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Incident Reporting Sys Rept 11.4,containing Excerpt from NUREG-0090,Vol 4,Number 1 Re 800628 Incident at Facility
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Site:	05000000, Browns Ferry
Issue date:	09/08/1981
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	FOIA-81-380 NUDOCS 8204150180
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{{#Wiki_filter:( e L,.. '. ~ -. . }. 4 i,, 'g, .l. ^ L. y,, ,1 .,.e, SEP S 1931 11+0 RESTRICTED No. IRS DIFFUSION RESTREINTE Date of Receipt 25th August 1981 Date de R6ception Name of nuclear power station Browns Ferry 3 (USA) Nom de la centrale Date of incident 28th June 1980 Date de l' incident Type of reactor BWR Type de reacteur Authorized electrical power Niveau de puissance diectrique 1067 IWe (net)* autorisd First commercial operation March 1977* Date de mise en service

added by NEA Secretariat.

Included is the extraction from NUREG,090 vol. 4, No. 1, " Report to Congress on Abnormal Occurrences", with the approval of the IRS coordinator in the United States. 8204150100 811109 PDR FOIA CONNOR 81-380 PDR 4765 t

Failure of Control Rods to Insert Fully During a Scram I As stated in the' previous update report, the NRC Office of Inspection and Enfore ment issued Bulletin 80-17, Supplement 4 (Ref. B-4) on December 18, 1980 to all operating General Electric (GE) BWR power reactor facilities with scram discharge volume designs similar to Browns Ferry. This Supplement required l the affected'11'censees to provide assurance that the Continuous Monitoring System (CMS) installed in response to Supplement 1 (Ref. B-5) had been tested to demonstrate operability as installed, remains operable during plant operation, and is periodically tested to demonstrate continued operability. Also as previously reported, orders were issued to all operating GE BWR power reactor facilities with scram discha.'ge volume designs similar to Browns Ferry on January 9, 1981. The Orders required the affected licensees to install an automatic system to initiate a reactor control rod insertion on degraded air system conditions. On March 31, 1981, the NRC Office of Inspection and Enforcement issued a Temporary Instruction to verify BWR licensee action implementing commitments relating to the January 9,1981 Orders (Ref. B-6). Once the modifications required by the January 9, 1981 Orders have been implemented, all necessary short-term corrective measures will be in place..The only remaining issue is the long-term modifications to improve the scram discharge system reliability. With the exception of FitzPatrick, Millstone, Nine Mile Point, and Vermont Yankee, GE BWR licensees have made acceptable commitments to long-term correc-tive measures proposed in the staff's Generic Safety Evaluation. Report dated December 1,1980 -(Ref. B-7). Discussions with these licensees are being held to resolve any outstanding technical positions. The staff plans to issue Orders confirming the licensees' commitments after resolution with the remaining plants is achieved. i

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DEC 2 2 P^l No.IRM RESTRICTED DIFFUSION RESTREINTE 28.11.80 Date of Receipt Date de Reception Name of nuclear power station Arkansas Unit 1 and 2 Nom de la centrale Date of incident 7th April,1980 Date de l' incident Type of reactor Type de reacteur M 836 MW (Unit 1)

Authorized electrical power Niveau de puissance diectrique 912 MW (Unit 2)*

autoris6 First commercial operation Date de mise en service l l added by OECD/dhA Secretariat i l l l l l l { l l

1 6 2 m = s REPORT ON LOSS OF OFFSITE POWER EVENT AT ARKANSAS NUCLEAR ONE, UNITS 1 AND 2 ON APRIL 7, 1980 F by the Off'ce for Analysis and Evaluatien of Operational Data October 15,198n t Prepared by: Wayne D. Lanning, Senior Reactor Systeas Engineer NOTE: This -ecort document.s results of studies completed to date by the Office 'or Analysis and Evaluation of Operational Data with regard to a particular coeratina event. The findings and recomendations con +ained in this report are provided in succort of other ongoine NRC activities concer91no this event. Since the studies are cegoing, the recort is not necessarily final, anc tne findings and reco-: nee-4tions do not represent the cosition or recuirements of the rescon-sible crocrar of # ice of the Nuclear Deculatory Commission. (Oll[3 of9

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A CONTENTS Executive Summary........................... 1 Preface................................ iii 1.0 Event Description......................... 1 2.0 Findings Concerning the Event................... 6 3.0 Comoarison of Unit Transient Responses.............. 21 4.0 Recommendations.......................... 23 Footnotes............................... 26 Figures................................ 29 Tables................................ 31 Appendix A - Uni t 1 Transient Report................. 37 A I Appendix B - Unit 2 Transient Report... 43 Appendix C - Shift Technical Advisor Log............... 49 Appendix D - Uni t i Log Entries.................... 52 Accendi x E - Uni t 2 tog Entri es.................... 53 Appendix F - Unit 1 Trend Recorder Charts............... 54 1 Appenois G - Unit 2 Trend Recorder Charts............... 61

e EXECUTIVE

SUMMARY

As a result of tornadoes in the Russelville, Arkansas area on April 7, 1980, both units at Arkansas Nuclear One experienced a loss of offsite Since both units were operating initially at approximately 100% power. power, a study was initiated to compare the natural circulation response of a Babcock and Wilcox Nuclear Steam Supply (NSSS) (Unit 1) to a Combus-tion Engineering NSSS (Unit 2). Both units experienced a loss of offsite power af ter tornado damage to offsite transmission towers which resulted in the loss of four of the five lines providing power to the station. Although the remaining ifne provided power to the station switchyard, a failure in the bus tie autotransformer circuitry isolated this offsite power source from both units. The onsite emergency diesel generators energized the essential buses and both units began to cool down by nat-ural circulation as exoected. Each unit experienced ecuf pment performance anomalies during the initial phase of the event. The High Pressure Injection (HPI) System was actuated manually by Unit 1 coerators in response to decreasing system pressure and pressurizer level due to shrinkage of the reactor coolant system after reactor trip. One of the +r FPI isolation valves failed to open. On Unit 2, the energencv 3 'ed

,er ' low was interruoted ecmentarily due to loss of cumo suct..a t#,t a feedwater suction flashing. Heither mal-function adversely affected the recovery of either unit during the transient, i

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6 Sustained operation of the HPI system required Unit 1 operators to cycle the pressurizer electromatic relief valve to reduce system pressure. In addition, the valve was cycled several times to ascertain that the system was not solid, (i.e., loss of steam bubble in the pressurizer). The analyses and evaluation of the event and the natural circulation re-soonse of each unit identified procedural and design deficiencies. These findings, which may be generic to other operatin7 plants, have been included in the recommendations for corrective actions to be ' considered by the NRC Office of Nuclear Reactor Regulation. The most important findings include: the lack of regulatory reouf rements for the station switchyard to function following a single failure; improper emergency feedwater pump suction align-ment which resulted in loss of feedwater flow; improper alignment of manual selector and mode switches which resulted in loss of the orocess and trend computers; lack of regulatory recordkeeping reouirements for operator actions, alarms, and system conditions needed for post-transient analyses; continued unavailability of the unit 2 turbine-driven emergency feedwater train due to numerous problems with the turbine governor; and lack of uniform natural circulation criteria and operator understanding and recognition of natural circulation conditions. l 11

6 PREFACE The findings and recommendations contained in this report are based on in-formation gathered through informal channels between Arkansas Power and Light Company and the Nuclear Regulatory Commission. The information has been reasonably verf fied by confirmation through other sources. The findings regarding the underlying causes of the loss of offsite power which occurred at Arkansas Nuclear One on April 7,1980, relate directly to the switchyard at the plant. However, similarities among switchyard design and operation and corresponding NRC regulatory reouirements lead us to. believe that the findings and recommendations may be broadly and generically applied to most operating plants. Excluding tne findings related to the response of the B&W Nuclear Steam Supply System (NSSS) af ter a reactor trip and to systems which are PWR-vendor specific, the other findings and recommendations are independent of the NSSS and are therefore generic to both PWRs and BWRs. Accordingly, a plant-by-plant review, not possible in this investigation, should be under-taken to assess the applicability of the findings and implementation of the recommendations to other licensed power reactors. Additionally, the scope of this evaluation was intentionally limited so as to address only the specific, direct and underlying causes of the loss of offsite power and the natural circulation response for the two NSSSs at Arkansas Nuclear One. ( AECD has another case stucy in progress to assess natural circulation obenomena which is generic to PWRs). We do believe however, that the information presented herein can be useful to those involved directly in the generic issue of station blackout. I iii

6 REPORT ON LOSS OF OFFSITE POWER EVENT AT ARKANSAS NUCLEAR ONE, UNITS 1 & 2 ON APRIL 7, 1980 1.0 EVENT DESCRIPTION 1.1 Introduction At 1848 hours, on April 7,1980, both units at Arkansas Nuclear One experienced a loss-of-of fsite power event. Unit 1 is a Babcock & Wilcox Nuclear Steam Supply System (NSSS) and Unit 2 is a Combustion Engineering NSSS. The initiating cause of the event was tornado damage to offsite transmission towers. Although offsite power was available to the station switchyard, a relay fault occurred which disconnected both units from the offsite supply. Both units were at approximately 100t power although Unit 2 had begun a load reduction at the time. Both units established natural circulation and plant response was as anticipated except each unit experienced one signif-icant malfunction during the transient. On Unit 1, one of the four high pressure injection valves failed to open. On Unit 2, the emer-gency feedwater flow was interrupted momentarily due to loss of pump suction caused by feedwater suction flashing. Forced circulaticn was restored after approximately three hours for Unit I and one hour for Unit 2. Unit I returned to power operation, but Unit 2 remained shut-down to repair some pretransient conditions (e.g., leaking safety valve, cump seal and spray valve). 1.2 Cause The system dispatcher had notified the station that there was a tor-nado warning for Pope County and surroundings at 1655 hours. At 1728

m hours, the 500 KV transmission line to Ft. Smith was lost and 57 minutes later the 500 KV line to Mabelvale was lost. The 500 KV line to Mayflower snd the two 161 KV lines (Russe 1ville and Morrii ton) were still available. Subsequently, the remaining 500 KV line and the 161 KV line to Russelville were lost. The Morri1 ton line was still available. Coincidently, relay protective switches 1212 an'd 1215 (see Figure 1) mal functioned and opened. This action disconnected the remaining offsite power (Morrilton line) to the bus tie autotransformer which supplies power to the unit 1 startup trans-former (ST-1) Unit 2 startup transformer (ST-3). The autotransformer ties the three 500 KV lines to the two 161 KY lines through a ring bus. Startup transformer ST-2 is connected directly to the 161 KY system. It can be shared by both units, but is normally locked-out to prevent overloading (under-voltage condition) of the transformer if both units are connected simultaneously. tianual action from the control room is required to sequence emergency shutdown loads on this transformer since ST-2 is not designed to carry normal auxiliary loads for both units simul taneously. No coerator action was initiated to secuence loads to the transformer since the operators apparently failed j to recognize that a source of offsite power was still available. l The reason for the malfunctions of the relay protective switches which isolated the autotransformer is unknown. The licensee has investigated tne failure and attempted to identify the failure mode by trying to repeat the conditions leading to the failure. The reasons for the mal-functions were not determined and the licensee did not expect to further investinate the cause of t"e malfunctions. 2

6 The performance of the autotransformer appears cuestionable based on this and previous events of February 22, 1975, and September 16, 1978. Although the initiating causes of these events were different, both resulted in the isolation of the autotransformer and actuation of the diesel generators when a source of offsite power was still available to the switchyard. The September 16, 1978 event resulted in an NRC 1 order for certain modifications to the electrical power systems to prevent oegraded voltace to engineered safety features. At that time, the staff ouestioned whether the electrical power system was in conformance with General Design Criterion 17 of Appendix A to 10 2 CFR Part 50. Evidentiv, a staff position regarding conformance to GDC 17 was not formalized. The autotransformer is a point of common-ality for all offsite power but, apoarently, has not been required to meet tne single failure criterion. 1.3 Plant Status Prior to Event Due to the tornado warning, Unit i had started diesel generator No. 1 per Emergency Procedure 1202.44, Revision 4, Section II, " Natural Emergencies - Tornadoes." Unit 2 procedure did not reouf re starting a diesel generator (reason is unknown). Neither plant was operating under any technical specification limiting conditions for oceration. Immediately prior to the event, two of the three 500 KV transmission lines to the switchyard were inocerable due to tornado damace to offsite transmission towers. 3

a At 0205 hours on the day of the event, Unit I had completed mainte-nance and performed stroke tests on the steam admission valve (CV-2667) to the turbine for the emergency feedwater pump. Pre-viously, during surveillance testing, the valve fully opened on the second and third attempt but would not fully close. The valve had to be manually closed and was declared inoperable. A redundant steam path was available through valve CV-2617 while repairs were made. At 0633 hours on the same day, Unit I had completed the quarterly test of the high pressure injection motor-operated isolation valves. These valves were declared operable. During the event, one of these valves failed to open. At 1500 hours the turbine driven emergency feecwater pump P7A on Unit I was taken out of service to repack the pump gland to reduce the amount of waste water wnich had to be processed. The pump was restored to operability at 1806 hours (42 minutes before the event) af ter repacking. On Unit 2, all of the atmospheric dump valves (2CV-0302, 0305, and 0306) were isolated and tagged inoperable due to vibration problems and with failure-to-reseat problems af ter actuation. Aporoximately ten minutes before the event, Unit 2 commenced a load reduction of 200 in'e at the recuest of the load dispatcher. None of these existing conditions or equipment outages appeared to have an adverse imoact on the plant response following the loss of offsite power event. 1.4 Transient Descriotion The chronolocies of the loss of offsite power transient are listed in Table 1 for Unit 1 and Table 2 for Unit 2. Each chronology contains I

= only the sionificant events which occurred during the transient for each unit. These chronolootes were compiled from the licensee tran-sient reports ( Appendices A and B) and discussions with the Arkansas operations personnel. A log was maintained by the Shift Technical Advisor and included as Appendix C (it was primarily for unit 1). There is only one Shift Technical Advisor per shift to cover both units. The transient reports contained the operators' log ( Appendices 0 and El and strip charts ( Appendices F and G) for each unit. The process computers for both units were unavailable during the transient. The selector switches (discussed later) for both the process and trend computers for Unit 1 were in the wrong position. It is believed that the Unit 2 process computer self-protected on low voltage. It was not restarted until after unit recovery by the plant staff. Consequently, a precise determination of alarms, equipment operations, or sequence of events was not possible. The operators' logs lacked sufficient detail and completeness for ana-i ly:ing operator actions and plant response during the transient. 1 r. f ___n ..,.m. -7 -..,7__ __.m..-p.____ -,g m_ _p- .,v,..

2.0 FINDINGS CONCERNING THE EVENT 2.1 Offsite Power Systems - Both Units The bus tie autotransformer which supplies power to the Unit 1 startuo transformer (ST-1) and the Unit 2 startuo transformer (ST-3) is a single point of commonality for all offsite power sup-olies. The failure or isolation of this transformer will discon-nect both units from the 500 KV sources of offsite power and de-energize the connected startuo transformers. A manual action is then recuired to connect either unit to the remaining startup transformer (ST-2) if the 161 KV system is still available. But before the manual action can be completed, the diesel generators will have already started and energized the essential buses. The 161 KV system feeds both the autotransformer and ST-2 which can be shared by both units. However, ST-2 alone does not have the capacity to carry the normal auxiliary loads of both units at the same time. It does have the capacity to carry the emergency shut- ~ down loads for both units but there are no automatic load shedding provisions to trim the extra loads. For protection, this transformer is manually locked-out to prevent overloading the transformer. Con-sequently, the emergency shutdown loads must be manually secuenced to this transformer. Therefore, upon loss of the bus tie autotrans-former, both units will transfer in a few seconds to the onsite power system provided by the diesel generators even though off-site power is still available to ST-2. 6

6 Finding The finding concerning the offsite power system is that a single failure (loss of autotransformer) results in a loss of offsite power event for both units at Arkansas Nuclear One. Since the implementa-tion of GDC-17 has not required the offsite power system to meet the recuirements of the single failure criterion, this deficiency may be generic to all operating plants. It is undesirable that a single failure should result in a loss of offsite power transient for both units and the actuation of safety-related eculpment. 2.2 Emergency Feedwater System - Unit 2 prior to the event, the emergency feedwater pump suction was aligned, 31 shown in Figure 2, to both the condensate storage tank and the Startup and Blowdown Ocmineralizer System (S/S DS). This is the nor-mal alignment used by Unit 2 during startup, hot standby, hot shut-down, or normal cooldown to obtain higher quality feedwater since Unit 2 does not have a 100% full-flow polishing system. In addition, by recycling the condensate to the steam generators, some of the thermal energy from the condensate is recovered. The suction of the motor-driven emergency feedwater pump, which is used during these operational modes, is aligned through the startup and blowdown demineralizer to the discharge of the condensate feedwater pumos and also aligned to the condensate storage tank. I Uoon lost of offsite power, the main feedwater pumps trioped and the emergency feedwater cumps started taking suction from the S/B DS. i 7 I

The pressure in the S/B DS was higher than in the condensate storage tank thereby preventing water flow from the tank. Representatives of the utility believed that the most likely situation was that water was drawn to the feedwater pump suction from the main feedwater system in che reverse flow direction through the S/B DS. By this means, hot water was drawn from a leaking moisture separator / reheater valve, through the feedwater heaters, through the S/B DS to the emergency feedwater pump suction. The feedwater flashed either at the pump suction or in the feedwater piping. Nonnally, the S/B DS would have taken suction from the condensate system by taking suction from the discharge of the condensate pumps. But, upon loss of offsite power, the condensate pumps were inoperable. An alternate possibility was that the loss of auxiliary cooling water to the steam generator blowdown heat exchangers might have caused the demineralizer effluent to heat up to the flashing point. But this blowdown from the steam generators should have isolated automatically upon loss of offsite power. In either case, the flashing caused some cavitation of both emergency feedwater pumps. The operator immediately recognized the l l low discharge pressure in the emergency feedwater pumps, isolated the S/B DS, directed an auxiliary operator to manually vent the emergency feedwater pumps one at a time to sustain some feedwater flow, and restored full amergency feedwater flow. The AE00 evaluation of the loss of feedwater flow causes tends to agree with the "most likely situation" described above. However, the feedwater flow probably flashed at the pump suction ratner than in the feedwater S l

a piping. The feedwater temperature was probably increased by the feed-water heaters and, when subjected to the decreased pressure at the pump suction and heat addition during the purping cycle, the fluid flashed. The leaking valve from the moisture separator / reheater probably had no effect on the flashing of the feedwater. Another possible explanation is that the degradation of feedwater flow occurred when the demineral-1:er tanks in the S/B DS began to empty. Since the emergency feedwater flow was not recorded, it is not possible to detennine if the loss of feedwater af ter fif teen minutes into the event was due to depleting the inventory in the two tanks. Since the emergency feedwater pumos were throttled during the fif teen minutes, the time to tank deDletion could not be calculated based on the design flow rate of the pumos. Regardless of the exact cause of the emergency feedwater flow degrada-tion the remedial action was the isolation of the emergency feedwater cump suction from the S/B 05. Finding The finding concerning the emergency feedwater system is that the flow path from the S/B DS should be isolated automatically or kept adminis-tratively closed to ensure that emergency feedwater is taken from the condensate storage tank. Valve (2C33) to the S/B on Unit 2 has been put under administrative control since the incident. The procedures and valve alignments have been changed such that the valve is now closed upon reaching five percent full power. 9

o 2.3 Hioh Pressure Injection System - Unit 1 The High Pressure Injection System (HPI) was manually actuated for Unit 1 to recover system pressure af ter reactor trip. HDI would have probably been automatically actuated on low system pressure without operator action. Manual actuation of the HPI was timely and appropriate. Even though one of the four HDI isolation valves failed to open, the cross-connections between the HPI trains ensured adequate flow delivery to the system. During maintenance on the high pressure injection isolation valve (CV-1227) prior to the event, the valve was manually closed using the hand wheel. In orqer to manually close this motor-operated valve, a lever must be operated to engace the hand wh' eel and disenoage the electric motor clutch. This engage lever is spring loaded such that when released, it should disengage the hand wheel and enable the electric motor clutch to operate the valve. The engage lever stuck in the manual position and prevented the motor clutch from enoaging during the event. It is believed that a lack of lubrication prevented proper operation of the enoage lever. The crocedures for maintenance on these valves have been changed. The new procedures recuire the operators to stroke tne valve from the control room following any manual valve manipulation. l As a result of the Three Mile Island incident, nuclear plant ocerators are now reluctant to throttle HPI flow after a system depressurization i l 10 l

a 9 even though the 50* margin to saturation is maintained. As a result, the system repressuriZes and the pressurizer level goes' off-scale high. For the Arkansat transient, the operators opened the pressurizer electromatic relief valve (ERV) limiting the system pressure to about 2440 psi, but the pressurizer level went off-scale high. As a result of sustained HPI flow and filling the pressurizer, plant operators realize the system may go solid. This possibility was certainly considered by the Arkansas Unit 1 operators during tne transient. The ERY was intermittently opened as a method to determine if the pressurizer was solid; it was not. However, as a result of high pressure injection filling the pressurizer, the pressurizer was cooled thereby reducing the control effectiveness of the pressuri:er heaters. Consequently, the system pressure was reduced by the operators from 2440 to 1840 psi in approximately 30 minutes to increase the pressurizer heater effectiveness and to restore pressuri:er level to the indicated range. The indicated margin to saturation in the hot leg was above 70* during the depressurization. Findings There are three findings concernino operation of the HPI system. First the HPI system, wnich is safety-related, is apparently needed to recover system pressure and pressuri:er level in a B&W NSSS af ter a reactor trio, an anticipated operating occurrence. This implies 11

= that the design of the pressurizer lacks sufficient volume to compen-sate for system shrinkage after a scram. Second, sustained operation of the HP1 system results in overpressurizing, overcooling, and possi-bly overfilling (system solid) the pressurizer. Overpressurization results in the opening of pressurizer relief valves and possibly safety valves. This results in a temporary breech of the reactor coolant pressure boundary. Overcooling the pressurizer subjects it to an additional thermal stress cycle and reduces the effectiveness of the pressurizer heaters for pressure control. Overfilling the pressurizer could result in the pressurizer going solid and water being relieved through the relief and safety valves for which they are not designed. Failure of these valves to close would result in a sustained loss of coolant from the primary system. Third, whenever a motor-operated valve is manually operated, the valve should be operated subsequently from the control room to verify its operability. 2.4 Process Comcuters - Both Units The process computers (SELS) for both units were not available during the event. In addition, Unit I has another computer (NOVA) which is used for recording trends of variables and for performing calculations. This computer was also unavailable during the transient. The process computer for Unit 1 was lost because the manual transfer switch, which selects either a DC/AC or AC power supply, was positioned only for AC power which was lost. Similarly, the trend computer (NOVA) l 12 l

s was unavailable because the mode switch was not in the self-protect position which would have enabled the computer to retain its memory and restart af ter the loss of offsite power. The switches for both computers are now controlled administratively to ensure that they are in the correct position and available following a loss of off-site power. The reason for losing the process computer for Unit 2 has not been dete rmi ned. It does not have the selector switch feature found on Unit 1. It is believed that it experienced a voltage decrease and sel f-protected. Power was available to the computer during the transient. The licensee is continuing to diagnose the failure. The process computers are not safety-related equipment and the oper-ators indicated that they are not needed during a transient. Alter-nate methods are available for obtaining incore thermocouple readings, boron concentration, core physics, and other important parameters. No attempt was made to restore the computers to operation until after the event. Finding The finding concerning the NOVA computer and the process computer for each unit is that their function during plant transients is not regarded with sufficient importance. The operators at Arkansas considered each process comouter primarily an administrative tool for compiling monthly operating reports. Arkansas does not keep a copy of the computer 13

s p rintouts. Consequently, the computer log for the time preceeding the loss of offsite power event had been disposed of; and thus, was not available for post-event analysis. This is of significant con-cern because the process computer is capable of providing impo-tant diagnostic system data during a transient and provides the important function of recording alanns and sequence of events for pnst-transient analysis. 2.5 Doerators' Log - Both Units A partial substitute for a computer log might be the operators' log. However, a review of the operators' log for both units (included as Appendix D and E) revealed that the logs lacked sufficient detail and completeness to accurately reflect operator actions and plant status during the transient. During the transient on Unit 1, the Shift Tech-nical Advisor recorded most of the significant operator actions. Since there is only one Shift Technical Advisor (STA) to cover both units, a sequence of events for Unit 2 was not compiled by the STA. Finding The finding concerning the operators' logs is that there are no regula-tory requirements or guides addressing the content or extent of details recuired in the operators' logs. The logs involved in this event were not useful for constructing a secuence of events or identifying operator actions for a post transient analysis. Also to be noted is the limited attention available to more than one unit by the single Shif t Technical Advisor when the units experience a simultaneous transient. This prob-14

lem is further aggravated because the units are significantly different in their design and in tneir response to the same transient. 2.6 Reactor Coolant Pumo Seal Injection - Unit 1 As a result of the loss of offsite power, seal injection to the reactor coolant pumps for Unit I was interrupted for approximately three minutes. The component cooling water to the pumos was also lost and not reestablished until after the plant had recovered from the transient. Subsecuent to the event of April 7,1980, Unit 1 experienced a loss-of-coolant event due to a ruptured seal on reactor coolant pump "C" on May 10, 1980. Findino A potential finding is the possible effect of loss of seal injection on seal degradation. The effects of the loss of offsite power and other transients and events on the degradation of the seals is the subject of a separate case study being perfonned by AE00 and will be reported later. 2.7 Diesel Generator Ooeration - Both Units Unit 1 procedures (but not Unit 2 procedures) for natural emergencies, such as tornado warnings, recuire that one diesel generator be started, but not loaded. There is some concern that running the diesel unloaded results in carbon buildup which reduces its capability to start on 3 future demands. The diesels are started at Unit 1 on the average of 3-4 times per year cue to tornado warnings. The maxirium time a given diesel has been run at any one time his been approximately three hours. 15

Finding The finding concerning diesel operation for no load conditions is that the method that Arkansas emoloys for running the diesel unloaded is note-worthy, and seems to b,e responsible for extremely high diesel reliability. At Unit 1, the diesel is not idled, but run at rated speed for the entire duration. After the running period, the diesel is always loaded and operated under loaded conditions for at least 30 minutes. Evidently, this mode of operation prevents carbon builduo and the reliability of the diesel is not adversely affected when run unloaded. The same tech-nioue will now be apolied to Unit 2 diesels since Unit 2 procedures have been changed to start a diesel during natural emergencies. 2.8 Emeroency Feecwater System - Unit 1 Prior to and during the event, the steam acmission valves to the turbine driven auxiliary feedwater pumps for Unit I would not close completely. These valves had also failed to open previously during surveillance testing. After the event, the torque switch and bolts to the hand wheel housing on both valves were replaced because the switch could not be securely fastened. The valves operated satisfactorily thereaf ter, per-haps because the bolts were replaced and properly secured. Finoing A number of LERs on various limitorcue valves has been noted wnerein the torque switch has recuired adjustment in order for the valve to operate properly. The underlying problem for a number of toroue 16

1 1 switch maladjustments may be that the switch is not firmly secured. As a consequence, during operation of the valve the adjustment of the switch changes. 2.9 Electromatic Relief Valve - Unit 1 Prior to the transient, the block valve to the pressurizer electro-matic relief valve (ERY) for Unit 1 was closed as a result of the Crystal River event of Febraury 26, 1980. This event involved the spurious opening of a relief valve. During the first 15 minutes of the Arkansas event, the block valve was opened and the ERY was used to reduce pressure in the reactor coolant system. The pressure increase resulted from operation of the High Pressure Injection System which had been manually actuated to recovery pressure after reactor trip and emergency feedwater actuation. The use of the ERY during the mitigation of this transient was an appropriate operator action to preclude opening of the code safety valves. The ERY was cpened subsecuently to verify that the pressurizer had not gone solid (e.g., steam bubble collapsed). Findino i The findino is that, as a result of using a safety-related system (HPI) to mitigate an operational transient, the ERY must be used to control system pressure. This increases the number of times the ERY is cycled i and increases the likelihood for the ERY to fail open. After the TMI-2 accident, the NRC initiated efforts (e.g., increased the set point) to i i 17 l t

minimize the exercising of this valve. In addition, the NRC (IE Bulle-tin 79-06A) required operation of the HPI for 20 minutes after automatic actuation caused by a low pressure condition. Even though this event did not involve automatic actuation, additional guidance to the licen-sees may be appropriate, advising against continued operation of the HPI after system pressure is recovered and appropriate system subcooling is established. 2.10 Natural Circulation Criteria The operators indicated that natural circulation was achieved in both units within fifteen minutes and independent of operator action. Three operators were asked what criteria they used to ascertain that natural circulation had been achieved. Each operator had different criteria as follows: 1. For Unit One, the hot leg temperature should decrease and remain below the saturation tencerature. 2. For Unit One, the difference between the hot and cold leg temperatures should be relatively constant and less than the full power temperature difference. 3. For Unit Two, the hot leg and cold leg temperatures should diverge and the hot leg temperature should be less than the saturation temperature. In addition, incore thermocouple temperatures must be decreasing. The conditions for natural circulation contained in the operating procedures were as follows: Unit 1 (Both conditions must be satisfied) 1. All hot and cold leg tenceratures are below the saturation temperature for the existing RCS pressure. 18

2. RCS hot leg temperatures decrease as secondary pressure is decreased. Note: T and T may diverge slightly during cooldown due hot cold to primary water density changes, but T should trend hot downward. Unit 2 (All conditions must be satisfied after 10 minutes) 1. Loop A T (T -T ) less than normal full power A T. hot cold 2. T constant or decreasing. cold 3. T stable (i.e., not steadily increasing). hot Findino Although the criteria for natural circulation are contained in the procedures for the two Arkansas Units, it is not clear that the operators completely understand and comprehend the criteria. The potential exists for operator confusion and misunderstandino as to 4 whether natural circulation has been achieved. The finding is that the training for operators may not adeouately address the conditions reouf red to ascertain natural circulation. The operator licensing examination should include questions which evaluate the operator's understanding of natural circulation criteria. An additional finding which is generic to all operating pressurized reactors (pWR) is that the criteria for establishing natural circula-tion are not uniform and have not been reviewed by the NRC. The test 19 I i ,_.y ~.- ~ ~ ~

criteria for natural circulation tests for Sequoyah, Salem 2 and North Anna 2 were reviewed as part of the near term operating li-cense requirements. Some criteria were reviewed by the Bulletins and Orders Task Force during their review of small break procedures. Since the NRC has required the PWR licensees to trip the reactor coolant pumps for certain small break loss-of-coolant conditions which results in natural circulation conditions, the NRC should ensure that adequate criteria exist to ensure an orderly plant cool-down. In addition, a uniform criterion is required in the event of an incident to avoid confusion and enable a timely evaluation of system conditions. Natsral circulation conditions also exist for other causes for loss of forced circulation provided by the reactor coolant pumps. J 20

3.0 COMPARISON OF UNIT TRANSIENT RESPONSES Arkansas Nuclear One, Units 1 and 2 are B&W and CE Nuclear Steam Supply Systems (NSSS), respectively. Since both units were operating at essen-tially 100% full power at the time of the event, a comparison of the relative performance characteristics of the NSSSs during the event (under natural circulation conditions) was att?moted. The different plant de-signs, procedures, and operator training, with respect to recovery from the transient, severely complicated the comparison. For example: for pressure control, Unit 1 operated the ERY whereas Unit 2 utilized the pressuri:er auxiliary sprays; depressurization in Unit I required the operation of the HPI (600 gam) whereas Unit 2 was able to recover using the charging pumps (132 gam); steam pressure was controlled by the operator opening the atmospheric dump valves for unit 1 and passively controlled by the main steam safety valves in Unit 2. The available trend charts from both units are included as Appendices F and G and were compared for system response during the transient. The follow-ing general observations can be made. 1. Unit 1 (B&W) experienced a more severe pressure transient than did Unit 2 (CE). Unit 1 initially deoressuri:ed from 2150 psi to about 1850 psi and then increased to about 2440 psi. Unit 2 deoressurized from 2550 psi to about 2000 psi and recovered to about 2320 psi. 2. Both units maintained adequate margin to saturation during the tran-sient. The minimum margin was 70' for Unit 1 and 55' for Unit 2 measured in the hot leg. 21

3. Operators for both units indicated that natural circulation was obtained easily and within fifteen minutes after the loss of forced flow. 4 The momentary loss of emergency feedwater for Unit 2 occurred after natural circulation was established but appeared to have no adverse effect on the system response. 5. Since the atmospheric dump valves were inoperable for Unit 2, the steam pressure remained relatively constant after the initial open-ing of the steam safety valves, primary system pressure was controlled by the pressurizer auxiliary scrays. 6. After offsite power was restored, the reactor coolant pumos for Unit 2 were started about two hours before Unit 1. Since Unit 1 was also stable on natural circulation, there was no urpency to restart the cumps for either unit. Additional time was needed to check-out the startup transformer to verify its operability before starting the Unit 1 pumps. 7. The Unit I cuench tank rupture disc did not ructure during the vent-ing of the ERV. No abnormal increases in radioactivity levels oc-curred for either unit during the transient. 8. Water hammer vibrations in the main feedwater system 3Dpeared to be more severe for Unit 2 than Unit 1. The Unit 2 condensate pumps were started in a timely fashion to eliminate these effects. 22

4.0 RECOMMENDATIONS 1. The design arrangement and operation of the bus tie autotransformer should be considered and reviewed by the licensee and NRC to deter-mine possible failure modes and minimize the probability of losing off site power. A single failure (loss of bus tie autotransformer) in the offsite power supply system should not result in a two unit upset and a need for the onsite emergency power system. In this regard, the implementation of GDC 17 should be reevaluated. In the past, GDC 17 has not been implemented to require the offsite power source to meet the single failure criterion. 2. An IE information Notice has been issued concerning the loss of the emergency feedwater system due to simultaneous alignment to the Startup and Slowdown Deminerali:er System and the condensate storage tank. Al-though not included in this notice, each licensee should be requested to describe the modes of operation of the emergency feedwater system and other safety related systems for non-emergency conditions including operation at low reactor power and refueling. The acceptability of simultaneous alignment below some specified power level for these systems (e.g., 5% full power) should be evaluated by NRR. I 3. The safety implications of overfeeding and overcooling the pressuri:er with the HPI for BA'4 plants should be evaluated. Sustained operation of the HPI results in limited pressure control and possible loss of the pressuri:er steam bubble. There is also an increased probability of a stuck open relief valve. In addition, the system is subjected to an 23

additional thermal stress cycle. The licensees should be advised against sustained operation of the HPI system after the system pressure has been recovered and adeouate subcooling exists. 4. Licensees should be advised of the failure of the high pressure injection system isolation valve due to a stuck hand wheel engage lever, carticularly if this oroblem has been experienced else-where. It should be emphasized that all safety-related valves should be tested from the control room after the valves have been manually operated (e.g., during maintenance). 5. Action should be initiated to develoo recordkeeping recuirements or perhaps a Regulatory Guide to address the need for adequate and accurate operator log entries during normal and transient operation, especially when the process computer is unavailable. This informa-tion is required for post-event analysis. 6. Licensees should be advised of the need to ensure that plant response data and information developed immediately prior to and during a tran-sient is appropriately retained. The licensee should ensure that any selector or mode switch, if provided for the process or trend computers, is always in the position which ensures that the computer is available during a loss-of-offsite power event. 7. There have been repeated problems with the Unit 2 turbine-driven emeroency feedwater train which have rendered it inoperable (LERs 50-368/80 40, 36, 24

30, 22, 79-35, 79-72, 79-81, 79-104). This results in only one full-capacity, notor-driven emergency feedwater train available to provide the safety function of providing emergency feedwater to both steam genera to rs. It is important to ensure the reliability of the notor-driven energency feedwater train until the problems with the turbine-I driven train are resolved. Resolution of the problems with the turbine-driven trairi should be expedited, and until full resolution has been achieved, interim licensee actions should be implemented to ensure high 5 reliability of the motor-driven emergency feedwater train.

8. 'PromDt 'and careful consideration should be given by NRR to the develop-ment of suitable criteria to be used by reactor operators to determine and thereby claim that natural circulation has been achieved. This is a pctentially serious area for misinterpretation or misunderstanding during an event wherein it may be important to quickly communicate the plant status to the NRC in unambiguous terms. Operator academic instruc-j tions and training programs should specifically address these criteria l

and assure that the ocerators have a complete understanding regarding i how natural circulation can be determined. I f I l I I l l 25 i

FOOTNOTES 1. Letter, R. Reid (NRC) to Arkansas Power and Light Company, ATTN: W. Cavanaugh, III, ORDER FOR MODIFICATION OF DOCKET 50-313, License dated October 27, 1978. This order resulted in the manually locking gout of ST-2 to both Units and sequencing safety loads to the startup trans fo rmers. 2. Summary of Meetine For Arkansas Nuclear One and the Incident of September

16. 1978 Regarding Overload Conditions on Startuo Transformer No. 2 and the Consecuent Unit 2 Containment Soray, Leon B. Engle (NRR), dated February 9,1979.

The " Millstone Fix" which provides a second level of undervoltage tric has been implemented for Unit 2. This modification provides an under-voltage trip (about 92% of normal) in addition to loss of power trip (about 60%). This modification has not been implemented on Unit 1. The Millstone fix is not considered pertinent to GDC 17 requirement for indeoendence between the two recuired offsite power circuits, but facilitates GDC 17 recuirements for independence between the offsite and onsite oower supplies. 3. Ennancement of Onsite Emergency Diesel Generator Reliability, NUREG-CR-0660, February 1979. 1 j a. A lack of operator confidence on how to verify natural circulation occurred at St. Lucie on June 11, 1980. After the loss of comoonent cooling water, 26

the reactor coolant pumps were tripped. As the hot leg temperature be-gan to increase, the operator " bumped" a reactor coolant pump to enhance natural circulation. The increase in hot leg temperature was actually normal and predicted to occur by Combustion Engineering for the loss of forced flow transient. The event at St. Lucie is the subject of another AE00 case study and the results will be reported separately. The lack of well-defined criteria for natural circulation is further evidenced by the response of a Senior Reactor Operator at Indian Point. Unit 2, when asked how he knew the unit had achieved natural circulation after a loss of offsite power. He replied, "the hot leg temperature response was the same as displayed on the simulator for loss of offsite power transient." Westinghouse has, however, provided criteria to the Westinghouse Owners' Group for natural circulation. The criteria or conditions are as follows: 1. Cold leg temperature approaching no-load steam temperature (approximately 547'F). 2. Reactor coolant pressure more than 2000 psig. 3. Pressurizer level higher than normal level for no-load conditions. 4 The average thermocouple read.ings or hot leg temperatures less than 600*F. 5. Maintain normal make-up and letdown flow to the reactor coolant system. 27

5. Subsequent to the transient, Unit 2 chose to run the turbine-driven emergency feedwater pump continuously to meet operability requirements. When tested, the turbine would trip on overseeed. During a subsequent loss of offsite power transient on June 24, 1980, the Unit 1 turbine tripped on overspeed (PNO-IV-80-23). The motor-driven pump performed as recuired. The turbine and governor for Unit 1 are of the same type as for Unit 2. 28

8158 1458 11. ^ ^ - Itsy I love r Smi t ti 5102 5122 i m m 5:30 5118 ) 5148 m m Ta lini t 2 - -' ] F Generator l To Unit 1 5129 5112 Generator 5134 Sil4 o n l 5106 ( Russelville East 5 10 5126 )2512 n n m Mabelvale 1212 1205 A n-500 KV n 5951 System Aut ot rans for-r kj!. 161 KV System 1285 1218 )126 )125 m n l )1220 8812) l To Startup #1 (ST-1) Horritton East Unit ~- ^^ Auxiliary ~ ^ Startup Startup #2 g I_ ANO-2 13 (58-3) ANO-1 (Si-2) FIGURE I ANO Switcliyard

8 b%b I I.

a

!i n' l ) ( _) x 2 d. j [ e ~ p I l 2 3 3 g n ('3 6 ^ i s \\ j' .q e I Is f2i .3!

:s.

A I ' I g3 i 15 2 :2 L* I i. s i ll L. e)!! r ( 1: i L h C, 4 a h a 30

Table 1 Secuence of Events for Unit 1. April 7,1980 Time (aceroximate) Event 1709 Started diesel generator number 1.* 1728 Lost 500 KV to Ft. Smith. 1825 Lost 500 KV to Mabelvale. 1848 Lost 500 KY to Mayflower. Lost 161 KV to Russelville. Main generator tripped, auto-transfer from unit auxiliary transformer to startuo transformer ST-1. Reactor tripped due to de-energized control rod drive motors. Main steam line safety valves opened. Diesel generator No.1 energized bus A3. Diesel generator No. 2 started and energized bus A4. Lost process computer (SEL) and trend computer (NOVA). Momentarily (14 sec) lost NNI Y-bus. Manually actuated HP!; Valve CV-1227 failed to open. Main steam line safety valves opened. . Service water pumps started. 1850 TDEFW Pumo A running. i -"anual Oceration. 3) L i

Time (aporeximate) Event 1852 EFW Pump B running. 1854 Throttled HP1 flow.* 1858 SG level at 50%. Manual control of AFW flow. 1900 Shift supervisor indicated natural circulation established. 1903 Opened pressurizer (PIR) relief block val ve.* Opened PZR electromatic relief valve (ERY).* Cycled ERY approximately 5 times during 10 minute interval.* Opened atmospheric relief valves.* 1906-1918 Controlled System pressure by alternating between feeding and dumping steam genera to rs.* 1909 Steam admission valves for TDAFW pump failed to fully close. 1910 Closed diconnect bypass to ST-2.* 1924 PZR level offscale high. Cycled pressurizer ERY to determine if system was solid.* ( 1933 Started pressure reduction to increase saturation conditions in pressurizer after cooldown due to HPI.* Re-established system control using pres suri zer.* 1948 Secured HPI.* l l 1950 Steam dumo to condenser.* I -Manual Operation. 32 1

Time (acoroximate) Event 1958 Tried to secure TDAFW pump P7A.* 2108 Started RCP "C".* 2117 Started RCP "A".* 2127 Bus H2 energized on ST-2, Bus A2 energized off ST-2.* 2131 Started RCP "D".* 2142 Energized ST-1.* 2159 Bus H1 switched to ST-2.* 2200 Work order to repair CV-2617 and 2667 authorized.' 2204 RCP "D" tripped on undervoltage. 2211 Opened breaktrs.85112 and 5134 due to voltage dropping.* 2252 Restarted RCP "D".* 2306 Secured TDAFW pump P7A.* 2354 Diesel generators secured.* j April 8 0130 Determined HPI isolation valve CV-1227 l manual engage lever stuck in engage

position, performed stroke test after disengaging.*

0148 Performed stroke tests on steam admission valves af ter replacing toroue switch on both valves.* Note: Peactor coolant pump "B" was also started, but no record appeared

i. either the operator's log or the Shift Technical Advisor sequence of events.

-Manual Operation. 33

Table 2 Seouence of Events for Unit 2, April 7,1980 Time (approximate) Event 1728 Lost 500 KV to Ft. Smith. 1825 Lost 500 KV to Mabelvale. 1836 Commenced 200 MWE load reduction.* 1848+ Lost 500 KV to Mayflower. Reactor tripped on low DNBR (probably). Steamline safety valves opened. Generator breakers opened. Turbine tripped. Auto-transfer to ST-3 from auxiliary transformer. Both diesel generators started and loaded buses 2A3 and 2A4. Service water pumos started. Emergency FW pump started. Lost process computer (SEL). 1849 Three charging pumps operating. Isolated letdown line.* 1855 Throttled EFW flow.* 1900 Lost suction to EFW pumps 2P7A and 2P7B. (Duration believed to be less than one minute). Isolated Startup and Blowdown Demineralizer Suction to EFW Pumps.* 1906 Commenced auxiliary spray to control pressure.' 'Manuai Operation. 34 L

Time (acoroximate) Event 1910 Bus 2A2 energized by ST-2.* ST-3 still de-energized. 1920 Started "B" condensate pump to reduce water hammer effects.* Started both instrument air compressors.* 1925+ TDEF'd pump 2P7A secured, EPd pumo 2P7B started.* Mechanics inspected 2P7A for noise believed to be bearing problem. 1930 EFW 2P7A returned to service, EPW 2P7B secured.' 2000 Started "A" circulating water pump.* 2007 Started RCP "A".* 2100 Shifted to ST-3.* 2105 Secured both diesel generators.* 2125 Started RCP "B".* 2140 Started RCP "C".* RCPs "B" and "C" tripped due to undervoltage. 2150 Restarted RCP "B".* 2225 Restarted RCP "C".* 2247 Started RCP "0".* RCPs "B" and "C" tripped due to undervoltage. April 8 0100+ Management decision to shutdown to perfom maintenance on equipment (not related to transient). " Manual Operation. 35

f l APPitIDICES f. f i l 36

I$. age 1 of 5 APPENDIX A Unit 1 - Transient Report { UNIT TRANSIENT REPORT Report No. I 80 01 unit year numoer Date/ Time of Transient ~4n/so / 1848 A. TRANSIENT DESCRIPTION The unit trip was caused by the loss of.all off site power. (see attached sheet). ~ ~ ' ,4 0 ~ 1 i I Prepared By:.: A[jf _/ Ne Date: # <-/Er> Reviewed DyI M'N 7 bi, Date:

Plant Perf orrapce Supervisor Reviewed By:

beo bMb e Date: If b 1 t Analysis Super encent Reviewed By: /4r 8 dC Date: Y/ O Manager ojr0perations & Maintenance k u

4 TRANSIENT DESCRIPTION On April 7, 1980, at 1655 hours, the operators were notified by the system dispatcher that there was a tornado warning for Yell County. At 1709 hours, the Number One Diesel Generator was started per Emergency Procedure 1202.44, Section II. At 1728 hours, the 500 EVA line to Ft. Smith was lost and 57 . minutes later the 500 KVA line to Mabelvale followed. Reactor power was at 100%. At 1848 hours, the Generator tripped and immediately the Reactor tripped. The unit trip was caused by the loss of all off site power. Due to the initial spike of the RCS pressure, it is believed that the Generator tripped first on an electrical fault signal with the Reactor trip following. Immediately the Diesel Generators performed their design function of auto-matica11y supplying power to buses A3 & A4 During this time, operators manually initiated High Pressure Injection in order to recover the degradation in primary pressure. High Pressure Injection flow was obtained with P-36A & P-36C through three out of the four possible flow paths. Because CV-1227 (High Pressure Injection Isolation Valve on Loop B) did not open, one of the flow paths was not available. After the initial spike in RCS pressure, immediately the pressure dropped to 1860 psi. This was due to the' drop in secondary pressure & the injection of Emergency Teedwater to the OTSGS. T dropped to 567'F and then increased g about 6' in about 5 minutes. Then T Uegan to decrease. This increase and subsequentdecreasecorrespondstot5eReactorCoolantPumpcoastdownand natural circulation being established. Over the next 30 minutes there was some oscillation on T due to changes in secondary pressure from Emergency H Feedwater injection and steam dumping. Since High Pressure In}ection was initiated, RCS pressure and pressurizer level recovered and went high. " For approximately the next 45 minutes, pressure was controlled by High Pressure Injection, Pressurizer Heaters, and Reactor Coolant being manually relieved to the quench tank through CV-1000. During this time, margin to saturation went high and remained well above the desired 50*. At 1900 hours, the operators verified that natural circulation was established. Two minutes later, Bus Al was put on Startup Transformer #2. Later Bus B2 was tied to B1 and B3 tied to B4. At 2354 hours, the Diesel Generators were secured. The final plant condition was Hot Standby with T at 537'T and gyg RCS pressure at 2150 psi. 33

8 Page 2 of 5 B. INITIAL PLANT CONDITIONS { 1. Reactor at 100 power 2.

1 Diesel Generator running

( C. OPERATING PERSONNEL ON DUTY SHIFT SUPERVISOR: Bill Moon PLANT OPERATOR: Rov Cachart ASST. PLANT CPERATOR: Dan s=ith MSTE CONTROL OPERATOR: steve cunnine AUXILIARY OPERATORS: 1.ar-v Mecee OTHERS: shire Technical Advisor Don Brown k n 1 m u-, + - - - - - na

s e i Page 3 of 5 { D. INITIATIf1G EVENT Loss of all off site power t i a E. SIGNIGICANT AUT01ATIC COMPONENT STARTS /ST005 (1) Nu=ber 2 Diesel Generator starts (2) Diesel Generators tie,on,to A3 & A4 (3) P7-A & P7-B C t i l F. SIGNIFICANT MAtlUAL ACTIONS TAKEN (1) Manual initiation of Righ Pressure Injection (2) ERV operation to Quench Tank (3) Placed Al on Startup #2 (I.) Stop P7-A & P7-3 i l 40 l t i

Page 4 of 5 G. SEQUENCE OF SIGNIFICANT ACTIONS, EVENTS { See Transient Description & the attached copy of the Station tog & the STA Log. ~' H. FINAL PLANT C0t:DITI0t:5 Hot Shutdcwn conditions T ;.g 537'T g KCS Pressure 2150 A, C. & D RCP operating 41

i 1 Page 5 of 5 { I. PROCEDURAL PROBLEMS OR HUMAN ERRORS None ~. J. EQUIPMENT MALFUNCTIONS CV-1227 (EPI Isolation Valve Loop B) failed to open due to manual engage lever-being stuck in Engaged position. (See LER No. 80-13) SEL cc=puter & NOVA compute'r fliled because of the less of power. Power j was not picked up by the computer because the inverter was selected to alternate power. K. COMBINED PLOTS OF PERTINENT PRIMARY / SECONDARY PARAMETERS Due to the loss of the computers, the Plant Monitoring System was not available for data retrieval. For the response of some primary / secondary parameters see the attached charts. k 42

..\\ " g 3 APPENDIX B Page 1 of 5 Unit 2 - Transient Report ( UNIT TRANSIENT REPORT D Report No. 2 so g3 unit year numoer Date/ Time of Transient 4-7-80 / iss7 s TRANSIENT DESCRIPTION A. The unit was at approx. 1002 power when two 500KV transr.ission lines were lost due to wather conditions. The dispatcher called and asked that the unit drop off approx. 200 5'E. During thc' process of power reduction (approx. 98.02 Power) off site power was lost. The Reactor probably tripped on loss of power to the CEDM system. Exact cause of Reactor trip could not be deter =ined due to the plant computer losing power and failing, to log the alarms and SOE's. The 2Hl. 2H2, 2A1, 2A2 buses were lost, therefore, all con-densate pumps, drain pumps., cire. pu=ps, RCP's, vacuum pu=ps, and other non-vital loads were without power. Both 2DG 01 and 2 auto started and supplied power to 2A3 and 2A4. "A" "B" service water pumps were. started. Natural circulation was estab-lished with 2P7A and 2P7B feeding the S/G's. Apprcximately 15 minutes af ter Reactor Trip, EWP's 2P7A & 2P7B lost suction (See LER 80-018). C Loss of EL*P suction was due to the feed suction flashing. The En?'s were taking suction from the start-up and blowdown effluent and the CST's. The SU & BD effluent was what flashed. Operators immediately isolated suction from 2!94A/B and all suction was taken faom the CST's. Loss of feed duration was apprcxi=ately 30 seconds.g Later 2P7A was turned off to control RCS cooldown. Approximately :4 minutes af ter less of offsite power S/U transfor:er #2 was energi:ed by Unit 2 to start "B" condensate pump and "A" cire pump. Af ter being on natural circulation for approx. I hour "A" RCP was started. Later the Unit 2 loads were transferred from S/U #2 to S/U #3. 2P7A was started to feed the S/G's and 2P7B was turned off for the mechanics to inspect possible problems with the inboard bearing race. Mechanics said there was no proble= that would affect the operablility of the pump. 2P7B was returned to operation and 2P7A operation was terminated. Both diesel generators were b/ uk.o4/ecured and g" " RCP was started. En11e atte=pt-Da te: W-T-N Prepared By: Reviewed By: [Y /\\ Date: O/MA' Plant Performante Supervisor Reviewed Dy: w tJ b Date: 17 0 P g Analysis Superintancent Reviewed By: [- Date: N Manager ofj0perat1ons & Maintenance s eh

)- i ing to start the third RCP, undervoltage relays tripped off the operating RCP "3". The final plant ' condition was "A" & "D" RCP running, "B" con-densate pump running "A" cire. water pump on, "A" & "B" service water pumps running. The next day a decision was made to go to mode 5 oper-l ation and repair small problems associated with the RCS. This was at an opportune time due to loss of transmission capability to support 100% power operation. i 1 e I l l } 4 I l I i ?.4 i i i

a Page 2 of 5 { B. INITIAL PLANT CONDITIONS

1) 98 : FP

2) 2CV-0302, 0305, 0306 Isolated

3) Two 500 KV lines inoperable due to weather conditions.

4) Power reduction in progress per request by dispatcher (drop off approx. 200 Mwe).

A ~ C. OPERATING PERSONf;EL ON DUTY SHIFT SUPERVISOR: r e+ Tavle-u PLANT GERATOR: ._1, ev T.+.. ASST. PLANT OPERATOR: se n +v n MSTE CONTROL OPERATOR: e=nd,u.-41+,e i AUXILIARY OPERATORS: c,,+ - w eees OTHERS: 's

o a i Page 3 of 5 i. i i D. INITIATING EVENT { loss of offsite power (100% load rejection) l ') 4 1 i E. SIGNIGICANT AUTOtATIC C0ftPONENT STARTS / STOPS

1) all components powered from 2H1, 2H2, 2A1 & 2A2 were stopped.

2) Diesel generaters started (2DG1 & 2DG2) c i

3) 2P7A & 2P7B started

(

4) "A"

& "B" Service water pumps auto started. I j F. SIGNIFICANT MANUAL. ACTIONS TAKEN t

1) Stopped 2P7A

2) Started "B" condensate pump

3) Started "A" & "D" RCP's.

4) Started "A" Cire, pump.

l

5) Isolate S/U Blowdown de=in. suction to EW pumps.

i 46 I

{ Page 4 of 5 { G. SEQUENCE OF SIGNIFICANT ACTIONS, EVENTS See Section A and hand written SOE. Also,~see Unit 1 Transient ' Report 1-80-01. 4 a I i i ( 1 e i H. FIHAL PLANT CONDITIONS "A" & "D" RCP's running P7B on "B" Cond. Pump On "A" Cire. Pump on RCS temp and Press nonnal for Mode 3 eperation (The next day the unit went to mode 5 operation.) i A 47

Page 5 of 5 { PROCEDURAL PROBLEMS OR HUMAN ERRORS None J. EQUIPMENT MALFUNCTIONS computer failed. Most precable cause was that the computer was being powered from the alternate At power source prior to the transient. When offsite i power was lost there is not aut0 xfer to battery power from the alternate AC power sourca. ( Loss of suction to 2P7A and 2P7B. K. CCMBINED PLOTS OF PERTINENT PRIMARY / SECONDARY PARAMETERS i See attached strip charts. Note: The computer printouts were not available due to loss of plant computer. A combined Unit 1 & Unit 2 hand writtem SOE is attached. i 48

APPENDIX C D.R. Brown 22:10 shift Technical Advisor tog 4 7.go SHIIT TECHNICAL ADVISOR LOG

i Tornado Warning Received From Pine Bluff for Yell County Until 5:45

<>(Primarily applicable to Unit 1) t 17:28:36 Lost 500 KVA to Ft. Smith B05106, B#5102 ' 18:25 Lost 500 KVA to Mabelvale B05110 18:33 Bad lightning strike on system 18:36 Dispatcher asked for 200 Mw load drop on Unit #2 18:45 Power reduction begun on Unit d2 18:48:00 ., Both units trip - loss of offsite power - degraded power lost computers - both units with diesel running from tornado warning 18:52 "B" EFW Pump running 18:54 On diesel power only EPI initiated manually on Unit 1 18:56 Both units seem to be under control 18:58 Throttling SG's @ 50% EPI. Unit 1 18:59 Unit'*1 i 19:00 Both units indicating natural circulation 19:02 Al on SU #2 Unit 1 19:05 aT at 46' Unit 1 19:09 Closing main steam valves - still open (refers to P7A steam inlet valves) 19:11 Quench tank @80% Unit 1 19:12 Getting off BWST i 19:20 Closing P2A discharge valve 19:24 Stable offsite power confirmed restored 19:27 Starting condensate pump 2P (need EFW) 19:32:16 Main turbine still turning 19:33:30 Transfer to atmospheric dumps Rx pressure dropping 19:34:16 EPI flow manually increased 19:35 Generator is LA). trip SU #1 is (0.- no flags in back 19:36:33 Condensate pump started 19:37 Throttle HPI 19:38 P:r. level high - coming down 19:40 SU #1 inspection in progress 19:40:33 B2 tied to B1 19:43 SG's @ 60% 19:44 Margin to saturation estimated at minimum 70* 19:46 SU #1 visually inspected, status questionable 19:50 Check MS4 A&B, opened same 19:48 EPI off SG's @ 50% 19:51 Main turbine wurning gear on manual 19:52 Main turbine on turning gear confirmed 19:54 P r. level coming down 49

Shift Techhical Advisor Log Page 2 Unit #2 attempting to start "A" Cire. H O - failed 2 19:58 Trying to operate W block valves 20:01 Securing steam EW pump P7A 20:02 Unit #2 starting RCP 20:04 Rearmed ERV Monitor Audio Alare 20:06 Attempted "B" Cire. H.,0 Puisp start - failed 20:08 Placed in Pull to loca

20:09 "A" Circulating H O pump started 2

20:10 Closing bypass to DI's 20:14 Sat. margin @ ~ 80' 20:18 Condenser spray open 20:18:45 "A" Main Chiller on ~ condenser #1 vacuum 25" #2 vacuum 28" 20:21 Increased auxiliary b1dg. activity noted 20:24 Operators comment that all emergency systems have operated ok 20:25 Put W pumps on turning gear 20:28 B3 & B4 load centers tied together 20:30 Closing atmospheric dumps 2676 & 2619 l 20:32 H. Miller confirmed SU #1 visually OK 20:38 SU #3 investigation started 20:50 Hit resets on."JW block valves 21:06 H1 energized 21:06 RCP 'C' oil pumps started 21:08:45 RCP "C" started OK 21:14 RCP "A" oil pumps started 21:17 RCP "A" started OK 21:18 Attempting to close W block valves 21:19 Closed W blocks 21:22 BRK's closed 1205,1218,1215, 5122 & Unit 2 indicates #126 closed 21:25 Unit #2 starting 2nd RCP 21:27 H2 energized off SU #2 on 2nd attempt l 21:27:30 A2 energized off SU #2 21:30 Preparing to energize SU #1 21:31 Start "D" RCP oil pumps 21:33 Started "D" RCP l 21:34 (0,on SU #1 cleared by Pine Bluff 21:40 Fine Bluff attempting to close 125 - Admin. Bldg. on normal l lighting i Security Diesel secured 21:41 Unit #2 starting 3rd RCP 21:42 125 elosed by Pine Bluff 21:43 X-fring to SU #1 (H1 & H2) Xfr'd off SU #2 (Al & A2) 21:52 Unit #2 starting RCP 21:58 All inverters OK 21:59 H1 switched to SU #2 22:04 "D" RCP stopped 22:05 Hi-line voltage dropping 22:11 MOD's open 05112 & 5134 22:12 Boron @ 750 @ 2202 hrs. 50

.. _ ~. - i t I I I 'f I l i Shift Technical Advisor Log Page 3 22:12:30 SU boiler on 22:17 Boiler lined up to reject header 22:27 Unit 2 attempting RCP start 22:29 Main turbine on T. Gear & Lo pumps stopped 22:32 Au T Generator lift pumps stopped r 22:52 "D" RCP started - restart difficult 22:53 SU boiler problems 23:06 Stopped P7A

23:17 T

'..L 1 to system on diesels s p cAnsel t I i a, 4 i k i I j i l l J l i a 51

8 *. i ~ r ') \\ .0 = APPENDIX o Unit 1-Log Entries rueer ssper.aos --. p's,./c., C_-e-sto,'s., ~ o z,,_-,,., - -... -. p..s. s.m. #Es.,,. > -/ 'os e, uve'

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= e '---~ o APPEr$1X E Unit 2 - Log Entries j DATE 7 2 ( CREW _E $HIFT 8 *)'/ _ _. _.OPIP.ATivG !'07Id POWER L!V~L. ". F. P. __ C RCS LIAKAG", CPM /*27 RC5 EORON CONC.. PPM l'A b A1. TILT MAX.. f / IIASI, M AX.* d M i S/D MA2GlN, f. OK/K 2 7, @c CIA POSITIONS, GP.6O PLCEA'S O FINAL SHIFT ETPD kV I( ?9--} t///~i~.C D J'o."Qc'e.5on..yAt~.uo e /us.,/* s.? u..A e e ie c, l 7.22 D ).C 2.. A. D' O. (r -4' A i/W. 6~< t.:. 7~<u.s/ e A 1.?2.1. $JlC HL.e As'c= '.2stips* f.0. / .] L e**usCa.c1.0 _,rlL.b.ic.sivc /.4<<<)- :c. 2 ee s~r10.c'.-- - 1.?.Y 7-8 LA.C.K.G uT SM.Ct C.Cuc.V !)s.t's ctg rs<t,- ss), J l V 'lE J/ LA UT.Lc' 0 svs1._: _s,.n11L. C.)it l' ut A 7tuu L A 6/* G A J~.t D J n ts4.odns' C /J.c.,~sc w t e +' e A 22.C2.C l* h z:L~L.5 -s'.t.u'st./nt tL 3 t.d.</ s2 usti'.S / 1.9.f5~ !.N.f.cs.r1 c' 0 //*.A.C.- /.t' 41efiv 7 W ts* ~

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0 APPIMDIX F Uni

1 - Trend T<ecorder Charts STANDING CRDER No. 45 Page 1 of 1 ATTACHMENT A UNIT ONE TRANSIENT DATA COLLECTION Collect the following information and assemble in a package:

1. Computer alarm printouts for a sufficient period before and after the transient to include all pertinent information. 2. Post Trip Review Printout from computer (Reactor Trip Inter-cepts closed or Generator Output Breakers open). 3. Copy of pertinent pages from the Station Log. 4. Sequence of Events Printout from computer,(if available) 5. Any applicable computer group trends or ;rtn.' recordet t. harts running during transient. 6. Plant Monitor (FM) (Reactor or Turbine Trip). NOTE Retrieving the PM data should be accomplished by the Computer Support Group. Notify one of these personnel within 2 hours after a reactor or turbine trio. RECORDER CHARTS 7. Cut out and remove that portion of the following recorder charts and any other charts containing pertinent data during the transient. Tape the chart paper,t,oa. ether and label chart paper lef t on the re-corder with time, date, reason for removing data and initials. Label the extracted chart paper with recorder number or chart description. (. Recorder Number Description FR-1022* ' RCS. Loo A Vide Range Pressure 4R-1038 - RCS Loop B Narrow Range Pressure 4 -1011 Ma rgid-Q SaturTeion /LR-1000 Pressurizer Level .h I- <TR-1023 ' RCS Temperature T TR-1024 Not IN 6 M G7%LC#624-Y RCS Temperature h ! -2632 Feedwater' Flow Loop A FR 4R-2682 Feedwater Flow Loop B d-2659 OTSG Level A LR-2609 OTSG Level B j 4R-6677* in Steam Pressure l PR-2634 .3G Generated Megawatts ne Header Pressure '<No Number

If narrow range recorder stays on range throughout the transient, it is not necessary to collect the narrow range chart.

COLLECTED BY'M h DATE/ TIME REVIEVED B / ' / !N <*.S ' ' SHIFT SUPERVISOR .DATE, /' NOTE: Attach a written narrative containing all information required in section 2.4 of the Standing Order. Make a copy for the Control Room and route the original to the Plant Perfor=ance Supervisor for cocpletion of the Transient Report. Revision 0 Standing Order No. 45 Februar7 7,1980 sd

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APPENDIX G Uni 6 f. - Trend Recorder Charts STANDING ORDER No. 45 Page 1 of 1 ATTACHMENT B UNIT TWO TRANSIENT DATA COLLECTION Collect the following information and assemble in a package: 1. Computer alarm printcuts for a Eufficient period before and af ter the transient to include all pertinent information. 2. Post Trip Review Printout from computer (Reactor Trip only). 3. Copy of pertinent pages from the Station Log. 4. Sequence of Events Printout from computer (if available) 5. Any' applicable computer group trends or trend recorder charts running during transient. RECORDER CHARTS 6. Cut out and remove that portion of the following recorder charts and any other charts containing pertinent data during the transient. Tape the chart paper together and label chart paper left on the re-corder with time, date, reason for removing data, and initials. Label the extracted chart paper with recorder number. Recorder Number Description 2PR-4624* Pressurizer Pressure Vide Range 2PR-4626 Pressuri:er Pressure Narrow Range 2TR-4c15/4715 .t Margin to Saturation LR-4628 Pressurizer Level .2 R-4615/4715 RCS Wide Range Temperature T ( C 2TR-4614/4714 RCS Narrow Range Temperature TH 2FR-1029/1030 2E24A Feedwater/ Steam Flow 2FR-1129/ll30 2E2tB Feedwater/Stest Flos 2LR-1031 SG 2E24A/B Narrow Range Level-2LR-1079* SG 2E24A/B Wide Range Level 2PR-0200* Main Steam Pressure to HP Turbine 2IR-9624 Net & Gross Generated Megawatts 2PR-1041 SG2E24A/B Pressure

If narrow range recorder stays on range throughout the transient, it is not necessary to collect the carrow range chart.

COLLECTED BY_ b. $ M v s.4. /2d4dDATE/ TIME / y RE\\~IE'ED BY M. [o 5 C.__. P/d~fb SHIFT Si;PERVISdR DATE NOTE: Attach a writ *.en narrative contain'ing all infermation. required in section 2.4 of the Standing Order. Make, a ecpy for the Control Room and route the original to ( the Plant Performance Supervisor for completion of the ( Transient Report. Revision 0 Standing Order No. 45 February 7, 19S0 61

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ML20050Y406

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