ML15238A600

Forwards, Audit of Oconee Procedures & Training for Pressurized Thermal Shock.

ML15238A600
Person / Time
Site:	Oconee
Issue date:	06/04/1982
From:	Defferding L Battelle Memorial Institute, PACIFIC NORTHWEST NATION
To:	Clifford J NRC
Shared Package
ML15238A601	List: ML15238A600 ML20054F638
References
CON-FIN-B-2512, REF-GTECI-A-49, REF-GTECI-RV, TASK-A-49, TASK-OR NUDOCS 8206170176
Download: ML15238A600 (43)

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REGULATUR NFORMAT1ON DISTRIBUTION STEM (RIDS)

ACCESSION NBR:8206170176 DUC,DATE: 82/06/04 NOTARIZED: NO DOCKET #

FACIL:50-269 Oconee Nuclear Station, Unit 1, Duke Power Co. 05000269 AUTH.NAME AUTHOR AFFILIATION DEFFERDINGiL.J, Battelle Memorial Institute, Pacific Northwest Laboratory RECIP.NAML RECIPIENT AFFILIATION CLIFFORDJ. NRC - No Detailed Affiliation Given

SUBJECT:

Forwards, "Audit of Oconee Procedures & Training for Pressurized Thermal Shock."

DISTRIBUTION CODE: A049S COPIES RECEIVED:LTR - ENCL . SIZE:iiL...

TITLE: Thermal Shock to Heactor Vessel NOTES:AEOD/Ornstein:1cy. nkSA- Pit 4t# 4.0 05000269 RECIPIENT COPIES RECIPIENT COPIES ID CODE/NAME LTTR ENCL ID CODE/NAME LTTR ENCL ORB #4 BC 01 7 7 INTERKAL; ACRS A80TTPE I I ACRS IGNEE 1 1 AEO0 1 COM AUSTIN 1 1 COM LIAW,8 1 1 ELD/HDS4 12 1 0 MURLEY,T 1 1 NRR CLIFFORD 1 1 NRR DIR 1 1 NRR GOODWINpE 1 1 NRR HAZELTON 1 1 NRR JOHNSON 1 1 NRR KLECKER 1 1 NRR LOISL 1 1 NRR OREILLYP 1 1 NRR RANDALL 1 1 NRR THROME 1 1 NRR VISSINGG04 1 1 NRR/DE DIR 1 1 NRR/DHFS DEPYO9 1 1 NRR/DHFS DIR 1 1 NRR/DHFS/PTR8 1 1 NRR/DL DIR 1 1 NRR/DL/ADSA 1 1 NRR/DL/ORAB 11 1 0 NRR/DSI DIR 1 1 NRR/DSI/RA8 1 1 NRR/DSI/RSB 1 1 R1 1 NRR/DST/GIB 1 1 05 1 1 RES BASDEKAS 1 1 RES VAGINSM 1 1 RES/DET 1 1 RES/DRA 1 1 RGN2 1 1 EXTERNAL: ACRS 10 16 16 LPDR 03 1 1 NRC PDR 02 1 1 NSIC 06 1 1 NTIS 1 1 NOTES: 1 1 TOTAL NUMBER OF COPIES REWUIRED: LTTR 64 ENCL 62

OBatelie Pacific Northwest Laboratories P.O. Box 999 Richland, Washington U.S.A. 99352 Telephone (509) 375-2925 Telex 15-2874 June 4, 1982 James Clifford U.S. Nuclear Regulatory Commission M/S AR-5215 Washington, D.C. 20555

SUBJECT:

PROCEDURES AND TRAINING REVIEWS FOR PRESSURIZED THERMAL SHOCK (FIN-B2512)

A review of the procedures and training for pressurized thermal shock at Duke Power Company's Oconee #1 plant was completed on May 11-13, 1982. Enclosed is a copy of the final report for this plant.

If you have any questions please feel free to call me.

Sincerely Leo . Def e/rding Sr. Research Engineer LJD:taz Attachment 8206170176 820604 PDR ADOCK 05000269 P PDR

Ldit Au" -of flcrinee Prc gltr---

and Trai ning for PreSSUri ed Thermal Shock CONTENTS 1 INTRODUCTION . . . . . . . . . " 1 Short-Term Effort Objectives and Scope of Review 1 1.1 Current Status of Generic PTS Issue . . . . . . . . . 2 1.2 1_3 Oconee ConfiQuration FOR OCONEE AUDIT . . . . . . . . 7 2 SHORT-TERM CRITERIA USED 2.1 Transient and Accident Analyses . . . . .

Introduction . . . . . . . . . . * *. . .. . 7 2.1.1-Oconee Overcooling Events Summary . . . . 8 2.1.2 2.1.2.1 Event 1: Unit 1 - May 5, 1973 . . . . 8 2.1.2.2 Event 2: Unit 2 - Jan. 4, 1974 9 Event 3: Unit 2 - July 11, 1974.. . 9 21.2.3 Event 4: Unit 2 - Sept. 10, 1974 . . 10 2.1.2.4 8206170178 820604 PDR ADOCK 05000269 P PDR

Event 5: Unit 2 - Sept. 17, 1974 10 2.1.2.5 2.1.2.6 Event 6: Unit 2 - March 7, 1975 . . . 11 Event 7: Unit 3' - April 309 1975 11 2.1.2.7 2.1.2.8 Event 8: Unit 3 - May 25, 1975 . . . 12 2.1.2.9 Event 9: Unit 3 - June 13, 1975 . . . 12 Event 10: Unit 3 - July 13, 1975 13 2.1.2.10 2.1.2.11 Event 11: Unit 1 - Aug. 149 1976 13 2.1.2.12 Event 12: Unit 1 - Dec. 14, 1978. . . 13 2.1.2.13 Event 13: Unit 3 - Nov. 10, 1979 , . 14 2.1.2.14 Event 14: Unit 2 - Jan. 30, 1980 . . 15 2.1.2.15 Event 15: Unit 3 - March 14, 1980 . . 16 2.1.2.16 Event 16: Unit 1 - May 4, 1981 . . . 16 2.1.2.17 Summary of Events . . . . . .. ; . . . 16 2.1.3 Oconee Termination Criteria . . . . . . . . . 18 2.1.3.1 Reactor Coolant Pumps (RCPs) . . . .18 2.1..3 2 Feedwater . . . . . .== . . . . . . 18 2.1.3.3 HPI Termination During LOCA . . . . . 19 2.1.3.4 HPI Termination During Steam Supply

. . . = = = 20 Rupture 2.1.3.5 Thermal-Hydraulic Analfysis . . 20 for Procedural Reviews . . .= = = .= = . 22 2.2 Criteria Training Program . . . . . . . . . . 23 2.7 In-Pl.ant

AUDIT . . . . . . . . . . 26 3.:KEY FINDINGS FROM THE OCONEE and Accident Analyses . . . . . . . . . . . 27 3.1 Transient

. . . . 27 3.2 Training .

3.2.1 Introduction . . . . . . . . . . . . . . . . 27 3.2.2 Comparison of Training With Audit Criteria 29 3.2.3 Findings on Training .. . . . . . . . . . 29 3.3 Procedures . . . . . . .3

. ....... . . 0 7.3.1 Introduction 3.:.2 Comparison of Procedures With the Audit Criteria . . . . . . . .

• 1.

1 Finding on Procedures .... . . . . . . 35 3.3.3

. . . 35 3.4 Summ-ary . . .....

, . . . . . . . 36 4 RECOMENDATIOS . . . . .

May 11, 1982, an interdisciplinary audit team visited Oconee On Nuclear Station to evaluate certain aspects of the Pressurized Thermal Shock (PTS) issue. The question that the audit team focused on was:

ARE CORRECTIVE ACTIONS REQUIRED THAT MUST BE INITIATED BEFORE THE LONGER TERM PTS PROGRAM PROVIDES GENERIC RESOLUTION AND ACCEPTANCE CRITERIA?

were the only areas in Emergency procedures and operator training the Oconee audit team applied the above general question. As which noted in the NRR March 9j 182 presentation to the Commission:

" we will undertake a program to verify that exi sting operating procedures contain the steps necessary to prevent and/or mitigate PTS events, and to verify that operator education/training programs regarding PTS are acceptably thorough.

Du to the limitation of the review to training and procedures, the resolution of various technical questions on PTS (thermal-hydraulic probabilities) was not part of the audit analyses, fracture mechanics, implementation of any recommendations (see team charter. Also, Section 4) is subject to coordination and consistency with the longer term generic program (USI A--49).

A visit to Oconee took place on May 11-14 1982, during which time the audit team evaluated procedures and training. The key findings of the group are discussed in Section 3. In preparation for the Oconee audit the audit team used the general criteria addressed in Section 2.

1.2 Current Status of the Generic PTS Issue Efforts to pursue an integrated PTS program involving a variety of areas are continuing under USI A-49. The summer of 1983 is technical the current schedule for finalizing the. generic regulatory along with required corrective actions if the

-requirements for PTS Key issues are yet to be resolved generic requirements are not met.

to provide the foundation for the generic and extensive programs exist regulatory requirements.

effort resulting in regulatory requirements is Before the above

completed however, the staff has committed to the Commission to have initial position for the summer of 1982 (June).

developed an interim position will consist of NRC evaluation of the The interim initial operation (and initial corrective actions Safety of continued plant identified as representative required- for the eight plants previously Technical assistance is being of plants having the highest RTNDT.

team. PNL has been contracted to provided by a PNL multi-disciplinary work with the staff to provide recommendations regarding the June 1982 initial position on the safety of continued operation and to recommend corrective actions that PNL believes should be any additional initiated before the NRC generic resolution and acceptance criteria are adopted. The June recommendations by the NRC staff to the Commission will also consider the findings and recommendations in Sections . and 4 of this report, as well as other audit addressed teams formed for related investigations (such as fluence reduction at the vessel wall).

1. Oconee Con.1figuration The Oconee Nuclear Station is a three unit 2568 MWt B&W lowered loop The Reactor Coolant System (RCS) configuration is a two-loop, design.

leg design utilizing the B&W once-through steam generator four cold Plant control is by the integrated Control System (ICS),

(OTSG).

reactor power and feedwater flow to the electrical which matches demand. Plant transients are mitigated by the Reactor generation

(RPS) and the Engineered Safety Feature System Protective System (ESFS) whichp if necessary, actuates the Emergency Core Cooling System (ECCS) for long term core subcriticality and decay heat removal.

High Pressure Injection System (HPIS), the The ECCS includes the System (CFTS), and the Low Pressure Injection passive Core Flood Tank The HPIS, which also provides reactor coolant pump System (LPIS).

seal injection and normal makeup and letdown control, consists of three pumps injecting into four cold leg locations. The HPI pumps are actuated on low RCS pressure at 1500 psig. Two of the three pumps are normally aligned to the A loop. The two passive CFT's have a liquid each and inject through two core flood lines to volume of 1010 ft(3) vessel downcomer. Injection begins when the RCS pressure the reactor the 600 psig nitrogen overpressure in the tank. The decreases below RCS pressure at LPIS consists of two pumps that are actuated on low to the reactor vessel 500 psig and inject through the core flood lines Although the LPIS is actuated at 500 psig, the pump downcomer.

shutoff head prevents injection until the RCS pressure decreases below is not functional for non-LOCA transients.

200 psig, so that the LPI is accomplished by the pressurizer spray (200 RCS pressure control (1638 kW), the pressurizer relief valve gpm), the pressurizer heaters and two pressurizer safety valves (1-4/5 inch ID).

(1-3/32 inch ID),

delivered from the condenser hotwell to the steam Feedwater is pumps, three condensate booster pumps, and generators by three hotwell 4

two turbine-driven main feedwater pumps. A closed secondary cycle of stages of feedwater heaters is utilized. The two trains of six Emergency Feedwater System (EFWS) consists of two motor-driven and one turbine-driven pump. One motor-driven pump is dedicated to each steam the turbine-driven pump is shared. Steam generator generator and the Turbine Bypass System (TBS),

pressure control is performed by which is part of the ICS, and the main steam code safety relief valves. Each steam generator is equipped with two turbine bypass valves with 12.5% total steam relief capacity, and eight safety valves with 58.5% total steam relief capacity.

The Oconee Nuclear Station has two control rooms. One control room 2 , while the second contains the controls/displays for Units 1 and control/displays for Unit 3 only. The control room contains the former control room is U-shaped. Half of the "U" provides the for Unit 1, while the other half, which is controls/displays Unit 2.

essentially a mirror image, provides the controls/displays for open portion of the "LI". The Back panels are located behind the an operator following table contains the major parameters available to

,at nconee that would assist in monitoring PTS events:

Parameters Display RCS Pressure Wide- and narrow-range meters and digital readout 5

T-hot had a narrow-range RCS Temperature meter and a narrow-range strip recorder. T-cold had a wide-range meter and wide-range strip recorder.

These temperatures could also be read on a CRT In-Core Temperature Read on a CRT with back-up voltage readings from a back panel. Voltages are converted to temperature using graph contained in a procedure Digital readout showing Subcooling Margin subcooling margin for T-hot, T-cold, and RPV in-core temperature Cooldown Rate Instantaneous cooldown rate is provided on the CRT 6

2 SHORT-TERM CRITERIA USED FOR OCONEE AUDIT 2.1 T 2.1.1 Introduction Overcooling events in PWRs may occur as a result of steam line breaks (excessive steam flow), feedwater system malfunctions, or accidents. Multiple failures and/or operator errors loss-of-coolant in more severe overcooling events. Of particular concern can result are those events in which repressurization of the primary system occurs following the severe overcooling. This section addresses an 1,2, and 3 overcooling events that occurred overview of Oconee Units since the plant was built. Aside from the primary mission of the also provided (Section audit team to examine procedures and training, 2.1.4) is a summary of the thermal-hydraulic analyses available for evaluating pressurized thermal shock events.

provides our comments and conclusions on these events and Section 3.1 analyses.

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2.1.2 aconee uvercuu oEvet ma of Oconee has rysulted in A detailed review of the operating history of events that have resulted in exceeding the the identification limit of 100 F/hr, as well as identifying those events cooldown rate exceeding the cooldown rate limit if not that could have led to controls and protective.functions or mitigated by automatic plant operator action.

2.1.2.1 Eventj1 Unt 1 - May 5 1973 during pre-commercial testing and includes several This event occurred and operator actions which are atypical of current system responses power level of 18%9 a control system (CS) operation. From an initial trip of both MFW pumps. A manual trip of the upset resulted in a at !0 seconds. The turbine bypass system (TBS) on reactor followed steam generator (SG) A was in manual due to controller problems and SG in automatic pressure control. Since TB valves on SG A remained B was following reactor trip on loss of feedwater, SG A partially open decreased to 700 psig. The essentially boiled dry. Both SG pressures pump at this time) was not in EFW pump (only one turbine-driven automatic control and did ntt *start. Three minutes after trip the feedwater system (MFWS) was manually restored and an overfeed of main The combination of low SG pressure and overfeed, both SG's occurred.

with a low decay heat level, resulted in a minimum RCS pressure along 13

a minimum temperature of approximately* 500 F. The of 1336) psig, and normal post-trip temperature is 550 F. System conditions stabilized within 15 minutes.

2.1.2.2 Event 2: Unit 2 - January 4 .174 initial power level of 75% resulted in A loss of offsite power from an a reactor trip, RC pump trip, and MFW pump trip. The EFW pump (one turbine-driven pump) initiated fill of the SG's to 95% SG level as originally designed for natural circulation. An auxiliary steam demand of 809000 lb/hr was being supplied to the auxiliary steam header. These conditions caused reductions in T-cold(A) from 562 F to 422 F, and T-cold(B) from 562 F to 426.5 F in the first hour. These cooldown rates of 140 F/hr and 135.5 F/hr respectively. This are transient was the first operational occurrence of natural circulation in RW plant. The excessive cooldown rates necessitated a reduction circulation setpoint from 95% to 50% on the steam in the natural generator level operating range.

2.1.2 Event Unit 2_ -Juy 11,._1974 from an initial power level of 80% resulted in a A loss of ICS power and a Ios of normal feedwater control whereby feedwater reactor trip through both the main and auxiliary feedwater headers.

was delivered failed open on In addition, the pressurizer relief valve apparently 9

is not the current fai lure mode, which is the loss of ICS power. This ICS power. Approximately 20 to 30 seconds to fail closed on loss of the system had depressurized to 1550 psig and the HPIS following trip; seconds and was actuated. ICS power was manually restored in 30 to 45 to normal pressure within 3 to 4 minutes. The the system returned was 515 F, and the. minimum pressure 1450 minimum RCS temperature pi g.

2.1.2.4 Event 4: Unit 2 Septembe 10 1974 From an initial power level of 80"/., a partial failure of the turbine header pressure signal to the ICS caused the TB valves on SG A to fail The ICS responded to the reduction in electrical generation by open.

meet the megawatt demand. The operator was withdrawing rods to alerted to the situation and, after identifying that the TB valves incorrectly, manually isolated the valves. The were functioning faulty electronic component was replaced and the TBS returned to a increase in reactor power. The unit remained on line.

small Event 59 Unit 2-Se2tember 17 _1 4 2.1.2.5 Following a reactor trip from 100% power, the ICS did not successfully The moderate overfeed resulted in a high SG level run back feedwater.

pumps at 220 seconds. The EFW pump (one trip of both MFW was actuated. The transient resulted in a turbine-driven .pump) 10

minimum R: temperature of 547 F, and a minimum pressure of 1700 psign 2.1.26 6175 Event 6: Unit 2__Mrch.7.

At an initial power level of 15%. feedwater control began the normal switch from the startup control valve to the main control valve. As the B main block valve opened, an overfeed of SG B occurred which was terminated by the high SG level trip of the MFW pump. RCS pressure decreased to 1925 psig, at which time the operator manually tripped the reactor. The subsequent investigation identified that the MFW control valve B was stuck open. The valve was repaired. The RCS temperature decreased only slightly.

2.1.2.7 Event 7: Unit 3_- 2i 1 0. 1975 During a loss of load test from 100% power, the ICS runback of main was too slow and resulted in a high SG level trip of both feedwater one main steam code safety valve did not MFW pumps. In addition, until 850 psig (normal reseat pressure 1000 psig). RCS reseat to 1575 psig, and a minimum temperature of 540 F pressure decreased resulted.

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2.1.2.8 E'EDn 8: UnitT.-MY i.

From an initial power level of 100%, a blown fuse in the power supply supply to the TB valves on SG A to a solenoid valve on the air resulted in the valves failing open. The ICS responded by increasing rods. The reduction in T-ave resulted feedwater flow and withdrawing in an increase in reactor power, and a trip on high flux occurred.

The turbine bypass valves were isolated at approximately 20-25 minutes following trip. Pressurizer level decreased to 25 inches, and the resulting minimum temperature was 485 F.

2.1.2.9 Event 9: Unit 3 -une 13 1975 During a normal shutdown from 100% power, an RCS pressure spike 19% power due to manual pressure control of the SM's. The occurred at valve opened at 2267 psig and failed to reseat.

pressurizer relief reactor tripped on low RCS pressure 80 seconds later. HPI was The 1500 psig 209 seconds after the relief actuated on low RCS pressure at valve failed, the block valve was manually closed 25 minutes following relief valve failure, and the RCS pressure bottomed out at 720 psig.

transient was under control 28 minutes after relief valve failure The A normal cooldown then followed.

with the RCS temperature at 510 F.

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2. 1.2. 10 E~~-Ui .j~v1K~Z level of 80%, a transistor failure in, the TBS From an initial power caused the TB valves on SG B to fail open. The ICS responded by Reactor power increased in response to the rod withdrawing rods.

the decrease in T-ave. The operator promptly identified motion and them. The unit remained on the open TB valves and manually isolated Sin e.

2.1.2.11 Event 11: Unit 1 - Augypt_14 197A During three pump operation at 75% power, an asymmetric rod position a runback of 60% poweg. Soon afterward, control rod alarm initiated into the core due to a rod drive problem. The group 6 dropped of feedwater during the ensuing power operator assumed manual control Difficulty with feedwater in manual control resulted in an increase.

and tripped the MFW pumps and the turbine. The overfeed of SG A, reactor subsequently tripped on high pressure. No cooldown occurred.

2.1.2.12 Event 12:.Unit 1 -December 118 From an initial power level of 98%, a short in the ICS T-ave recorder transmitted a low T-ave signal resulting in rod incorrectly The operator noticed power increasing and assumed manual withdrawal.

With T-ave control by rods defeated, the ICS transferred rod control.

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T-ave control to the MFWS which resulted in a reduction in feedwater flow. The operator recognized T-hot increasing with decreasing flow and assumed manual control of feedwater. The reactor feedwater tripped on high temperature. Feedwater was increased rapidly, and the resulting high discharge pressure tripped both pumps. The EFW pump was actuated 7 seconds later, and was (one turbine-driven pump) stopped 21 seconds later when the MFW pumps were reset and started.

to decrease until SG A reached 6 inches and SG B SG levels continued boiled dry. Recognizing the loss of SG level, the operators proceeded headers, and restore SG A to to feed both SG's through the auxiliary 30 inches and SG B to 30 inches. The EFW pump was started to help feed SG B. In response to the refilling of the SG'sq RCS pressure decreased resulting in HPISactuation and a minimum pressure rapidly 1450 psig. Both MFW pumps then tripped on low vacuum, and the EFW of aligned to feed both SG's. RCS temperature reached a pump was then minimum of 500 F.

2.1.2.13 Event 13: Unit 3 - November'10..197 From an initial power level of 99%q a false signal tripped the hotwell pumps. This pumps which tripped one of the three condensate booster a reactor runback on low feedwater flow. The runback was initiated unsuccessful, and the reactor tripped on high pressure at 55 seconds.

A loss of ICS power occurred at 115 seconds. This resulted in a trip both MFW pumps, and actuation of all three EFW pumps. The loss of of 14

ICS power caused an e..tensive loss of instrumntaion. RCS wide range All three HPI pumps were put in operation.

pressure was unaffected.

At that time RCS pressure was ICS power was restored at 223 seconds.

and increasing, and pressurizer level was 20 inches and 1675 psia The RCS temperature was 525 F. On restoration of ICS increasing.

power9 the TB valves partially opened. Auxiliary steam was being Both SG's were near boiled dry supplied from this unit at that time.

conditions. Approximately 10 minutes after transient initiation, the level in SG B increased abruptly following startup of one hotwell pump and one booster pump. SG pressure was 400 psig. As a result of these the RCS temperature decreased to 420 F in steam generator conditions, 20 minutes. This is a cooldown of 115 F, which exceeds the cooldown limit of 100 F/hr. At 31 minutes following transient initiation, the steam flowpath and the TB valves were isolated. A return to auxiliary hot shutdown conditions proceeded normally.

2.1.2.14 Event 14_ =Dit 2 - januarv_3QW,1 Q recognized that Following a reactortrip from 89% power, the operator flow rapidly enough, as indicated the ICS was not decreasing feedwater manual control of feedwater was attempted, a by SG level. Although SG level trip of both MFW pumps occurred. The RCS temperature high decreased to 540 F.

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2.1.2.15 Evtj:*Unt3-arh1.

from 100% power5 the ICS failed to runback Following a reactor trip and calibration error.

feedwater as designed due to a wiring problem MFW pumps on high SG The subsequent overfeed of SG A tripped both level. The RCS temperature decreased to 546 F.

2.1.2.16 Event 16: Unit_1 -_M02-91.1 From an initial power level of 100%, the SG A pressure input to the high causing the TB valves on SG A to open. The resulting ICS drifted a 12.5% decrease in electrical generation. The ICS steam leak caused iDhibited by high flux at 103 responded by withdrawing rods until power. The unit remained on line. RCS temperature decreased by 4 F.

2.1.2.17 SymmaryofEvents the operating history includes a variety of initiating In summary, failures that resulted in the potential for overcooling by two mechanisms, SG overfeed and TBS failures. No steam line breaks have been experienced. In the 23 years of accumulated operating experience, a total of 186 reactor trips have occurred as of August, 1981. Following each trip not initiated by a loss of feedwater, the

- 16

a main feedwater runbackg nine of which were not ICS initiated slow runback or a failure to maintain the successfulg due to a runback, which subsequently resulted in an overfeed of one or both flow rate. All nine overfeed events were SG's at a reduced successfully terminated by the high SG level trip of both MFW pumps, was insignificant. The and in all cases the resulting RCS cooldown occurred due to the original SG level setpoint for one EFW overfeed has since been natural circulation which, as a result of the event, reduced. Two events had potential for overcooling due to a loss of pressurizer relief valve. Of the six TBS inventory through the failure events, there were no instances where the TB valves on both If all four valves were open, it was a result SG's failed full open.

operator manually throttlilg the valves to a partially open of the a complete position. Three of.the six TBS failures, each of which was both valves on one SG, did not even result in a reactor failure of action. Failure of a trip due to automatic ICS response and operator main steam code safety relief valve to reseat contributed only 150 psig below the minimally to one event when the reseat'occurred normal reseat pressure. In almost all events operator response was In the remaining events operator very prompt and appropriate.

response was sufficiently prompt to prevent an excessive cooldown.

Operator error was infrequent and not severe.

the 100 F/hr cooldown limit.

Of the sixteen events odly two exceed Both events are precluded in the future by implemented design changes.

17

resulted in a reduction of the SG level setpoint Event 2 (140 F/hr)

The likelihood of Event 13 (115 F/hr) for natural circulation.

to the upgrade in ICS power supplies, recurring is very low due operator awareness as a result of operating experience and increased similar events, and the development of an emergency review of procedure specific to the event.

2.1.3 Oconee TerminationCriteria.

2.1-.3.1 Reactor CoolantPumps (RC8s when the primary system pressure falls to 1500 The RCPs are tripped greater than PQ F subcooled, one RCP per loop psig. When the RCS is is to be restarted.

2.1.3.2 Feedwater If all four RCPs trip, the ICS transfers main feedwater from the main feedwater header to promote natural feedwater header to the auxiliary main feedwater - pumps also trip on low suction circulation. The pressure at 235 psig.

isolated to both steam generators for steam Auxiliary feedwater is to the faulty steam generator for steam supply system ruptures and For a steam supply system rupture, the generator tube ruptures.

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startup teedwater or emergency-eedwater valve on the unaffected steam 25 inches with the generator is to be controlled to bring level to the RCPs off.

RCPs on or to 50% of the operating range with The emergency feedwater system (EFWS) inputs through the auxiliary main feedwater header. The EFW pumps are automatically actuated by a feedwater pump trip. Main feedwater pumps trip when discharge equal to 750 psig and/or when main feedwater pressure is less than or pump turbine oil pressure is low.

2.1.3.3HPI .erminatioDringLC The HPI System must remain in operation until one of the two following conditions are met:

The LPI System is in operation and flowing at a rate in (1) excess of 1000 gpm in each line and the situation has been stable for 20 minutes, or All hot and cold leg temperatures are at least 50 F (2) below the saturation temperature for the existing RCS pressure and HPI termination is necessary to prevent the indicated pressurizer 1 evel from going off scale-high.

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2.1.3.4 Hperitlr DLSpv..IA The HPI termination criteria for this event are the same as for HPI termination during a LOCA (see above).

2.1.3.5 Thermal-Hydraylic_8nalyvis 1i) BW-1648 Yesel __0tegritv Analyis. The analysis B&W-1648(1) is limited to that of the small provided in break LOCA with extended loss of feedwater. This was in response to an earlier NRC request(2). In the report, were gjvgn to the selections of the break justifications locations and sizes. Comparative analyses were made on three different break sizes, i.e., 0.007, 0.0159 ad 0.023 ft^2, located in the pressurizer. Conservative assumptions on RC pump trip, HPI flow and ECC water were used. Comparisons were made between temperature the cases with and without operator actions (i.e., HPI throttling). However, the decay heat of 1.2 times the ANS standard is not conservative in the sense that it prolongs the natural circulation.

In the Oconee 150 day response (.3)

(2) Qconee PTS Analyis.

to NRC on the PTS issue, transients on small break LOCA 20

with extended loss of feedwater excessive feedwater and uncontrolled turbine bypass valve (TBV) leaks were analyzed for the pressure and temperature histories.

The report gave several possible scenarios for each of the two overcooling transients (excessive FW and TBV leaks) with different combinations of component malfunctions that are most likely to occur. It also provided discussions on the selections of break locations, break sizes and system initial conditions.

Analytical experience obtained from the B&W generic report (BAW-1648) was used to establish the bounding SB LOCA parameters. A realistic decay heat of 1.0 (not the previous value of 1.2) times the ANS standard was used.

However, for the overcooling transients, there is a lack of detailed sensitivity analysis on these parameters.

The selections of the scenarios was not based on systematic PRA analyses. Operator actions are very critical to the pressure'and temperature behavior during a PTS.transient. Sensitivity analysis in this area also seems lacking.

21

.2 2.2 Citeria for Procedlueiews The procedures to be reviewed were selected based on the perceived of conditions occurring that might subject the reactor likelihood to pressurized thermal shock conditions and based on the vessel likely transients. Such procedures potential consequences of less selected included normal startup and shutdown, steam generator tube rupture, steam supply system rupture, and loss of coolant accidents.

The audit criteria for the content of procedures was somewhat flexible to account for operator knowledge and to identify which procedures In addition, detailed must be used to respond to a given transient.

could operator knowledge of actions for preventing or mitigating PTS offset some weaknesses in procedures. With this in mind, the following criteria were established for the procedures audit:

(1) Procedures should not instruct operators to take actions that would violate NDT limits.

(2) Procedures should provide guidance on recovering from transient or accident conditions without violating NDT or saturation limits.

(3) Procedures should provide guidance on recovering from PTS conditions.

22

(4) PTS procedu ral tuid ance should have a supporting technical basis.

(5) High pressure injection and charging system operating instructions should reflect a consideration for PTS.

(6) Feedwater and/or auxiliary feedwater operating instructions should reflect PTS concerns.

(7) An NDT curve and saturation curve should be provided in the control room. (Appendix G limits for cooldowns not exceeding 100 F/hr).

2.3 In-Plant TrainingProgram The effort of the audit team to determine the effectiveness of Duke Power Company (DPC) training in PTS began. by selecting training criteria which would be used in evaluating the training material5 interview Oconee shift personnel, and assessing the evaluation DPC made after completion of the training. The criteria developed into three general areas:

(1) Training should include specific instruction on NDT

vessel limits for NORMAL modes of operation.

should include specific instruction on NDT (2) Training vessel limits for transients and accidents.

should particularly emphasize those events (3) Training known to require operator response to mitigate PTS.

the review of the More specific criteria were also developed to aid in training program and in preparation of interviews with operating personnel. These included:

(1) Training in NDT limits should include the knowledge that irradiation adversely affects fracture toughness properties of the reactor vessel. Operators should know that the vessel and welds will lose ductile material properties and trend toward embrittlement.

Operators should be aware that NRC has sent letters to (2)

DPC on the PTS issue and that DPC had responded that additional training was underway.

understand that a rapid reduction in (3) Operators should vessel temperature/pressure can raise the reactor 24

possibility of crack propagation, particularly if lowest pressure rises after the temperature reaches its value.

events which (4) Operators should be aware of the types of to involve PTS (such as MSL breaks and are known secondary side malfunctions).

(5) Operators should appreciate that other safety limits (such as core cooling and shutdown margin) must also be balanced with the PTS limits.

(6i Training should emphasie the instrumentation available to observe key parameters as they approach limits.

Strategies/options which are under operator control should be emphasized.

Operators should undetstand the basis for current (7) specifically more severe transients

-5mphasis on PTS, have occurred than expected (Rancho Seco, Crystal River).

of their training program on DPC was requested to furnish an outline PTS and the lesson plan which was used in the training classes. They 25

evaluate the effectiveness were also questioned on the method used to of the training sessions.

for review of the training program included a review of Preparation including a report on vessel DPC correspondence with the Commission, of Babcok & Wilcox operating plants (BAW-1648), normal and integrity specifications, and emergency procedures furnished by DPC, technical the FSAR. An interview plan was developed which used the general and the specific subjects that were included in the training criteria DPC training materiaL.

Each interview was preceded by a discussion of the reason for the use all material audit and acknowledgment that the individual could available in the control room, particularly the followup or recovery procedures. Several interview aids were steps in the emergency for discussion prepared to provide the operators a point of reference t strategies and to allow them to predict responses or execu e recovery to mitigate PTS or challenges to other' limits.

3 KEY FINDINGS OF THE OCONEE AUDIT The following is a description of how the audit was conducted and the key findings resulting from the audit.

26

Prior to the plant visit to Oconee; PNL reviewed the procedures listed description of in 3.3.15 the Oconee training outline which included a response (DPC-RS-1001 dated Jan past events and the Oconee 150 day 1932). During the plant visit, PNL reviewed the training schedule, of the training staff and an individual interviewed key members responsible for procedures writing. Procedures which dealt with PTS were reviewed against the audit criteria. Past Oconee PTS events, overcooling transient scenarios used in potential events and potential (as reported in DPC-RS-1001) were analyzed along the DF'C simulations with the procedures and these served as a basis for interviews with to det;erwine the effectiveness of the plant operating personnel program and operator. knowledge on PTS. Seven licensed training operations people were interviewed.

3.2 Traiig 3.2.1 Intrgduction review of the The audit of Oconee's training program consisted of a and PTS training outline, a description of the requalification program We also interviewed three a detailed training schedule and syllabus.

training staff and the following licensed key members of the operations personnel:

27

- 2 STAs (are also licensed SROs)

- An assistant shift supervisor

- A shift supervisor

- 2 control operators

- An assistant control operator

.2.2 Cmarison ofIgwith Atgit Criteria Training_5shgId include eIfijc instruCtion on rNDT (1) for NORMAL mode of- operatiog. Segment 1 of vess.e a . limits

...... 1. .

Periodic Training Requalification includes a the discus.sion of the PTS' issue in general and NDT vessel limits and the interim brittle fracture curve as they normal and off-normal operations. All apply to both interviewees showed cood knowledge in this area.

Trainin< should include soeci f ic instructions on NDT (2) vessel __ li ts for m-r transi ents and accidents.

training deals with NDT Segment of the requalification

vessel limits and the interim brittle fracture curve and their use during transient. This is also a topic in shift training when there are ahanges to covered which have PTS implications. All procedures were questioned in this area and interviewees demonstrated a good understanding.

(3)Trainfing__ghg1d_ gati cul ~y mhszetoeeet known to reggire _gggrator respnm to itigate PTS.

Training in the classroom, on shift and on the generic simulator at B&W does cover these topics. The emphasis is on preventing PTS and includes termination criteria for HPI5 use of P-T diagrams and how to establish and maintain subcooling margins and not exceed cooldown One area that should be given more attention in rates.

training and in the procedures is what the operator should do if he finds the plant operating either on the saturation curve or beyond the interim brittle fracture curve.

3.2.3 FindingEo_ TraininDg The training program appears to have covered PTS subject adequately.

program involves continuous requalification training The training which is designed to ensure that operators are constantly aware of PTS

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rather than being retrained only once a year. The area that was found PTS events to be weak deals with acquainting the operators with past that have occurred in the industry, e.g., Rancho Seco and Crystal these events River. This weakness was evident from our interviews and were not listed in the training syllabus.

the training program and interviews with the Both the review of they had a good supervisors, STAs and control operators indicated that They demonstrated a knowledge of transients understanding of PTS.

PTS and a generally good understanding of how to that could result in avoid PTS. They seemed a little less certain of what to do if they operating either on the saturation curve or found themselves Concurrently, with the PTS audit team visit, approaching NDT limits.

PNL conducted licensing examinations of eight control operators.

Several questions on PTS were asked and in all cases the examinees showed a good understanding of PTS.

3.3Procedures 3.3.1 Introduction Our audit included a review of selected procedures as discussed in discussions with a licensee representative on the Section 2.2,

g relating to PTS and the basis for these instructions, and instructions copy of the procedures to determine its an audit of the control room legibility and currency. Our audit included the following,Operating Procedures (OP) and Emergency Procedures (EP):

OP-01 Controlling Procedure for Unit Startup OP-10 Controlling Procedure for Unit Shutdown EP-04 Loss of Reactor Coolant EP-OS Steam Supply System Rupture EP-17 Steam Generator Tube Rupture 2 ... Cgmpri on of Procedures With the Audit Criteria (1) Procedures should notinstruct operators to take actill.5 that.would viol ate NDT limit. The procedures that were audited generally did not appear to contain instructions cause an operator to violate NDT limits. The that would to or included cautions to stay procedures referred the limits of the Interim Brittle Fracture Limit within which are more conservative than the NDT (IBFL) curves, limits. The NDT curve was consistent with the technical 31

for heatup and cooldown limits. The I BFL speci fication curve waS based on Babcock  : Wilcox analyses and was, essentially, a 100 F subcooling curve below the pressure at which HPI is initiated (HPI 1500). Above 1500 psig the curve rises vertically on the 500 F to the upper limit of the P-T diagram (2400 psig).

In many cases the procedures direct the operator to use the P-T diagram enclosed with the procedures. This P-T diagram is to be used to determine whether the plant is acceptable regions with respect to operating in the subcoolihg margin and cooldown rate. There are five instructions on the P-T diagram. Instruction 4 states, "maintaining the Reactor Coolant at 50 F subcooled takes the Brittle Fracture Limit." This precedence over instruction was found to be ambiguous and confusing to the operators we interviewed and should be clarified.

In discussions with plant representatives, this was brought up and they have agreed to clarify the meaning of this instruction.

(2) P ur gidance on cerity frm transi ent or acci de.nt condi tions without _vigl tingN'I saturation limits. See item (1) above for a or discussion on NDT limits. The procedure for

refers operators to the figure (a P-T depressurization shows the saturation curve, the 50 F diagram) that cure, the IBFL curve, and the NDT curve. The subcooled that tell the operator: 1) figure provides instructions to operate only. between the IBFL curve and the 50 F subcooled curve with RCPs off, and 2) to operate between the NDT curve and the 50 F subcooled curve with the RCPs on. In all cases where a PTS event is the procedures refer the operator to this possible, diagram.

(T.) Procedures shouldprovide guidance on recoveringfrom While the procedures provide PTS conditions.

instructions for maintaining the RCS within conditions allowed by the NDT curve, the procedures do not cover cases where a PTS event has occurred before the operators are able to begin to control plant conditions.

The procedures also do not give guidance to the operator given that the cooldown rate has been exceeded. Thus, there are no instructions in the procedures to tell the operator how to recover from a PTS condition.

(4) PTS gdo ggudance shold have a technical basis. The procedural guidance on PTS is based on analyses and studies conducted by B&W and

reported in the 150 da. response (BAW-1648).

(5) Hig _DreSSUreinjection and chargil SY'stEer--t t I refIect a consideration for PTS.

instructions should 50 F subcooling criterion for HPI termination The PTS concerns. There are no specific reflects instructions for operation of the charging pumps following a depressurization.

(FV) and/or auxiliaryv feedwater (AFW)

(6) Feedwater instructions should reflect PTS concerns.

gperating are provided in the steam generator tube Instructions procedures to terminate rupture and the loss-of:.-coolant flow to the faulted steam generator. These FW/AFW provide instructions to maintain steam procedures also levels in the nonfaulted steam generator generator within a defined baud.

(7) An NDT curve and a saturation curve should be rgvided control room. These curves are provided in all in the applicable procedures.

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3..3Findingso rcegyre In general, the procedures do give the operator guidance on preventing a PTS event. The guidance deals with such items as terminating HPI restarting reactor coolant pumps. The procedures and conditions for have included in them the actions the operator should take if should approaching or in a PTS event. Instruction 4 on he finds the plant the P-T diagram is ambiguous and confusing and should be clarified.

There are no specific instructions on operation of the changing pumps following a depressurization.

3.4 ummary individuals were interviewed. They ranged in Seven licensed supervisor to an assistant control operator.

experience from a shift They all exhibited an understanding of the basic PTS issue and why PTS to their plant. We presented a number of detailed was a concern scenarios which involved the potential for over-cooling or repressurization and all interviewees knew what to over-cooling with interviewed in the control room were able to do. The people we actions and demonstrate that they knew the location describe the right involved in their actions.

and functions of the displays and controls The training program covers PTS subjects in the classroom, during shift training and in the simulator. The procedures are generally coverage of PTS. The only subject that needs adequate in their 35

both in the procedures and training is that of how to attention where the plant is operating outside the recover from a situation on the P-T diagrams. The training program did not acceptable zones PTS events in the industry. The procedures adequately cover past to plot cooldown rate but did not provide a called for the operators means to do this.

4 RECOMMENDATIONS Oconee audit team Based on the findings presented in Section 3 the recommends the following:

(1) The training program should provide a thorough understanding of past industry-wide PTS events and how the operator would deal with these were they to occur at Oconee.

(2) The training program and the procedures should provide more guidance to operators on how to recover from situations where the plant is found to be outside the 50 F subcooling curve and NDT limit curve (Region I &

II) on the P-T diagram.

should be provided a better means of (3) The operators

tracking cooldown rate and subcooling margin. The instantaneous subcooling margin is displayed by a digital display and the instantaneous cooldoyn rate is shown on a CRT. In both cases the operators must plot this information on a graph in order to see trends.

When the computer is down this task becomes much more difficult, very time consuming, and is prove to human error.

the procedures written as part of the B&W In the longer term, Anticipated Transient Operating Guidelines (ATOG) program should be reviewed under item 1C1 of the Task Action Plan to verify that they the guidance to avoid a PTS event and how to provide the operator with cope with a PTS situation should that become necessary.

REFERENCES BAW-1648 "Thermal-Mechanical Report - Effect of HPI on Vessel (1)

Small Break LOCA Event with Extended Loss of Integrity for Feedwater", Babcock & Wilcox, Lynchburg, Virginia, 1980 (2) NURE-0737, "Clarification to the Action Plan", 1980

3) Licensee 150 - Day Response to NRC on PTS, Duke Power Company, Oconee Nuclear Station Unit 1, DPC-RS-1001, January 1982