiate RBES 4 ft (initial BWST 4 ft (initial BWST Initiating Event Unit transfer (ft) level = 48.5 ft) level = 46.0 ft)

Large-break LOCA (cold leg) 1, 2 2.37 0.19 0.62 3 2.77 0.022 0.24 i Large-break LOCA (hot leg) 1, 2 4.43 0.39 0.85 3 4.83 0.10 0.63 Medium-break LOCA (cold leg) 1, 2 2.10 0.17 0.59 3 2.50 0.018 0.20 Medium-break LOCA (hot leg) 1,2 3.10 0.25 0.70 3 3.50 0.038 0.34 Small-break LOCA (cold leg) I, 2 2.0* 0.17 0.58 3 2.33 0.016 0.18 Small-break LOCA (hot leg) 1, 2 2.25 0.18 0.61 3 2.65 0.020 0.22 Feed-and-bleed cooling 1, 2 2.25 0.18 0.61 3 2.65 0.020 0.22

' based on procedure 11

1

• -. . s LER No. 269/98-004 l

reached were estimated by linearly interpolating between the probabilities estimated for water levels of 2,4, and 6 A. Representative operator error probabilities are shown in Table 5.

Substantial uncertainty is associated with the probabilities estimated for this branch. As noted earlier, the operator action being modeled is outside the domain of contemporary HRA methods. This, plus the fact that the impact of errors in procedures have not been considered in simulator exercises, results in very little information being available to accurately estimate such probabilities. The estimated probabilities are considered reasonable, considering the state of the art.

Operators Proceed Without Delay through Procedure (NO-DELAY). If RB water level indicates 4 A when the BWST level is 6 R, the operators are expected to begin transferring the suction for the ECCS pumps to the RBES as required by the EOP. Following a hot-leg break, if the operators prolong the transfer and delay isolating the BWST until its indicated level approaches 2 A (as allowed by the procedure), the ECCS pumps can also fail from vortexing. Success for this branch implies the operators proceed expeditiously in transferring the pump suctions to the RBES. A failure probability of 0.1 was utilized for large- and medium-break LOCAs, ,

where a delay of a few ofminutes is sufficient to initiate vortexing, considering the miscalibrated BWST level transmitters. For small-break LOCAs and feed-and-bleed cooling, because of the slow BWST drain down, only a deliberate Table 5. Probability of Operator Failure to Transfer ECCS Pumps Probability of Operator Error Probability of Operator Error BWST Level (ft) - without TSC support - with TSC support 6 1.0 0.9 4.8 0.8 -

0.7 4 0.5 0.3 3.1 0.3 0.1 2 0.1 0.01

]

decision to delay BWST isolation until a BWST level of-2 A is indicated will result in pump damage; a failure probability of 0.01 is assumed in these cases.

Depressurization to Allow LPR (DEPRESS). Medium- and small-break LOCAs and feed-and-bleed cooling

! require HPI for injection success. When the inventory of water in the BWST is depleted, the LPI pumps are used to take suction from the RBES and provide flow, at adequate NPSH, to the HPl pumps. Oconee procedures require the HPI pumps be lined up in series with the LPI pumps when the water level in the BWST 12 q

L J

LER No. 269/98-004 is at 10 ft. De loss of LPI pump flow at the onset of vortexing is expected to fail the HPI pumps, resulting in the need to rapidly depressurize the RCS to allow use of the LPI pumps for injection. Depressurization is possible following a LOCA, provided wand =y-side cooling is available (depressurization cannot be used during feed-and-bleed cooling hu=ae secondary-side cooling is unavailable). Consistent with previous precursor analyses of ev ents at Oconee (Ref. 9), the probability of failing to depressurize the RCS to allow use i of the LPI pumps for injection was assumed to be 0.1.

LPR Recovered (LPR-REC). Success for this branch implies that LPR is recovered following an initial failure to transfer, for example, through use of the third LPI pump once transfer is complete. Failure to recover LPR would be highly dependent on the initially faulty assessment that resulted in the failure of the runnmg LPI pumps, and is considered essentially unreliable for a large-break LOCA. For a medium-break LOCA a nonrecovery probability of 0.5 was employed. The additional time and TSC support that would be available following a small-break LOCA would improve the likelihood of recovery; a failure probability of 0.1 was used with this initiator.

Using the'above probabilities in the mohl shown in Figs. 2 and 3 results in the following estimated CCDPs from sequences that require recirculation: ,

Estimated CCDPs from Sequences that Require Recirculation .

. Unit I and Unit 2 Unit 3 Large-break LOCA 4.6 E-007 2.2 E-007 Medium-break LOCA 9.8 E-007 8.5 E-007 ,

l l

'Small-break LOCA 6.2 E-008 6.7 E-008 Feed-and-bleed cooling 1.8 E-007 2.4 E-007 Total 1.7 E-006 1.4 E-006 i

-Analysis Results The combined CCDP associated with the BWST level transmitter miscalibration and RB water level error over a 1-year period for recirculation-related sequences is 1.7 x410 for Units I and 2, and 1.4 x 10 4 for Unit 3.

Because design and installation errors such as those that comprise this event are not typically addressed in PRA (their contribution to nommal cut sets is zero), this CCDP is also the increase in the nominal core damage probability (CDP), or importance, for the event. De overall CCDP, considering all sequences, is therefore the estimated CDP for Oconee in a 1-year period (1.8 x 105, based on the ASP models) plus the above increases, or 2.0 x 108 for Units I and 2, and 1.9 x 10-5 for Unit 3.

Although the significance of the event at Units I and 2 is slightly greater than at Unit 3 (a result of the higher calculated RB water level at Unit 3), the dominant sequence (6.1x 10-7) within the subset of recirculation-13

LER No. 269/98-004 releod sequences involves a medium hot-leg break at Unit 3. In this sequence, when the BWST is drawn down te en indicated level of 6 A following a postulated medium-break LOCA, the RB water level indicates 4 A, and the operators begin to transfer the suction for the ECCS pumps to the RBES. However, the operators delay isolation of the BWST until the water level approaches 2 A and the ECCS pumps unexpectedly fail as a result of the (incorrectly indicated) low water level in the BWST. Depressurization to allow use of the LPI pumps is successful but the operators fail to recover LPR, resulting in core damage. His sequence is highlighted on the medium-break LOCA event tree shown in Fig. 4 and on Fig. 5 [which represents the recirculation (PB-COOL) branch in Fig. 4]. The medium-break LOCA model is similar to that developed to support the analysis of LER 287/97-003 in the 1997 ASP report (Ref. 9) and is described in that analysis. (Sequences associated with the late failure of HPI, which was important in the analysis of LER 287/97-003, have been excluded.)

De second most donunant sequence (with a CCDP of 2.9 x 109) is similar to the dominant sequence, but occurs at Units 1 and 2. In addition to medium br,eak LOCA sequences, large break LOCA and feed and bleed cooling sequences with CCDPs greater than 1.0x 10-7 occur at all three units. As can be seen~ in the above table, small break LOCA sequences contribute to a minor extent. All small break LOCA sequences have CCDPs below 1.0x104.

To illustrate the calculational process, definitions and probabilities for the event tree branches associated with the potential loss of sump recirculation at Unit 1 or 2 following a medium-break LOCA with an initial water level in the BWST of 48.5 A are shown in Table 6 (overall, this unit, initiator, and BWST-level combination contributes most to the CCDP). The conditional probabilities for the six recirculation-related core damage sequences are shown in Table 7. Table 8 lists the sequence logic associated with the sequences listed in Table 9.

14 9

LER No. 269/98-004 Acronyms ALIRA as low as reasonably achievable (radiation exposure)

BWST borated water storage tank CCDP conditional core damage probability l CDP core damage probability j ECCS emergency core cooling system I EOP emergency operating procedure )

HPR high-pressure recirculation i HPI high-pressure injection l HRA human reliability analysis LOCA' loss-of-coolant accident -

LPI low-pressure injection .;

LPR low-pressure recirculation NPSH net positive suction head (pressure)

RB '

reactor building RBES reactor building emergency sump SITA SelfInitiated Technical Audit -

SLOCA small-break LOCA TSC Technical Support Center References

1. LER 269/98-004, Rev.1,"ECCS Outside Design Basis Due to Instrument Errors / Deficient Procedures,"

April 7,1998.

2. OconeeEmergencyOperatingProcedureEP/l/A/l800/01,"CooldownFollowingLargeLOCA,"CP-601, Revision 18, p 13.

3. LER 269/97-010, Rev. O, " Inadequate Analysis of ECCS Sump Inventory due to Inadequate Design Analysis," January 8,1998.

4. NRC Information Notice 96-55, Inadequate Net Positive Suction Head ofEmergency Core Cooling and Containment Heat RemovalPumps under Design Basis Accident Conditions, October 22,1996.

5. Rates ofInitiating Events at U.S. Nuclear Power Plants: 1987 - 1995, NUREG/CR-5750, Februasy 1999.

6. Westinghouse Reactor Protection System Unavailabiliry, 1984 - 1993, NUREGICR-S$00, Vol. 2, in press.

15

l LER No. 269/98-004  !

7. H. M. Thomas, " Pipe and Vessel Failure Probability,"Reliabihty Engineering, Vol. 2,1981, pages 83 -

124.

8. Loss ofResidualHeat RemovalSystem, NUREG-1269, June 1987, Appendix C, p. 4. i 1

9. Precursors to PotentialSevere Core DamageAccidents: 1997, A Status Report, NUREGICR-4674,Vol.

26, November 1998. ,

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19 i

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a 1:1 st i ]Et ili i Fig. 5 Event tree for failure to transfer the ECCS pumps to the RBES.

21

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LER No. 269/98-004 Table 6. Definitions and Probabilities for Event Tree Branches for LER No. 269/98-004 (Medium Break LOCA at Unit 1 or 2 with Initial BWST Level of 48.5 ft Only)

Branch Failure name Descripti'on Probability i Ef.4CA Initiating Event - Medium-Break bss of Coolant Accident 4.0 E 005 RT Reactor Trip 5.5 E-006' HPI High PressureInjection 2.4 E-004' RECIRC Sump Recirculation Ryuired 3.6 E-005 6 RBES-OK RBES Level a 411 when BWST Level- 6 ft 5.5 E-001 CLBREAK Cold Leg Break 4.0 E-001 RBES-MIN ' RBES - 4 ft at BWST Minimum Water Level (Cold-Leg Break) 1.7 E 001 RBES - 4 ft at BWST Minimum Water Level (Hot Leg Break) 2.5 E-001 OPS-MIN Operators Switch to RBES at BWST Minimum Water Level (Cold-leg 1.1 E 001 Break).

Operators Switch to RBES at BWST Minimum Water Level (flot-Leg 2.7 E 001 Break)

NO-DELAY Operator: Proceed Without Delay through Procedure 1.0 E 001 DEPRESS Depressurization to Allow LPR 1.0 E 001 LPR REC LPR Recovere. 5.0 E 001

• System failure probability estimated using Oconee ASP model fault trees.

' Initiating event for Figure 5. This is the probability in a 1-year period that surnp recirculation is required following a medium-break LOCA. The medium-break LOCA probability is weighted by 0.9 to reflect the probability that the water level in the BWST will be 48.5

. ft.

1 l

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. LER No. 269/98-004 i

i Table 7. Sequence Conditional Probabilities for LER No. 361/98-003 (Medium-Break LOCA at Unit 1 or 2 with Initial BWST Level of 48.5 ft Only) a !

Conditional Event tree Sequence core damage Core damage Importance Percent name number probability probability (CCDP-CDP) contribution' (CCDP)* (CDP)6 RECIRC 2-4 2.9 E-007 0.0 2.9 E-007 37.7 RECIRC 2-5 6.5 E-008 0.0 6.5 E-008 8.4 RECIRC 2-9 1.0 E-007 0.0 1.0 E-007 13.0 i

RECIRC 2-10 2.2 E-008 0.0 2.2 E-008 2.9 RECIRC 2-14 2.4 E-007 0.0 2.4 E-007 31.2 RECIRC 2-15 5.3 E-008 0.0 5.3 E-008 6.9 Total (all sequences) 7.7E-007 0.0 7.7E-007 Up-1 0 * *

"X r ang ?

' Sequences 1- 6 only b

Since design and installation errors such as those that comprise this event are not typically addressed in PRA.their contribution to nominal sequences is zero.

23

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LER No. 269/98-004 l

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l Table 8. Sequence Logic for LER No. 361/98-003 (Medium-Bmak LOCA at Unit 1 or 2 with Initial BWST Level of 48.5 ft Only) i Event tree name Sequence Logic  !

number MLOCA + RECIRC 2-4 ,/RT, /HPI, /RBES-OK, CLBREAK, NO-DELAY,  !

/ DEPRESS, LPR-REC MLOCA + RECIRC 2-5 /RT, /HPI, /RBES-OK, CLBREAK, NO-DELAY, DEPRESS MLOCA + RECIRC 2-9 /RT, /HPI, RBES-OK, /CLBREAK, RBES-MIN, OPS-MIN, l

/ DEPRESS, LPR-REC l MLOCA + RECIRC 2-10 /RT, /HPI, RBES-OK, /CLBREAK, RBES-MIN, OPS-MIN,  ;

DEPRESS-

.MLOCA + RECIRC 2-14 /RT, /HPI, RBES-OK, CLBREAK, RBES-MIN, OPS-MIN,

/ DEPRESS, LPR-REC MLOCA + RECIRC 2-15 /RT, /HPI, RBES-OK, CLBREAK, RBES-MIN, OPS-MIN,  ;

DEPRESS i j

i l

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24

n GUIDANCE FOR LICENSEE REVIEW OF PRELIMINARY ASP ANALYSIS Background ,

l The preliminary precursor analysis of an operational event that occurred at your plant has i' 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 actualinitiating events, such as a loss of

, off-site power (LOOP) or loss-of-coolant accident (LOCA), degradation of pis,nt conditions, and i

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 ll

• The models used for the analysis of 1998 events were developed by the Idaho National l' l 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.  !

l 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, i

Guidance for Peer Review Comments regarding the analysis should address:

o Does the " Event Description" section accurately describe the event as it occurred? I e Does the " Additional Event-Related Information" section provide accurate additional l information conceming the configuration of the plant and the operation of and  !

procedures associated with relevant systems? l e Does the "Modeling Assumptions" section accurate' describe the modeling done for the event? Is the modeling of the event appropriatt the events that occurred or that had the potential to occur under the event conditionsy This also include's assumptions regarding the likelihood of equipment recovery.

Enclosure 2 L

, I i.

, )

t'(.

ee I

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 portens of the LER, AIT, or other event documentation concoming the sequence of events. System and component capabilities should be supported by references to the FSAR, IPE, plant procedures, or anafyses. 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&lDs),*

- electrical one-line diagrams,'

- results of thermal-hydraulic analyses, and  ;

operator training (both procedures and simulator),* etc. j Systems, equipment, or specific recovery actions that were not in place at the time of the event l 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, l

-- 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). i 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 i 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 pattemed 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.

4

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If g mitigation effect for the standby feedwater system would be credited in the analysis I

provided that the following material was available:

standby feedwater system characteristics are documented in the FSAR or accounted forin 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.

e The specific LER, augmented inspection team (AIT) report, or other pertinent reports, e 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 1 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 (ORNIJNOAC-232) Volume 26, Lockheed Martin Energy Research Corp., Oak Ridge National Laboratory, and Science Applications Intemational Corp., Oak Ridge, Tennessee, November 1998.

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Dsske Duke Power Company ghyg A Mr Enegy Comp.y Box 1439 Seneca SC29679 W.R.McConum,)r. (864) 885-3107 ornct Vice 1%sident (864) 885-3564 rsx April 7, 1998 U.S. Nuclear Regulatory Commission Document Control Desk Washington, D.C. 20555

Subject:

Oconee Nuclear Station Docket Nos. 50-269, -270, -287 Licensee Event Report 269/98-04, Revision 01 Problem Investigation Process No.: 0-098-0707 0-098-0825 Gentlemen: l Pursuant to 10 CFR 50.73 Sections (a) (1) and (d), attached is Revision 1 to Licensee Event Report 269/98-04, regarding the potential operation of the Emergency Core Cooling System and Reactor Building Spray System outside their design bases. This event involves old design issues that affected Borated Water j Storage Tank and Reactor Building water level indications and Emergency Operating Procedure Guidance.

The original report contained only the abstract and was transmitted under a cover letter dated March 14, 1998. In that letter I stated that additional time was needed to sufficiently evaluate the impact of a later, related occurrence on the initial event. I also stated that the related occurrence would be reported as LER 269/98-06 and would be submitted on or before March 23, 1998. However, our review has determined that the related occurrence is sufficiently related to be considered as part of the initial problem. Therefore, it is now included in this report and LER number 269/98-06 will be reassigned for future use as needed.

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This report is being submitted in accordance with 10 CFR 50.73 (a) (2) (i) (B) , (a) (2) (ii) (B) , and (a) (2) (v) (D) . This event did not adversely impact the health and safety of the public.

l l

Very truly yours,

- , j W. R. McCollum, Jr J Attachment I

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l Document Control Desk Date: April 7, 1998 Page 3 ,

cc Mr. Luis A. Reyes Administrator, Region II l U.S. Nuclear Regulatory Commission

, 61 Forsyth Street, S. W., Suite 23T85 l Atlanta, GA 30303 l Mr. D. E. LaBarge l U.S. Nuclear Regulatory Commission Office of Nuclear Reactor Regulation

. Washington, D.C. 20555 1

l INPO Records Center 700 Galleria Parkway, NW l

Atlanta, GA 30339-5957 .

l Mr. M. A. Scott NRC Resident Inspector Oconee Nuclear Station l

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ECCS Outside Design Basis Due To Instrument Errors / Deficient Procedures.

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HAME TELEPHONE NUMBER J.E. Burchfield, Regulatory Compliance Manager AREA C@E (864) 885-3292 COMPLETE ONE LINE FOR EACH COMPONEtrT FAILURE DESCRIBED IN THIS REPORT (13)

CAUSE SYSTEM COMPONEWT MANUFACTURER REPCETABLE CAUSE SYSTEM COMPONE0rf MANUFACTURER REPORTABLE TO NPRDS TO NPRDS SUPPLEMElfTAL REPORT EXPECTED (14) EXPECTED MOffrH DAY YEAR y l SUBMISSION TES (! yes, complete EXPECTED EUBM!S$10W DATE) DATE (15) l NO Ah8 TRACT LLimit to 2000 spaces. i.e. approximately litteen single space typewritten lines) (16)

On 2-12-98, Unit 1 was at 65% Full Power '(FP) and Units 2 and 3 were at 100%FP. An engineer, investigating a Self-Initiated Technical Audit (SITA) issue, found that the indicated zero of the Borated Water Storage Tank (BWST) level instruments was calibrated about 18 inches lower than assumed in calculations supporting Emergency Operating Procedure (EOP) actions. Thus the indicated level was higher than the actual level. Therefore, the EOP guidance might have resulted in vortex formation before the Operators could cwep the Emergency Core Cooling System (ECCS) and Building Spray (BS) pumps cuction from the BWST to the Reactor Building Emergency Sump (RBES). At 1815 hours0.021 days <br />0.504 hours <br />0.003 weeks <br />6.906075e-4 months <br />, all units entered Technical Specification 3.0. Recalibration was completed using revised procedures at 0309 hours0.00358 days <br />0.0858 hours <br />5.109127e-4 weeks <br />1.175745e-4 months <br /> on 2-13-98. The root cause w23 Deficient Written Documentation, technical inaccuracy. Another engineer rcviewed the BWST level issue and recognized that two other SITA issues might algo impact this swap. At 1700 hours0.0197 days <br />0.472 hours <br />0.00281 weeks <br />6.4685e-4 months <br /> on 2-20-98, Engineering concluded that tha EOP guidance did not assure a successful swap from the BWST to the RBES.

Therefore, the ECCS and BS may not have performed their required functions, for some worst case conditions. Unit 1 was at 60%FP and Units 2 and 3 were Et 100%FP. The EOP was revised. This root cause was Deficient Design Analysis.

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BACKGROUND The Borated Water Storage Tank (BWST) [EIIS:TK) has a tank volume of 388,000 gallons and a Technical Specification minimum level of 46 feet.

The tank is vented to the Auxiliary Building. The level instruments are differential pressure transmitters attached such that one side has an impulse line connected to the tank and the other side is vented to atmosphere. (See Attachment A)

The.BWST is used normally as a source of borated water for filling the refueling cavity and fuel transfer canal during refueling operation. Its emergency function is to provide the initial source of borated water for the Emergency Core Cooling System (ECCS) (composed of the High Pressure Injection (HPI) [EIIS:BG), Low Pressure Injection (LPI) [EIIS:BP), and Core Flood (CF) [EIIS:BP) Systems) and the Containment Cooling System (composed of the Building Spray (BS) [EIIS:BE) System and Reactor Building Cooling Units (RBCUs) [EIIS:BK]) following an Engineered Safeguards [EIIS:JE]

actuation. The Core Flood tanks and RBCUs operate independently of the BWST.

During a Loss Of Coolant Accident, flow is initiated in the HPI and LPI Systems from the BWST to the reactor vessel and in the BS System to the building spray headers. When the BWST level approaches the minimum level, the Operators re-align suction to the Reactor Building Emergency Sump to transition to long term operation in the recirculation mode. Wide Range Reactor Building Water Level instrumentation is used to indicate the Reactor Building Emergency Sump level following a LOCA. Current calculations require a minimum indicated level of 3.75 ft (45 inches),

which includes +8.8 inches for instrument uncertainty, in order to assure that pump NPSH requirements are met.

EVENT DESCRIPTION During the period of November 10, 1997 through December 11, 1997, the Duke Power Nuclear Generati Department Regulatory Audit Group conducted the on-site portions of a self-Initiated Technical Audit (SITA) to assess the operational readiness and functionality of the High Pressure Injection w

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-(HPI) and Low Pressure Injection (LPI) systems and interconnecting systems at the Oconee Nuclear Site. This internal audit identified a number of findings and recommendations and, as part of the audit process, the team I initiated Problem Investigation Process (PIP) entries to address the issues.

The inspection team concluded that the subject systems were capable of performing their safety functions, but some potentially incomplete and non-conservative inputs may have been used in some design calculations. The SITA report stated:

"These errors could have significant cumulative impact but typically the errors had small impact.on the validity of the calculations" L

The SITA team and Systems Engineering reviewed the issues and Systems Engineering concluded that their apparent significance did not justify an operability evaluation at that time.

Subsequently, as more detailed investigations of the issues were conducted as part of the evaluation for proposed' resolutions, two related problems were identified which specifically impacted the operability of the Emergency Core Cooling System and Building Spray System. Each of these problems is addressed in the following event description.

Borated Water Storace Tank (BWST) Level Problem On January 12, 1998, at 1645 hours0.019 days <br />0.457 hours <br />0.00272 weeks <br />6.259225e-4 months <br />, the SITA team personnel initiated PIP 0-098-0150 to address specific issues related to potential sources of l Borated Water Storage Tank (BWST) level errors. Two of these were:

! 1.BWST level transmitters did not have a "zero" elevation specified to l

ensure that the transmitter zero corresponded to the BWST zero reference, which was assumed to be at the elevation of the tap where the impulse line connects to the BWST.

2. The BWST Level Transmitter Calibration Frocedure did not provide guidance to ensure that the calibration cource instrument was

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flUf' EE 4 Oconee Nuclear Station, Unit 1 269 98 04 01 OF 30 positioned properly to correlate the transmitter zero to the tank zero.

Neither of these issues-indicated that a problem actually existed. It was expected that a review would verify that the instruments were calibrated to an appropriate zero level, and that minor documentation enhancements would l resolve the SITA issues. I An Electrical Systems engineer was assigned to do a Problem Evaluation of the PIP 0-098-0150 issues. As part of the evaluation, he reviewed the piping, instrument, and owner's manual ~ drawings related to the BWST level I instruments. Due to inconsistencies between some of these drawings, he  ;

requested that the transmitter installations be surveyed, including the I elevation of the test tees and the elevation of the instrument impulse line  !

tap on each Unit's RWST to determine the correct zero level reference.

The results of this survey were received on February 11, 1998, and were found to be in conflict with the piping installation drawings. Therefore, the Electrical Systems engineer requested that the survey be verified. On February 12, 1998, the installations were resurveyed and the instrument levels were confirmed to be below the value used in ca.lculation OSC-2820

• Emergency Procedure Guidelines Setpoints," which applies to all three Oconee Units. This was non-conservative because it affected the NPSH cvailable for the Emergency Core Cooling System (ECCS) and Building Spray (BS) pumps. Most of the transmitters were approximately one foot low but the worst case instrument (located on Unit 3) was approximately 17.5 inches low.

The Electrical Systems engineer informed the appropriate Mechanical Systems  ;

cngineer and his management, who in turn notified Regulatory Compliance I personnel. Operations was notified that an operability evaluation was in )

progress.

PIP 0-098-0707 was generated at 1415 hours0.0164 days <br />0.393 hours <br />0.00234 weeks <br />5.384075e-4 months <br /> on February 12, 1998. It was ,

recognized that the BWST levels were referenced in the Emergency Operating l Procedure (EOP) for swapping Emergency Core Cooling System (ECCS) and f Building Spray (BS) pump suction to the Reactor Building Emergency Sump (RBES). The operability issue questioned if the guidance given might be t i

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"f0 'ME" 5 Oconee Nuclear Station, Unit 1 269 98 04 01 OF 30 inadequate due to the non-conservative calibration such that the level error may have resulted in loss of adequate NPSH an'd potential damage to the ECCS pumps before the Operators would be able to complete the transfer of suction sources from the BWST to the RBES.

The Technical Specification minimum level requirement was still met since there were 46 (or more) feet in the tank above the zero reference point and the amount of BWST inventory available for use post-LOCA was not affected.

At 1815 hours0.021 days <br />0.504 hours <br />0.003 weeks <br />6.906075e-4 months <br />, the Operability Evaluation was presented by the Mechanical Systems engineer to Operations and all BWST level instruments were declared inoperable on all Units due to the potential impact on system operation following a LOCA. Oconee Unit 1 was operating at approximately 65% Full Power (FP) and Units 2 and 3 were operating at 100% FP. Technical Specification (TS) 3.0 was entered for all three Oconee Units.

At 1830 hours0.0212 days <br />0.508 hours <br />0.00303 weeks <br />6.96315e-4 months <br /> a one hour non-emergency notification was made to the NRC.

The procedures to calibrate the BWST level instrumentation were revised such that the zero reference point would be the instrument tap where the impulse line connects to the BWST, as assumed in OSC 2820.

By 0222 hours0.00257 days <br />0.0617 hours <br />3.670635e-4 weeks <br />8.4471e-5 months <br /> on February 12, 1998, one instrument train had been recalibrated on each unit so that the units exited TS 3.0 and entered a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Limiting condition of Operation (LCO) per TS 3.3.4. By 0309 hours0.00358 days <br />0.0858 hours <br />5.109127e-4 weeks <br />1.175745e-4 months <br />, a second BWST level instrument was calibrated and returned to service on each unit and the units exited TS 3.3.4. By 0431 hours0.00499 days <br />0.12 hours <br />7.126323e-4 weeks <br />1.639955e-4 months <br />, the third BWST level instrument on each unit was calibrated and returned to service.

At site management's request, an investigation team was created. One part of the team was assigned to perform a root cause analysis.

The root cause team found that the existing level transmitters were installed on all three units by Nuclear Station Modification (NSM) 2450 in 1989. This NSM replaced two previous pneumatic level instrument trains with three electronic trains and upgraded the Quality Assurance rating of '

the system to meet Reg. Guide 1.97. The field implementation drawings specified that the new transmitters be mounted at elevation "799'-1" or

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FACILITY NAME (1) DOCKET NUMBER (2) LER NUMBER (6) pAgg g3, YEAR 61gU M 1AL Agwinign NUMBER NUMsga b Oconee Nuclear Station, Unit 1 269 98 04 01 OF 30 below". (See Attachment A.) As stated earlier, the new calibration test tees were typically located about i foot below the elevation of the impulse line tap into the system, but the worst case (this transmitter is on Unit

3) was 17.5 inches. The drawings for the instruments in place in 1974, when the procedure was originated, indicate that the elevation difference was approximately 4 inches.

There are several types of potential head corrections associated with calibration of pressure sensing instruments. Some of the issues raised by the SITA team specifically questioned how these corrections were addressed )

for the BWST level instruments. One head correction term is the differential between the elevation of the impulse line where it enters the j process pipe and the elevation of the installed instrument. The correction i for this difference is typically specified in the controlling procedure.

Another type of potential head correction is the elevation differential between the calibration reference instrument and the installed instrument.

This factor may be controlled within the procedure or by " skill of the craft" standardized work practice.

A review of the calibratica procedure confirmed that it did not contain a head correction for the differential between the elevation of the impulse line where it connects to the tank and the elevation of the installed instrument. A review of superseded versions in the Master File revealed that, historically, it had never contained such a correction. Due to the elapsed time, no firm reason could be determined for this omission in the original procedure.

The procedure was updated following NSM 2450, but these changes addressed the new model of instrument and did not address the elevation differences.

Current practice in other instrument procedures is to include a "zero offset" on the calibration data sheet which accounts for the difference between the instrument test tee elevation and the impulse line tap (or other designated zero, if appropriate).

The second correction factor that the SITA had questioned was the relative elevation of the reference instrument during calibration. The root cause team confirmed that the calibration procedure did not control this factor either. However, interviews with Instrument and Electrical (I&E)

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"7Tl "M 7 l Oconee Nuclear Station, Unit 1 269 98 04 01 OF 30 Technicians indicate that the normal practice, governed by " skill of the craft", is to calibrate the instrument by adjusting the calibration test instrument elevation to match the elevation of the calibration test tee on the instrument being calibrated. If the procedure had contained a zero offset, this practice would have been sufficient. Since there was no zero offset in the BWST calibration procedure, this made the calibration tee elevation the zero reference point for the BWST level.

In 1986, the Safety Analysis section in the General Office performed a series of error calculations, which included BWST level uncertainties.

These calculations assumed that the zero reference point for the BWST level was the elevation of the impulse line tap. This data was used to determine the appropriate procedural setpoints for BWST to RBES swapover to satisfy ECCS pump NPSH requirements and to avoid initiation of vortexing in the pump suction lines. In January 1988, these calculations were designated OSC-2820, " Emergency Procedure Guidelines Setpoints" to document sources or derivations of numerical values used as EOP Setpoints.

These calculations were updated on several occasions, including after the NSM 2450 instrument upgrade. However, the assumed zero reference point was not changed. Therefore, since the I&E technicians were calibrating to the calibration tee elevation, the error between the BWST level assumed in the calculations and the indicated level was approximately 1.5 feet for the worst case, in a non-conservative direction.

A second part of the investigation team was assigned to perform a past operability evaluation. The results of that team's evaluation are discussed in the safety Analysis section of this report.

A third part of the investigation team addressed corrective actions. As stated earlier, immediate corrective action was taken to revise the calibration procedure and recalibrate the instruments to agree with the EOP assumptions. In addition, a search of the Oconee equipment data base was conducted for devices which met any of the following criteria:

1) functionally safety related (QA-1 or use code 9),

OR

2) required to mitigate predetermined accidents, 1

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3) utilized in Safety Analysis calculations.

Only one other application was found where the pressure and/or level instrument procedures did not contain head corrections where appropriate.

Instrument procedures related to Reactor Coolant System Narrow and Wide range pressure calibration did not contain such corrections. The reviewers confirmed that this correction was minor with respect to instrument accuracy and that the omission did not affect operability of the instruments. i Other corrective actions'are listed in the Corrective Action section of l 1

this report.

Reactor Buildina Water Level Problem .

Following the BWST level problem discussed above, Mechanical Systems 1 l

Engineer A, who is assigned lead responsibility on RBES issues, was  !

reviewing the operability evaluation for the BWST level problem when he recognized the impact of a requirementLin the EOP that Reactor Building (RB) water level must indicate greater than 4 feet prior to initiation of j realignment of the ECCS and BS pump suctions to the RBES. Due to the impact of other SITA issues (discussed below) on the expected RBES water level, the water level instrument might not indicate greater than 4 feet as the BWST level reached 6 feet. Therefore, the operators might not be able to satisfy both conditional statements in the EOP. The engineer initiated PIP 0-098-0825 at 1750 hours0.0203 days <br />0.486 hours <br />0.00289 weeks <br />6.65875e-4 months <br /> on February 19, 1998, to address this concern. (See Attachment B)

After review by Engineering, it was concluded that the EOP setpoints did not provide the necessary guidance to assure that the operators could successfully swap suction from the BWST to the RBES under all design basis conditions. There is reasonable assurance the operators would have completed the swapover for most accident conditions. However, for some i worst case conditions, it could not be positively assured that the ECCS would have been able to perform its required function. Interim guidance was provided to the operators to address the procedural deficiency at 1700 hours0.0197 days <br />0.472 hours <br />0.00281 weeks <br />6.4685e-4 months <br /> on February 20, 1998 and a one-hour, non-emergency event

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" SUI" "E7 9 Oconee Nuclear Station, Unit 1 269 98 04 01 OF 30 notification was made at 1710 hours0.0198 days <br />0.475 hours <br />0.00283 weeks <br />6.50655e-4 months <br />. Unit I was at 60%FP and Units 2 and 3 were at 100%FP. Since the interim guidance established conditional operability, no LCO was entered. The EOP was revised prior to 2400 hours0.0278 days <br />0.667 hours <br />0.00397 weeks <br />9.132e-4 months <br />.

Another investigation was initiated to address this occurrence.

The original (1973) guidance provided in emergency procedures for transferring suction from the BWST to the RBES was that transfer should occur upon receipt of a low-low level alarm, set at a BWST level of 3 feet.

No conditional requirement to verify RBES level was included in the original guidance.

In 1985, this guidance was revised to require a BWST level of less than 6 feet and added a requirement that RBES level be greater than 2 feet. The two foot guidance was included as an additional precaution to assure adequate sump inventory for certain beyond design basis accidents where inventory may be lost outside containment. The RBES level instruments in place at th.at time had a range of 0 to 3 feet.

As part of Post-TMI upgrades, two Wide Range Reactor Building Water Level Transmitters (LT-90, LT-91) were installed for each of the three Oconee units in a series of, refueling outages over the time period from December 1984 through December 1986. These instruments provide post-LOCA indication of RBES level from 0 to 15 feet. In December 1987, calculation OSC-2578 was created to document the uncertainty analysis for these instrument trains.

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As stated earlier, in January 1988, the Safety Analysis Section produced OSC-2820, " Emergency Procedure Guidelines Setpoints" as a formal calculation to document the action setpoints used in the EOP. OSC-2578 was used as one of the inputs to the setpoints calculation. Calculation OSC-2820 included an analysis of minimum NPSH requirements during the l

recirculation mode. A RBES setpoint of 3.5 feet was established to assure j minimum sump inventory for beyond design basis accidents. The intent was I to confirm that the BWST inventory had been transferred to the Reactor Building rather than some point outside containment. The supporting analysis for the 3.5 foot setpoint included an allowance of +8.8 inches for instrument uncertainty to account for the possibility that the

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"$,*7 "$'N" 10 Oconee Nuclear Station, Unit 1 269 98 04 01 OF 30 instruments might read high, but did not recognize the possibility that the level indication might read low and never reach the EOP setpoint if the negative instrument uncertainty was applied, l In February 1988, OSC 2578 was revised to include a term for current leakage. This calculation estimated the worst case uncertainty (indicated minus actual) as +8.8/-21 inches. At this time, the calculated " actual" l water level in the RB for a design basis LOCA was 5.3 feet (64 inches) when level in the BWST reached 6 feet. Thus, assuming a worst case I uncertainty (-21 inches) , the possible indicated level (43 inches) was greater than 3.5 feet (42 inches). Therefore, an indicated level would be achieved that would satisfy the EOP step requirement. However, this evaluation was not performed in the calculations, and the small margin between the required level and the worst case potential indicated level was not recognized.

In April 1988, the EOP was revised to incorporate the setpoint of 3.5 feet as a required minimum indicated level prior to initiation of swapover.

The procedural enhancements were worded as a requirement prior to transfer under all conditions rather than as a confirmation applicable only for beyond design basis accidents.

In July 1989, OSC-2820 was changed (by Safety Analysis) to require a  !

minimum indicated level of 3.75 feet to assure minimum NPSH requirements.  !

However, given the expected " actual" level of 5.3 feet (64 inches) and a worst case uncertainty (-21 inches), an indicated level of 3.75 feet (45 ,

inches) might not be achieved. Again the calculation did not evaluate the uncertainty in this manner. It was not recognized that, for limiting ecenarios, this indicated level might not be reached. However, the EOP was not revised to reflect this change at that time.

On May 31, 1994, as a result of a review by Systems Engineering, the EOP was revised (by Operations). For instrument readability reasons, the EOP established a minimum indicated RBES level of 4 feet, which met the minimum of the 3.75 feet documented in OSC-2820. As discussed in the Safety Evaluation section of this report, this guidance might have prevented proper operation of the ECCS and BS systems. This EOP change did not recognize this adverse impact.

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"EcF "Z7 11 Oconee Nuclear Station, Unit 1 269 98 04 01 OF 30 Subsequent revisions to the applicable calculations have presented opportunities to recognize this discrepancy, but the instrument uncertainty was never applied in the manner necessary to recognize this problem.

This problem was impacted by another SITA issue which questioned the available RB water inventory. As a result, the expected Post-LOCA RBES level was reduced. On November 20, 1997, the SITA team had initiated PIP 0-097-4165 to document potentially non-conservative assumptions which were used in OSC-1925, the calculation for the Reactor Building (RB) water inventory and " actual" level following a large break LOCA. The significant inventory issues were:

1. the modeling of water trapped in the Reactor Vessel Cavity area and the deep end of the Fuel Transfer Canal such that it could not flow to the RBES,

2. water needed to make up for Reactor Coolant System shrinkage during cooldown,

3. water needed to refill the pressurizer,

4. water needed to fill the BS piping inside containment, and

5. water needed to account for the vapor content maintaining containment pressure.

An Operability Evaluation was completed by Systems Engineering on November 23, 1997. It conservatively assumed that existing restrictive drains i became blocked, trapping water in the vessel cavity and Fuel Transfer l Canal. It concluded that the net effect of the inventory issues listed above was to lower the available '2ctual" water level from 5.3 feet to -

3.07 feet. This operability evaluation analyzed the impact of this

" actual" level change on the available NPSH for Emergency Core Cooling System (ECCS) pumps. The Operability Evaluation concluded that this NPSH was acceptable and the RBES and associated ECCS were operable. It did not use instrument inaccuracies to determine or assess the possible '

" indicated" water levels.

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The restrictions in the drain lines were removed to assure that water inventory would not be held in these areas. This restored the expected l Reactor Building " actual" water level to approximately 4.5 feet. {

Subsequently, Mechanical Systems Engineer A realized that the Operability Evaluation performed on November 23, 1997 had not considered that the reduced " actual" water level would increase the flow velocities (and,  ;

potentially, debris transport) toward the RBES. Another operability i evaluation was performed which ultimately concluded that the debris transport issue did not affect system operability. This issue was reported as Voluntary LER 269/97-10 on January 8, 1998.

On February 19, 1998, Mechanical Systems Engineer A noted the cumulative effect of these several SITA issues and questioned the adequacy of the EOP guidance.

The impact of the lower expected " actual" RBES level was that, when the current worst case instrument uncertainty (revised to -18.1 inches in 1996) is applied, the minimum " indicated" RBES level at the time of swapover dropped to approximately 3 feet (35.9 inches). This means that the EOP conditional requirement for indicated RBES level to exceed 3.5 feet might not have been met, for some conditions, ever since April 1988, when this value was ;evised in the EOP.

The potential consequences of this condition are discussed in the Safety Analysis section of this report.

CONCLUSIONS BWST Level Problem The root cause investigation team determined that the root cause of the BWST level instrument problem was Deficient Documentation, deficient written procedure. The calibration procedure for the BWST level instruments historically had not included a head correction for the difference in the elevation of the instruments and the associated level i tap where the impulse line connects to the BWST. Due to the historical nature of the omission, no specific reason could be identified.

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"E"E! "Z$" 13 Oconee Nuclear Station, Unit 1 269 98 04 01 OF 30 The root cause team concluded that BWST level transmitter modifications in 1989 presented an opportunity to identify the need for a head correction in the calibration procedure. The NSM 2450 modification installation procedure contained flexibility which allowed the three transmitters to be installed at potentially different elevationn. The design input assumption that the level transmitters should be calibrated to the tap location was not clearly identified in the modification package, which included the revised calibration procedure.

Wide Range Reactor Building Water Level EOP Setpoint The root cause of the subsequent issue of the Wide Range Reactor Building Water Level EOP setpoint is Design Deficiency, Inadequate Design Analysis.

The EOP was revised in 1985 to include a conditional step to verify sump inventory prior to swapping over to the recirculation mode. This change  !

was implemented as an additional precaution for certain beyond design basis accidents where inventory may be lost outside containment. The governing design documents addressed the minimum required level for sump NPSH. However, these design documents did not address the possibility that the indicated level may not exceed the EOP setpoint during a design basis LOCA when worst case instrument uncertainties are considered.

Over time, changes occurred in the Wide Range Reactor Building Water Level cetpoint, the expected water level in containment following a design basis LOCA, and the instrument uncertainties. However, a clear link between these interrelated calculations did not exist. Therefore, when these calculations were revised, the potential impact on the EOP setpoint for cump level was not recognized. Thus, an EOP step that was included to cddress beyond design basis accidents eventually led to inappropriate guidance in reliably mitigating certain design basis LOCAs.

The change in the RBES expected inventory calculation, which was discussed previously in Voluntary LER 269/97-10, did not cause the system to be inoperable. (The systems would have been operable, even at the new expected level, if the EOP did not have the sump level limitation on initiation of swapover. ) It did extend the period of time the EOP

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= " "ta""'= ' "'" " "^"^""= = l LER NUMBER 16) pAgg g3 j TEAA 61QUENTIAL Etyjbivh j nussa musen 14 Oconee Nuclear Station, Unit 1 269 98 04 01 OF 30 guidance was inappropriate to include the time from April 1988 through {

May, 1994. Several issues identified by the SITA audit had cumulative I effects which combined to reduce the level of water expected to be inside the reactor building. If the lower expected water level had been in place since original design, the margin between the minimum required level for NPSH and the expected level would have been small, and might have affected decisions on the EOP setpoints. However, awareness of this issue did contribute to the questioning attitude of Mechanical Systems Engineer A that led to the discovery of the inadequate EOP guidance.

A process deficiency was observed during this investigation. This deficiency was a weakness in communication among various Engineering groups, Safety Analysis, Operations, and Maintenance of changes such as calculation revisions, station modifications, procedure revisions, or regulatory commitments.

An Operating Experience Program (OEP) search was performed to identify prior similar events. The root cause team identified numerous industry OEP entries on similar calibration and setpoint problems. The most applicable entry was NRC Information Notice (IN) 91-75 " Static Head Corrections Mistakenly Not Included in Pressure Transmitter Calibration Procedure."

The Duke Power OEP response to IN 91-75 states that "The water leg effect for instruments that are located away from the sensing elements have been ovaluated by all three (Duke) nuclear facilities. The correction factors for water legs have been incorporated into the effected (sic) instrument loop procedures." "Present instrument generic / loop procedures have been reviewed and revised to reflect these issues. Due to extensive research and actions that have been taken by the stations, no immediate action is required." From the available documentation, it is not possible to reconstruct the full scope of the referenced procedure review. It was apparently not conducted in adequate depth to identify the two procedures identified in this report as not having water leg correction. This was a i missed opportunity to discover and correct that problem.

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As a result of this search, it appears that errors in instrument setpoints I and/or calculations have been a problem for the industry in general. '

Oconee has not had a history of setpoint problems. Oconee has had several design analysis events, including LER 269/97-02 on water hammers in Reactor Building Cooling piping and Voluntary LER 269/97-10 resulting from the change in Reactor Building expected water' level. Therefore, this event is i considered recurring. However, corrective actions from the operating experience items listed above would have occurred after the historical actions which resulted in this event. Therefore, corrective actions from those events could not have prevented this event.

There were no personnel injuries, radiation releases, overexposures, or equipment failures associated with this event.  :

CORRECTIVE ACTIONS l Immediate-l

1. Operations was notified and a Technical Specification 3.0 Limiting Condition for Operation was entered on each unit. 1

2. The Borated Water Storage Tank (BWST) level calibration procedures were l revised.

3. All nine BWST level transmitters were recalibrated to include head corrections.

i

4. When the Reactor Building water Level issue was raised, interim guidance was provided to the operators to address the Emergency Operating Procedure deficiency.

Subsequent:

i

1. An investigation team was formed. i

2. A review for other potentially affected instruments was conducted at Oconee.

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3. When the Reactor Building water Level issue was raised, the Emergency Operating Procedure was revised. The EOP was changed to include a note l that wide range Reactor Building water level should be 3 feet and increasing at the time of swapover.

4. The identified BWST drawing errors have been corrected. l 5.An additional review was performed for installed instrumen'ts used in surveillances and periodic tests which might require head corrections.

No applications were found where head corrections would impact the acceptability of the test.

6. The Unit 2 Reactor Coolant System Narrow and Wide range pressure l instruments have been surveyed and the calibration procedures revised to include head correction. Engineering has performed a bounding evaluation to verify that the head correction does not impact operability of these instruments for Units 1 and 3.

Planned:

1. The Unit 1 and 3 Reactor Coolant System Narrow and Wide range pressure calibration procedures will be revised to include head correction. Due to the location of the instruments and taps, each unit will require shutdown conditions to obtain precise elevations by survey.

2. All EOP setpoints will be reviewed for accuracy and completeness.

Inputs are to be verified as current and appropriate.

3. All EOP setpoints will be reviewed to assure setpoints with minimum and maximum limits are appropriately documented.

4. Review and revise, as necessary, directives and procedures used to perform self Initiated Technical Audits (SITAs) to assure that these audits will always include as part of the audit, verification that relevant operating experience related to the affected system has been

. appropriately addressed.

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5. Perform a risk-informed review of operating experience. The review will identify the most significant areas of operating' experience for ONS based on insights from the ONS PRA. A detailed review will be performed to assure Oconee has appropriately addressed the most risk significant operating experience.

6. A process to identify, control and maintain Oconee-specific calculation inputs will be developed. This process will provide for two-way communication and review during the review / approval process of any change to the calculation input / output data.

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7. Historical calculations will be enhanced to meet the new process developed in Corrective Action 6. This enhancement will be applied

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those safety related, risk significant calculations that are to be  ;

maintained in an as-built configuration.

8. System Engineering will evaluate options to increase the NPSH margin for operation in the ECCS recirculation mode. -

9. Benchmarking visits will be performed to compare Oconee's processes against industry best practices regarding the identification and control i

of input assumptions for engineering calculations.

1 Planned corrective actions 1 through 6 are considered NRC commitment items. These are the only NRC commitments included in this report.

SAFETY ANALYSIS The Borated Water Storage Tank (BWST) provides the initial source of borated water for the High Pressure Injection (HPI) and Low Pressure

Injection (LPI) Systems for Emergency Core Cooling (ECCS) and the Reactor i Building Spray (BS) System for Containment Cooling when actuated by the

{ Engineered Safeguards (ES) System. After a period of time which varies depending on the accident scenario, the BWST inventory is exhausted and these systems are realigned to use the LPI and BS pumps to take suction from the Reactor Building Emergency Sump (RBES). This realignment requires operator action. The procedural guidance for this operator action has varied over time. Guidance in the past, especially prior to upgrades L

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"E"# "Z$" 18 Oconee Nuclear Station, Unit 1 269 98 04 01 OF 30 following the Three Mile Island ('n4I) event, may not have been adequate.

Prior to these upgrades, the swapover process was initiated at a BWST level of approximately 3 feet. Among other factors, the post-TMI upgrades addressed operator response times, valve stroke times, and conservatively

&ccounted for potential instrument uncertainties.

Over the last several years, the EOP directed the operators to begin this realignment while the BWST level equals or exceeds 6 feet (decreasing) and the Reactor Building wide range water level instrument indicates that RBES level equals or exceeds 4 feet (increasing). The current calculation shows the actual sump level at this time is expected to be approximately 4.5 feet. The operators are directed to open the isolation valves in the RBES suction paths and, while BWST level is still greater than 2 feet, to close the isolation valves in the BWST suction paths. The requirement to initiate transfer at 6 feet is also included in the operations Management Procedure Manual as an operator memory item.

The effect in this event of the Reactor Building wide range water level instrument uncertainty was that, for the percentage of time that the instruments read lower than the actual level, the operators might find themselves in the situation where the conditional step in the EOP for initiating transfer to the RBES could not be met. If an actual level of greater than 4 feet was indicated as less than 4 feet, the step logic.could not be met, therefore delays in implementing the subsequent steps to realign the pumps to the RBES might occur.

The effect of the BWST instrumentation level calibration error in this event was that the actual level in the BWST could be as much as 18 inches lower than assumed in the calculations which derived the EOP setpoints to manually perform the swapover from the BWST to the Reactor Building sump. '

Oconee Technical Specifications require a minimum BWST level of 46 feet.

The locations of the instruments, taps, and calibration tees are all above the physical bottom of the BWST. Therefore, regardless of which location is used as the zero reference point, there is a small quantity of water remaining below the zero reference point and 46 (or more) feet above the l zero reference point. The ability of the instrument to measure the level j of water above the reference point is not an issue. Furthermore, the EOP

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FACILITY NAMK (1) DOCKET NUMBER (2) lek NUMBER 46) pAgg (3, VIAn 64QUENT I A1. Asvision Nuwarn Num in 19 Oconee Nuclear Station, Unit 1 269 98 04 01 OF 30 action setpoints are based on transferring 40 feet of BWST inventory into the Reactor Building. Since the same instrument would be used to initiate and terminate the transfer, and since the transfer would still be terminated at an elevation above the drain line, 40 feet of inventory would be available for use. Therefore, this error has not affected compliance with the Technical Specification minimum level requirement.

However, the BWST calibration error does make a difference relative to the ECCS and BS pumps, which are physically located in the Auxiliary Building basement. The lower water level in the BWST combined with high BWST suction flow rates during swapover could lead to vortex formation. Vortex formation could potentially result in a lack of adequate NPSH due to air entrainment in the ECCS pump suction before the operators could complete the realignment. This could lead to operation of the pumps under degraded conditions and is considered outside the design basis of the plant.

An evaluation has been performed to assess the safety significance of this event for the design basis events which rely on realigning the ECCS pump suction from the BWST to the RBES. This realignment would be required for large break LOCAs, and certain small break LOCAs. For some beyond design basis accidents, decay heat may be removed by a primary system feed and bleed. Duke's precursor analysis considered the fact that certain beyond design basis scenarios may also require a transfer to the containment sump for recirculation.

Effect on ECCS Laroe Break LOCAs For large breaks, an analysis has been performed on the rate of BWST inventory depletion and the realignment to the emergency sump. This analysis also considered the effect of the post-LOCA pressurization of the containment. A containment pressure of greater than approximately 10 Psig will cause the emergency sump, rather than the BWST, to become the suction source for the LPI and BS pumps as soon as the sump isolation valves (LP-19 and LP-20) are opened at the beginning of the realignment. A review of the post-LOCA containment analyses that have 1

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"$$^' *=7 20 i Oconee Nuclear Station, Unit 1 269 98 04 01 OF 30 been performed with NRC-approved methods supports a conclusion that the  ;

only large break LOCA which can result in a containment pressure less I than 10 Psig at the time of realignment is a hot leg break.

Considering the random nature of the instrument uncertainty, there are 4 l large break cases to ' evaluate: l A. Wide Range Reactor Building Water Level during a hot leg break LOCA indicates less than 4 feet  !

B. Wide Range Reactor Building Water Level during a hot leg break LOCA indicates greater than 4 feet C. Wide Range Reactor Building Water Level during a cold leg break LOCA indicates less than 4 feet D. Wide Range Reactor Building Water Level during a cold leg break LOCA indicates greater than 4 feet Case A:

Actual sump level is approximately 4.5 feet at the time of swapover, but Wide Range Reactor Building Water Level during a hot leg break LOCA indicates less than 4 feet. The combined effect of the EOP guidance regarding sump level and the assumed Reactor Building Water Level low indication could result in delays in the operator's actions during the swapover process. A primary consideration is the time necessary for the operators to conclude that sump level will not reach 4 feet before the BWST depletes to an unacceptable level.

BWST depletion calculations predict a minimum time of 23 minutes before the EOP setpoint of 6 feet is reached. During this time, the control room operators and the Shift Technical Advisor (STA) would be monitoring inventory. If containment inventory was not approaching the required setpoint, the STA would assist in investigating the potential for inventory losses from containment. The lack of radiation alarms in the Auxiliary Building would provide additional information to support a

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Nu N "Z$" 21 Oconee Nuclear Station, Unit 1 269 98 04 01 OF 30 conclusion that the sump is a viable suction source. Thus, the operator is expected to recognize that the BWST will not remain a viable suction source and take action even though the procedure logic is not met.

Opening the sump recirculation valves is necessary to provide a suction source and is a logical action (a possibly adequate source is better than a known inadequate source).

During a hot leg break LOCA, Reactor Building pressure is not expected to be greater than 10 Psig at the time of swapover. Thus, in addition to opening the sump suction valves, the BWST isolation valves must also be closed. This is necessary because the containment overpressure for the hot leg breaks is not sufficient to assure suction from the sump once the sump suction valves are opened. Normally, isolation of the BWST is needed prior to BWST level decreasing below 2 feet to assure air is not drawn from the BWST into the LPI pump suction lines. However, with the calibration error present, isolation of the BWST before level decreases below 3.5 feet (in the worst case) would be necessary.

For the cases where air entrainment could occur and the ECCS pumps begin to indicate unstable operation as the BWST level decreases towards empty, the possibility exists that the air core of the vortex could reach the pump. This would momentarily degrade pump performance, reducing flow, which would then collapse the vortex. Therefore, this phenomenon would be self correcting. The LPI and BS pump vendor has expressed an engineering opinion that, over a short period, such as the time required to complete the swapover, no pump damage would occur. In addition, the momentary erratic performance of the pump would be apparent to the operators and they would stop the affected pumps prior to pump damage. A number of licensed operators were interviewed to determine what their actions would be in this event. The consensus response was that tney would secure operating pumps in each system (LPI and BS) if any indication of loss of NPSH became apparent. They would l then complete the alignment to the RBES, start one pump, and, as the '

RBES is confirmed as a viable source, restart additional pumps one at a time. An Engineering evaluation has concluded that the pumps would be ,

capable of restarting once the suction source was realigned to the sump. l Actual RBES levels would exceed 4 feet at this time and adequate NPSH would be available.

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S0$" ",',0$" 22 Oconee Nuclear Station, Unit 1 269 98 04 01 OF 30 It is also noted that Oconee has a third low pressure injection pump (the C LPI pump), which is not credited in accident analysis. It would be available to be manually started in the event that all other ECCS pumps were to fail for any reasons. The C LPI pump would be sufficient to prevent core damage for the LOCA scenarios of concern.

If LPI flow is interrupted at the time of swapover, calculations l indicate that approximately 7 minutes is available prior to the onset of l core uncovery. Thus, time is available to restart one of the LPI pumps and assure core cooling. Thus, although there may be some air  ;

l entrainment in the LPI pumps for Case A, it is concluded that the ECCS pumps would continue to function and long-term core cooling would be l achieved for this scenario.

Case B:

If Wide Range Reactor Building Water Level during a hot leg break LOCA indicates greater than 4 feet, the EOP step logic would be satisfied.

There would be no question about the operator initiating transfer. If he completes swapover promptly, it will be successful. If he does not complete swapover before actual BWST level is too low due to the BWST calibration error, vortexing and loss of NPSH could occur and the rest of the scenario would be as described in Case A. It is concluded that long-term core cooling would be achieved for this scenario.

Case C:

If Wide Range Reactor Building Water Level during a cold leg break LOCA indicates less than 4 feet, the Reactor Building Pressure is expected to be greater than 10 Psig. As in Case A, there is a potential delay in operator action to initiate transfer. Once the operator initiates swapover, opening the sump recirculation valves will assure a suction source and isolation of the BWST is not time critical. It is concluded that the potential for air entrainment is significantly less for this case and long-term core cooling would be achieved for this scenario.

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NUMBER NUMB 1R 3 Oconee Nuclear Station, Unit 1 269 98 04 01 OF 30 Case D: I If Wide Range Reactor Building Water Level during a cold leg break LOCA indicates greater than 4 feet, the situation combines the best aspects of Cases B and C. Because the EOP step logic would be satisfied, there  ;

would be no question about the operator initiating transfer. Once the  ;

operator initiates swapover, opening the sump recirculation valves will I assure a suction source and isolation of the BWST is not time critical.

It is concluded that long-term core cooling would be achieved for this scenario without any adverse effects from air entrainment. '

Small Break LOCAs Three classes of small break LOCAs were evaluated:

A. Small break LOCAs with some LPI flow (break size greater than approximately 0.025 square feet)

B. Small break LOCAs which may require HPI operation in the recirculation mode (break size between approximately 0.005 square feet and approximately 0.025 square feet)

C. Very small break LOCAs which may require HPI operation in the recirculation mode (break size less than approximately 0.005 square feet)

Case A:

For small break LOCAs with a break size greater than approximately 0.025 square feet, depressurization of the Reactor Coolant System (RCS) [EIIS:

AB) is sufficient to assure operation in the recirculation mode using the LPI System. Therefore, operation of the HPI pumps in the recirculation mode is not required for these breaks. The swapover to sump recirculation for these small break LOCAs is similar to the swapover during a large break LOCA. The evaluation of the impact of the BWST and wide range Reactor Building Water Level issues for these small breaks is similar to the large break LOCA section above. Duke analyses

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Case B:

This case considers small break LOCAs which may require HPI operation in the recirculation mode (break size between approximately 0.005 square feet and approximately 0.025 square feet). The occurrence of a small break LOCA in this break size range does not necessarily imply operation in piggyback mode. Depending upon break size, location, and equipment availability, the operators may be able to successfully cool and depressurize the Reactor Coolant System to allow alignment of normal decay heat removal prior to depletion of the BWST, or the LPI system may need to operate in recirculation mode as in a large break scenario.

For the subset of small break LOCAs where RCS pressure remains above the shutoff head of the LPI pumps, the EOP instructs the operators to align one LPI pump discharge to the suction of the HPI pumps for " piggyback" operation. In this mode of operation, the suction source of the HPI System is the discharge of the LPI pumps. If the break is greater than approximately 0.005 square feet, but less than approximately 0.025 square feet, Duke's containment analyses predict Reactor Building Spray will actuate. A minimum of 1.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> is available to the operators prior to swapover.

The EOP instructs the operators to align one LPI train to the HPI System for piggyback operation, beginning at greater than ten feet BWST level.

For the percentage of time that the wide range Reactor Building Water Level instruments read higher than 4 feet, the EOP step logic would be satisfied. There would be no question about the operator initiating

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FACILITY NAML 11) DOCKET NUMBER (2) LER NUMBER (6) pgg 433 "Ef' M" 25 Oconee Nuclear Station, Unit 1 269 98 04 01 OF 30 transfer. Once sump suction valves LP-19 and LP-20 are opened, the Reactor Building pressure will be high enough to assure that the emergency sump will provide the suction source. The operators would close the BWST isolation valves and the recirculation mode would be successful.

If the Reactor Building water level indicates less than 4 feet, even though actual sump 3 0 vel should be approximately 4.5 feet when the BWST level approaches 6 (eet, the operators might find themselves in the i situation where the conditional step in the EOP for initiating transfer '

to the RBES could not be met. For this scenario, the operator would be forced to take action as BWST level continued to drop.

Since the progression of a small break LOCA is much slower than a large break LOCA, ample time exists to assess inventory conditions in the BWST and the Reactor Building. The control room operators and the STA would have time to evaluate the potential for inventory losses outside containment. In addition, the maximum time to staff the Technical Support Center (TSC) is 75 minutes. Thus, the TSC would be assembled and it is highly likely.they would review the conflicting inventory data. Radiation protection surveys and reviews of radiation alarms in the Auxiliary Building would support a conclusion that no inventory is being lost from containment and that the sump suction source is viable.

The EOP requires initiation of the swapover to the sump at a BWST level of greater than 6 feet and completion of the swapover process prior to reaching 2 feet in the BWST. Because of the BWST calibration error, the operators must open sump suction valves LP-19 and LP-20 before the BWST level indication decreases below 3.5 feet (worst case). If the operator initiates swapover, the Reactor Building pressure will be high enough to assure that the emergency sump will provide a suction source once the sump valves are opened. The operators would close the BWST isolation valves and the recirculation mode would be successful.

However, despite the slower progression of these small break LOCAs, it

is conceivable that delays in initiating the swapover process could lead l- to damage of the HPI pumps. BWST depletion analyses indicate that 5 minutes is available between a BWST level of 6 feet and 3.5 feet. If

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"$Ef' ",',7407 26 Oconee Nuclear Station, Unit 1 269 98 04 01 OF 30 the RBES level indication does not satisfy the EOP, the potential exists for delay due to inadequate procedure guidance and/or the belief that the BWST would remain an adequate source until the indication neared two feet. Regardless of indicated RBES level, if delays in opening valves LP-19 and LP-20 result in pump cavitation or erratic operation, the operating LPI and HPI pumps would be stopped. Although this action would prevent damage to the LPI pumps, the different design of the HPI pumps may result in their' loss for the remainder of the accident.

For the remote case where the HPI pumps become damaged, the EOP instructs the operators to open RCS vents and depressurize the RCS using the steam generators. It is highly likely these actions would decrease RCS pressure to allow Core Flood Tank injection and operation of the LPI pumps in the recirculation mode. Considering the very limited set of break sizes, instrument errors, compensatory operator actions, the fact that the TSC is staffed, the Shift Technical Advisor would be monitoring inventory, and the absence of leakage outside containment, the probability that the HPI system would fail is very low. The likelihood of these actions being unsuccessful is considered in the precursor analysis.

Case C:

If the break size is less than approximately 0.005 square feet, Duke's containment analyses do not predict Reactor Building pressure to reach 10 Psig. Therefore, there should be no Reactor Building Spray actuation. Thus, at least 4.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> will be available prior to depleting the BWST to 10 feet. The slow BWST depletion rate allows ample time to assess BWST and sump inventory and successfully complete the swapover. The TSC would be staffed for over 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> and would be able to conclude that the sump is a viable suction source. Therefore, given the time and availability of technical resources, including the STA, it is concluded that the swapover to recirculation would be successful. In addition, it is also expected that the RCS would be cooled and depressurized to LPI conditions prior to reaching 6 feet in the BWST. Therefore, the risk of either LPI or HPI pump damage for these very small break sizes is negligible.

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"$2^' "5'lJ'" 27 Oconee Nuclear Station, Unit 1 269 98 04 01 OF 30 Effect on Reactor Buildino Cooline Building Spray is initiated if an event causes Reactor Building pressure to exceed 10 Psig. Therefore, the only applicable scenarios are large break LOCAs and a range of larger small break LOCAs. If operators fail to initiate transfer to the RBES at the proper time, the BWST level will continue to decrease until minimum NSPH requirements are no longer met. If no action is taken, this would result in damage to the operating BS pumps, and potentially cause loss of the BS system. However, as discussed below, appropriace operator action is expected and the BS pump vendor has stated an engineering opinion that the BS pumps can reasonably be expected to operate adequately even if minimum NPSH is lost momentarily during transfer. Therefore, the potential for loss of BS pumps due to this issue is not considered large.

The loss of the BS system due to this issue would only occur during the swapover to recirculation. The BS system does not include heat exchangers, therefore, the loss of the BS system in recirculation mode would result in only a partial loss of containment cooling capability. At this time in the scenario, containment pressure will be well below the design limit of 59 Psig and the Reactor Building Cooling Units (RBCUs) provide sufficient heat removal to assure long term control of containment pressure even in the event that the BS pumps are not running.

The BS pumps are also credited for helping to control the Reactor Building temperature within the requirements of the Environment Qualifications (EQ) envelope. However, for scenarios with high containment temperature, the building pressure would be higher than 10 Psig, which would assure adequate NPSH. For scenarios with low containment pressure, the containment temperature would also be lower, so that EQ requirements could be maintained by the RBCUs alone. '

Therefore, there are no containment integrity concerns and the potential loss of BS pumps due to this issue is not safety significant.

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",$3F "Z$" 28 Oconee Nuclear Station, Unit 1 269 98 04 01 OF 30 Safety Analysis Conclusion The non-conservatisms in the BWST level setpoint and the wide range Reactor Building Water level instructions in the EOP created a condition of conflicting procedural guidance and difficulty in reliably mitigating certain loss of coolant accidents within the design basis during the sump recirculation phase. The Duke Energy analysis concluded that the LPI and Building Spray systems would still have been able to perform their safety functions. In addition, considering the low probability for the combination of the narrow spectrum of break sizes, the unfavorable window of instrument errors and vortex conditions, along with the mitigation capability of LPI pump C, and the expectation that the Control Room Operators, Shift Technical Advisor, and Technical Support Center would correctly assess the condition and take appropriate action, the likelihood of complete failure of the HPI system during a small break LOCA is considered low.

The potential core damage significance of this event has been addressed by considering:

o the frequency of LOCA break sizes of concern 1

o the probability that high pressure recirculation is required as a result )

of failure to cool down and depressurize the primary system to LPI l conditions during small break LOCAs o instrument system inaccuracies are in the unfavorable range i

o and the probability of LPI pump C failure and failure of the plant staff to detect pump cavitation and make timely alignment of at least one of the three LPI pumps to the RBES The incremental core damage potential is estimated to by 9.2E-7 for this event, compared to the nominal total annual core damage probability of 8.9E-5 per reactor.

Therefore, the health and safety of the public were not affected by this event.

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