Text

Rev 1 to North Anna Unit 1 870715 Steam Generator Tube Rupture Event Rept
	ML20238F616
Person / Time
Site:	North Anna
Issue date:	09/15/1987
From:	; VIRGINIA POWER (VIRGINIA ELECTRIC & POWER CO.)
To:	;
Shared Package
ML20238F607	List: ML20238F605; ML20238F616;
References
	NUDOCS 8709160244
	Download: ML20238F616 (237)
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North Anna Unit 1 July 15,1.987 Steam Generator Tube Rupture Event Report.

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\ NORTH ANNA UNIT 1 JULY 15, 1987 STEAM GENERATOR TUBE RUPTURE EVDIT REPORT TABLE OF CONTENTS CHAPTER PAGE I. EXECUTIVE

SUMMARY

A. Purpose 7

B. Brief Description of North Anna Power Station 7 C. Overview of Event 8 D. Virginia Electric and Power Company and NRC 9

Response

II. DESCRIPTION OF EVENT A. Introduction 13 B. Conditions Prior to the Event 13 C. Event Description and Analysis 14 D. Operational Analysis 17 E. Procedure Utilization and Analysis 18 III. RADIOLOGICAL EFFECTS OF EVENT A. Summary 33 B. Evaluation of Radiological Release 33 IV. EMERGENCY RESPONSE A. Emergency Plan Implementation 43 B. Emergency Response Computer System 46 V. SAFETY EVALUATION A. Comparison of North Anna Unit 1 Tube Rupture Event 48 to UFSAR Analysis B. Fuel Integrity Evaluation 48 C. Conclusions 49

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NORTH ANNA UNIT 1 JULY 15, 1987 STEAM GENERATOR 'IVBE RUPTURE EVENT REPORT TABLE OF CONTENTS CHAPTER PAGE VI STEAM GENERATOR EVALUATION A. North Anna Steam Generator Operating Experience 53 B. Failed Tube Identification, Examination 55 and Removal C. Failed Tube Evaluation 57 D. Steam Generator Inspection 68 E. Steam Generator Repairs and Modifications 72 VII. BASIS FOR RETURN TO SERVICE ,

A. Downcomer Flow Resistance Plate 92 B. Remove Susceptible Row 9, 10, and 11 Tubes from Service 92 C. Improved Monitoring of Primary-to-Secondary Leakage 92 D. Plug Confirmed Eddy Current Indications 94 E. Stabilize and Plug Failed Tube 94 F. Plug Neighbor Tubes to Failed Tube 94 .

VIII. LESSONS LEARNED A. Corrective Actions 95 B. Enhancements 100 C. Good Practices 102 IX. CONCLUSIONS 104 l

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.s LIST OF FIGURES FIGURE NUMBER DESCRIPTION I-1 Recovery Organization 1-2 Nuclear Steam Supply System I-3 Westinghouse Series 51 Steam Generator II-1 Pressurizer Level 11-2 Reactor Coolant Pressure (Loop A)

II-3 Reactor Coolant Temperature (Loop A)

II-4 Steam Generator "C" Level II-5 Steam Generator "C" Pressure II-6 "A", "B" and "C" Steam Generator Levels II-7 North Anna Unit 1 Power History Prior to Event II-8 On-line Chemistry Monitoring System Data V-1 Reactor Core Safety Limits and State .

Point Prior to Trip VI-1 Map of Plugged Tubes - Steam Generator ngn VI-2 Map of Plugged Tubes - Steam Generator "B"

VI-3 Map of Plugged Tubes - Steam Generator "C"

VI-4 Linear Regression of Steam Generator

" Leak Before Break" Analysis

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LIST OF TABLES TABLE NUMBER TITLE II-1 North Anna Unit 1 Operating Conditions Prior to Steam Generator Tube Rupture II-2 Reactor Coolant System Leak Rate Prior to Tube Rupture Event II-3 Unit 1 Air Ejector Activity Prior to Tube Rupture Event III-l Calculated Release Activity From Condenser Air Ejector For Time Period From 0630 to 0756 Hours III-2 Calculated Noble Gas Release Activity From Steam Driven Auxiliary Feedwater Pump Exhaust For Time Period From 0636 to 0648 Hours III-3 Calculated Release Activity (Excluding Noble Gases) From Steam Driven Auxiliary Feedwater Pump Exhaust For Time Period From 0636 to 0648 Hours III-4 Calculated Release Activity from Steam Driven Auxiliary Feedwater Pump Exhaust For Time Period From 0648 to 0745 Hours III-5 Reactor Coolant Radiogas Concentrations and Corresponding Release Activities Based on Mass Balance Calculations III-6 Environmental Samples - 15 July 1987 V-1 North Anna Unit 1 Steam Generator Tube Rupture -

Comparison to UFSAR Accident Analysis V-2 North Anna Unit 1 Steam Generator Tube Rupture -

l COBRA /WRB-1 Point Estimate of Minimum DNBR VI-1 Steam Generator Tube Plugging By Indication Type During 1987 Refueling Outage VI-2 North Anna Unit 1 Tube Plugging Summary VI-3 Condenser Air Ejector Radiation Monitor Count Rate (cpm) as Recorded on Operator Logs Page 4

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JIST OF TABLES (Cont'd) l TABLE NUMBER TITLE p1 VI-4 Constant K for Leak Rate Calculation Sased on Air Ejector Count Rate .

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9 VI-5 Estimated Primary-to-Secondary Leak Rate (gpd) Based on Air Ejector Count Rate VI-6 Estimated Primary-to-Secondary Leak Rate (gpd) Based on Air Ejector Grab Samples VI-7 North Anna Unit'l - Steam Generator Tubes Inspected '

VI-8 North Anna Unit 1 - Tubes to be Removed from Service VI-9 Steam Generator Tubes Plugged by Indication Type During July, 1987 Outage i

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LIST OF ATTACHMENTS ATTACHMENT TI*,'LE >

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Chronology of Steam Generator Tube Rupture Event 2 Significant Operational and Maintenance Activities Prior to

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3 Sequence of Events - Health Physics 4 .Y.mergency Plan Chronology 5 Emergency Operating ProcM ure EP-0, Patetor Trip or Safety Injection 6 Emergency Operating Procedure EP-3 Steam Generator Tube Rupture '

7 Emergency Operat'ing Procedure ES-3.1, Post Steam Generator Tube Rupture Cooldown Using Backfill q

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I. EXECUTIVE

SUMMARY

A. Purpose This report provides a detailed description of the July 15, 1987 steam generator tube rupture event at North Anna Unit 1, and the ensuing evaluations and actions performed and planned by the Virginia Electric and Power Company (Virginia Power).

The detailed sequence of events including the response of the operators and key plant equipment is discussed in Chapter II. The radiological effects of the event are evaluated in Chapter III. An evaluatio: of the implementation of the Emergency Plan is discussed in Chapter IV. The safety consequences and significance of the event are discussed and evaluated in Chapter V. The cause of the steam generator tube failure and the actions taken to address the tube failure are discussed in Chapter VI, p.nd finally the lessons learned and .

i corrective actions taken or planned by Virginia Power as a result of the event are discussed in Chapter VII.

l B. Brief Description of North Anna Power Station i

l The North Anna Power Station is a two unit station owned jointly by Virginia Electric and Power Company and Old Dominion Electric Cooperative and operated by Virginia Electric and Power Company (Virginia Power). It is lecated on the southern shore of Lake Anna, in Louisa County, approximately 40 miles north of Richmond, Virginia. Each unit includes a three-loop pressurized water reactor nuclear steam supply system (Figure I-2) and turbine generator furnished by Westinghouse Electric Corporation. The balance of plant was designed and constructed by Virginia Power with the assistance of Stone and Webster Engineering Corporation. Each nuclear unit is licensed to operate at a core power of 2893 MW thermal.

Each unit has three Westinghouse Series 51 steam generators illustrated on Figure I-3. These Series 51 steam generators have 3388 tubes, 0.875 inch 0.D.

by 0.050 inch wall thickness. The tubing is Inconel 600 in the mill annealed condition. The tubes are hardrolled above the bottom of the tubesheet, and were explosively expanded prior to operation to eliminate the open annular crevice that remained within the tubesheet. Each steam generator has seven tube support plates which are carbon steel with drilled tube holes having a small clearance between the tube and support plate.

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Unit 1 achieved commercisi operation in June 1978 and has completed operation of its sixth fuel cycle. To date, Unit I has operated for approx-imately six effective full power years.

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1 C. Overview of Event At approximately 0635 hours0.00735 days 0.176 hours 0.00105 weeks 2.416175e-4 months on July 15, 1987, the North Anna Unit I reactor was manually tripped from 100% power due to indications of a steam generator tube rupture in the "C" steam generator. Approximately twenty seccnds later, the safety injection system automatically initiated from low reactor coolant system pressure (1765 psig).

At 0639 hours0.0074 days 0.178 hours 0.00106 weeks 2.431395e-4 months , a " Notification of Unusual Event" was declared following the reactor trip and safety injection and indications of a possible tube ;

rupture. Initial notifications to State and local governments were completed I by 0651 hours0.00753 days 0.181 hours 0.00108 weeks 2.477055e-4 months . By 0654 hours0.00757 days 0.182 hours 0.00108 weeks 2.48847e-4 months , the event was upgraded to an " Alert" classification at the direction of the interim Station Emergency Manager due to the preliminary estimates that primary-to-secondary leakage through the tube rupture exceeded 50 gpm. Notifications to the NRC and offsite agencies j that- were required as a result of the upgraded classification were completed by 0702 hours0.00813 days 0.195 hours 0.00116 weeks 2.67111e-4 months . All major plant equipment functioned properly, and the unit was stabilized in accordance with Station Emergency Operating Procedures. The Emergency Plan Implemetiting Procedures for an " Alert" classification were implemented to augment the on-shift staff. By 0747 hours0.00865 days 0.208 hours 0.00124 weeks 2.842335e-4 months , an accountability of all station personnel had been completed. By 0757 hours0.00876 days 0.21 hours 0.00125 weeks 2.880385e-4 months , the Technical Support Center and Operational Support Center were fully manned and activated.

The Corporate Emergency Response Center was activated ct 0820 and by 0915 hours0.0106 days 0.254 hours 0.00151 weeks 3.481575e-4 months , the Local Emergency Operations Facility was fully manned and activated.

The initial indications available to the operators were from the main steam line radiation monitors which went into alarm at approximately 0630 hours0.00729 days 0.175 hours 0.00104 weeks 2.39715e-4 months on July 15, 1987. Subsequently, pressurizer pressure and level began to decrease rapidly. Pressurizer pressure decreased (after the manual reactor trip) to approximately 1730 psig which is below the safety injection (SI) setpoint of 1765 psig. Pressurizer level decreased from its 100% power program level of approximately 65% to offscale low prior to recovery. The maximum primary to secondary leak rate has been estimated to be 550 to 637 gpm. The reestablishment of pressurizer level and isolation of the ruptured "C" steam generator was completed under Station Emergency Operating Procedures (EP-0, Reactor Trip or Safety Injection and EP-3, Steam Generator Tube Rupture Revision 1). EP-0 and EP-3 are included as Attachments 5 and 6.

Cooldown and depressurization of the Reactor Coolant System (RCS) was initiated at 0710 hours0.00822 days 0.197 hours 0.00117 weeks 2.70155e-4 months in accordance with Station Emergency Operating Procedure ES-3.1, Revision 1, Post Steam Generator Tube Rupture Cooldown Using Backfill, (Attachment 7) and proceeded routinely. At 1108 hours0.0128 days 0.308 hours 0.00183 weeks 4.21594e-4 months , the RCS was cooled down to below 350 degrees F and Unit I was placed in Mode 4, Hot Shutdown. At 1336 hours0.0155 days 0.371 hours 0.00221 weeks 5.08348e-4 months , the RCS was cooled down to less than 200 degrees F.

and the unit was placed in Mode 5, Cold Shutdown. Plant conditions were stable and the emergency was terminated at 1336 hours0.0155 days 0.371 hours 0.00221 weeks 5.08348e-4 months , at which time termination notifications were made to the NRC and offsite agencies.

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1 During the course of the event, effluents were releared from "C" steam generator prior to its isolation through the condenser air ej ector and auxiliary feedwater pump turbine exhaust. The release rates were calculated based on isotopic analysis of samples and radiation monitoring system data.

The noble gas release rate averaged over a one-hour period was 0.33% of the Technical Specification limit.

D. Virginia Electric and Power Company and NRC Response i

Following the termination of the emergency, Virginia Electric and Power f Company (Virginia Power) management immediately initiated recovery activities.

An organization was established and resources identified for evaluating the incident and recommending recovery actions. In addition, the NRC Region II, in Atlanta, Georgia, notified' Virginia Power that an inspection team was being j dispatched to North Anna. The NRC's inspection team was on site and first met with Virginia Power's recovery organization at 1455 hours0.0168 days 0.404 hours 0.00241 weeks 5.536275e-4 months on July 15, 1987.

The team was. upgraded to an Augmented Inspection Team (AIT) after arrival.

'The AIT was designated to examine the Virginia Power's response to the incident and perform a separate investigation. Virginia Power's recovery organization was in place and functional immediately following termination of the emergency.

The Virginia Power Recovery Organization ('igure I-1) was divided into j six groups reporting to the Recovery Manager. Overall coordination of the event evaluation and recovery actions was the responsibility of the Recovery Manager and the Local Emergency Operations Facility (LEOF) Command Center.

The Maintenance and Repair group was responsible for outage planning and steam generator maintenance activities. The Technical Evaluation group was responsible for the steam generator inspection program, tube failure analysis, steam generator integrity evaluation and tube plugging criteria and ,

recommendations. The Nuclear Safety and Licensing group we.s responsible for 1 the event evaluation including evaluation of the response of the plant and emergency response organizations, as well as interfaces with the NRC. The ,

Industry Interface group was responsible for interfacing with the media as well as INPO, State and local authorities, and Old Dominion Electric Cooperative. The Health Physics group was responsible for evaluating the radiological effects of the event.

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il II. DESCRIPTION OF EVENT A.- Introduction-The following narrative describes the significant operating events for the North Anna Unit'1. steam generator tube rupture which occurred on July 15, 1987.

> Attachment 1 _provides a more concise and detailed chronology of events. The narrative and sequence of -events were ' compiled from a variety of -sources including 1) the Sequence of Events Recorder (SER), 2) the Control Room P-250 process computer and alarm printouts, 3) the Emergency Response Facility Computer. System (ERFCS) historical file,'4) interviews.with. licensed Control Room Operators (CRO) and Senior. Reactor Operators (SRO), 5) CR0 and SRO logs 6)

Emergency Response Facilities legs and 7) strip charts from Control Room recorders. The response-of important reactor and secondary system parameters,

-including pressurizer level, RCS pressure and temperature and ruptured steam generator level and pressure are provided on Figures II-1 through II-6 to assist the reader in following the event and associated recovery actions.

B. Conditions Prior to the Event Prior to the event North Anna Unit I was operating at 100% power (which was first achieved on July 14, 1987) after having been returned to service from a refueling outage on June 29,1987 (See Figure 11-7 for power history). Reactor and secondary system conditions were normal and are shown on Table II-1. I Reactor' Coolant System (RCS) leak rate measurements taken the day before the event indicated less than 0.25 gpm unidentified leakage. Results of RCS leak rate measurements taken prior to the event are shown on Table 11-2. Two main feedwater pumps, three high pressure heater drain pumps, two low pressure heater drain pumps, and three condensate pumps were in service on the secondary syatem.

Operation of charging and letdown was normal with one charging pump in operation. Service water and component coolh g systems were normal with one component cooling pump and one service water pump on each unit in service.

The air ejector radiation monitor (RM-RMS-121) had been declared inoperable at 0809 hours0.00936 days 0.225 hours 0.00134 weeks 3.078245e-4 months on July 13, 1987 when it was determined to be indicating low.

Af ter condensation was drained from the monitor, it was returned to operable status at 0815 hours0.00943 days 0.226 hours 0.00135 weeks 3.101075e-4 months on July 14, 1987. Later, the monitor again operated erratically and was once again declared inoperable at 2238 on July 14, 1987. No other safety-related or other equipment relevant to the tube rupture event was out of service at the time of the event.

As a result of the air ejector radiation monitor being inoperable, grab samples were being taken every eight to twelve hours in accordance with Station Health Physics procedures. The Technical Specifications requirement was to obtain a backup " grab" sample on a 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months frequency. A sample taken at 2245 hours0.026 days 0.624 hours 0.00371 weeks 8.542225e-4 months on July 14, 1987 showed a slight but not significant increase in air ejector activity from the previous sample at 0114 hours0.00132 days 0.0317 hours 1.884921e-4 weeks 4.3377e-5 months on the same day.

However, the sample taken at 0620 hours0.00718 days 0.172 hours 0.00103 weeks 2.3591e-4 months on July 15, 1987, and analyzed at 0623 hours0.00721 days 0.173 hours 0.00103 weeks 2.370515e-4 months , showed a significant increase in activity. However, there was not sufficient time to report this information to the Shift Supervisor prior to the event. Results of isotopic analysis of grab samples taken prior to the event are shown on Table II-3.

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-Unit I secondary system chemistry data, including silica, chloride, sodium, sulfete, cation conductivity, boron, pH, were reviewed beginning with'the startup from the refueling outage through July 15, 1987. Although the plant experienced 'several chemistry transients due to multiple startup and shutdowns over this period, there were no precursor indications of the tube rupture'. The on-line- chemistry monitoring system, which is undergoing pre-operational checkout, was partially in service during the time of the event. The on-line [

system indicated a decrease in pH and an increase in specific conductivity in !

"C" main steam at approximately 0624 hours0.00722 days 0.173 hours 0.00103 weeks 2.37432e-4 months on July 15, 1987 (Figure 11-8).

A chronological listing of significant operational and maintenance events involving Unit 1 prior to the time of the event-is provided in Attachment 5.

At the time of the event, the operating shift was manned by three Senior

' Reactor Operators, including the Shift Supervisor, four licensed Reactor Operators and seven ' unlicensed Reactor Operators. A Shift. Technical Advisor (STA) with an active SRO license was also assigned'to the operating shift. A Health Physics shift and chemistry technicians were also onsite.

C. Event Description and Analysis At 0630 hours0.00729 days 0.175 hours 0.00104 weeks 2.39715e-4 months on 7/15/87, an alarm was received on the Unit 1 Annunciator Panel for Main Steam (High Range) Radiation Monitor. Upon ir.vestigation, it was determined that the NRC (Nuclear Research Corporation) Radiation Monitors on the "A" and "B" main steam lines were in." ALERT" and the "C" main steam line monitor was in "HIGH" alarm. Subsequently, the Unit 1 Control Room Operator (CRO) noted pressurizer level decreasing rapidly, and informed the Unit 2 Senior Reactor Operator (SRO) of a possible primary-to-secondary leak. The Unit 1 SRO and the Shift Supervisor were recalled to the Control Room and the Superintendent of Operations was contacted by telephone by the Unit 2 SRO. The Shift Technical Advisor (STA) and NRC Resident Inspector also responded to the SRO recall and reported to the Control Room. Meanwhile, the Unit 1 CR0 took manual control of makeup and set the normal charging flow control valve (FCV-1122) to full open.

Upon return to the Control Room, the Shift Supervisor was advised by the Unit 2 SRO that a steam generator tube rupture may have occurred. The Shift Supervisor then took command of Unit I and directed that letdown from the Reactor Coolant System (RCS) to Chemical Volume Control System (CVCS) be isolated. The Unit 1 CR0 also aligned charging pump suction from the Volume Control Tank (VCT) to the Refueling Water Storage Tank (RWST) due to the rapid RCS inventory loss. The Shift Supervisor also directed that a power ramp down at 2% per minute be initiated. The Unit 1 SRO returned to the Control Room and assisted the Shift Supervisor during the event.

Pressurizer level and pressure continued to decrease and at approximately 45% level (100% program level is 65%) and 2100 psi t (normal operating pressure is 2235 psig), the Shift Supervisor directed the Unit "R0 and Backboards CR0

. (who had assumed Unit 1 Balance of Plant duties) to mar ally trip the unit. The manual reactor and turbine trips were performed at 0635 hours0.00735 days 0.176 hours 0.00105 weeks 2.416175e-4 months and EP-0, Revision 1 (Reactor Trip or Safety Injection) was implemented. An additional licensed CR0 from the shift was assigned the responsibility of " Procedure Reader".

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Approximately 20 seconds after the manual Reactor Trip, an automatic Safety fnjection (SI) was received on " low-low" pressurizer pressure (less than 1765 poig on 2 out of 3 channels). EP-0 was completed through Step 23 at which time the Shift Supervisor directed a transition to EP-3, Revision 1 (Steam Generator Tube' Rupture).

A " Notification of Unusual Event" (NOUE) was declared at 0639 hours0.0074 days 0.178 hours 0.00106 weeks 2.431395e-4 months . The Unit 2 SRO became the interim Station Emergency Manager and assigned two unlicensed Control; Room Operators to be communicators to .the State / Local governments and to the NRC. Notifications of the NOUE were made within 15 minutes to the State'and Local governments as required by the Emergency Plan.

Communication was established with the NRC and continuously maintained throughout the event.

The' basic strategy for the response to and mitigation of a steam generator tube rupture is as follows: 1) Identify the ruptured steam generator (s), 2)

Isolate the flow from the ruptured steam generator (s)', 3) Initiate RCS cooldown (to establish subcooling margin), 4) Depressurize the RCS (to minimize breakflow and reffil the pressurizer), and 5) terminate SI (to prevent oing solid in the RCS).

At Step 3 of EP-3, the ruptured steam generator is identified. Although i there were several possible indications (i.e., steam generator level and steam '

line radiation) that "C" steam generator was the ruptured steam generator, the Shift Superviser was not absolutely sure and decided to continue on without identifying the ruptured steam generator (i.e., the Response Not Obtained column of Step 3 was entered).

Subsequently, after resetting SI and the Phase A Containment Isolation signals, the Shift Supervisor directed that Auxiliary Feedwater flow to be isolated to "C" steam generator for verification. After isolation, it was noted that level in "C" steam generator continued to rise. Based on this

" uncontrolled" increase in level, the Shift Supervisor identified "C" steam generator as the ruptured generator and proceeded with the steps in EP-3 to isolate steam flow from the "C" steam generator. Once isolation of "C" steam generator was completed, a rapid cooldown of the RCS to approximately 480*F was initiated.

During the above evolutions, the interim Station Emergency Manager upgraded the "NOUE" to an " ALERT" status. Within 8 minutes of this declaration, the required notifications to the State / Local governments and to the NRC were made.

Following the " ALERT" declaration, a callout of offsite station emergency response personnel was made along with the accountability of all personnel at the station. The Health Physics shift leader was requested to report to the Control Room to implement EPIP 4.01, Radiological Assessment Director Controlling Procedure.

The rapid cooldown of the RCS as required by EP-3 was accomplished by dumping steam from the "A" and "B" steam generators to the main condenser via two steam dump valves. After the RCS was cooled down, RCS pressure was rapidly reduced and equalized with the ruptured secam generator's pressure.

Depressurization was accomplished by using both pressurizer spray valves and one pressurizer power operated relief valve (PORV). As SI flow increased over the steam generator primary to secondary leakage flow, due to RCS depressurization, pressurizer level came back on scale and continuously increased. When pressure Page 15

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l equalized 'between the RCS and the ruptured steam generator, the primary to secondary leakage . slowed and the level in "C" steam generator stopped increasing. Subsequently, the criteria for SI termination were met, and one 1 Charging /High Head Safety Injection pump was secured. Normal makeup to the RCS was then established, and the SI flow path through the Boron Injection Tank (BIT) was isolated. Normal letdown from the RCL to. the CVCS was established next.

An orderly cooldown and depressurization of the RCS to Cold Shutdown was initiated at 0718 hours0.00831 days 0.199 hours 0.00119 weeks 2.73199e-4 months (48 minutes from the initial indication) by transitioning from EP-3 to ES-3.1, Revision 1 (Post-SGTR Cooldown Using Backfill). Operating procedures were also referred to and utilized as appropriate during the cooldown. The cooldown rate was limited to approximately 42' F.per hour in order to allow depressurization of the ruptured steam generator at the same rate.as the depressurization of the RCS. The cooldown rate was maintained initially by dumping steam from the intact steam generators to the condenser via two steam dump valves and then by the RHR system. Cold ,

Shutdown (Mode 5) was reached at 1330 hours0.0154 days 0.369 hours 0.0022 weeks 5.06065e-4 months , and the emergency was terminated at {

1336 hours0.0155 days 0.371 hours 0.00221 weeks 5.08348e-4 months hours and the " Recovery" phase was initiated. l The transition from EP-3 to the post-SGTR cooldown procedure allows for three options. These options are: 1) Post-SGTR Cooldown Using backftiling (ES 3.1), 2) Post-SGTR Cooldown using Blowdown (ES 3.2), and 3) Post-SGTR Cooldown using steam dump (ES 3.3). Since RCS letdown to CVCS was available, cooldown by backfilling (ES 3.1) was the option of choice. This option minimized the amount of RCS (i.e. contamination) in the secondary system while maintaining the most j rapid cooldown rate allowed by Technical Specifications. The methodology used l in ES 3.1 is to backfill the ruptured steam generator secondary side inventory into the primary through the ruptured steam generator tube. This is accomplished by cooling the RCS and depressurizing the RCS until subcooling dropped below 30*F on the core exit thermocouple or pressurizer level increased above 70%. Letdown was used to control pressurizer level between 30% and 70%.

Auxiliary feedwater and condensate feed were used to maintain the required level in both the intact and ruptured steam generators. The above sequence was repeated until the RCS was lower than 120*F and 100 psig. Shutdown margin was maintained throughout the event. After the "C" RCS loop was isolated and drained, the secondary side of the "C" steam generator (the ruptured generator) was purged with nitrogen and vented through the Gaseous Waste process vent charcoal and HEPA filter. Later, the secondary side inventory was drained to the Liquid Waste system and processed. The secondary side was also flushed to remove any remaining boron. 1 Prior to isolating the "C" loop, the "C" steam generator was still at saturated condition. As a result, the "C" steam generator responded like a

" pressurizer", and as it cooled down, pressure in the steam generator decreased.

With decreasing pressure in the steam generator, RCS pressure had to be reduced in order to preclude refilling of the steam generator with RCS. Once the loop was isolated, this concern was eliminated. However, until the ruptured steam generator was cooled sufficiently to allow draining, the RCS water in the secondary side of the steam generator continued to degas. Prior to venting, the hydrogen concentration had increased to approximately 15%.

Page 16

D. Operational Analysis The purpose of this section is to analyze the performance of the Operating and Health Physics shifts on duty during the event and.the transitions of key emergency management responsibilities.

The Unit 1 Control Room Operators' (CR0s), Senior Reactor Operators' (SR0s),

and the Shift Technical Advisor's (STA) overall response to the steam generator tube rupture was excellent. The reactor was manually tripped and immediate actions (as required by EP-0, Revision 1. Reactor Trip or Safety Injection) were L performed in a timely manner. The automatic initiation of Safety Injection (SI)

I and the indications of a tube rupture were quickly recognized. The ruptured steam generator was isolated within 13 minutes of safety injecting and did not overfill. Pressurizer level was restored and pressurizer pressure was stabilized within 34 minutes of safety injecting. Pressurizer level was restored without- going solid, and the reactor trip and cooldown were accomplished without lifting any steam generator power operated relief valves (PORVs) or safety valves. The cooldown to Cold Shutdown was conducted in a controlled manner and without incident. The Unit 2 CR0 performed Abnormal Procedure 47 (AP-47, Unit Operation During Opposite Unit Emergency) to verify that the Unit 1 transient had no adverse impact on the continued safe operation of Unit 2. The operational perf(-gance exhibited is attributed to the classroon and simulator training received on steam generator tube ruptures which is structured to integrate the Emergency Operating Procedures, Emergency Plan Implementing Procedures, and the Critical Safety Functions.

The Emergency Plan was implemented by the interim Station Emergency Manarer (the Unit 2 SRO) in an excellent manner. The correct emergency classifications were made in a timely manner, and the predesignated communicators for the NRC and State / Local governments performed their initial notifications and updates as required by the Emergency Plan.

During the early stages of the event, the interim Station Emergency Manager consulted, by telephone, with the Station Manager and the Superintendent of Operations. Upon arrival of the Station Manager, the interim Station Emergency Manager began an orderly and detailed turnover. This was followed by an orderly turnover of the Emergency Plan Implementing Procedures and communication responsibilities to the Assistant Station Manager. Upon completion of these activities, the Station Emergency Manager (Station Manager) and Procedures Coordinator (Assistant Station Manager) relocated to the already mobilized Technical Support Center.

The interim Station Emergency Manager interface with Health Physics was adequate, although the demands to classify the emergency and implement the Emergency Plan hampered thorough communications with Health Physics. The interim Radiological Assessment Director was not given a detailed briefing on where the radioactive release paths had occurred from. This was compounded by the very small amount of radiation being released (no radiation monitors were in alarm after the ruptured steam generator had been isolated), and the fact that the air ejector radiation monitor was inoperable. It should also be noted that by the time the interim Radiological Assessment Director reported to the Control Room, the "C" steam generator had been completely isolated.

Most of the operating and health physics shifts on duty at the time of the svent had been on-duty since at least midnight. The health physics normal shift Page 17 u- _ __ _____ _ __

I relief was arriving about the time the event initiated. The operations shift, which was not due to be relieved until 0800 hours0.00926 days 0.222 hours 0.00132 weeks 3.044e-4 months , was quickly supplemented by the " Relief Office" crew which was already on site. The " Relief Office" crew i (operatim a personnel assigned to tasks other than direct day to day operations of the plant)' consisted of two licensed CR0s and three experienced, unlicensed operators which were utilized by. the Shift Supervisor and interim Station Emergency Manager as required. Upon arrival of the " day" operating shift, personnel reported to_ Operations Support Center (OSC) as required by the Emergency Plan. When the OSC had assembled more than sufficient operational personnel, the " day" shift was sent to the Control Room to begin a shift turnover. The turnover for licensed operators took place one at a time and was performed by having the replacement operator work with the on duty operator for 20 to 60 minutes to ensure continuity and full understanding of plant conditions by the oncoming operators.

The STA responded quickly to the Control Room and performed his duties expeditiously. The STA also monitored the Critical Safety Functions (CSF) and the Safety Parameter Display System. Two " Yellow"_ paths on the Critical Safety Functions were monitored during the event related to pressurizer level and steam generator level. No higher level C3F conditions occurred. The STA also monitored the Integrated Core Cooling Monitoring System which provided RCS inventory (RVLIS) and core subcooling data and assisted the CRO in plotting cooldown rate information.

E. Emergency Operating Procedures (EOPs) Utilization and Analysis The Revis1on 1 E0Ps being utilized at North Anna Power Station were implemented April 30, 1987. The current edition of the Unit 1 E0Ps used during the Steam Generator Tube Rupture event was June 12, 1987 (i.e. Unit 1 E0Ps were updated at the completion of the refueling outage to reflect modifications installed during the outage). Prior to April 30, 1987, each licensed operator and STA had received classroom training on the E0Ps (to include ECAs and FRPs) and simulator training on most of the E0Ps. The training was conducted during two cycles of the Licensed Operators Requalification Program. As a result of the training, licensed operators had a good working knowledge, as well as, confidence in the accuracy and effectiveness of the E0Ps.

Based on interviews with the licensed operators on the shift during the event, it was concluded that the E0Ps were very effective. However, there have been several areas identified that may need further review. First is Step 3 of EP-3, which is used to identify the ruptured steam generator. During the event and subsequently confirmed by the modeling of the event on the North Anna Simulator, Step 3 of EP-3 was reached before a " positive" identification could be made. The procedure can accommodate inability to imme0iately identify the ruptured steam generator by the Response Not Obtained (RNO) section of the step.

However, by using the RNO, the isolation of the ruptured steam generator (and associated radioactivity release path) is delayed and the Low Head Safety Injection pumps are secured based on RCS pressure. The second is the lack of a specific step in the procedure to evaluate the air ejector exhaust requirements.

The final concern is the delay until Step 32 for stopping and shutting down the Emergency Diesel Generators (EDG) which may result in excessive time in running with the EDGs unloaded.

Page 18

It should be noted that none of the above concerns affected the operator's ability to adequately use the procedure to respond to and mitigate the tube rupture in a timely manner. However, a thorough study of these potential

! concerns, as well as ,- the entire use of E0Po during the Steam Generator Tube l Rupture event will be conducted by the Westinghouse Owners Group (WOG) j Operations Subcommittee.

From the perspective of the operator, the initial indications were all three main steam line radiation monitors ("A" and "B" were in " Alert" alarm and "C" was in "High" alarm) . This is symptomatic of a steam generator tube rupture (SGTR). The next indications available were rapidly decreasing pressurizer level and pressure. This is symptomatic of either a Loss of Coolant Accident U.0CA) or a SGTR. The Shift Supervisor directed action to isolate normal letdown and start a second charging pump. (A second charging pump was inadvertently not started but the normal makeup flow control valve was opened fully and charging pump suction was shifted from the VCT to the RWST.) The Shift Supervisor then checked containment conditions and found them normal. The absence of radiation monitor alarms in the Auxiliary Building indicated no abnormal RCS makeup or letdown line leak outside of containment. There was no abnormal indication of steam generator levels or flow rates at this time, and therefore even af ter entering EP-0 and safety injecting, the Shift Supervisor was not positive of what the problem was (although a SGTR was suspected). At step 23 of EP-0, a transition was made to EP-3 based on steam generator main steam line radiation monitors being in or having been in alarm. Prior to entering EP-3, the steam dump valves had modulated closed as RCS T decreased to and then below 547'F due to full auxiliary feedwater flow to a$5*three steam generators. The closing of the steam dump valves stopped steam flow (except for the steam flow to the steam driven auxiliary feedwater pump) and the main steam line radiation monitor alarms cleared. When step 3 of EP-3 was reached (approximately 0640 hours0.00741 days 0.178 hours 0.00106 weeks 2.4352e-4 months ) the only indication available for identifying the ruptured steam generator was " Unexpected Increase' in Steam Generator Narrow Range Level". Figure II-6 depicts Narrow Range level in all three steam generators during this time period. (Note: A steam generator sample had been requested, but was not yet available and the steam generator blowdown radiation monitors were isolated by the Phase A Containment Isolation). The Shift

. Supervisor was aware that "C" steam generator level was higher than "A" which was unusual because "A" steam generator is supplied by the steam driven auxiliary feedwater pump which refills faster than the motor pumps which supply the "B" and "C" steam generators. The Shif t Supervisor was also aware that "C" main steamline radiation monitor had been reading higher, but at this time was no longer in alarm. As a result, no decision to isolate a steam generator was made because of the overriding concern of isolating the wrong steam generator.

The concern with isolating the wrong steam generator is the loss of that steam generator for cooldown via the condenser. The steam generator would still be available for cooldown via the PORV to the atmosphere but this cooldown path is much less desirable.

From Step 3, the Shift Supervisor proceeded to Steps 6 through 13. At Step 8, all steam generators are assumed to be intact and narrow range level is checked. (See Figure II-6.) Although level in any steam generator did not exceed 50% at this time "C" steam generator level was higher, and auxiliary feedwater could have been (but was not) throttled to ensure that the level increase was controllable. At 0644 hours0.00745 days 0.179 hours 0.00106 weeks 2.45042e-4 months , Step 13 was completed and Step 14 returned the Shift Supervisor to Step 4 to isolate flow from the ruptured steam generator. At approximately 0646 hours0.00748 days 0.179 hours 0.00107 weeks 2.45803e-4 months , auxiliary feedwater to "C" steam Page 19 i

generator was isolated and level was noted to still be increasing. (See Figure l

'1I-6.) Based on this indication, the Shif t Supervisor be. identified "C" as the-ruptured steam generator, and it was completely isolated by 0648 hours0.0075 days 0.18 hours 0.00107 weeks 2.46564e-4 months (18 minutes into the event or 13 minutes af ter safety injection.)

The diversion status of the air ejector exhaust was focused on between 0720 and 0730 hours0.00845 days 0.203 hours 0.00121 weeks 2.77765e-4 months . However, the final decision to divert to containment was not made until 0756 hours0.00875 days 0.21 hours 0.00125 weeks 2.87658e-4 months . A specific step in EP-3 addressing the air ejector exhaust divert status would probably have identified and isolated this release- ,

path much sooner in the event. It should be noted that once the steam dump valves went closed (less than 10 minutes into the event) the release through the air ejector exhaust was minimized, and once the ruptured steam generator was isolated (approximately 18 minutes into the event or 13 minutes after safety injection), the release was essentially eliminated.

The EDGs could have been shutdown at Step 12 and, realigned for auto start rather than Step 32. However, the decision to do this would be manpower dependent, since more shift manpower would probably be available at Step 32 than at' Step 12.

During the initial portion of the event (i.e. approximately 5 minutes between the first indication and the manual reactor and turbine trip), operator actions were driven by several Abnormal Procedures (APs) and Annunciator Responses (ARs). Specifically, ARs were in for " Main Steam Loops 1-A-B-C Auxiliary Steam Loop Hi Radiation and Rad Alert" as well as for "PZR LO LEVEL" and "PZR HI-LO PRESS". The required operator actions for these ARs were carried out except for Step 2.3.5 (Carry Out AP-44, Loss of RCS Pressure) of the PZR HI-LO PRESS" AR. Health Physics was notified that a possible steam generator tube rupture had occurred and were requested to get steam generator samples.

The immediate actions of AP-24.1 " Steam Generator Tube Leak" were carried out except for starting the second charging pump. As previously stated, the Shift Supervisor directed the start of this pump but inadvertently the pump was not started. Also, the immediate actions of AP-5.1 and 5.2 were carried out.

However, none of these APs were formerly entered prior to the manual trip.

AP-24.1 was completed during the event but AP-5.1 and AP-5.2 were not formally entered since they were not required once the E0Ps were initiated. AP-47 " Unit Operation During Opposite Unit Emergency" was completed on Unit 2 as directed by EP-0.

1 The " Procedure Reader" was a licensed CR0 which complied with the North Anna l Power Station standard that the procedure reader be a licensed SRO or CRO.

However, the standard does state that the first preference for " Procedure Reader" is an available SRO who is not assigned other priority duties. In j general, the Procedure Reader interacted well with the Shift Supervisor and the

.two CR0s on the Unit I control board. Based on interviews with the licensed operators, none indicated any problems with hearing the " Procedure Reader" or being heard. However, not all steps were read, or if read, acknowledged by the l CROS on the control board. In these cases, the " Procedure Reader" directly l confirmed the step. Also, the " Procedure Reader" did not check off steps in the E0Ps'as they were completed. (These methods are consistent with the way the

" Procedure Reader" is trained on the simulator).

The number of personnel in the Control Room was minimized to the extent possible as required by Station Administrative Procedure ADM-20.11 " Control Room Access".

I Page 20 !

l

l:

.i During.the time interval between the manual reactor and turbine u tp and the

' closing of the steam dump valves, excessive noise.was created in the . Control Room. each time the Unit i side Control Room door was opened. This resulted in !

distraction to the Unit 1 CR0s and SR0s. To limit access. the. Shift Supervisor. j requested Security to post an officer at the Unit 1 Control Room Door. The primary' sources of noise _ in . th e - Control Room .were. the utility and alarm

typewriters, telephones ringing, and communications between personnel.

Three additional minor problems were identified with the EPIPs and concerned or affected available shift-resources prior to activation of the TSC. The first problem dealt with the lack of a Backboards Operator. As previously stated, this operator had assumed Unit I control board responsibilities ' as balance-of-plant operator.. As a result, the transmission of radiation monitor readings and meteorological data was slowed down. It would iave been helpful if the Health . Physics personnel reporting to the Control Room .ad been trained in obtaining'this information.

The second' problem concerned the detailed and large quantity of- information required by the:-NRC. . The NRC communicator was an experienced unlicensed operator with responsibility for the Safeguards Watchstation but was not licensed. (When the TSC was activated, NRC communications were performed by a licensed SRO.) Information was provided to the NRC as requested but at some

-impact on the limited shift resources initially available.

l i

Page 21

q:

I TABLE II-1 NORTH ANNA UNIT'1 OPERATING CONDITIONS PRIOR TO STEAM GENERATOR TUBE RUPTURE

Reactor Power: 100%

RCS Pressure: 2235.psig Pressure Level: 64.5%

RCS Average Temperature: 586.5'F RCS Loop Temperatures: "A" "B" "C" T F 621 618 617 h

T F. 556 555 - 553 c

Boron Concentration: 1320 ppm Hydrogen Concentration: 36.9 cc/kg Volume Control Tank:

m Level 42.5%

Pressure. 23 psig Temperature 112'F Charging Flow: -67.5 gpm Letdown Flow: 82 gpm I Reactor Coolant Pump Seal Injection:

"A" RCP: 7.6 gpm "B" RCP: 7.7 gpm "C" RCP: 7.7 gpm Steam Generators: "A" "B" "C" Pressure, psig 870 870 870 Level, % 45 45 45 6 0 6 Feed Flow,' lbm/m 4.3X10 4.3X10 4.23X10 6 6 Steam Flow, Ibm /m 4.35X10 4.35X10 4.42X10 Containment Conditions:

Temperature: 93*F Pressure: 9.45 psia

Source: Unit 1 Reactor Operator Log 1-LOG-4 Date: 07-15-87 Time: 0400 Page 22

, , l I

)

TABLE II-2 REACTOR' COOLANT SYSTEM LEAK RATES PRIOR TO TUBE RUPTURE EVENT IDENTIFIED UNIDENTIFIED MODE LEAK-RATE LEAK-RATE 07-05-87 1 1.2 GPM' O.14 GPM 2107 _.

07-08-87 1- 1~.9 GPM' O.16 GPM

'2023-07-11-87 3 2.0 GPM 0.01 GPM 1904 14-87 1. 1.9 GPM 0.25 GFM 2108 l

'1 J

1 l

. 1 l l l

1 1

I

= _ _ _ _ _ . _ = _ _ - _ _ - _ _ _ _ _

Li i

1 1

i TABLE II-3

_ UNIT 1 AIR EJECTOR ACTIVITY (UCi/CC)

PRIOR TO TUBE RUPTURE EVENT 1 13' July l'987- 13 July 1987- 14 July 1987 14. July 1987- 15' July.1987 0900. Hours 1740 Hours 0114' Hours 2249 Hours- 0620 Hours.

E

.85.5% Power 87.8% Power 99% Power 100% Power 100% Power

Ar -5.94E-6 7.18E-7 4.59E-5 6.02E-5 1.34E-3

'Kr-85m- - - 1.68E-6 3.61E-5 5.84E-5

'Kr-87, 3.21E-6 6.62E-6'

~ 1.~ 3 6E-4 ' .

Kr-88J - .

4.78E-6 7.29E-6 1.50E Xs-133 , - -

4.615-6 5.90E-6 1.49E Xa-135m. 2.78E-6 -

2.00E-5 4.92E-5 2.22E-4' Xs-135: 2.02E-6 9.31E-7 '1.84E-5 3.43E-5 4.92E-4

-Xe-138- -~ - -

3.08E-5 6.34E-4

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k III. RADIOLOGICAL RELFASES ;

A. Summary Release data during the event has been evaluated and independently calculated. This review indicates that the reported release of 2.65E-1 curies on July 15, 1987, was valid based on the sampling data available at the time of the event. Followup calculations were performed to bound the release. The maximum inventory available for release based on reactor coolant to secondary side mass balance calculations was 2.24 curies. This is the maximum amount of activity that could have been released.

Calculations based on sampling and radiation monitor data indicated that only a total of 1.59E-1 curies were released.

Radiological data showed that approximately 84% of the release consisted of radiogases. Calculated whole body dose rates were found to be less than background at the site boundary in the affected sector (s).

B. Evaluation of Radiological Release

1. Onsite During the course of the event, effluents consisting primarily of radiogases were released from the "C" steam generator via the two release paths prior to its isolation. A release pathway through the condenser air ejector exhaust existed from approximately 0630 until 0646 hours0.00748 days 0.179 hours 0.00107 weeks 2.45803e-4 months when the "C" main steam trip valve was closed isolating the "C steam generator from the condenser. (It should be noted that the steam dump valves closed and stayed closed prior to 0640 hours0.00741 days 0.178 hours 0.00106 weeks 2.4352e-4 months , effectively isolating "C" steam generator from the condenser). Following isolation of the "C" steam generator, only minimal activity from "A" and "B" steam generators was '

being released via the air ejectcr, and the release path was e mpletely isolated at 0756 hours0.00875 days 0.21 hours 0.00125 weeks 2.87658e-4 months when the air ejector exhauct was diverted to the containment. A total gaseous activity of 9.90E-2 curies was calculated to have been released via the air ejector release pathway. This calculation was based on the Kaman normal ranee Vent-Vent "A" stack monitor data and the air ejector grab sample taken at 0650 hours0.00752 days 0.181 hours 0.00107 weeks 2.47325e-4 months and assumed a release duration of 86 minutes from 0630 to 0756 hours0.00875 days 0.21 hours 0.00125 weeks 2.87658e-4 months (see Table III-1).

The second release pathway was from the discharge of the steam driven auxiliary feedwater (AFW) pump. This pathway conservatively existed from approximately 0636 until 0745 houro when the steam driven AFW pump was shutdown. The steam supply to the steam driven AFW pump consisted of steam from the three steam generators from 0636 until 0648 hours0.0075 days 0.18 hours 0.00107 weeks 2.46564e-4 months at which time the "C" steam generator supply was manually isolated. Following 0648 hours0.0075 days 0.18 hours 0.00107 weeks 2.46564e-4 months , steam to the steam driven AFW pump was provided by "A" and "B" steam generators only, effectively eliminating the steam driven auxiliary feedwater pump as a release pathway. A total activity of 6.04E-2 curies was calculated to have been released via this pathway. The noble gas component (Table III-2) of this calculation was based on the Kaman normal range monitor data by assuming that the average release rate through the condenser air ejector immediately prior to the turbine trip was also the release rate for the AFW pump exhaust. The tritium, particulate, and halogen compcnent of the total activity is based on isotopic analysis of Pao,e 33

blowdown samples taken at 0943 (Table III-3). Partition factors were used to determine the halogen and particulate components. A total release duration of 12 minutes from 0636 to 0648 hours0.0075 days 0.18 hours 0.00107 weeks 2.46564e-4 months was assumed. The total release of activity through the AFW pump exhaust frqm 0648 to 0745 hours0.00862 days 0.207 hours 0.00123 weeks 2.834725e-4 months l, was insignificant (Table III-4). Gaseous activity discharged through the P air ejector and the AFW pump exhauss was 1.37E-1 curies.

The above air ejector sud st: eat driven AFW pump releases equate to a total of 1.59E-1 curies. This compares to a radioactivity release of 2.65E-1 curies that was estimated by the dose assessment team during the tube rupture event.

A primary to secondary mass balance calculation, based on a transfer of 55,013 pounds of reactor coolant from 0630 to 0648 indicated a total of 2.24 curies of radiogas available for release. (Table III-5)

A review of the inplant radiation monitoring charts confirms that the only release paths were as discussed above. No increase was noted on the Vent-Vent "B" ventilation stack gas and particulate monitors or the process vent gaseous and particulate monitors. In addition, no increase was noced on the Unit 1 containment gas and particulate monitors or the Unit 1 manipulator crane area monitors. This was expected since no activity was released to the containment until the condenser air ejector exhaust was diverted to containment at 0756 hours0.00875 days 0.21 hours 0.00125 weeks 2.87658e-4 months , and the "C" steam generator had been isolated from the condenser for more than one hour before the exhaust was diverted.

Increases were observed on the Unit 1 "A", "B" and "C" main steam monitors and the steam driven AFW pump exhaust monitor. "C" main steam radiation monitor readings in the range of 7 to 9 mR/hr wera indicated during the time period of the reactor trip. Readings on the "A" and "B" main steam line monitors were in the 0.4 to 1 mR/hr range during this same period. No response was observed, although one would have been expected, on the Unit 1 "A", "B", and "C" steam generators blowdown monitors. The response of these monitors during the event is probably due to the fact that the ruptured tube did not start leaking until shortly before it ruptured. The impact of the ruptured tube on the RCS resulted in safety injection and isolation of the steam generator blowdown radiation monitors.

The Unit I condenser air ejector radiation monitor was inoperable during the event. This monitor has subsequently been repaired and returned to service.

2. Offsite Whole body and thyroid average dose rates at the site boundary were calculated based on the release rates discussed in the previous section. A whole body dose rate of 4.04r-4 mrem /hr and a thyroid dose rate of 8.30E-4 mrem /hr were calculated. For the release, a whole body dose of 5.78E-4 mrem and thyroid dose of 1.14E-3 mrem were calculated.

Given the low concentrations of activity released, a background count rate of approximately 0.02 mR/hr, and the lower limits of detection for field and laboratory analyses of air particulate and radiciodine, no detectable increase in dose rate or radioactivity would have been expected during the event at the site boundary in the affected sector (s). This conclusion is supported by the survey and sampling results and dose rate readings taken during the event.

Page 34

~,.

Additional environmental samples vere collected after the event and forwarded to an environmental consultant for analysis (see Table III-6).

The air particulate and radiciodine environmental samples of sectors H and K were counted at the station prior to being forwarded to the consultant.

These analyses indicated no increase in normal background levels of

/

radioactivity. On July 20, 1987, the consultant reported that all samples had been analyzed and that ne increases in normal environmental radioactivity levels had been indicated. This supports the conclusion ,

that the release consisted primarily of radiogases at very low '

concentrations.

B f

C

'O D a O/9 1$

TABLE III - 1 CALCULATE 7' RELEASE ACTIVITY FROM CONDENSER AIR EJECTOR FC TIME PERIOD FROM 0630 to 0756 HOURS -

(BASED ON AIR EJECTOR SAMPLE TAKEN AT 0650 HOURS)

CALCULATED SAMPLE RELEASED ACTIVITY ACTIVITY ISOTOPES uCi/CC uCi -s Ar-41 4.90E-3 4.73E+4 Kr-85m 2.08E-4 1.98E+3 Kr-87 4.48E-4 4.36E+3 Kr-88 5.30E-4 5.15E+3 Xe-133 5,79E-4 5.54E+3 Xe-135m 3.99E-4 3.86E+3 ,

Xe-135 1.83E-3 1.76E+4 Xe-138 1.36E-3 1.32E-4 TOTAL CURIEF = 9.90E-2 i

4 Page 36 e

i.... . . . . . . _ _ _ _ _ _ . _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ . _ _ _ _ . _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ .

t: o.

l- with developing specific plans and procedures for recovery. -The Recovery Organization was establishol.under the direction of the-

'Vice President - Nuclear Operations Department. The organization created ~ a

" command center" in the LEOF, established a long-term interface arrangement with the.NRC and State, and formulated the following support structure:

'l. Maintenance and Repair Team

2. Technical Evaluation Team
3. -Nuclear Safety and Licensing Team
'4. Industry Interface Team.
5. Health Physics' Team The recovery organization was implemented upon termination of the event.
Summary The July 15, 1987 SGTR event demonstrated that emergency response personnel within the Virginia Power organization are capable of satisfactorily responding
. to- an emergency of this nature. Furthermore, the NRC and emergency organizations within the State of Virginia demonstrated the capability to respond to requests for assistance during such an emergency. In conclusion, the' North Anna Power Stetion and those emergency response agencies that support it effectively mitigated the transient event and adequately protected the health and safety of the public.
Page 45
B. jmergency Response Facility Computer System Overview The North Anna Power Station Emergency Response Computer System (ERCS) operates the Data Acquisition System (DAS) for Unit 1 and Unit 2. The DAS covers the collection and communication of plant data required by Supplement 1 to NUREG-0737 (NRC Generic Letter 82-33) to be available to each unit Control Room and the Emergency Response Facilities. A subset of the DAS serves as the Safety Parameter Display System (SPDS) required by Supplement 1 to NUREG-0737, and also includes other information determined to be useful to plant and emergency response personnel. The plant SPDS and DAS vere extensively used, during and following the steam generator tube rupture event. An evaluation of the performance and utilization of the SPDS and DAS by emergency response personnel in the Control Room and other emergency response facilities, and personnel involved to the event analysis was conducted by interviewing selected individuals. The objectives of this evaluation were to determine: 1) whether the SPDS and DAS ratisfied regulatory requirements and guidelines, and 2) whether the SPES and DAS served as an effective aid, above and beyond the ,
regulatory objectives, in the assessment, recovery, and analysis of the July 15, 1987 event.
Control Room Utilization This evaluation showed that overall the SPDS worked well and that displays were used to provide helpful information to the Control Room personnel during the event. Because of the nature of this particular event (ie, the cause of the transient was quickly recognized and the proper mitigative actions were taken in a timely manner), the " accident assessment" function provided by the information which was available on the SPDS (eg, trend plots) was not utilized to its fullest extent. The Shift Technical Advisor (STA) who was the principal user in the Control Room noted that the display of SPDS information was quite useful and convenient. Information provided by the DAS were also used by Control Room personnel and found to be helpful both during the initial phase of the event and for confirming the successful completion of accident response actions taken later in the event.
ERF Utilization The SPDS displays were also available in the Emergency Response Facilities (ERFs) and were mainly used by the personnel manning these facilities to obtain current plant status. ERF personnel made extensive use of the information provided by the DAS to assess and trend plant conditions as mitigative actions were taken. An example of this was the fact that Technical Support Center personnel were able to use DAS information to assist Control Room personnel in responding to the event. Because of the nature of the July 15, 1987 event and the manner in which it was mitigated, the radiological and meteorological capabilities of the DAS were not used to their fullest extent. Significantly, ERF personnel did not interfere with Control Room operations at any time during the event, as the information provided by the DAS was complete enough for the performance of required tasks by ERF personnel.
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, ur I
Event Analysis The event data stored' by the DAS was found to be an excellent event-analysis tool, providing more extensive and more detailed data than was previously available. The resolution of the data collected and stored by the DAS (ie, sampling frequency) will be evaluated further to determine if higher resolution data would be advantageous for possible future events.
Summary
.While the SPDS demonstrated that it satisfied the regulatory requirements and guidelines, a number of shortcomings were identified that prevented the SPDS from, serving _ as a fully effective aid to Control Room personnel. These :
. shortcomings appear to fall into two broad categories, data point treatment by I the SPDS software and human factors concerns. Specifically, SPDS alarm setpoints appear to be overly conservative and lack the necessary degree of flexibility to' reflect plant status during a rapid transient. The amount of necessary interactions between the user and the SPDS, and the presentation of ,
certain information in the SPDS displays do not appear to meet the best human I factors engineering criteria.
Overall, the performance of the DAS in the functioning of the ERFs met applicable regulatory requirements and guidelines. As for the SPDS, the deficiencies identified during the event and the event progression prevented-the DAS from being used to its full potential. 'Some cf the problems encountered are identical to the SPDS problems discussed above, and concern the manner in which data is handled by the DAS (alarm setpoints/ data flexibility) and human factors /information presentation concerns (more detailed piping and instrumentation diagrams). The need for additional training of ERF personnel was also identified.
The problems highlighted by the personnel being interviewed will be addressed and resolved. However, these. problems were not detrimental to the overall performance of the Emergency Response Computer System (ERCS) as an ,
effective tool for managing off normal events at Virginia Power nuclear facilities. .
Page 47
I B'
i V. SAFETY EVALUATION A. Comparison of North Anna Unit 1 Tube Rupture Event to UFSAR Analysis An analysis of a steam generator tube rupture is presented in Section 15.4.3 of the North Anna UFSAR. The analysis considers a double-ended rupture of a single tube at hot full power. Initial break flow rates for this case are calculated to be approximately 710 gpm. An evaluation of the t reak flow rate which results from reaching equilibrium conditions with the safety inj ection flow is presented. A total primary to secondary mass transfer is calculated by conservatively assuming this equilibrium break flow remains at a constant value for a full half-hour. For calculating whole body and thyroid doses at the site boundary, this mass is conservatively increased by 15%. The site boundary doses are calculated based on the assumption of steam release through the main steam safety valves with an initial coolant activity level corresponding to 1% of the fuel in the core being failed. Even with these conservative assumptions, the calculated offsite doses were only a small fraction (less than 2%) of the 10 CFR 100 limits.
I Table V-1 presents a summary comparison of the North Anna event of July 15, 1987 with the analysis results and assumptions of the FSAR. As can be seen by every significant measure, the actual conditions occurring du.ing the incident were bounded by the UFSAR assumptions, in some cases by orders of magnitude. The primary to secondary mass transfer has been calculated by both a RETRAN transient simulation of the event and an independent calculation based on the measured boron concentration in the secondary side of the faulted generator following the event. These results are in good agreement.
Examination of the faulted tube showed that the break was a double-ended break, as addressed in the UFSAR. Break flow rates are highly geometry dependent. The actual break occurred high on the cold leg side of the generator, and the tubes were not completely offset from one another. The effects of the tube length upstream of the break and the likelihood of significant interaction between the flow streams from the two tube segments are therefore the probable cause for the observed break flow rates being less than predicted in the UFSAR.
B. Fuel Integrity Evaluation During the event, the plant was not in any condition which could have compromised the integrity of the fuel. A review of the plant data shows that there was no evidence of reactor coolant system voiding, to core uncovery was precluded. The core thermal limits were not violated at any time during the svent. The closest approach to the thermal limits was during the initial depressurization phase, just prior to the manual reactor trip. A representation of this statepoint along with the therral limits for the reactor condition just prior to trip is shown in Figure V-1. Note there were cubstar. dal margins to both the DNB and vessel exit boiling portions of the limit curves.
Page 48 l
,.i' t
j .-
A point estimate of the DNBR in-the hottest coolant channel in the core at
.this;; point'just prior.to trip was performed using the COBRA code. Assumptions are presented in Table V-2.- The minimum calculated WRB-1 'DNBR was 1.85.
'(compared to a 1.23 limit) .
The' addition of. soluble boron from the Safety Injection System increased the boron concentration of the reactor coolant system by over 300 ppm over' the first. two and one half hours of the event. .This increase provided adequate shutdown reactivity margin throughout the cooldown evolution.
.C. Conclusions The above evaluation has demonstrated that the consequences of the steam generator tube rupture event on July 15, 1987 on North Anna Unit'No. I were bounded by the analysis presented in the accident analysis chapter (Chapter 15) of the UFSAR. In terms of offsite public health consequences, the event had no offect. The core was effectively and adequately, cooled'throughout the' event. '
The integrity of the fuel was not compromised in any way.
1 i
1 l
m_________._____ _ __ _ _ - - _J
---,,-,--------,,-,--------y i
TABLE V-1 NORTH ANNA UNIT 1 STEAM GENERATOR TUBE RUPTURE COMPARISON TO UFSAR ACCIDENT ANALYSIS UFSAR Assumption Coniidsration 7/15/87 Event Or Result ____
1.< Tube rupture arma Double ended rupture of- Double-ended rupture a single tube. . Geometry of a single tube effects reduce the discharge coefficient to less than 1.0
2. . Initial. break flow- Approx. 550-637 gpm Approx. 710 gpm (UFSAR Fig. 13.4-32)
3. ' Integrated primary- Less than 100,000 lbm Calculated:
to-secondary mass 115,000 lbm transfer Used for dose calculation:
132,000 lbm
4. - Initial. coolant .00938E-6 Ci/gm 1%-failed fuel =
activity (Measured 7/14/87) 4.0E-6 Ci/gm
5. Ralease path for Condenser air ejectors exhaust Main steam safety valves radionuclides to Steam driven AFW pump exhaust environment
6. Operator response Approx. 34 minutes 30 minutes d time to' identify accident type and terminate break flow
.to faulted generator
7. Offeite power Available Unavailable 8 .. . Site boundary dose
- whole body 5.78E-4 mrem
350 mrem **
thyroid 1.14E-3 mrem
370 mrem ***
Conservative estimate - no dose rate above background was actually measured
1.4% of 10 CFR 100 limits
0.12% of 10 CFR 100 limits Page 50 L i
TABLE V-2 NORTH ANNA UNIT 1 STEAM CENERATOR TUBE RUPTURE
-COBRA /WRB-1~ POINT ESTIMATE OF MINIMUM DNBR Parameter . Assumption /Value Thermal Power / Heat Flux Rated Thermal Power +2% Unct.
Reactor Inlet Temperature 561 F (strip chart,- SPDS) + 4 F uncertainty Hot Channel F-delta-H 1.510.(1.398 measured on 7/14 with
'8% uncertainty)
RCS Pressure 2070 psig (strip. chart,-
SPDS) - 30 psig uncertainty
_ Reactor Coolant Flow Rate 305,500 gpm (calculated from rated thermal power of observed Thot and Teoid)
Resultant WRB-1 DNBR 1.85 WRB-l'95/95 DNBR limit (with'5% 1.23 retained margin for rod bow) i I
l 4
lI i
Page 51
-as i
I l
\
l Nominal T,,,= 586.8 4 ;
Moninal RCS flov = 289200 CFM ]
643 -
655 2400 psia 654 '
'd 5 - 2250 psia .
848 Ell 3pslo limit 455 850
, gg 2000 ps I828
[ 815 - 1860 psia
SI4 -
885 Set 695 54-
$85 '
Reactor Stats-Just Prior To g -
ggg Trip 675
8. .I .2 .8 4 .5 .8 .7 .4 9 8. 1.1 f.J POWLj _ treactlen er noelnell FIGURE V-1 REACTOR CORF SAFETY LIMITS AND STATE POINT PRIOR TO TRIP Page 52
)
i VI. STEAM GENERATOR EVALUATION A. North Anna Steam Generator Operating Experience i
Since start-up in 1978, Unit I has been on All Volatile Treatment (AVT) chemistry. During February 1979, powdex resin was inadvertently introduced into the steam generators. During the resin intrusion event, the resin decomposed to form sulfuric acid, lowering'the steam generator pH to 6.02 and increasing the cation conductivity-to 25.0 micro-mhos. Two other less severe intrusion events occurred in July and September of 1979. During the September 1979 refueling outage, tube denting was identified in the hot leg, and a boric acid treatment was initiated. Unit I has operated in accordance with Westinghouse recommendations for use of a boric acid treatment since 1980.
Subsequent inspections have confirmed denting at the hot leg tube support plcte ,
locations. However, the denting has not resulted in extensive tube '
deformation. Recent -comparisons of data taken in 1984 and 1987 indicate that '
the growth in both the number of dented intersections and extent to which intersections have been deformed has been essentially arrested.
Tube degradation involving primary side cracking of the Row I and 2 U-bends has j also been observed (during the 1979 inspection on Row I and during the 1987 j inspection on Row 2). . Preventive plugging of Row I tubes and stress relief of unplugged Row 2 tubes in the threa steam generators has been accomplished to address these issues.
Unit I was removed from service for refuelin g outages beg _aning in December, 1980 and again in May, 1982. During both outages, all three steam generators were examined using eddy current in accordance with the facility Technical Specifications. No significant indications were observed.- Duritg the May, 1982 refuelit g outage, partial tube end repair was performed in steam generators A and C. Broken split pins from the upper internals package of the reactor vessel had migrated to these steam generators and damaged the tube ends. This damage only affected the ability to insert an eddy current probe.
The integrity of the steam generator and its sbility to perform its intended function were not compromised.
The first significant indication of steam generator tube corrosion on North Anna Unit I was in December 1983. Primary to secondary leaktge in Steam Generators "B" and "C" increased to a maximu'n value of 396 gallons per day (gpd). The unit was shut down Ianuary 10, 1984, and a visual inspection of both steam generators during a hydrostatic test showed a total of five (5) ,
leaking tubes and four (4) leaking explosive plugs between the two steam generators. A total of 579 tubes were inspected in Steam Generator "B" during the outage. Four (4) tubes were identified with greater than 40% wall indications at the tube support plates while 13 tubes wore identified as having significant distortion. All leaking tubes exhibited eddy current indications, but none of the signiffsantly distorted indications were identified as leakers.
In Steam Generator "C", a total of 552 tubes wsre inspected. Four tubes contained deep eddy c'urrent indications and.were plugged. Also, one tube was plugged preventively. Additionally, two tubes were identified as having distorted indications. The unit returned to service in February and operated until the scheduled May 1984 refueling outage.
Page 53 j
Steam -generator activities during the May 1984 refueliig outage included complete eddy current inspection in all 3 steam generators and an attempted tube removal effort. A total of eight tubes in Steam Generator "A", 1 tube in Steam Generator "B", and 4 tubes in Steam Generator "C" exhibited eddy current indications greater than 40% thorough-wall. Additionally, 2 tubes in Steam Generator "A" and 1 tube in Steam Generator "C" were plugged as a preventive measure. Complex signal distortions arising from denting, copper, and magnetite were also observed during this outage, but not recorded. Two attempts were made during the outage to remove a tube from Steam Generator "A", 3 but both were unsuccessful. l The unit returned to service in September 1984 and operated until August 2, 1985 when the unit was shutdown again due to primary to secondary leakage.
Primary to secondary leakage was first detected in February 1985 in trace amounts. Noticeable step changes occurred in April 1985. The leakage gradually increased to a maximum value of 213 gpd in Steam Generator "A" in late July. The unit came off-line on August 2, 1985, and an inspection of Steam Generator "A" was performed. A video inspection of the tubesheet was performed while the steam generator was filled and pressurized. A total of 3 tubes were identified as leaking. Subsequently, a total of 830 cubes were eddy current tented, twelve (12) of which had pluggable indications (eleven of these were greater than 90% thru wall). Tubes with distorted indications were also identified in this inspection, but none were plugged. Thirteen tubes were removed from service, including one tube which was preventively plugged.
The unit returned to service in mid-August, 1985 with trace leakage in Steam Generators "B" and "C". The leakage suddenly increased after approximately five days online to approximately 90 gpd where it remained until the November.
1985 refuelitg outage. Steam generator activities performed during the i November, 1985 outage included complete eddy current of all three steam >
generators, and the removal of two tubes containing a total of four support plate intersections from Steam Generator "C". The eddy current testing program resulted in the plugging of 43 tubes for indications greater than Technical Specifications limits. Thirty additional tubes containing strong distorted indications were also removed from service for preventive purposes. The unit returned to service in January 1986 with no primary to secondary leakage.
Trace, intermittent leakage was detected in Steam Generator "A" beginning in February 1986.
During the November,1985 refueling outage of North Anna Unit 1, eddy current inspection results at the hot leg support plate intersections of all three l steam generators revealed tubes with eddy current signals in which the interpretation of the extent of tube wall penetration was precluded due to the level of signal distortion crused by tube denting. The eddy current analysis !'
at that time concluded that the signal characteristics were representative of tube wall degradation but because of signal distortion, depth of penetration could not be quartified. Subsequently, in an effort to characterize the type !
and extent of tube wall degradation in the steam generators, Virginia Power had two tubes extracted from Steam Generator "C" and metallographically examined.
The tube examination program conducted included detailed physical measurements of the tubes at the tube support plate intersection locations, characterization of the tube metallurgical structure, chemical analysis of the tube surface deposits, and corrosion testing of the tubing. As a result of the tube examination program, the tube wall degradation has been characterized as outer diameter (OD) and inner diameter (ID) initiated stress corrosion cracking Page 54
(SCC), located within and extending beyond the tube support plate thickness in conjunction with tube denting.
Unit I returned to service following the November, 1985 refueling outage and r operated with only a small amount of primary-to-secondary leakage near the end '
! cycle. The unit was shutdown for refueling in April,1987. During the outage, l an extaisive 100% eddy current program was performed employing the most I advanced eddy current techniques available. In addition, a tube stress relief demonstration program wac conducted at the tube support plate and all available Row 2 U-bends were stress relieved. Indications were found at the tube support plate, the antivibration bars in the area of the steam generator U-bends, and 4 the tubesheet. A total of 263 tubes were plugged during the outage as shown on Table VI-1. In addition, two tubes were removed from Steam Generator "A" for laboratory examination of the tubesheet indications. Currently, the removed tubes as well as the demonstration program for tubes stress relief at the tube support plates are being. evaluated. j Because greater than one percent of the tubes in,the initial tube inspection sample group in the April, 1987 outage were found to be defective, NRC approval of the actions taken to return the steam generators to an operable status was required before returning th it 1 to service. A meeting was held with the NRC on June 3, 1987 to discuss the .esults of the steam generator tube inspections and Virginia Power's plans to evaluate the two tubes that were removed from steam generator "A". Virgh is Power also committed at this meeting to impose a 100 gallon per day limit on primary to secondary leakage for the duration of the upcoming fuel cycle. NRC approval for restart of Unit I was given at this e meeting.
A historical . summary o'. the numbers of tubes plugged in each steam generator by outage date is prceided in Table VI-2. Maps of the locations of the plugged tubes in each of the three steam generators are provided on Figures VI-1, VI-2 and VI-3 for Stear Generators "A","B" and "C", respectively.
I B. Failed Tube Identification, Examination, and Removal j J
1. Steam Generator Cooldown, Flush a d Purge l
(
Following the steam generator tube rupture event on July 15, 1987, a recovery organization was established to provide a technical evaluation of the event, determine the root cause of the rupture, and formulate steam generator inspection plans.
Initially, Steam Generator C was filled with a mixture of primary and secondary coolant at a level of approximately 63% (wide range). Beric ccid concentration was approximately 814 ppm. Both radioactive and j nonradioactive gases were present in the steam generator. Hydrogen l concentration was found to be approximately 15% at the time of venting.
i Reactor Coolant Locp C was isolated on the primary side by closing the l loop stop valves. Ove r the course of the next several days, plans for j venting Steam Generator "C" were developed. Gases were vented by the process vent system via the waste gas processing system. This method !
I provided a controlled, monitored release path for the gases. At no time did this controlled release pose a threat to safe operation or to Page 55 l
l
the public. Operations were conducted in accordance with approved procedures and were carefully controlled. Preparations were also made and completed to establish a cold shutdown, degassed condition for the rest of the reactor coolant system and to place Steam Generators "A" and "B" in a wet lay-up condition.
The next activity was to drain the primary side of Steam Generator "C". The purpose was twofold. One, inspection of the secondary side of the steam generator would eventually require that the primary side be drained and dry. Tuo, this draining would establish the approximate elevation of the primary-to-secondary leak and aid in further developing the inspection and recovery plan. This plan would consider location, past history, and inspection plans and techniques.
The steam generator was filled with nitrogen on the secondary side as level decreased during the primary drain. Because of the tube :
rupture, Steam Generator "C" could not be cooled down in a normal manner and cooled down at a slower rate. The proposed inspection plan included .the use of eddy current and optical viewing equipment which has specific maximum operating temperatures. Thus, it was necessary to refill the steam generator with cool water to reduce its temperature. After the fill to approximately 90% was complete, the secondary side water drained through the ruptured steam generator tube. When the draining stopped, the elevation of the leak was confirmed to be in the vicinity of the 7th support plate. The primary side of Steam Generator "C" was drained and the manways removed.
2. Identification of Ruptured Tube With the primary side now accessible, the location of the leak was determined by the presence of water at the tubesheet. A slight increase in the secondary side water level was made to make the location more evident. The leak was located at Row 9, Column 51.
With this location established, past experience and examination information were reviewed for use in revising the inspection and recovery plan for Steam Generator "C". The steam generator secondary side was then drained.
In the past this tube was inspected twice, from the hot leg side through the seventh support piste on the cold leg side, during the refueling outages of September, 1979 and December, 1980. More recently this tube has been inspected on the hot side through the 7th support plate, hot leg. No indications were found using the (standard) bobbin coil eddy current device.
I
3. Eddy Current Testing (ECT) and Video Inspection ;
{
Equipment needed to examine the leaking steam generator tube was j The leakt g tube was first inspected placed in the primary side.
using an eddy current probe. This examination provided the exact location of the leak and some limited information about the size and extent of the failure. Following this activity, the tube was viewed from the cold leg side using a fiber-optic device. The exact location and extent of the break was determined. The ruptured tube was Row 9, Column 51 at the 7th support plate on the cold leg side. The tube was Page 56 I I
j
broken circumferential1y and'the tube ends separated to approximately.
one-half inch above the tube support plate.
The fracture surfaces were viewed three times. The fiber-optic device L was inserted into the cold leg twice in order to view the . hot leg surfece. The device was inserted into the hot leg side and pulled l over the U-bend once in order to view the cold leg surface. These observations enabled an initial assessment of the fracture surface and' potential failure mechanism. 1n 0 all three occasions the surfaces were viewed using. a straight ahead approach and a right angle viewer. If the tube removal had not been successful, this information would have been available for further review. In addition, information obtained from the viewings has been useful in the development of the tube stabilization process.
4. Tube Removal The next phase of the evaluation was the removal of.the failed tube for. laboratory analysis, both nondestructive and destructive.
Initially, tube removal'was coupled with stabilization of the U-bend and hot leg portion of the failed tube. Further evaluation of available techniques permitted tube removal to proceed independently from tube stabilization.
The ID of the' cold: leg side of the failed tube was measured for ovality using a profilometry device. This measurement was taken to determine if the tube had been dented which may have prohibited tube removal. The results indicated that tube removal could proceed. The-steam generator' supplier was asked to remove the tube using previously used, and thus proven, removal procedures. Approximately thirty.one
.(31)' feet of straight tubing had to be removed to obtain the fracture surface.
The tube removal was successfully accomplished. The breakaway tensile load was approximately 14,000 pounds. During tube movement the
. maximum tensile load was near 10,000 pounds, which decreased to less than 500 pounds during the removal operation. Elongation, measured in inches, occurred during removal, principally in the upper most portions of the tube. Nine (9) sections in lengths varying from 47.5 inches to 32.5 inches were obtained. The tube sections were'placed in a shipping cask and sent to the laboratory for analysis. A more detailed description is contained in the Westinghouse Electric Corporation Report on the tube failure.
C. Failed Tube Evaluation
1. Metallurgical Failure Analysis
a. Introduction Tube R9C51 in steam generator C of North Anna Unit 1 was observed by Endoscope examination, prior to the tube pull, to have severed circumferential1y immediately above the seventh cold leg support plate. A tube pull removed the cold leg segment of the tube from the tubesheet bottom to the fracture face at the top edge of the Page 57
i seventh support plate. . The following summarizes the findings of the failure analysis which was conducted on.the fracture face.
'b.1 . General Condition and Properties of.the Pull'ed Tube The cold leg tube segment.,was removed with :0.9 inches of elongation ( occurring during the tube pull. The elongation was-observed to be confined'to above the third support plate and 'to increase 'with increasing elevation.
The tube 'remcyal ' data suggest'that support plate dent:.ng in~the upper cold leg support plate ~.. restrained the tube during. the tube pull. (Field eddy current' profilometry also showed denting at these.. locations)..
From a' region of the tubing where no tube pulling elongation occurred,;two room temperature tensile specimens 'were. obtained and' pulled. .Results from these test agreed closely with 1971 tubing certification data for the heat in location R9-C51. These mechanical property values are considered typical of. tubing in North Anna Unit 1. The microstructure appears typical of mill y annealed ' Alloy' 600 in. North Anna Unit 1. The grain size is small, ASTM 9.5.
c. NDE Examination.of Seventh Support Plate Region Radiography, consisting of double wall radiographs taken at- 4 rotations' 00* apart and of a single wall radiograph using a rotisserie technique, revealed no indications in the seventh' support plate . region other than the fracture at the top edge of L .the support plate location.
Eddy current examinations were also conducted on the seventh support plate region using bobbin, 8 x 1, RPC, and OD pencil-probes. No indications were observed below the fracture face in the support plate region.
d. Visual and Macroscopic Examinations of Seventh Support Plate Region For reference purposes, the 45* location corresponds to the plane of the U-bend'. Minimal surface deposits were observed although demarcation of the support plate edges was clearly observed. As will be discussed later, multiple site fracture initiation occurred between approximately 90* and 180*. The tubing between 90* at d 180* is determined to have protrud:.d approximately 0.07 l inches'above the top edge of the support plate (0.82 inches above the bottom edge of the support plate demarcation). This location is the fracture region closest in elevation to the top edge of the support plate. The highest elevation of the' fracture is located at 315* and is approximately 0.17 inches above the top edge of the support plata.
On the fracture face a dark deposit was noted from approximately 90* to 150*. Typically the deposit extends from the OD to 3/4 through-wall, although it may have touched the ID locally. An analysis of these deposits showed that they had a composition Page 58 1
E._ _ _ _ _ _ . _ _ . _ _ . _ _ _ i
similar to adjacent OD deposits and that they contain elements which would be expected from secondary side water-born deposits.
Later it will be shown that fatigue cracks initiated in this location. . The significance of these deposits is that they show the shape of the early micro-crack before faster crack growth rates occurred which did not leave sufficient time for disposition .of water-born material. From the shape of the deposit, it is believed that the micro-crack initially broke through-wall over a 40' crack front that extended from 100*.to 140'. Fatigue striation orientation data, presented later, also support this hypothesis.
Visual examinations ard macroscopic examinations of the fracture surface and the outside surface adjacent to the fracture surface were conducted to determine the surface condition and to determine crack origins and paths of crack propagation. I
e. SEM Fracture Face Examination Scanning Election Microscope (SEM) fractograpinc examinations of the fracture surface confirmed the conclusions of the optical-microscopic examinations that the crack origins were located on the outside surface. At low to intermediate magnifications, the fracture (in the 30' to 210' portion of the fracture) has a transgranular, feathery, cleavage-like, faceted appearance. The feathery appearance results from microscopic tear ridges (which, like macroscopic tear ridges, run in the direction of local crack propagation) and small regions of ductile fracture (produced by ductile cutting) which interconnect multi-level, fingerlike plateaus and sub-regions on those plateaus. Dimpled rupture (the predominant mechanism of ductile, overload fracture) was found only in the final portion of the fracture (from about 210' through 360* to the 15' portion of the fracture). At higher magnifications frequent variations in the direction of. local crack propagation of nearly +45' (both vertically and horizontally), could be noted as indicated by I
changes in the orientations and directions of the plateaus.
Crack growth occurred simultaneously along facets at different levels so that tear ridges and undercutting of one facet by another was a common occurrence. Such phenomena are common to fatigue crack propagation.
One definitive feature of fatigue cracks that is often observed is the presence of numerous, usually evenly spaced, striations that run perpendicular to the direction of local crack propagation. The striations develop as a consequence of repeated blunting and resharpening of the crack tip during the cyclic applications of load, so each striation marks the position of the l
crack tip at the time it was formed.
1 Striation-like markings could be seen at very high magnifications during the SEM fractography. The striations appear like those that occur in fatigue fractures inasmuch as they run perpendicular to the direction of local crack propagation; however, the resolution by SEM was not adequate to determine if l l
l Page 59 j
u i
1 4
m h the spacing is uniform or random or to determine the striation p 8 pacing.
$ No intergranular cracking was found at any position in the l' fracture. This total absence of intergranular cracking eliminates the possibility that cracking initiated as, or propagated by, intergranular stress corrosion cracking. On the other hand, these fraccographic features are typical of both ;
high-cycle fatigue and transgranular stress corrosion cracking in
( austenitic steels, although transgranular stress corrosion cracks are usually branched and rarely occur in Alloy 600.
f. TEM Fractographic Examination Transmission Electron Microscope (TEM) fractographic examinations were performed to provide the extra resolution to definitively
[?
determine if the striation-like markings observed during SEM fractography were indeed fatigue striations and to provide b quantitative data pertaining to the spacing of the striations.
Two-stage carbon replicas were utilized for this examination.
The first stage consists of a cellulose acetate replica of the i entire fracture surface. The second stage consists of making small carbon replicas (usually referred to as grids, since small h metallic grids are used to support the frag!1e carbon replica) from selected areas of the. cellulose acetate replica. Actually, f
i three sets if replicas were made: two before Endex cleaning (cathodic desealb g of oxide deposits) of the fracture surface and the third after Endox cleaning of the fracture surface.
g. Summary and Conclusions Fatigue was found to have initiated on the outside surface of i Tube R9C51 (cold leg) immediately above the 7th cold leg support i plate. No evidence of accompanying intergranular corrosion was s observed on the fracture face or on the adjacent outside l surfaces. Multiple fctigue initiation sites were found over a region from 90' to 180* with major sites located at 110', 120*,
l 135', and 150*. The plane of the U-bend is located at 45' with the orientation system used or approximately 85* from the geometric center of the initiation zone. High cycle fatigue striation spacings approached 1 micro-inch near the origin sites.
]
From approximately 100* to 140' the early crack front is believed j to have broken through-wall. From this time on, crack growth is j believed (as determined by striation spacing, striation i direction, and later observations of parabolic dimples followed j by equiaxed dimples) to have accelerated and to have changed ;
direction with the resulting crack front running perpendicular to 1 the circumferential direction. The crack front moved more j quickly and extended approximately twice as far in the clockwise l i
direction than in the counter clockwise before final tensile overload occurred which resulted in the final severing of the tube between approximately 315* and 15*. This would indicate that more than pure vibratory bending normal te the U-bend plane .
was involved in the fatigue failure and that torsion or eccentric loading may have contributed to the fatigue growth.
Page 60
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se,,,
l, 2.- Causative Mechanism and Corrective Actions Summary T I 'Upon gaining' access tot 'he steam generators, the primary focus of the outage and technical efforts were to:
L.
1.- Determine the root cause of the failure
2. Ascertain the condition of the steam generators, particularly
.with respect to the failure mechanism.
3. Ferform the necessary corrective actions to preclude the future b' occurrence of a tube rupture event.
The conclusions from each of these areas are summarized below:
F Root Cause of Failure Based upon detailed evaluation of the failed tube fracture face, the cause of_the failure has been firmly established to be fatigue. No evidence of any significant intergranular corrosion was observed on or immediately adjacent to the fracture surfaces. High cycle fatigue g _ striations were present and were measured to obtain the stress
-intensity which led to initiation of the fatigte crack and crack 3
propagation. Further, based upon the mode of crack propagation, leakage was concluded to have occurred between the time of complete through-wall _ development of the crack front and the final circumferential break.
The orientation and spacing of the striations led to the conclusion that normal design operational loadings were not sufficient to lead to the fatigue' failure. Therefore, some other loading mechanism was acting on the tube to induce the failure. Messirements of the striation spacing provided necessary data to determine the range of loadings that led to eventual fatigue of the tube. Adverse flow mechanisms were evaluated such as turbulence, vortex shedding, and fluid elastic excitation. After careful consideration and revfew of the data on hand, fluid elastic excitation was concluded to be the only mechanism that could provide sufficient loadings or alternating dtresses to induce fatigue.
In parallel, as a means of verifying the striation spacing measurements and resulting loading conclusions, a second method was utilized to determine the loadings. This method entailed using the L
tube dent data (obtained through profilometry and physical measurements) and finite element analysis to establish the mean stress through the dent. Using this mean stress data, the dented
" configuration and the fatigue curve, the alternating stress intensity required to initiate a fatigue crack was determined. This calculated q ranFe of stress intensity supported the conclusions made from the
< striation spacing measurements.
Finally, the fluid elastic stability ratio was defined for the failed I tube. This calculated ratio was determined using the current North L Anna flow parameters. Engineering assumptions relatf_ve to the degree of damping of the tube were made. Analytical calculations Page 61
demonstrated that the tube would be more susceptible to fluid elastic instability due to lower damping caused by denting. Simulated shaker tests supported the conclusion that in this regime of low damping, Row 9, Column 51 would be fluid elastica 11y unstable. Prior, separate leak tests on fatigue cracks were used to develop a crack leak rate model. Correlation of actual North Anna Unit I leak rate data with the crack leak rate model further substantiates the assumption that the failed tube was fluid elastica 11y unstable.
In summary, the destructive examination and later analytical analyses revealed:
1. The tube failed due to fatigue.
2. Normal design loadings were not sufficient to provide the alternating stress intensities which would initiate and propagate fatigue cracking.
3. Striation spacing measurements were made and used to determine the actual loadings experienced.
4. Fluid elastic instability was concluded to be the mechanism by which the loadings were applied.
Steam Generator Condition As discussed in Section VI.D., no indications of a circumferential nature or suggestive of the same failure mechanism were found at any seventh support plate location. This is consistent with the fatigue mechanism described in the previous section. The vast majority (90-99%) of the fatigue process lies in the working (via alternating stress) of the tube. Once the fatigue crack initiates, the time required to propagate the crack, is comparatively small.
Additionally, a large number of antivibration bar (AVB) indications were identified. While this is not unusual in a Series 51 l
k' westinghouse steam generator, a few indications were identified as far down as Row 8. In order to obtain additional data, extensive mapping of Rows 8 through 12 was performed, using eddy current techniques, to
) identify AVB locations. This analysis revealed that the majority of l the Row 9, 10, and 11 tubes are supported by AVBs, but the failed tube ras not supported. Correlation with th: known deflections required to provide sufficient stress to in?;1 ate fatigue show that the AVBs limit the tube motion to below the required deflection limit. This data provides further support to the conclusion that the loading mechanism was fluid elastic excitation.
Corrective Actions In order to preclude future similar tube failures, Virginia Power has undertaken an aggressive repair program. This program consists of several tiers, each of which on a stand alone basis should prevent this mechanism from resulting in a similar tube rupture event. These actions are summarized below and consist of installation of a Page 62
I l
i downcomer flow resistance' ring, preventive plugging of potentially >
susceptible Row 8, 9,10 and 11 tubes, and as a means of final -
j defense, an augmented leakage surveillance program.
- Downcomer Flow Resistance Plate A downcomer flow resistance plate has been manufactured and installed in North Anna Unit 1. The effect of installing this plate is to reduce the recirculation ratio. Reducing the ratio reduces the mass flow in the U-bend area which in turn results in reduced loadings on the tubes. Based upon analysis of the loadings and damping assumptions, it is estimated that over a 15%
improvement in the stability ratio can be expected by installing the resistance plate. This should provide sufficient margin to preclude fluid elastic instability in Rows 8 through 11.
Preventive Plugging The second tier of corrective actions encompasses preventive plugging of susceptible tubes located in Row 8 through 11. The essential criteria for identifying specific tubes for preventive plugging is that they be unsupported by at least one AVB. All such tubes will be plugged. On the cold leg side, each tube meeting this plugging criteria will be plugged with a sentinel plug. The sentinel plug will permit internal pressurization of the tube and low level leakage in the event a through-wall crack develops in the plugged tube. This will serve as an early warning detection method for occurrence of a similar circumferential break of a plugged tube, prior to substantial interaction with a neighbor tube which is in service.
i In summary, the root cause of the failure has been established.
Substantial evidence exists, through close scrutiny of the tube in the laboratory, analytical calculations, and observations made from the field eddy current data to support fluid elastic excitation as the primary operational mechanism that induced the fatigue failure. -
In response, Virginia Power has employed e three tiered, redundant action plan to prevent similar steam generator tube failures. This approach relies principally on reducing the loadings experienced by susceptible tubes through the installation of the downcomer plates.
The second line of defense is the preventive plugging of susceptible tubes. Although the downcomer modification is expected to provide sufficient margin to preclude instability, preventive plugging was performed to further reduce the probability of a tube rupture.
Further the sentinel plug will assist in providing information relative to the effectiveness of the modification. Finally, the last line of defense is enhanced leakage monitoring and the establishment of a leak rate limit. In the event that the downcomer modification and preventive plugging are unsuccessful in precluding the occurrence of a similar fatigue failure, the implementation of an enhanced monitoring program should provide sufficient notification to permit the orderly shutdown of the unit prior to the tube rupturing.
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i 1
3. Leakage Prior to the Tube Rupture i l
Prior to the failure of tube R9C51 on July 15,-1987, the Control Room 4 Operators had no indication, on the instrumentation normally used to ~!
I detect primary-to-secondary leakage, that leakage was increhsing.
However, a post-event analysis of other data collected prior to the rupture does show that primary-to-secondary leakage "as present and increasing for a significant period of time prior to the rupture.
During operation, primary-to-secondery leakage is normally determined once per week by performing a mass balance calculation based on the activity concentration of the radioisotope Na-24 present in water samples drawn from the Reactor Coolant System and the secondary side of each of the three steam generatorn. The presence of Na-24 in the steam generator samples indicates a primary-to-secondary leak and, by performing the mass balance calculation, the leak can be quantified in
. gallons per day (gpd). This technique requires several days at equilibrium power level conditions in order to satisfy the assumptions used to derive the calculation.
The Control Room Operator has available several other methods of detecting the presence of primary-to-secondary leakage, but these methods do not allow quantifying the leak rate. Radiation monitors installed on the steam generator blowdown lines and on the condenser air ejector discharge line monitor the total activity present in these paths. Increased count rates on these monitors indicate increased activity which may be due to increased primary-to-secondary leakage.
These instruments provide readout indication in the Control Room and will activate an alarm upon exceeding a setpoint. The alarm setpoint values prior to the rupture were selected based on insuring that no r
echnical Specification radioactive release limits were exceeded. The setpoints were not selected to give an alarm on exceeding a set value of primary-to-secondary leakage. While there is a correlation between the count rate indicated on these instruments and the primary-to-secondary leak rate, it is not quantifiable without performing a calculation which was not derived prior to the rupture.
Prior to the rupture, the primary-to-secondary leak rate was i determined, using the Na-24 technique, on July 6 and on July 13 and showed no significant leakage. Both of these leak rates were determined with the unit at non-equilibrium conditions. The blowdown radiation monitors showed no significant increase in count rate prior to the event. The air ejector radiation monitor did show an increasing count rate prior to to the event as shown in Table VI-3.
As described in Section II.B., this monitor had been declared inoperable at 0809 hours0.00936 days 0.225 hours 0.00134 weeks 3.078245e-4 months on July 13, 1987, returned to service at 0815 hours0.00943 days 0.226 hours 0.00135 weeks 3.101075e-4 months on July 14, 1987, and declared inoperable again at 2238 on July 14, 1987. While the increase in count rate on the monitor was significant, it was not judged to be abnormal and, at that time, was felt to be associated with the ramp up to 100% power.
As a result of the air ejector radiation monitor being inoperable, grab samples were collected and analyzed to insure that radioactivity release limits were not exceeded. The results of the isotopic analysis of these samples are shown in Table II-3.
l Page 64 l
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1 i
Following the tube rupture,-it was deemed important to determine if there was, in fact, priwary-to-secondary leakage prior to the rupture.
Careful. review of available~' data showed there were, in fact, indications of leakage in the air ejector radiation monitor count rate readings and in the grab sample analysis results. An engineering study was perfcrmed to verify this and to quantify the amount of ,
leakage. I To quantify leak rate using air ejector radiation monitor count rate, a formula was derived using count rate, air ejector flow rate, primary system Xe-135 concentration and a constant. To derive the constant, data collected during the period from January 12 through' April 13, 1987 was used. -During this. period, just prior .to the refueling
- outage, the unit was at power with known primary-to-secondary leakage.
Sixteen calculated primary-to-secondary leak rates performed using the-Na-24 method were used in the formula K = (prinary Xe-135)(Na-24 leak rate)
(air ejector flow)(air ejector count rate) to calculate the constant as shown in Table VI-4. Once the constant was derived, it was used in the formula Estimated Leak Rate (gpd) = K(air ejector flow)(air ejector count rate)
(primary Xe-135) to estimate the primary-to-secondary leak rate present prior to the rupture. The results are shown in Table VI-5. It should be noted that, because these calculations use available data points, such as air ejector count rate and primary system Xe-135 concentration, which were collected for other reasons and, therefore, were not timed to be taken concurrently, the estimated leak rate values are subject to some error. They should not be used to quantify a specific leak rate at a given point in time. However, it is valid to use these calculations to establish that leakage was present and that it was increasing prior to the rupture.
A second method of estimating primary-to-secondary leak rate is to use the data available from the grab samples taken on the air ejector.
These samples had been analyzed and the concentration of radioactive gases present determined. This data is presented in Table II-3. In addition, primary system samples had been collected and analyzed prior to the rupture. While these samples were not collected at the same time as the air ejector grab samples, their results can be used to estimate the concentrations of the various gaseous radioisotopes !
present in the primary coolant at the time the air ejector grab l samples were collected. These estimated' concentrations can then be used to perform an isotopic balance calculation of estimated primary-to-secondary leak rate. The formula used is Estimated Leak Rate (gpd) =
(Air Ejector Activity)(Air Ejector Flow)(Primary System Volume)
(Primary System Activity)(Primary System. Mass) 1 Page 65 l l
I JThe results of these calculations are'given in Table VI-6. It should be noted that the last air ejector grab sample was collected ' at 0620 on July .15, 1987, just minutes before the rupture occurred. Again, the'results of these calculations are subject to some error due to the -
timing of sample collection and the use of estimated primary system activities. They do, however. 'give positive indication that primary-to-secondary leak rate increased significantly over an appreciable period of time prior to the tube rupture.
By combining the two sets of estimated leak rate data and plotting the.
results (Figure VI-4), .it can be seen that the mean estimated leak rate increased by almost three decades in the 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months prior to the rupture. Also, the. mean estimated leak rate exceeded 100 gpd !
approximately 19 hours2.199074e-4 days 0.00528 hours 3.141534e-5 weeks 7.2295e-6 months prior to the rupture and exceeded 500 gpd approximately .6 hours prior to the rupture. .It should be noted that these magnitudes of leak rates are still low enough that RCS pressure-
'and inventory are not noticeably affected.
The conclusions reached based on the above calculations using two
,- different sets of data are as follows:
1. Primary-to-secondary leakage was present prior to the tube rupture,
2. The leakage increased significantly over time, and
3. The lesk rate reached a detectable level well before the tube ruptured.
The above conclusions are supported by the resulta- of the metallurgical examinations, which indicate that the crack opened-through-wall over a 40* to 60" arc and then proceeded to propagate around the circumference until final failure occurred. Based on the results of leak rate testing, a 40" to 60* circumferential crack would be expected to result in a leak rate of 50 to 100 gpd. This leak rate would increase dramatically as the crack propagated.
4. Establishment of a Primary-to-Secondary Leak Limit Although the removal from service of those tubes which may be subject to fatigue failure and the installation of the downcomer flow resistance plate provide a high level of assurance that no fatigue failures will occur in the future, it is prudent to establish operating limits which will allow unit shutdown prior to rupture if such an failure should occur. It has been shown in the previous section that fatigue failure does result in detectable Icakage for some extended period prior to rupture. Therefore, a shutdown limit based upon leak rate may be established. This section will develop the basis for that limit.
The limit established must provide sufficient time to allow a reduction in power to that level below which a fatigue crack will no longer propagate, followed by a unit shutdown. The leak rate limit should also be large enough to allow for positive detection.
Page 66
.l' In order to establish"the limit, it..is first necessary to establish the' time required to bring the unit to a safe power level and then, using the results of the analyses performed, determine the leak rate predicted at that . time. Also, in order to insure that sufficient ,
margin exists in the limit, various conservatism will be used. To ;
establish the time required, the following factors will be used- 1 l
1.. The unit will be brought to less than or equal to 50%. power to atop crack propagation,
~
2. The time required to detect the leak rate exceeding the limit is 60 minutes,
3. The time required to initiate a power reduction and bring As unit power below,50% is 30 minutes, and i
~
4. The leak rate indication underestimates actual leak rate by 50% -
These factora are conservative in that:
1. A preliminary analysis shows that, assuming a crack angle of 120' to 180*,- reduction of power below 50% will bring the stability ratio below 1.0. At that point, crack propagation will cease.
Work is in progress to verify.the calculations used to support this conclusion.
2. The installation of the N-16 detector, which provides continuous indication of leak rate in units of gpd and is alarmed, will provide rapid indication of increasing leak rate. In additicn, the air ejector radiation monitor alarm will be set at a value which will provide timely indication of increasing count rate due to increased. leak rate. Either of these indications should allow
-for' identification of excessive leakage within a few minutes.
3. Once excessive leak. age is identified, the unit can be reduced in power level at a rate of 3% per minute. This rate of power ;
decrease is well within the ability of control systems. At this !
rate, a reduction of 50% power will take 17 minutes. (If necessary, higher power decrease rates can be used.)
4. The N-16 monitor has an error band of +10% when calibrated .
~
against a known leak rate. When calibrated using calibrated transfer coefficients, the error band is +30%. Therefore, a +50% )
error band is conservative for establishing the alarm setpoint.
]
.By using a total time of 90 minutes to identify excessive leak rate and reduce power to below 50% and assuming a post-modification maximum stress amplitude of 7 ksi, a leak rate limit of approximately 500 gpd is obtained from the leak rate versus time curve contained in the I Westinghouse report on the tube failure. If the 50% indication error band is applied to this value, the leak rate limit is approximately 333 spd. If the curve for a mean stress amplitude of 5 ksi is used, a j leak rate Ifmit of over 1000 god is obtained. This curve is felt to !
be more representative of actual conditions and correlates with the I actual conditions observed during the rupture of tube R9C51.
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Ikvever, to be conservative,. the value obtained from the curve for 7 ksi will be used. In view of this fact, the current, administrative 1y imposed leak rate limit of 100 gpd due to the presence of axial stress corrosion cracking at the tube support plates is considered bounding and will remain in effect.
D. Steam Generator Inspection
1. Eddy Current Inspection Methods and Scope Preparations were made to nondestructively examine each steam generator using various eddy current testing (ECT) techniques. Eddy current testing is the principal method used for performing tube ;
inspections. This inspection method involves the insertion of a test coil inside the_ tube that traverses the tube length. The test coil is excited by alternating current, which creates a magnetic field that induces eddy currents in the tube vall. Disturbances of the eddy currents caused by flaws in the tube wall will produce corresponding changes in the electrical in.pedance as seen at the test coil terminals. Instruments are used to translate these changes in test coil impedance into output voltages which can be monitored by the test -
operator. The depth of the flaw can be determined by the observed phase angle response. The test equipment is calibrated using tube specimens containing artificially Induced flaws of known depth.
It was planned to use (standard) bobbin coil, the 8x1 probe, and the rotating pancake coil (RPC) probe. The bobbin coil probe detects ID ,
and OD axial flaws with good resolution. It is used to implement the facility Technical Specification required sampling program. The 8x1 probe locates both ID and OD circumferential indications and ID and OD axial indications. Finally, the RPC probe is similar to the 8x1 probe detection capability, but moves at a slower speed. RPC was used to verify signals of interest from the bobbin and 8x1 probes.
The following inspection plan was implemented:
All 3 steam generators standard bobbin coil probe of the tube portions not inspected during the previous (April,1987) refueling outage
-- 8x1 probe of the hot legs and the cold legs through the seventh tube support plate P
--- RPC of 8x1 indications
-- profilometry of selected intersections j
'C' steam generator additional inspections
-- Technical Specification required inspection, tubesheet to tubesheet.
Page 68
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h. .
:2. . ECT Analyst-Qualification.
A .spe'cific steam . generator eddy current data analysis program was
~
implemented for.the' inspection plan discussed above. This program y
' ensured' that 'the' evaluation of the eddy: current data would be of the '
L' , highest quality possible.- The program contains five elements which-are designed to meet this goal. They are:
a)' demonstration .of the ability to correctly interpret data by each analyst;
.b) data evaluation by two analysts working independently (of each other);
c) reporting of any indication on which agreement of interpretation was difficult to obtain; d) written " analysis rules" which provide instructions about-interpretation of signals specific to North Anna; and, e) all. complex indications are considered relevant until dispositioned by RPC or until more definitive rules for bobbin or 8x1 are established. j Analysts evaluations'were categorized as follows:
. a) for bobbin, clear indication (in percent, %, of penetration depth), distorted' indication (DI), and tubesheet indication (TI);
and, I b) for 8x1, possible indication (PI).
RPC was. used to verify those indications determined to be DI, TI, or .l PI.
3. ECT Data Evaluation Methods The data acquisition system consists of a Remote Positioner (SM-10), a ,
MIZ-18 Data ' Acquisition System, and a DDA-4 Display and Evaluation !
System to monitor data acquisition.
SM-10 is a fully automated computerized positioner designed to I automatically locate and verify the position of steam generator tubing. The functioning of the SM-10 is verified by two remotely operated cameras. One camera is attached to the actuator ann.
Benchmarks such as plugged or marked tubes are used to ensure the accuracy of the remote positioner.
The 'MIZ-18 acquisition system is attached to the SM-10 via a conduit system. Eddy current calibration' standards are connected in series with.the conduit to facilitate system calibration.
The MIZ-18 functions as a probe pusher and an analog-to-digital converter.
Page 69
E Analog' signals are converted to a digital format within the MIZ-18 for
-display on a DDA-4 Evaluation System.
Prior to probing tubes, the ' system is set up and configured. .The L MIZ-18 then acquires 100 percent of the eddy current' data within the
' configuration parameters.
I The DDA-4 Evaluation System is used to monitor data acquisition and to evaluate.the results of eddy current testing. During data acquisition the DDA-4 is used to verify the extent of examination and to ensure the eddy current . probes are functioning properly. During data acquisition, eddy current data are stored on standard VHS magnetic tapes.
Following data acquisition the' tapes are duplicated for primary and secondary data , review. Because the data are acquired digitally, the-data analyst can independently calibrate and mix any of the 16 channels of eddy current information acquired. Several software packages have been written for DDA-4 which' allows the evaluation of standard bobbin,'8x1,-and RPC eddy current data.
When a. tape is to be evaluated by the eddy current data analyst, . he-calibrates the DDA-4 in accordance with a written procedure utilizing the calibration standards recorded on the tape. He then reviews each tube recorded on the tape. The results of the review are stored on a floppy disk. The two reviews are compared and the differences are arbitrated.via a resolution process.
Following' resolution, the final results are stored on the "Supertubin" Data Base system.
4. ECT Inspection Results The inspection plan discussed earlier was implemented to collect data for analysis of the current steam generator condition. This data was then analyzed and, based on the plugging criteria discussed later in this report, appropriate tubes will be removed from service.
Identified indications were either present in the April, 1987 refueling outage with no discernable change indicated or in previously uninspected portions of each steam generator. Additionally, a review of the data from the last outage using the current analysis rules revealed several tubes that should now have a pluggable call placed on them. This apparent, though not actual, change in the steam generator condition is due to the change in the analysis rules and increased awareness by the analysts of North Anna specific ECT signals. A review and comparison of Steam Generator C hot leg data demonstrates that there is essentially no change in tube condition from the April, !
1987 refueling outage to July, 1987 (when the event occurred).
Finally, there were no indications of circumferential nature found at ;
any tube support plate locations, including the seventh tube support j plate. i l
The number of tubes inspected is shown in Table VI-7. Each steam generator contains 3388 tubes. However, tubes have been plugged as previously discussed. The number of non-plugged tubes are:
Page 70
Steam Generator A - 3179; Steam Generator B - 3210; and, Steam Generator C - 3117.
L Tubes to be removed from service based on ECT inspection are listed in Table VI-8. A summary of tubes to be plugged by indication type is provided in Table VI-9.
5. Steam Generator Tube Plugging Criteria Inserting plugs in the hot and cold leg ends of steam generator tubes renders the tube inactive as a primary pressure boundary or heat transfer surface. Plugging criteria have been established to remove tubes from service that may become unserviceable prior to the next inspection. This action assures that tubes accepted for continued service will retain adequate structural margins against a gross tube 1 failure under normal operating and accident conditions. The following plugging criteria were established:
plug all clear indications greater than 40% (This complies with the Facility Technical Specifications.); ;
l plug all confirmed axial indications on which depth of degradation cannot be determined; and, plug all confirmed circumferential indications.
6. Steam Generator Foreign Objects This section discusses the actions taken as a result of the loose parts alarm (Vibration and Loose Parts Monitoring System) received during the event on July 15, 1987.
The permanently installed Vibration and Loose Parts Monitoring System (VLPMS) has sensors located on each steam generator and the upper and lower portions of the reactor vessel. At approximately 0900 on July 15, 1987, a loose parts alarm was received on the control room annunciator system. In response to this annunciator, the Shift Technical Advisor (STA) vent to the VLPMS panel and determined that the alarm came from Steam Generator C. The STA, using the audio portion of the VLPMS, listened to the channel for Steam Generator C.
The noise was characterized as a distinct, sharp, and crisp metallic j noise. The location of the noise within the steam generator could not be determined. Later in the event a similar alarm was received for Steam Generator B. This noise was characterized as a rhythmic, i tapping sound. Following termination of the event with the unit at l cold shutdown, these noises were no longer detectable.
Unit I had recently returned from a refueling outage that began in i April, 1987. During the outage each steam generator was examined for l foreign objects. Foreign objects were found but could not be removed.
A safety analysis was performed which evaluated operation with these objects on the secondary side of the steam generator. The analysis concluded that operation throughout the next cycle was acceptable with these objects present.
I Page 71
)
i l
After cold shutdown was achieved following the event, preparations were made to enter the primary side of each steam generator for eddy I current inspection. The hot and cold leg sides of each steam i generator were observed for loose parts or indications of loose parts.
No loose parts were found and no indications of loose parts impingement were observed. An inspection of the secondary side was then scheduled to examine that portion of each steam generator. In addition, a review of work procedures used during the refueling outage j was performed t6 determine if any foreign objects had been introduced. )
This review concluded that appropriate measures were implemented to control tools and equipment used within the steam generators. 1 A search for ' foreign objects was conducted on the secondary side of )
each steam generator. This examination used high resolution, remote l optical viewing egraipment. One object was located in Steam Generator ,
A. It was a short piece of wire which was removed. One object was f located in Steam Generator B. This was an unrecognizable object that 1 had also been located during the last outage. It was wedged between the tubes and removal was attempted during the last outage but was i unsuccessful. A safety analysis to support continued operation with !
this object lodged in the tubes will be prepared and reviewed by the Station Nuclear Safety and Operating Committee. One object (a small, brittle wire) was found in Steam Generator C. This object was removed. ;
The cause of the loose parts alarms could not be determined. No other plant activities at the time of the alarms correlated to a possible ,
cause. However, based on the inspections conducted, no foreign objects were present that could affect steam generator integrity. l Furthermore, the operability of VLPMS is required by the facility Technical Specifications. Therefore, the system will be available to detect loose parts of a magnitude that could cause damage.
E. Steam Generator Repairs and Modifications
1. Introduction In order to safely end reliably return the unit to service, several i repairs and modifications will be performed. All of these actions are l intended to correct the postulated cause of the Row 9, Column 51 tube I failure, fluid elastic instability. The engineering approach utilized is conservative and redundant in that it involves:
) l l
1. Corrective actions to preclude instability of the failed tube 1 remnant and interaction with neighbor tubes. (Stabilization) I i
2. Preventive actions to minimize the consequences of potential I inst *11ty of the failed tube.
. (Preventive plugging of neighbor tubes with Sentinel plug)
3. Corrective actions to preclude instability of susceptible tubes. j (Downcomer plates) :
Page 72
i
'4 . Preventivefactions to: . minimize- the consequences of continued instability of tubes susceptible to flow induced instabilities.
(Preventive plugging of unsupported tubes with the Sentinel plug)
5. Monitoring of the condition of the preventively plugged tubes to substantiate' the effectiveness of the corrective actions.
-(Sentinel ; ugs).
Each of these actions (stabilization, installation of downcomer plates, preventive plugging of neighbor and unsupported tubes, and use and basis of sentinel plugs) is discussed below.
2. Cold Leg Stabilization
a. ' Description Thermal-hydraulic analysis of the' flow conditions surrounding the Row- 9, Column 51.irdicated that the severed tube U-bend would be fluid elastically unstable during power operation. Once unstable, the remnant section could then impact neighboring tubes
'and ovar time wear the neighboring tubes. As a result, a stabilization technique was developed to secure the tube remnant from the cold leg side.
After removing the cold leg section of tubing from the steam generator, only the hot leg remnant of the tube including the
.U-bend portion remained in the steam generator. A threaded assembly (j ointed spear) was designed and manufactured for
-insertion into the cold leg tubesheet and support plate hole.
The assembly featured the following:
Eight threaded sections, each assembled and inserted into the bare hole.
A locking feature to preclude separation of the threaded sections.
Hydraulic expansions at each tube support plate and into the free end of the remnant. j Roll expansion attachment of the spear to the tubesheet.
b. Verification and Analysis The jointed spear components and design were verified through a combination physical tests and computer analysis. These tests and analyses included:
- Torque and bending tests on the spear to remnant tube joint.
1 Axial separation (pull) tests and cyclic loading tests on both j the threaded joint and on the spear to remnant joint. '
- Tube / spear vibrational analysis.
Page 73
Wear calculations.
All of these analyses demonstrated that the critical components (threaded . joints and spear to remnant joint) would withstand the design bases operational and transient induced forces.
Additionally due to the small gap between the seventh support.
plate and the spear, damping would be higher, further reducing the loadings and susceptibility of the spear to a fatigue failure when compared to a pF 3ged tube configuration.
c. Installation Sequence Installation of the jointed spear is accomplished as follows:
1. The sections of the spear are assembled (threaded together) in the steam generator channel head as the assembly is moved into the tube remnant.
2. After engagement into the U-bend, the jointed spear is hydraulically expanded into contact with the U-bend. This i provides the means of attachment of the spear to the J remnant.
3. The spear assembly is hydraulically expanded at the sixth support. This serves to draw the U-bend down approximately 1/4 inch, precluding contact of the remnant U-bend with neighbor tubes.
4. The hydraulic expansion of the spear into the seventh tube support is next accomplished.
5. The next steps are hydraulic expansion of the lower support plates, starting with the fifth and ending with the first.
6. The final step is to roll the bottom of the spear into the tubesheet.
After completing these installation process steps, the spear is eddy current tested to confirm the existence and proper positioning of the expansions. As the tubesheet end of the spear is approximately 10 inches into the tubesheet, the bare hole is plugged with an Inconel weld plug.
3. Hot Leg Stabilization 1
i
a. Description, Installation, and Verification As a preventive measure, the hot leg portion of the remnant tube i will be stabilized. Stabilization of the hot leg will be l performed using a flexible stainless steel cabic with swaged sleeves at support plate elevations. This stabilizer design is a )
one piece assembly with a swage connection to a standard Inconel ;
mechanical plug.
]
l Page 74 1
- - _ _ _ - _ _ _ _ _ _ _ - - - _ _ I
l:
The stabilizer is inserted into'the remnant tube and extends over
'three inches above the top' of the hot leg leventh, support l plate
.and slightly' into the U-bend.. After proper positioning, the.
mechanical plug is expanded into the tube.
/
No. specific verification' analyses were performed for the hot:1eg
( ' stabilizer used at North' Anna as this type of . design- has been previously tested, qualified and used by Westinghouse at other facilities.
4.' Downcomer Flow Recistance Plates a.. . Description and Installation The downcomer flow resistance plates will be -installed in the secondary.. side of the' steam generator. The plates are welded to the lower deck plate and extend' approximately six' inches into.the annulus of the ~ steam generator. .AL' total of twenty of these plates will' be installed in the annulus.between the wrapper and the shell. In its installed configuration, the plates form a continuous ring between the. wrapper and the shell,
b. Function.
The purpose of installing the downcomer plates is to' reduce the recirculation ratio in the steam generator. Changing the recirculation. ratio will reduce the recirculation flow, thereby reducing the effective velocity.. The effective velocity is one of the key parameters used.in determining the stability ratio.
With- the presence of the.downcomer flow resistance plates, an improvement of over 15%'is expected in the stability ratio.
Such an improvement in the stability ratio should preclude the failure of any of these tubes during the remaining design life of the steam generators.
i
5. Sentinel Plug .
l
a. Introduction In addition to plugging tubes meeting the criteria established in l
Section VI.D.5 of this report, Virginia Power intends to J
preventively plug certain tubes. Such tubes will meet all of the following criteria:
- Susceptible tubes located in Rows 8, 9, 10, or 11.
Unsupported by at least one antivibration bar.
Tubes meeting these criteria vill be preventively plugged on the hot leg side using a standard Westinghouse mechanical plug, while the cold leg side will be plugged using a sentinel plug. ]
Page 75 a
b. Description The sentinel plug is manufactured from a mechanical plug. The stm dard mechanical plug is altered by drilling a small hole in the top of the plug. The hole permits the pressurization of a tube during operation.
However, in the event of a through-wall leak in the plugged tube, the hole permits leakage of primary water into the secondary side. The hole diameter is designed to permit a sizeable leak rate in excess of the administrative 1y imposed limit of 100 gpd, but well under the Technical Specification limit of 500 gpd.
Currently Westinghouse is performing testing to verify the hole diameter size and desired leak rate. Leak rates from 200-400 gpd are being analyzed. .
c. Function As previously stated, Virgi ia Power intends to install these ,
plugs in tubes meeting the criteria specified in Section 4.a.
f. additionally, these plugs will be installed in the eight neighboring tubes adjacent to Row 9, Column 51 in the Steam Generator C. The basis for installing plugs of this design is:
1. Tubes potentially susceptible to fluid elastic instability are preventively plugged. (Thus limiting the effect of the tube failure in the unlikely event the downcomer plate installation does not provide sufficient improvement).
2. In the event that one of theee plugged tubes were to fail by fatigue, it could interact with its neighbors, resulting in a later rupture of the neighbor tube. A sentinel plug would permit prompt identification of the failure of ;ne of the preventively plugged tubes. The unit could be shatdown in an orderly manner, the leaking tube readily identified, and repairs initiated.
3. The plug design precludes the consequences of a tube rupture, but permits the tubes to experience the operational loads, providing additional data on the failure mechanism and the effectiveness of the downcomer modification.
i I
I l
Page 76 L____ _________ - _
TABLE VI-I STEAM GENERATOR TURES PLUGGED BY INDICATION TYPE DURING 1987 REFUELING OUTAGE Total 3
Tube Tubes 2 ,
clear 1 Distorted Sheet _ Plugged S/G Indications Indications Indications This Outage A 25 43 15 83 B 14 37 11 62 0
C- 30 78' 9 118
.1 Clear Indications (defective) -
greater than 40 percent "thru-wall" indications.
2 Distorted Indications - tube support plate indications of undetermined "thru-wall" depth.
3 Tubesheet indications -
not evident on standard eddy current' testing which were identified by the 8X1 probe and confirmed by the RPC probe.
4 Includes one tube that was erroneously plugged.
l l
l 1
Page 77
- _ _ _ _ - - _ _ _ _ - _ - _ _ - _ _ _ _ _ _ i
y s I
{.
TABLE VI-2
. NORTH ANNA UNIT 1 TUBE PLUGGING
SUMMARY
OUTAGE DATE STEAM GENERATOR TOTAL A B_ C_ TUBES September'1979 -94 94 96 284 January.1984 0- 4 5 -9 May 1984 .10 1 5 16
' August.1985 13 0 0 13 g ' November 1985 9 17 47- 73.
' April 1987- 83 62 118' 263 July 1927 1 25 21 39~ 85 i
TOTAL 234 199 310 743
% (6.9%) (5.9%) (9.1%) (7.3%)
Plugging summary is as of 9/14/87 based on ECT results - does not include tubes to be plugged as a preventative measure based on fatigue i considerations or other' concerns. )
Page 78
h I'
Table VI-3
. CONDENSER AIR EJECTOR RADIATION MONITOR COUNT RATE (cpm)
AS RECORDED ON OPERATOR LOGS-D '3 TIME LEAK RATE July 13, 1987 0000-0800- 10 0800-1600 60 1600-2400 282
' July'14, 1987 0000-0800- 450 0800-1600 1000 1600-2400 3000 Page 79
~
, .i Table VI-4
' CONSTANT K'FOR LEAK RATE CALCULATION BASED ON AIR EJECTOR COUNT RATE l
Primary' Air Ejector Air Ejector !
Xe-135 Na-24 Leak Flow Rate' Count Rate DATE (uCi/ gram) Rate (gpd) .ft /3 min (cpm) K
'1/12/87 -1.6E-1 31.4 13.4' 2000 1.87E-4
'1/13/87 .1.5E-1 27.8- .13.4 1930' l'. 61E :
1/19/87.- 1.5E-1 30.6" 14.0 3800 8.63E-5 1/21/87 1.2E-1 31.1 ~13.8 4700 5.75E-5
'/1/26/87 6.8E-2 35.0 '13.6 3000 5.83E-5 2/2/87. 1.5E-1 41.8- 12.9 5700 8.53E-5 .
1 2/23/87 1.6E-1 31.7 14.0 5700 6.36E-5 3/2/87 -1.6E-1 49.3 13.5 4700' 1.24E-4 ,
'3/9/87 9.5E 41.0 15.8 6100 4.04E-5 3/16/87 1.8E-1 37.1 14.9 5300. 8.46E-5 l 3/20/87 1.8E-1 32.0 14.8 7300 5.33E-5 !
3/23/87 2.4E-1 31.9 13.2 8700 6.67E-5 3/30/87 1.8E-1 45.2 12.8 11,300 5.63E-5 4/6/87 8.3E-2 64.4 14.0 14,000 2.73E-5
) 4/9/87 2.0E-1 70.1 13.5 13,700 7.58E-5
-4/13/87 2.1E-1 80.4 14.0 17,000 7.08E-5 AVG = 8.11E-5 i
Were'K,= (primary Xe-135)(Na-24 leak rate)
(air ejector flow)(air ejector count rate)
Page 80
,, 1 .i
'; fh ..
M ,' a 1
-l 1
. Table VI -!
ESTIMATED PRIMARY-TO-SECONDARY LEAK RATE (gpd)
BASED ON AIR EJECTOR COUNT RATE DATE TIME' LEAK RATE July 13, 1987 0000-0800 1.1 ,
b 0800-1600: 4.3 1600-2400 16.4 July 14, 1987. 0000-0800 19.7. I y 0800-1600 43.7 1600-2400 . 121.7 Page 81 l
N
[
Table VI-6 ESTIMATED. PRIMARY-TO-SECONDARY LEAK RATE (gpd)
BASED ON AIR EJECTOR GRAB SAMPLES ,
7/13/87 7/13/87 7/14/87 7/14/87- 7/15/87-
' Isotope: (0900)- (1740) (0114) (2245) (0620)
Ar-41 .28.5 .3.3- .177.4 232.7 5328
-Kr-85m --- ----
136.1 323.2 5676 Kr --- ---
130.0 :255.9 5407 Kr-88 --- ---
150.6 229.6 4860
-Xe-133 --- --- 135.2. 173.0 4494~
,Xe-135 24.5 9.4 152.0 263.2 -3624' AVERAGE 26.5 6.4 146.9 246.3 4898 i
l Page 82 l
_ _ _ _ _ _ _ _ _ - - __ _ i
Table VI-7
^
NORTH ANNA UNIT 1 STEAM GENERATOR TUBES INSPECTED Steam Generator Bobbin 8x1 A 2685 3179 B 2662 3210 C 2764 3117
.i 1
1 Page 83 I i.
. Table VI-8 NORTH ANNA UNIT 1 TUBES TO BE REMOVED FROM SERVICE AS OF 9/14/87 Steam Generator A Row Column Indication 4 19 PI*
27 30 DI 38 33 Broken probe 45 36 PI 21 38 PI 22 38 PI 23 39 TI 13 43 PI 14 43 PI 15 46 PI 15 48 PI 32 47 TI 25 48 TI 28 48 TI 31 48 TI 5 53 DI 11 53 DI 45 54 Restricted for 8x1 40 56 DI 6 61 DI 13 63 TI 11 65 PI*
5 68 DI 12 88 PI 15 90 PI Steam Generator B Row Column Indication 12 21 PI*
9 25 TI 11 25 TI 12 26 PI l
13 26 PI 44 33 TI 16 35 DI 39 35 DI 22 37 PI 13 45 PI 15 48 DI 23 48 TI Page 84
Table VI-8 (Cont'd)
Row Column Indication 15 49 PI 15 50 PI 45 .54 Restricted for 8x1 3 58 PI 2 59 PI 19 62 TI 29 70 PI 8 77 PI*
4 79 PI*
Steam Generator C ,
Row Column Indication 4 3 DI j 4 8 PI p 37 25 PI 9 27 TI 4 28 TI 4 29 TI i 12 29 PI*
15 30 TI 5 31 TI 22 31 PI* 1 5 32 .TI 9 32 TI 21 32 PI*
19 34 PI*
13 36 TI 20 38 TI 13 40 TI 12 41 TI 42 41 Restricted for 8x1 11 43 TI 12 43 TI )
13 43 TI 13 44 TI 14 44 TI 13 46 TI l 13 47 TI )
14 47 TI 24 47 PI*
32 47 PI !
11 48 PI j 13 48 TI l 1
Page 85 l
_--__-___--______a
Table VI-8 (Cont'd)
Row Column Indication 31 49 78%
46 49 PI 9 .51 Failed tube 10 51 37%
11 51 PI 2 54 Broken probe 45 54 Restricted for 8x1 16 71 DI 0Circumferential in nature, in the tubesheet region - hot leg.
Page 86
c TABLE VI-9 STEAM GENERATOR TUBES PLUGGED BY INDICATION TYPE DURING JULY, 1987 OUTAGE 0
Tube - Tota 1 1 2 4 Clear Distorted Sheet 8x1 Possible Tubes
-S/G Indications Indications Indications Indications Other$ Plugged
.A 0 6 6 11 2. 25 E 0 3 5 12
-B~ 1 21 C 2 2 20 11 4 39' l
Clear Indications (defective). - bobbin indications of greater, than 40 percent "thru-wall" depth.
Distorted Indications -
bobbin indications of undetermined "thru-wall" depth at tube support plates.
3
'Tubesheet indications - . bobbin indications of undetermined "thru-wall" depth at:tubesheet.
4 8x1 Possible Indications - Indications identified by 8x1 probe.
' 5 l Tubes with broken probes or which would not pass 8x1 probe - includes failed tube.
6 Plugging summary is as of 9/14/87 based on ECT results - does not include tubes to be plu8 bed as a preventative measure based on fatigue considerations or other concerns.
Page 87
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VII. BASIS FOR RETURN TO SERVICE A thorough evaluation of the causative mechanism for the steam generator tube rupture has identified fatigue resulting from fluid e3astic instability as the most likely mechanism. Modifications to the steam generators have been identified to provide adequate stability margins for the steam generator tube oundle. In addition, Virginia Power has developed an augmented surveillance program for detection of primary-to-secondary leakage. This program is designed to detect tube leakage during the early stages of fatigue failure, so that an orderly shutdown can be accomplished before final failure occurs. And finally, certain steam generator repairs and tube plugging are required to address the specific tube which failed as well as other degraded tubes which were identified through the eddy current inspection program described in Chapter VI. These modifications and programs are described in this chapter and form the basis for our conclusion (see Chapter IX) that the unit can be returned to full service and operated safely. Specific corrective actions are delineated in Section VIII. The bases for return to service are summarized below.
A. Downcomer Flow Resistance Plate A downcomer flow resistance plate will be installed in each of the steam generators. The plate will be velded to the wrapper at the top of the downcomer and will result in a reduction in circulation ratio of approximately 33%. The effect of reducing the recirculation ratio is to reduce the mass recirculation flow in the tube bundle and thereby provide an adequate margin to fluid elastic instability.
B. Remove Susceptible Row 8, 9,10 and 11 Tubes from Service While the downcomer flow resistance plate is expected to eliminate fluid elastic instability as a tube integrity concern for the remainder of plant life, tubes susceptible to relatively high local flow induced stresses in Rows 9, 10 and 11 will be preventively plugged. A susceptible tube is one which is not supported by antivibration bars (AVB) and is in a region of local high fluid velocities. All tubes above Row 11 have AVE support, and tubes in Rows 8 and below have large stability margins and therefore are not presently considered susceptible.
C. Improved Monitoring of Primary-to-Secondary Leakage A program for augmented surveillance of rediation monitors, sampling and primary-to-secondary leakage has been developed. The program includes frequent recording and trending of selected radiation monitor data, sample isotopics, and more frequent calculations of leakage based on a variety of methods and indicators. The technical basis for expecting leak before break and the ability to oetect this leakage before break is developed in Chapter VI. From Chapter VI, it is concluded that leak rates between 10 gpd and 100 gpd can be detected in a timely manner and that even with fatigue fallure there is adequate time for shutting the unit down between exceeding 100 gpd and the gross primary-to-srcondary leakage experienced during a tube rupture event.
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Radiation Monitors The following radiation monitors will be recorded and/or evaluated' on the frequencies indicated. This data vill be evaluated for indications of leakage (trend and magnitude) during Mode 1 operation.
Steam Generator A,B,C Blowdown Monitors every 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Condenser Air Ejector Monitor every 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months N-16 Monitor continuous reading, above 30% power The alarm setpoint for the condenser air ejector monitor will be initially established to respond at an approximate leakage rate of 10-20 gpd. The applicability of the alarm setpoint will be periodically evaluated based on the primary-io-secondary leakage calculations discussed below to respond at a leakage of approximately 10 gpd above the maximum current leakage rate.
N-16 monitors are being installed to provide a diverse indicator of primary-to-secondary leakage. The N-16 monitors will be initially installed on the main steam header. Additional monitors will be installed on each of the main steam lines subsequent to returning the unit to service as the monitors become available. The N-16 monitor should be a more direct indicator of primary-to-secondary leakage as it relies on detecting a high energy gamma ray with rate ranging linearly with power as opposed to fission product or other activated isotopes buildup in the RCS. N-16 also has a very short half life which better assures : hat the N-16 detected has leaked through a relatively large tube crack in the steam generator as opposed to a pin hole leak. Therefore, the N-16 monitor should be especially effective in detecting significant increases in primary-to-secondary leak rate which might be a precursor to a fatigue failure and subsequent rupture of a tube. The N-16 monitor will have continuous readout in the Control Room and up to three persat alarms. The first alarm will be set consistent with the air ejector radiation monitor alarm. The second alarm will be set at 60 spd in order to detect the initial crack propagation of a fatigue failure. The third alarm will be set at the administrative 1y imposed shutdown limit of 100 gpd.
The following samples will be taken and analyzed on the frequencies indicated to permit calculation of primary-to-secondary leakage during Mode 1 operation. Sample activity levels will also be trended.
Air Ejector Exhaust every 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months Primary Coolant every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Secondary Coolant (Steam every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Generator Blowdown)
Primary-to-Secondary Leakage Surveillance Using the above radiation detector and sampling data, primary-to-secondary leakage vill be calculated every 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months based on air ejector exhaust isotopic activities and every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months based on secondary coolant isotopic activities. The primary isotopic activities will be used to relate the air ejector and secondary isotopic activities to primary-to-secondary leakage.
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In addition, the condenser air. ejector radiation monitor count rate readings will be used to estimate primary-to-secondary leakage every 4
. hours and the radiation monitor alarm setpoint will be adjusted to respond if leakage increases and stays 10 gpd above the most recent maximum leakage measurement. The N-16 monitor will provide a continuous readout of primary-to-secondary leak rate. Alarm setpoints for both the air ejector and N-16 radiation monitors will be set to provide early detection and will alarm on the annunciator panel in the Main Control Room.
Operational Response to Increased Leakage
Jhe detection of increased. primary-to-secondary leakage will result in increasing the frequency for determining leak rates over that frequency discussed above. it addition, a RCS leak rate will be calculated on a frequent basis and trended whenever primary-to-secondary leakage is increasing. Leak rates exceeding 100 gpd per steam generator will result in a shutdown of the unit. Leak rate step changes of greater than 60 gpd or leak ratre increasing at a rate that would rapidly exceed 100 gpd (per steam generator) will result in' prompt evaluation of whether to shutdown the unit.
D. Plug Confirmed Eddy Current Indications All tubes with indications found during the eddy current inspection which meet the plugging criteria will be removed from service by plugging.
E. Stabilize and Plug Failed Tube The ruptured tube (R9C51) in "C" Steam Generator will be stabilized on the hot leg side through the seventh support plate on the hot leg side. A jointed spear will be installed from the cold leg tube sheet up through each tube support plate and inserted into the remaining tube above the seventh support plate on the cold leg side. The jointed spear will be hydraulically expanded at each tube support plate and inside the remaining tube. Both the hot and cold leg sides of R9C51 vill then be plugged at the tube sheet. This stabilization and plugging of the remaining section of R9C51 left in the steam generator will preclude additional fatigue failures I in R9C51 end any damage to adjacent tubes.
l F. Plug Neighbor Tubes to Failed Tubes j The tubes immediately adjacent to the failed tube will be preventively plugged as despribed in Chpater V1.E.5. to minimize the potential consequences of instability of the failed tube, 1
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VIII. LESSONS LEARNED l A detailed review and evaluation of the steam generator tube rupture event t was performed co identify lessons learned. Lessons learned were defined as
[
' aspects of .the event, including the response of equipment, people and procedures, which require corrective action, may be improved or enhanced, or contributed in a significant, positive manner to the safe shutdown of the unit.
This latter category was termed " good practices." A summary of the actions
'that are planned to address lessons' learned from the event has been developed.
'These actions are presented below as either Corrective Actions (for areas determined to need improvement) or Enhancements (for areas that could be improved). Also provided are good practices.
A. Correct,ive Actions
1. Steau Generators Virginia Power is committed to the long term operability of the steam generators. Maintenance activities during each outage are directed toward this goal. Activities such as extensive eddy current testing, secondary inspections and sludge lancing are typical examples. A steam generator maintenance agreement between the steam generator supplier and Virginia Power provides for a cooperative agreement dedicated to maintaining steam generator integrity and operability. The following paragraphs discuss activities related to the degradation mechanisms that currently can be found in each steam generator.
Corrosion Primary water stress corrosion cracking (PWSCC) has been observed at the tube sheet, at tube / tube support plate intersections, and in the Row 2 U-bends. On the secondary side, intergranular attack (IGA) and stress corrosion tracking (SCC) have been observed at the tubesheet and at the tube / tube si:pport plate intersections. Denting has been observed at many intersections; however, the growth of denting appears to have been arrested by the secondary system boric acid treatment program.
Corrective actions taken or planned to address these various corrosion mechanisms are as follows:
(a) The EPRI Steam Generator Owners Group PWR Secondary Water Chemistry Guidelines will continue to be adhered to.
(b) Tube degradation by these mechanisms will be monitored during future refueling outages using eddy current testing methods.
(c) Tubes with eddy current indications exceeding Technical Specifications limits or other established plugging criteria (see Chapter VI.D) will be removed from service by plugging. This includes tubes with eddy current indications of defects for which a through-wall depth cannot be determined.
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'(d) An administrative leakage limit of 100 gallons per day per. steam generator has been established to assure titely detection of and f 3
. response co further tube degradation occurring as a result of 1 corrosion between steam generator' inspections. J (e) The secondary side boric acid treatment will .be continued in-accordance manufacturer.
with recommendations of the steam generator j
' l (f) Changes in primary water ' chemistry are being investigated to address' PWSCC concerns. Currently, primary coolant hydrogen concentration is being maintained at the lower end of. the specified operating band to minimize PWSCC.
(g) Efforts to reduce steam generator sludge deposits which may contribute to denting and secondary side corrosion are being pursued. A program to replace copper. bearing materials in the feedwater heaters is ongoing and a revised secondary chemistry treatment program ,is being evaluated. In addition, efforts to reduce condenser air inleakage'are being aggressively pursued.
(h) The Row 2 U-bend were stress-relieved during the April, 1987 refueling' outage. In addition, a stress-relief demonstration program for tube / tube support plate intersections was performed.
(1) Sleeving of affected tubes. at tubesheet and tube / tube support plate locations is being evaluated as a possible long term corrective action.
Fatigue The rupture of tube R9C51 was determined to be due to both fatigue initiation and propagation. The prerequisites for fatigue failure have been determined to be due to the combination of tube denting at the seventh tube support plate and local flow induced instabilities.
To increase t - assurance that fatigue failures will not occur in the future, the zo11owing modifications to the steam generators will be made.
(a) A downcomer flow restricting plate will be installed.
(b) Row 9, 10 and 11 tubes not supported by AVBs will be preventively plugged as described in Chapter VI.E.5.
(c) Susceptible Row 8 tubes will be preventively plugged.
(d) Tube R9C51 will be stabilized and adjacent tubes will be removed from service.
Antivibration Bar (AVB) Wear l
This mechanism is a minor contributor to the current steam generator degradation. Growth rate of indications has been generally slow and can be predicted based on past data. Eddy current testing will be used Page 96 L_-_--_______---_____
to monitor this problem .and affected tubes will be plugged in accordance with established plugging criteria. Growth- rate will be evaluated and. used to determine any changes in plugging criteria that' would be needed for continued steam generator integrity.
l Independent Review-l i
L The use of an independent consultant to review the activities of the steam generator supplier and Virginia Power has been effective in seeking root causes and establishing the adequacy of. corrective action.
This consultant will continue to review steam generator corrective actions when required. -Also, a Virginia Power Steam Generator Advisory Committee has been active in the review of steam generator issues.
This committee will continue 'to review ongoing steam generator
activities and make recommendations to Virginia Power management.
2. Use of Procedures The training program for licensed operators will be amended to include
. additional classroom and simulator training on the duties and requirements for the E0P procedure reader.
3. Adequacy of Procedures A review of the adequacy of the Emergency Operating Procedures used during the event identified the following.
During the event, the initial identification of the -ruptured steam generator was complicated by the fact that:
(1) The main steam line radiation monitors annunciated for all three steam lines and then cleared early in the event when the steam dump valves closed.at the P-12 setpoint.
(ii) The individual steam generator blowdown radiation monitors were isolated by the Containment Phase A isolation signal (from the safety injection actuation). The trip valves were subsequently reopened to obtain a sample, but this effort could not be performed in the time frame necessary to support identification of the ruptured steam generator.
(iii) There was no distinct level error or steam flow / feed . flow mismatch identified.
(iv) There was very low initial activity in the primary system, and as a result, identification using radiation monitors was not available.
The identification of the ruptured steam generator was subsequently confirmed by level indication after securing the auxiliary feedwater supply valve to C steam generator and observing the continued uncontrolled rise in level. The ruptured steam generator was i completely isolated within 18 minutes after the initiation of the j event. !
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During the cooldown to Mode 5 and RHR Cooling, there were several required actions that were not explicitly stated in the cooldown procedure (ES-3.1). These actions included:
(1) Lockout of LHSI/HHSI pumps.
(ii) Initiation of PORV NDTT protection.
(iii) NPSH concerns during cooldown and depressurization for the reactor coolant pump.
I (iv) Radiogas and hydrogen accumulation in the ruptured steam generator.
The Emergency _ Operating Procedure for the SGTR did not specifically require the verification of the condenser air ejector exhaust divert to the containment.
During the event, the emergency diesel generators started ;
automatically as required by the Safety Injection actuation, (no power !
interruptions were received) and were left running in an unloaded ,
condition for up to 55 minutes.
The following actions will be taken to address the above concerns.
(a) A team of personnel from the Westinghouse Owners Group Procedures Subcommittee, INPO and the North Anna Operations staff will conduct a review and recommend any required corrective actions.
Minimum areas to be reviewed include:
(i) Additional instructions to facilitate identification of the ruptured steam generator.
(ii) Interface with the normal operating procedures or more specificity in the supplemental emergency procedures to ensure all Technical Specification and other requirements are met during cooldown to a cold shutdown condition.
(iii) The verification of automatic actions including the condenser . air ejector divert to containment.
(iv) The procedural instructions and potential improvements for securing an unloaded emergency diesel generator.
(v) The overall strict adherence to Emergency Operating Procedures.
(b) E0P concerns identified in NRC Augmented Inspection Team Report l' Nos. 50-338/87-24 and 50-339/87-24 dated September 3, 1987 will be reviewed, and a written response provided to the NRC.
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4. Verification of Automatic' Actions ,
i In addition to the review of.the Emergency Operating Procedures for. 'l 1 the . verification of automatic actuations (see Corrective Action #3),
the Operations Department administrative controls have been amended to provide. additional. guidance to Operators whenever_ an automatic )
function is disabled or bypassed during normal operation.
~
-5. Radiation Monitoring Instrumentation j
The steam generator tube rupture event highlighted the importance of maintaining the radiation monitoring system operable.
(a) An evaluation of instrument calibration and maintenance intervals will be performed to increase assurance that the' instruments,;
including recording ' devices, are maintained operable during the interval. '
(b) _ A specific concern relating to the compatibility of the KAMAN radiation ~ monitoring system interface with its recorder (ie, scale differences) will be addressed.
(c) Nortnally, the high setpoints on the blowdown. and air ej ector radiation monitors are not adjusted after a refueling until the unit reaches equilibrium operation at 100% power. This practice will be discontinued, and the setpoints will be adjusted to increase assurance of early detection of primary-to-secondary leakage- prior to startup. from a refueling outage or an outage resulting from steam generator repair after- exceeding primary-to-secondary leakage limits.
(d) The blowdown radiation monitor's true reading is sometimes masked by high background radiation in the detector. These background levels will be minimized during future operation.
6. Technical Support Center Radiation Monitor The Eberline radiation monitor in the Technical Support Center was not activated in a timely manner due to equipment deficiencies.
The equipment deficiencies (i.e. alarm setpoints were improper. and channel 7 does not check / source) will be corrected.
7. Health Physics Network (HPN) Telephone Communication of health physics information to NRC using the HPN I
telephone in the Technical Support Center was delayed due' to health physics personnel unfamiliarity with HPN and the fact that the telephone was being used by the NRC for communication of plant status information. Health Physics personnel will be trained in the proper use of the HPN phone.
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_ _ _ _ - _ _ _ - _ _ _ - - _ - A
B. Enhancements
1. Shift Technical Advisor l
The Shift . Technical ' Advisor (STA) responded promptly ' to the Control !
4 Room and was able to provide valuable assistance to the Operations staff. In order to further enhance the role of the STA during
-emergency conditions, a task team will be established consisting of representatives from Operations, Training, Engineering and the Shift Technical Advisor groups. This team will be assigned the task of developing specific written guidelines for the STA function during l
emergency operating conditions.
2. Control Room Environment In order to reduce the noise level in the Main Control Room initially following _a reactor trip, an enhancement to the aldra snd utility
. typewriter enclosures to reduce noise ,w ill be investigated and corrective actions recommended.
3. Event Chronology Reconstruction
-The time clocks used by the various computers, logging devices and emergency response organizations were not synchronized which made reconstructica of the event chronology more difficult. In addition, notes taken by log keepers were sketchy in some cases making it difficult to reconstruct events and decisions.
(a) A procedure will be developed to periodically adjust the clocks for the Emergency Response Facility Computer System, P-250 process computer, Control Room, Control Room recorders including those for the radiation monitors, " Sequence-of-Events" recorder, and the on-line chemistry monitoring system.
(b) The problem of keeping logs by Operations and Health Physics personnel during the initial phase of an emergency situation will be evaluated and any enhancements needed will be recommended.
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{ 4. Emergency Response Computer System The Emergency Response Computer System performed very well during the event. The system was used by each of the emergency response facilities to assess the changing conditions of the unit and helped to minimize the need for manual transfer of information between locations. Some deficiencies in the system were noted including a few I data points that did not correspond to actual conditions and some inappropriate . alarm setpoints. Further, it was recognized during the event that use of the system could be improved by dedicating personnel in each facility to operate the system and facilitate data retrieval from the system.
(a) Provisions for dedicated personnel to operate the system in the LEOF and CERC will be incorporated into the appropriate emergency response procedures.
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(b) The deficiencies noted in the system will be corrected.
5. Health Physics Assessment of Release Paths During the initial phases of the event prior- to activation of the Technical Support Center, the health physics personnel in the Control Room experienced difficulties in identifying radiological release paths and reading meteorological panel and radiation monitor instruments. This necessitated assignment of an unlicensed control room operator to assist in obtaining the required information and some additional interaction with the Operations staff to identify release paths.
(a) Training of the Health Physics Shift Supervisors on.the possible release paths and the meteorological and radiation monitoring instrumentation in the control room will be provided. ,
(b) Emergency Plan Implementing Procedure 4.01 will be reviewed and possibly revised to include additional guidance on possible release paths and system alignments.
6. Emergency Response Facility Status Boards Differences between the ERF status boards and radiological / emergency status sheets contained in the Emergency Plan Implementing Procedures were noted during the event. The status boards will be updated as necessary.
7. Communication between Operations and Health Physics Departments The initial contacts with the Health Physics personnel to request samples, and following the Safety Injection actuation to direct entry into the EPIPs, were given quickly and without explanation due to the rapidity of events occurring. To improve the communications interface between Operations and Health Physics personnel, the Operator Training !
Program will be evaluated for inclusion of participation by the Health 1 Physics Shift Supervisors during simulator training. The simulated initiation of the Emergency Plan and the communications between Operations and Health Physics would be stressed during this training.
8. Steam Generator Primary-to-Secondary Leakage Monitoring An augmented surveillance program for steam generator leakage is being developed to assure early detection of future leakage events and will include the following elements:
1 I
(a) The periodic recording and trending of the condenser air ejector exhaust, and steam generator blowdown radiation monitors.
(b) The periodic sampling and trending of primary and secondary gross activities and condenser air ejector exhaust activity.
(c) The installation of an on-line, continuous measurement of steam generator leakage using an N-16 measurement system installed on the main steam lines.
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.(d). The~ development of a. periodic test procedure to evaluate leak rates _and provide operational guidance for when increasing leak rates-are detected.
9. Air Ejector Exhaust Divert To Containment When the air ejector exhaust' radiation monitor high-high setpoint is exceeded, the air ejector exhaust will be automatically diverted Jfrom the Ventilation Vent (i.e., to the atmosphere) to the containment. In the event that a-Phase A containment isolation signal is also received with the high-high setpoint exceeded, the divert to.the containment is c
isolated and the air ejector is shutdown. When the air . ejector' is shutdown, the condenser vacuum is lost and the condenser is no longer available to the operator for cooldown. To prevent unnecessary loss of. the condenser.during a SGTR or other type of event, the following actions will be taken.
(a) The high-high setpoint increase will be evaluated for a level consistent preventing 4 unacceptable radiation levels in the Turbine Building.
(b) An engineering evaluation will be conducted to determine if the divert of the air ejector to containment and the shutdown of the air ejector (on high-high radiation and Phase A isolation) are actually required.
10. Isolation of Steam Supply to Steam Driven Auxiliary Feedwater Pumps The E0Ps frequently require isolation of one or more of steam supply lines to the steam driven auxiliary feedwater pumps. This is normally accomplished by closing one-or more manual valves in the Main Steam Valve House (MSVF).. The isolation, if. required, is a high priority evolution and will be conducted during the initial phase of the event prior to establishing the radiological or other environmental conditions in the MSVH.
An engineering evaluation will be conducted to determine if the above i manual valves should be redesigned to allow automatic opening and I L closing frem the control room.
11. Licensed Operator Proficiency Licensed operator proficiency in dealing with SGTR and .other primary-to-secondary leakage events will be maintained at a high level by addressing these events in at least 5 of the 10 License Operator Requalification (LORP) cycles being conducted each year. I l
C.. Good Practices
1. . Inadequate Core Cooling Monitor The Inadequate Core Cooling Monitor (ICCM) was recently added to the control room to provide an integrated display of subcooling, reactor vessel level and core thermocouple instrumentation. The ICCM proved l
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to be a very valuable operational tool. The Operators and the STA used this display continually throughout the event.
2. Announcements At the time of the escalation to an " Alert", the unaffected unit CRO was directed to make the required announcements and sound the emergency alarm. This prevented any interruption of the activities that were occurring on the affected unit.
3. Watch Turnover / Relief The operating shift relief process was conducted after the unit was stabilized and a cooldown to Mode 5 was in progress. The shift relief was performed by placing the relieving Control Room Operator on the control board with the Control Room Operator for a period of time (30-50 minutes) until the relief operator was thoroughly familiar with the activities and procedures that were taking place. Personnel turnover was conducted one watchstation at a time.
4. Two Dedicated Communicators Two experienced, unlicensed operators of the Operations shift were preassigned duties as communicators with NRC and State and local authorities. Two dedicated and preassigned communicators had been established in response to a lessons learned from the Surry feedwater pipe rupture event. Prior to the Surry event, the communicator position was filled by single member of the Operations shift and was not predesignated prior to the start of the shift. The two communicators greatly facilitated the dissemination of information from the control room and allowed the Shift Supervisor and Control Room Operators to devote their full attention to the safe shutdown of the unit.
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IX. CONCLUSIONS A. The. overall' response of personnel, procedures and equipment to.the steam generator tube rupture event was excellent. All~ safety related !
equipment, with the exception of the condenser air ejector radiation monitor which was out of service prior to the event, performed as designed. The ruptured steam generator was isolated within 13 minutes of safety inj ec ting , without overfilling 'the steam generator 'er 4
lifting any of the steam generator relief or safety valves. Also,
. pressurizer level was restored and reactor coolant pressure was stabilized within- 34 minutes of safety. injecting without going solid-
, in the pressurizer or lif ting a pressurizer relief o or safety valve.
The operational performance exhibited is attributed to the classroom and simulator training received on steam generator tube ruptures which is' structured to integrate the Emergency Operating Procedures, Emergency Plan . Implementing Procedures, and the Critical Safety Functions.
The licensed operators on shift at the time of the event found the Emergency Operating Procedures to be very effective. The procedures had been recently revised to incorporate Revision 1. of the Westinghouse Emergency Procedure Guidelines. Several areas 'were identified as possibly needing further review by Westinghouse and this review has been initiated.
The emergency response by the various emergency organizations was equally effective. The interim Station Emergency Manager ( the Unit 2
. Senior Reactor Operator) correctly classified the emergency in a timely manner and notifications to the NRC and State and local authorities were performed as required by the Emergency Plan.
Following upgrading of the emergency to " Alert" classification at 0654, accountability of personnel was completed by 0747, the J Operations Support Center was activated by 0753, the Technical Support Center by 0757, the Corporate Emergency Response Center by 0820, the Corporate Public News Center by 0830, the Local Emergency Operations Facility by 0915 and the Local Media Center by 1000 hours0.0116 days 0.278 hours 0.00165 weeks 3.805e-4 months . As each of these facilities were activated, an orderly turnover of I responsibilities occurred. Once activated each facility fulfilled its j duties and responsibilities as required by the Emergency Plan.
_]
i B. Calculations of radioactivity released during the event show a minimal j release of only 0.159 curries, which equates to approximately i one-third of one percent of the Technical Specifications limit for a l one hour release. This negligible release is attributed to the timely manner in which the operating shift controlled the plant and isolated
)
i the various possible radioactive release paths, as well as the very l low activity in the RCS at the time of the event.
C. The consequences of the tube rupture event were bounded by the Chapter 15' accident analysis in the UFSAR in terms of maximum break flow rate, integrated primary-to-secondary case transfer and offsite dose consequences. The core was effectively and adequately cooled throughout the event and the integrity of the fuel was not compromised in any way.
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D. The ruptured tube (R9C51) in the "C" Steam Generator failed due to fatigue. The mechanism for fatigue failure has been analytically duplicated and determined to be due to the combination of stresses imposed by denting at the seventh tube support plate and local fluid flow conditions which led to fluid elastic instability. The fatiguing process resulted in multiple crack initiation sites with eventual through-wall propagation over a 40* to 60' arc. The remaining radius of the tube separae.ed by continued circumferential propagation of the crack by fatigue. No indications of a corrosion mechanism has been '
found. i E. Continued operation of the steam generators is justified because the stresses resulting in fatigue failure can be reduced to an acceptable level, whereby a similar failure should not occur, by modifying the -
recirculation ratio in the steam generator. Additional assurance can be provided by preventively plugging (Sentinel plug) those tubes in local high flow induced stress areas which.are not supported by AVBs.
In addition, tubes which show eddy current indications exceeding acceptable limits will be plugged. Finally, the ruptured tube (R9C51)
J will be stabilized and plugged and its adjacent tubes will also be preventively plugged.
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ATTACRMENT 1 CHRONOLOGY STEAM GENERATOR TUBE RUPTURE EVENT NORTH ANNA POWER STATION UNIT 1 JULY 15, 1987 To support the investigation of the Steam Generator Tube Rupture the following chronology was reconstructed from the print outs of the alarm typewriter attached to the Control Room P-250 process computer, the Sequence of Events Recorder (Dranetz) driven by the Hathaway annunciator system, the data printouts extracted from the record kept by the ERF Computet in the Technical Support Center, R0 and SRO logs and interviews, and strip charts from Control . a Room recorders.
Selected data was transmitted from the various records based on the significance of each datum as it identified a sub-event or demonstrated, .
explicitly or implicitly, a sub-event in the sequence. The intent is that this chronology can be integrated with other analysis to determine the timeliness, accuracy and effectiveness of the measures applied to mitigate the accident.
Once the data was transcribed, a review was performed to identify the' synchronism for time of the various data sources. The principal iteta selected for synchronism uns the Automatic Pzr Lo-Lo SI. The SI action incorporates , . .
several actions including feedwater isolation and normal charging isolation that make it readily comparable over all records. The Sequence of Events Recorder logged SI at 06:35:24:805; the P-250 logged SI at 0639. However the '. ,
earlier Reactor Manual Trip has caused the P-250 to alter its scan rates. The P-250 Post Trip review logged SI at 06:35:24 plus 1012 cycles, which equates to .
06:35:40.86. The ERFC data set collected at 06:34: 14 records full normal charging flow and full power feed flow to the steam generators, approximately 16 seconds after the reactor trip had been manually initiated. By 06:34:21, i the ERFC data set charging flow is reduced to 82.568 gpm and feed flows are about 600KLBH to 800KLBH. By 06:34:34, all flows had reached a stable but low level. It appears that SI occurred at or slightly before 06:34:14. This chronology will use 06:34: 14.
For automatic initiation of Safety Injection, the clock comparisons are as follows:
RECORDER TIME ,
Sequence of Events Recorder (SER) 06:35:24:805 P-250 Computer 06:35:41 ERF Computer (ERFC) 06:34:14 F
/
For Reactor Manual Tr.ip the clock comparisons are as follows:
RECORDER TIME Sequence of Events Recorder (SER) 06:35:04:548 P-250 Computer 06:35:24 EP.F Computer (ERFC) 06:33:56 It is concluded that.the P-250 led, the SER was within 20 seconds of the P-250 and the ERFC was about one minute behind the P-250.
1The chronology that follows is annotated by clock time based on the P-250.
All the events that occurred within each minute are listed in order of occurrence as could best be determined.
i i
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MR o v v v v v vo v vo RU L r r r r 0 r rL r rL OO e e e eC 5 e e e e FS O t 0 t t t F 2 t t C t t C N R n R n n nR - n nS n nS I S I CI I I E P I I T I I T E
R UP DE ET - - - - - - - - - -
CS O
R P
EE RC UN DE ER - - - - - - - - - -
CE OF RE PR T
N E1 V
ET I d EN e RU r l . n U a en . g o g o TN l ne s m n t i s s PO c ah r r i f U I 7 e pW oa s O p o e YRT8 d t l a R i .
G A9 r i a e S t 5 t t d OET1 s o . n r e 3 n u e LBS a t c l s 1 e d t 1 OU ,
w ao r om "h e - 2 m a E
NTR5 i t g d U d n P i O E1 ) i n t . g O . t G RRW 1 cn in"B H uo" "
l e
d n
a a m o
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e ATTACHMENT 2 NORTHA'NNA UNIT 1 OPERATIONAL HIETORY PRIOR TO THE "C" S/G TUBE RUPTURE EVENT OF JULY 15, 1987 DATE TIME COMMENTS 04-19-87 0800 Commenced Unit I ramp down for refueling outage.
500 Unit 1 off line.
04-20-87 0600 Commenced RCS hot hydrostatic test.
1300 llydrostatic pressure test terminated. Retested satisfactorily on 06-28-87.
04-28-87 0600 Started "B" S/G eddy current inspection.
05-05-87 1800 Completed "B" S/G inspections.
05-08-87 0000 Started "A" S/G eddy current testing.
05-15-87 2100 Completed "A" S/G inspections.
05-16-67 0600 Started "C" S/G eddy current testing.
05-23-87 1000 Completed "C" S/G inspections.
06-08-87 0013 Commenced RCS fill and vent.
06-10-87 2342 RCS stable at 195'F and 310 psig.
06-11-87 1022 Established Pzt bubble 06-12-87 0510 Drained, refilled, and added chemicals to "C" steam generator, level is 70% W.R.
06-15-87 1135 Established containment vacuum.
06-17-87 1244 Electrical trip on "A" Reactor Coolant Pump (1-RC-P-1A), found motor damage that required motor replacement. ECS still <200'F (mode 5).
1832 Containment vacuur. broken, and RCS depressurization underway to allow RCP motor work.
06-28-87 0132 RCP "A" motor replaced, containment vacuum established, unit enters mode 4, heat un in progress.
0816 Unit i enters mode 3 (>350'F)
Page 1
i DATE TIME COMMENTS
! 06-28-67 1450 Unit 1 0 521'F and 2296 psig for RCS hydrostatic pressure test.
2053 RCS hydrostatic pressure test is completed.
06-29-87 0310 Unit 1 reactor critical, unit is in mode 2.
0903 Completed " Low Power Physics Testing" 2229 Unit 1 on-line.
2248 Unit 1 Reactor and Turbine trip on SA Feedwater heater high-high level.
06-30-87 0321 Unit I reactor is critical.
0621 Unit 1 on-line.
1044 Unit 1 is 23% reactor power, holding due to inability to open the manual isolation valve on "C" main feedwater regulation valve.
07-02-87 0205 Unit I commenced a ramp down for maintenance on the FW manual. isolation valve.
0326 Unit 1 off-line.
0450 Shutting down Unit I reactor, entered mode 3.
0637 RCS cooldown and deprensurization to 205'F underway.
1445 Unit 1 is on RHR.
07-04-87 0445 Maintenance on FW manual valve is completed. Commenced heat up of RCS. ,
I 0501 Unit 1 in mode 3.
1534 Unit I reactor critical.
2123 Unit 1 on-line.
07-05-87 0210 Unit 1 is being held < 30% power on chemistry hold to clean up the steam generators.
l 1
07-07-87 0158 Unit 1 is being held at 83% power for investigation of low steam flows to the "B" Moisture Separator Reheater.
0240 Unit I rampdown to 50% power is commenced.
Page 2
1
/'
DATE TIME COMMENTS
.07-10-87 2103 Commenced rampdown of Unit I to allow maintenance work on "B" MSR stop valve.
2320 Unit 1 off-line.
Unit I reactor shutdown, entered mode 3. l 2340 07-11-87 0056 Cloced Unit 1 Main Steam Trip Valves (MSTV) for work on the "B" MSR Stop Valve.
2357 Completed work on "B" Reheat Stop valve.
07-12-87 0017 Unit I reactor critical.
0356 Unit 1 on-line.
0510 Unit I stabilized at 27% pcwer for steam generator chemistry hold.
1519 Ramp up of Unit I to 100% power underway.
1900 Chemistry notification of action Level 1 on high FW cation conductivity.
07-13-87 0809 Air ejector radiation monitor (RM-RMS-121) on Unit 1 is declared inoperable on erratic operation.
1524 Chemistry notification of Main Steam cation conductivity out of specifications, entered Action I.evel 1.
07-14-87 0815 Action Statement cleared on air ejector radiation monitor, the monitor has been stable over night.
2238 Air ejector radiation monitor is erratic, and is declared inoperable. Entered Action Statement with grab (local) samples again.
07-15-87 0630 Unit 1 Operator receives indications of a Steam Cenerator Tube Rupture.
Page 3
l ATTACHMENT 3
' SEQUENCES OF EVENTS HEALTH PHYSICS DATE A TIME COMMENTS 07-13-87 0900 Air Ejector sample due to RM-SV-121 being out of service. Power level 85.5%.
1740, Air Ejector sample due to RM-SV-121 being out of service. Power level 87.8%.
07-14-87 0114 Air Ejector sample due to RM-SV-121 being out of service. Power level 99%.
2245 Air Ejector sample due to RM-SV-121 being out of service. Power level 100%.
07-15-87 0620 Air Ejector sample due to RM-SV-121 being out of se rvic e . Power level 100%.
0650 EPIP 4.01 " Radiological Assessment Director Controlling Procedure implemented.
0650 Air Ejector Sample for S/G Tube Leak Evaluation.
Reference Table 111-1 for data.
0652 EPIP 4.02 " Radiation Protection Controlling Procedure" implemented.
0655 HP Technician assigned to the Control Room to observe Plant Radiation Monitors as follows.
Ventilation Vent A and B.
Process Vent.
Steam Driven Aux Feed Water Pump Exhaust. ,
Main Steam A, B, and C.
0658 EPIP 4.14 "Inplant Monitoring" procedure implemented.
0700 EPIP 4.28 "TSC/LEOF Radiation Monitoring System" procedure implemented.
I t
Page 1 t
DATE TIME COMMENTS 07-15-87 0705 EPIP 4.17 " Monitoring of OSC/TSC"~ procedure implemented.-
0708 EPIP 4.08 " Initial Offsite Release Assessment" procedure implemented.
0710 EPIP 4.15 "Onsite Monitoring" procedure implemented.
0712 EPIP 4.25 " Liquid Effluent Sampling During An Emergency" procedure implemented.
0718 Condensate sample.
0718 "A" Main Steam sample.
0718 "C" Main Steam sample.
0720 EPIP 4.03 " Dose Assessment Controlling Procedure" implemented.
EPIP 4.12 "Offsite Environmental Monitoring Instructions" procedure implemented.
0722 Cold Lab Particulate Charcoal sample 0722 EPIP 4.27 "Use of The Class A Meteorological And Dose Calculational Model" procedure implemented.
0728 EPIP 4.16 "Offsite Monitoring" procedure implemented, for monitoring Team 1.
0729 Operations support (OSC) Particulate / Charcoal sample.
0730 EPIP 4.19 "Use of Radios For HP Monitoring" procedure implemented.
0735 Technical Support Center (TSC) Particulate / Charcoal sample.
0738 Service Building hallway, Particulate / Charcoal ;
sample. i 0745 Access to MSHV, Turbine Building, Auxiliary !
Building and Steam Driven AFW Pump Building restricted.
0807 "C" Steam Generator primary sample.
Page 2
DATE- TIME COMMENTS 07-15-87 0807- Hot Leg Primary sample.
0813 Yard, Guard Tower 3, Particulate / Charcoal sample.
0815 Survey of Unit 1 Mechanical Equipment Room.
0816 Chemistry Sample Sink Particulate / Charcoal sample.
0823 EP1P' 4.10 " Determination of X/Q'" procedure implemented.
0824 Turbine Building, Common Sump, water sample.
0830 TSC Particulate / Charcoal sample.
0810 EPIP 4.16 "Offsite Monitoring" procedure implemented, for monitoring Team 2.
0846 Turbine Building, 279' Level Particulate / Charcoal sample.
u 0852 offsite air sample / survey et access road for count room analysis.
0853 EPIP 4.11 " Follow-up Offsite Release Assessment" procedure implemented.
0858 EPIP 4.09 " Source Term Assessment" procedure implemented.
0908 Ventilation Vent A sample.
0910 Offsite air sample / survey at Aspen Hills subdivision for count room analysis.
0913 Ventilation Vent B sample.
0915 OSC Particulate / Charcoal sample.
0921 Process Vent Particulate / Charcoal /Cas sample.
0926 TSC Particulate / Charcoal sample.
0929 Turbine Building, 271' level Particulate / Charcoal / Gas sample.
0938 Turbine Building Basement Particulate / Charcoal sample.
l Page 3
'DATE- TIME COMMENTS 07-15-87 '0943- Steam' Generator A, B, C Blowdown sample. Sample utilized to evaluate activity from steam driven Auxiliary. Feedwater Pump exhaust.
Reference Table III-2 for Data with A, B, C S/G Steam to -Pump.
Reference Table III-3 for Data with A, B S/G Steam to Pump, C S/C isolated.
0945 "A" Cold Leg primary sample 0956 Aux Building Walkway 272' Level, Particulate / Charcoal sample counted.
1004 Local Emergency Operations Facility (LEOF),
Particulate / Charcoal sample.
1010 EPIP 4.18 " Monitoring of LEOF" procedure implemented.
1032 TSC, Particulate / Charcoal sample.
1142 ' LEOF., Particulate / Charcoal sample.
1144 TSC, Particulate / Charcoal sample.
1205 Vegetation sampled at access road southwest of plant for count room analysis.
1228 TSC, Particulate / Charcoal sample.
.1333 Aux Building, 274' Level, Particulate / Charcoal sample.
1440 Monitoring Team Particulate / Charcoal sample counted.
1448 Monitoring Team Particulate / Charcoal saeple counted.
1453 Monitoring Team Particulate / Charcoal sample counted.
1629 - Soil and vegetation samples counted prior to 1941 shipment offsite for analysis Page 4
9 i
l
. ]:
i DATE TIME COMMENTS l
07-15-87 0658 - Miscellaneous onsite surveys were performed in 1 1252 accordance with EPIP 4.14. "Inplant Monitoring."
The following areas were surveyed.
Turbine Building Mechanical Equipment Room Service Building Hallways Outside Areas, within the Protected Area Auxiliary Building Chemistry Labs Technical Support Center Operational Support Center Local Emergency Operations Center Aux. Feedwater Pump House Laundry and PDA Area Main Steam Valve House No.1 i
Page 5 1
ATTACHMENT 4 DHERGENCY PLAN CHRONOLOGY TIME COMMENT 0638 EPIP-2.11, Notification of State and Local Governments, initiated.
0639 " Notification of Unusual Event". declared.
Unit 2 SRO assumed duties as Interim Station Emergency Manager.
EPIP-1.01, Emergency Manager Controlling Procedure, initiated.
EPIP-1.02, Response to NOUE, initiated.
0645 Security requested to dispatch officer to Control Room for access control.
0650 EPIP-4.01, Radiologic,al Assessment Director Controlling Procedure, initiated.
0651 Initial offsite notification regarding "NOUE" is transmitted to State and local authorities.
0652 EPIP-4.02, Radiation Protection Supervisor Controlling Procedure, initiated.
0654 Interim Station Emergency Manager upgraded event claselfication to
" ALERT". EPIP-1.03, Response to Alert, initiated.
Security officer established post at Control Room.
06$5 Security is notified by Control Room to initiate EPIP-3.01, Callout, EPIP-5.03, Accountability, and EPIP-5.04, Access Control.
Security is instructed by Control Room to have officer at roadblock to allow emergency response personnel onsite.
Non-essential personnel are to be held at roadblock, and all contractors, salesmen, and vendors arriving to the site should be turned back.
0700 EPIP-3.01, Activation of OSC, initiated.
Security directed to initiate EPIP-3.04, LEOF Activation.
EPIP-4.14, Inplant Monitoring, initiated. ,
EPIP-4.28. TSC/LEOF Radiation Monitoring System, initiated. )
i 0702 Initial " ALERT" notification messages transmitted to NRC, State j and local authorities. (EPIP-2.Cl previously initiated. i EPIP-2.02, Notification of NRC, initiated.)
t 0704 EPIP-3.02, Activation of TSC, initiated.
0705 EPIP-4.17, Monitoring of OSC and TSC, initiated.
Page 1
t 1
0708 Security roadblock established at Rt. 700 and station access road.
EPIP-4.08, Initial Offsite Release Assessment, initiated.
- 0710 General Office' Security conducts Corporate Emergency Response Team cellout.
EPlP-4.15, Onsite Monitoring, initiated.
0712 Security completes LEOF activation / setup.
EPIP-4.25, Liquid Effluent Sampling During an Emergency, initiated.
0715 Supt. Operations and SRO On-Call arrive in Control Room.
HP prepares to restrict access to Turbine and Auxiliary Buildings, as well as Main Steam Valve House.
Inplant monitoring teams dispatched. Radiological check-point and dosimetry issue established at entrance of Service Building.
0718 3rd message is transmitted to State and local authorities.
0720 Station Manager arrives in the Control Room.
EPIP-4.03, Dose Assessment Controllir.g Procedure, initiated.
EP1P-4,12. Offsite Environmental Monitoring Instructions, initiated.
0727 EPIP-4.27, Use of Class "A" Meteorological and Dose Calculational Model, initiated.
0728. Station accountability complete. 10 individuals missing.
Offsite monitoring team #1 _ dispatched. (EPIP-4.16, Offsite Monitoring, initiated).
0730 Assistant Station Manager arrives in Control Room and initiates transition of EPIPs and communications frem Control Room to TSC.
EPIP-4.19, Use of Radios for HP Monitoring, initiated.
0739 Station Manager assumes Station Emergency Manager (SEM) position.
0745 4th message in transmitted to State and local authorities.
Security- is notitied by HP that access to the following areas is restricted and that the areas are roped off:
UI - Main fream Valve House Ul - Steam Driven Aux Feedwater Pump House Turbine and Aux Building A radio announcement is made to all Security personnel on restricted access areas.
EPIP-4.06, Personnel Monitoring and Decontamination, initiated.
0747 All missing personnel located and accountability completed.
Page 2
0752 EP1P-5.08, Damage Control Guideline, initiated.
~
0753' TSC fully manned. OSC fully manned and activated.
0757. TSC activated.
0800 .Public Affairs inter-departmental callout conducted.
Press release #1 is issued.
0801 SEM and TSC Directors provide status update to facility.
0805 Sch message is transmitted to State and local authorities.
0818 Security is directed to allow access to Westinghouse representative.
0820 Corporate Emergency Response Center activated.
EPIP-2.04, Transmittal of Plant, Radiological and Emergency Status, initiated.
'0823 EPIP-4.10, Determination of X/Q, initiated.
0828 SEM, TSC Directors provide status update to facility.
Turbine and Auxiliary Building released from radiological controls / restricted access.
Westinghouse representative onsite.
6th message is transmitted to State and local authorities.
0830 Corporate Public News Center operational. 1 Rumor Control Area operational.
HPN Communications established with NRC from TSC.
Security is . notified by TSC to allow Virginia Power personnel at roadblock to assemble in Warehouse #2.
Offsite monitoring team #2 dispatched.
0843 LEOF updates Old Dominion Electric Cooperative.
0845 Security is notified by TSC to release Virginia Power personnel to no rmal work areas. All contractors are instructed to assemble in Project Area. Contractors that do not work in Project Area are I instructed to assemble in construction parking 1 t. All vendors l
and salesmen should still be turned back at the roadblock. Any news media personnel should be directed to the Local Media Center at Mineral Fire Hall.
Initiated callout of Security personnel to report at 1100 hours0.0127 days 0.306 hours 0.00182 weeks 4.1855e-4 months , in order to allow midnight shift personnel to leave.
0846 7th message is transmitted to State and local authorities.
Page 3
' 0853 EPIP-4.ll, Follow-up Offsite Release Assessment, initiated.
0858 EPIP-4.09, Source Term Assessment, initiated.
0900 2nd press release is issued.
0905 Security notifies Engineering and Construction that no vehicles will be allowed into Protected Area unless associated with the emergency.
0913 8th message transmitted to State and local authorities.
0915 LEOF activated.
0935 Corporate Security arrives at LEOF.
LEOF assumes responsibility for State and local notifications from TSC and transmits 1st message.
0937 CERC. weather forecast provided to LEOF.
0955 Security is directed by TSC to allow OMNI contract personnel into the Protected Area.
1000 Local Media Center fully operational.
1009 2nd LEOF message to State and local authorities transmitted.
. 1010 EPIP-4.18, Monitoring of LEOF, initiated.
1015 LEOF conducts conference to begin recovery planning process.
1018 UPI arrives at Security roadblock and is directed to the Local Media Center.
' 1035 LEOF making arrangements for media tour of site in afternoon.
1040 Received call from Jeff Lankford, NRC Region II. Notified that F. 4 Cantrell, B. Revsin, L. Nicholson, and S. Gagner en route to North Anna. ETA 1300 hours0.015 days 0.361 hours 0.00215 weeks 4.9465e-4 months . .
1043 3rd LEOF message transmitted to State and local authorities.
1058 CERC provides weather forecast update.
1100 3rd press release is issued.
1102 State Corporation Commission representatives arrive onsite (LEOF).
1115 4th LEOF message to State and local authorities is transmitted.
l PPFe 4
)
l 4 m..___.._._____.__. _ _ _ _ . . _ . _ _ _ . . _ .
b 1139 CERC provides weather. forecast update, 1140 Mr. Lankford with NRC informed that Cantrell, Revsin, and l Nicholson have a current badge at North Anna, and that access will be expedited.
1148 5th LEOF message transmitted to State and local authorities.
1210 CERC provides weather forecast update.
1220 6th LEOF message transmitted to State and local authorities' .
1238 CERC provides weather forecast update.
'1241 LEOF provides update to Old Dominion Electric Cooperative.
1252 7th LEOF message is transmitted to State and local authorities.
1303 NRC team arrives onsite.
1320 Security notified TSC that Channel 9 news was at roadblock and ;
stated that they were sent from Mineral Fire Hall (LMC). i 1326 8th LEOF message transmitted to State and local authorities.
1328 Security notified Channel 9 news at roadblock, as directed by TSC, to return to the LMC and that a press conference would be held onsite later in the day.
1333 EPIP-6.01, Re-entry / Recovery Guideline, initiated.
1335 Emergency terminated.
1336 Recovery meeting is scheduled in LEOF to outline organization and long-term plans (Recovery Organization is implemented).
NRC Communications terminated.
Emergency Response Facilities in process of deactivation.
1342 Security notified to terminate TSC and Control Room posts.
1343 9th and final (termination) message sent by LE0s to State and local authorities.
1345 Mr. Nicholson (NRC) onsite. Directed to LEOF for conference.
1355 Security instructed by LEOF to escort media from LMC to station for press conference.
1400 Final prors release issued.
Page 5 s4
- - _ - _ - _ _ - . _ _ . - - - . _ - - . _ _ - _ . _ - - - _ . _ _ - - -- . _ . _ . _ - . _ . - _ i
'1505' News media onsite.
Security roadblock terminated.
(
Security post at LEOF. terminated, 1603 Recovery meetings, outage planning proceeds into the night.
I Page 6
ATTACHMENT 5 EMERGENCY OPERATING PROCEDURE EP-0. REACTOR TRIP OR SAFETY INJECTION
i VIRGINIA POWER UEoYI* NORTH ANNA POWER STATION EMERGENCY PROCEDURE i
l Procedure Title Revision Number 1.00 REACTOR TRIP OR SAFETY INJECTION Page l 1-EP-0 (WITH TWO ATTACHMENTS) . 1 of 16 l Purpose The purpose of this procedure is to verify proper response of the Reactor Protection and Emergency Core Cooling Systems following actuation of a REACTOR TRIP or SAFETY INJECTION; and to assess plant conditions and identify the appropriate recovery procedure.
User NAPS Operations Personnel Entry Conditions Any of the following exist: , ,
i
1) -A-Reactor Trip has occurred as determined by NIS instrumentation, IRPI indication, or Reactor Trip breaker Status, l
2) A Reactor Trip is required as determined by setpoints or other requirements being exceeded,
3) A Reactor Trip / Safety Injection has occurred as determined by SI pump statuts or EDG status,
4) A Reactor Trip / Safety Injection is required as determined by setpoints or other requirements being exceeded, or
5) Transition from another plant procedure.
SAFE"Y RELA D Revision Record REV. 1.01 PAGES(S): 11, 13, Attach 2 DATE: 06-12-87 REV. PAGES(S): DATE:
REV. PAGES(S): DATE: l REV. PAGES(S): DATE:
REV. PAGES(S): DATE:
REV. PAGES (S): DATE:
Approval Recornmended Approved Date h )
Chairman Station Nuc ear Safety 06-12-87 and Operating Cummittee
FOLDOUT FOR FP-0 AND ES-0 PRO'!EDURES
1. RCP TRIP CRITERIA Trip all.RCPs if BOTH conditions listed below exist:
Charging /SI pumps - AT LEAST ONE RUNNING, AND
RCS subcooling based on Core Exit TCs - LESS THAN 25'T (70*F].
2. SI REINITIATION CRITERIA Manually initiate both trains of SI AND GO TO EP-0,. REACTOR TRIP OR SA?ETY INJECTION, Step 1 if either condition listed below occurs:
RCS subcooling based on Core Exit TCs - LESS THAN 30*F [20*F].
8
PRZR level - CANNOT BE MAINTAINED GREATER THAN 151 [501).
3. CHARGING /SI PUMP RECIRC PATH CRITERIA a) Isolate the Charging /SI pump recire. path MOVs if - RCS PRESSURE DECREASES TO LESS THAN 1275 PSIG [1575 PSIC).
b) Open the Charging /SI pump recire, path MOVs if - RCS PRESSURE INCREASES TO 2000 PSIG.
4. RED PATH
SUMMARY
a) SU3 CRITICALITY - Nuclear power greater than 5*
b) CORE COOLING - Core Exit TCs greater than 1200*F E
Core Exit TCs greater than 700'F AND RVLIS full range less than 461 with no RCPs running c) HEAT SINK - Narrow Range level in all SGs less than 10" [32"] AND total feedvater flov less than 340 gpm d) INTEGRITY - Cold leg temperature decrease greater than 100*F in last >
60 minutes AND RCS cold leg temperature less than 285'F e) CONTAINMENT - Containment pressure greater than 60 PSIA
5. ECST LEVEL CRITERIA Make-up to the ECST from the CST or provida alternate sources for AFW )
suction (SW or FP) when ECST level decreases to 401. i
me. s7een19 1
NUMBER. PROCEDURE TITLE REVISION
.00 1-EP-O' REACTOR TRIP OR SAFETY INJECTION .
PAGE j 2 of 16
- STEP ACTION / EXPECTED RESPONSE RESPONSE NOTQBTAINED NOTE: Bracketed [ ] numbers show immediate action Steps, i
NOTE: Setpoints in brackets [ ] are for adverse containment atmosphere (20 psia containment pressure or 10 R/HR containment radiation).
[1.] MANUALLY TRIP REACTOR:
a) Open both reactor tr$p breakers b) Verify reactor - TRIPPED b) GO TO 1-FRP-S.1, RESPONSE TO NUCLEAR POWER
Reactor trip and bypass GENERATION /ATWS, Step 1 breakers - OPEN
Neutron Flux -
DECREASING TO LESS THAN 5%
[2.] MANUALLY TRIP TURBINE:
a) Depress both turbine trip pushbuttons b) Verify all turbine stop b) Place both EHC pumps in valves - CLOSED P-T-L.
IF turbine still not Eipped THEN manually i runback turbine.
1 IF turbine canNOT be E nback, THEN close MSTVs and bypass valves.
c) Close rebeater inlet valves by depressing reset
FOLDOUT FOR EP-0 AND ES-0 PROCEDURES
1. RCP TRIP CRITERIA Trip all RCPs if BOTH conditions listed below exist:
Charging /SI pumps - AT LEAST ONE RUNNING, AND
RCS subcooling based on Core Exit TCs - LESS THAN 25'F [70*F].
2. SI REINITIATION CRITERIA Manually initiate both trains of SI AND GO TO EP-0,. REACTOR TRIP OR SAFETY INJECTION, Step 1 if either condition liste'd balow occurs:
RCS subcooling based on Core Exit TCs - LESS THAN 30*F [80*F].
8
PRZR level - CANNOT BE MAINTAINED GREATER THAN 15* [501] .
3. CRARGING/SI PUMP RECIRC PATH CRITERIA a) Isolate the CharginC/SI pump recire, path MOVs if - RCS PRESSURE DECREASES TO LESS THAN 1275 PSIG [1575 PSIG].
b) Open the Charging /SI pump recire. path MOVs if - RCS PRESSURE INCREASES'TO 2000 PSIG.
4. RED PATH
SUMMARY
a) SUBCRITICALITY - Nuclear power greater than 5" b) CORE COOLING - Core Exit TCs greater than 1200*F 8
Core Exit TCs greater than 700*F AND RVLIS full range less than 46" with no RCPs running c) HEAT SINK - Narrow Range level in all SGs less than 10" [321] ~AND total feedvater flow less than 340 gpm d) INTEGRITY - Cold leg temperature decrease greater than 100*F in last 60 minutes AND RCS cold leg temperature less than 285'F l l
e) CONTAINMENT - Containment pressure greater than 60 PSIA l j
5. ECST LEVEL CRITERIA Make-up to the ECST from the CST or provide alternate sources for AFW I
suction (SW or FP) when ECST level decreases to 401.
w.. ores 7:13 runtcER PROCEDURE TITLE REVISION 1.00 1 EP REACTOR TRIP OR SAFETY INJECTION PAGE 3 of 16
- STEP ACTIONMXPECTED RESPONSE RESPONSE Nu'TOD?AINED
[3.] VERIFY POWER TO AC EMERGENCY BUSSES:
a) AC emergency busses - AT a) Immediately restore power LEAST ONE ENERGIZED to at least one AC emergency bus.
F power canNOT be IF, restored, THEN GO TO 1-ECA-0.0, LOSS.OF ALL AC POWER, Step 3.
b) AC emergency busses - b) Try to restore power to ALL ENERGIZED deenergized AC emergency bus.
[4.] CHECK IF SI IS ACTUATED: Verify that none of the following conditions requiring
Charging /SI pumps - RUNNING SI have occurred:
LHSI pumps - RUNNING
Emergency Diesel Generators -
Low PRZR pressure RUNNING
High containment pressure
Any SI First-Out Annunciator
Steamline differential LIT pressure
High steamflow with low Tavg
High steamflow with low j steam pressure j IF,SI required, THEN GO TO Step 5.
IF NOT required, THEN GO TO 1-ES-0.1, REACTOR TRIP RESPONSE, S tep ,1_.
l
\
1 i
FOLDOUT FOR EP-0 AND ES-0 PROCEDURES I
i
1. RCP TRIP CRITERIA Trip all RCPs if BOTH conditions listed below exist:
J
Charging /SI pumps - AT LEAST ONE RUNNING, AND
RCS subcooling based on Core Exit TCs - LESS THAN 25'T [70*F]. l
2. SI REINITIATION CRITERIA Manually initiate both trains of SI AND GO TO EP-0,. REACTOR TRIP OR SAFETY INJECTION, Step 1 if either condition listed below occurs:
RCS subcooling based on Core Exit TCs - LESS THAN 30*F [80*F].
pR
PRZR level - CANNOT BE MAINTAINED GREATER THAN 15% [50%).
3. CHARGING /SI PUMP RECIRC PATH CRITERIA a) Isolate the Charging /SI pump recire. path MOVs if - RCS PRESSURE DECREASES TO LESS TRAN 1275 PSIG (1575 PSIG).
b) Open the Charging /SI pump recire. path MOVs if - RCS PRESSURE INCREASES TO 2000 PSIG. ,
4 RED PATH
SUMMARY
a) SUBCRITICALITY - Nuclear power greater than 5%
b) CORE COOLING - Core Exit TCs greater than 1200*F OR Core Exit TCs greater than 700'F AND RVLIS full range less than 46" with no RCPs running c) HEAT SINR - Narrow Range le al in all SGs less than 10" [32*] AND total feedvater flov less than 340 gpm d) INTEGRITY - Cold leg temperature decrease greater than 100'T in last 60 minutes AND RCS cold leg temperature less than 285'F a) CONTAINMENT - Containment pressure greater than 60 PSIA
5. ECST LEVEL CRITERIA l Make-up to the ECST from the CST or provide alternate sources for AFW suction (SW or FP) when ECST level decreases to 40%.
i l
I l l 1
7_,
m. ormersn NU:BER ' PROCEDURE TITLE REVISION 1.00-1-EP-0 REACTOR TRIP OR SAFETT INJECTION PAGE l
4 of 16 STEP ACTION / EXPECTED RESPONSE . RESPONSE NOT0 STAINED
[5.J MANUALLY INITIATE BOTH TRAINS OF SI
[6.} CHECK CHARGING /SI PUMP ALIGNMENT:
a) RWST Suction - OPEN .a) Manually open valves.
MOV-1115B
MOV-1115D b) VCT Suction - CLOSED b) Manually close valves.
MOV-1115C
MOV-1115E c) Normal charging - CLOSED c) Manually close valves.
MOV-1289A
MOV-1289B d) Letdown isolation - CLOSED d) Manually close valves.
HCV-1200A
HCV-1200B
HCV-1200C
POLDOUT POR-EP-0 AND ES-0 PROCEDURES ,
1. RCP TRIP CRITERIA Trip all RCPs if BOTH conditions listed below exist:
Charging /SI pumps - A7 LEAST ONE' RUNNING, AND
RCS subcooling based on Core Exit TCs - LESS THAN 25'F (70*F].
2. SI REINITIATION CRIT 2RIA Manually initiate both trains of SI AND GO TO EP-0,, REACTOR TRIP OR SAFETY
. INJECTION, Step 1 if either condition listed below occurs:
RCS subcooling based on Core Exit TCs - LESS THAN 30*F (80*F].
OR
PRZR level - CANNOT BE MAINTAINED GREATER THAN 15% [50%].
3.- CHARGING /SI PUMP RECIRC PATH CRITERIA a) Isolate'the Charging /SI pump recire. path MOVs if - RCS PRESSURE DECREASES TO LESS THAN 1275 PSIG (1575 PSIG).
b) Open the Charging /SI pump recire. path MOVs if - RCS PRESSURE
-INCREASES TO 2000 PSIG.
4. RED PATH SUMMART a) SUBCRITICALITY - Nuclear power greater than 5:
b) CORE COOLING - Core Exit TCs greater than 1200*F 9.E.
Core Exit TCs greater than 700*F AND RVLIS full range less than 46% with no RCPs running c) HEAT SINK - Narrow Range level in all SGs less than 10 (32%] AND total feedwater flow less than 340 gpm o
d) INTEGRITY - Cold leg temperature decrease greater than 100'F in last 60 minutes AND RCS cold leg temperature less than 285'F e) CONTAINMENT -' Containment pressure greater than 60 PSIA
5. ECST LEVEL CRITERIA Make-up to the ECST from the CST or provide alternate sources for AFW suction (SW or FP) when ECST level decreases to 40%.
. 1 3
No.C7887210 -
I REVISION
' NUMBER PROCEDURE TITLE 1.00 21-EP REACTOR TRIP OR SAFETY INJECTION PAGE 5 of 16.
1'
- STEP ACTIONMXPECTED RESPONSE RESPONSENOT06TAINED (7.]- VERIFY CHARGING /SI FLOW:
a) Two Charging /SI pumps - a) Manually start pumps.
RUNNING b) Cold leg SI flow - INDICATED 'b)
Manually align BIT:
FI-1961 1) Close BIT recirc
FI-1962 valves:
FI-1963
TV-1884A
FI-1943
TV-1884B .
FI-1943-1
TV-1884C
2) Open BIT outlet valves:
MOV-1867C i
MOV-1867D
3) Open BIT inlet valves:
MOV-1867A l l
MOV-1867B J
[8.) VERIFY FW ISOLATION:
Main FW flow control
Manually close valves.
valves - CLOSED ;.
FW isolation MOVs - CLOSED
Manually close valves. .,
Main FW pumps - TRIPPED
Manually trip pu'mps.
Bypass flow control valves -
Manually close valves.
CLOSED ,
Standby Main FW pump (s) in - *PlacedeP-T-L.
.P-T-L
- .:m m
. . _ . _ _ _ _ _____.__.._.__m.._ _ _ _ _ _ _ _ . _ _ . _ _ -
.POLDOUT POR EP-0 AND ES-0 PROCEDURES
1. RCP TRIP CRITERIA Trip all RCPs if BOTH conditions listed below exist:
Charging /SI pumps - AT LEAST ONE RUNNING, AND
RCS subcooling based on Core Exit TCs - LESS THAN 25'T [70'F].
2. SI REINITIATION CRITERIA Manually initiate both trains of SI AND GO TO EP-0, REACTOR TRIP OR SAFETY INJECTION, Step 1 if either condition listed belov occurs:
RCS subcooling based on Core Exic TCs - LESS THAN 30'F [80*F].
E
PRZR level - CANNOT BE MAINTAINED GREATER THAN ISI [50I].
3.
CHARGING /SI PUMP RECIRC PATH CRITERIA a)
Isolate the Charging /SI pump recire, path MOVs if - RCS PRESSURE b) DECREASES TO LESS THAN 1275 PSIG [1575 PSIG].
Open the Charging /SI pump recire, path MOVs if - RCS PRESSURE INCREASES TO 2000 PSIG.
4. _ RED PATH
SUMMARY
a)
SUBCRITICALITY - Nuclear power greater than 5%
b)
CORE COOLING - Core Exit TCs greater than 1200*F 8
Core Exit TCs greater than 700*F AND RVLIS full range c)c less than 46" with no RC?s running HEAT SINK - Narrow Range level in all SGs less than 10" [32".] AND d) total feedvater flow less than 340 gpm ,
INTEGRITY - Cold leg temperature decrease greater than 100'F in last )
',e) ' CONTAINMENT - Containment pressure greater than 60 PSIA 60 m
5. ECST LEVEL CRIT,ERIA _
I Maha-up to the ISST from the CST or provide alternate scurces for ATW suctiw (SU or, E7!) when ECST level decreases to 40*.
e s s'_
_ _- * - " " ' ~ _ _ _ _ _ _ . . - _ _ - - - ~ ~ ~ - ~ ~
we,steersto CU2'cER PROCEDURE TITLE REVISION 1.00 1-EP-0 REACTOR TRIP OR SAFETY INJECTION PAGE 6 of 16 i
e STEF ACTIOMMXMCTED RESPONSE RESPONSE NOTOSTAINED i
I
[9.] VERIFY AFW PUMPS - RUNNING: j a) Motor-driven AFW a) Manually start pumps. i pumps - RUNNING :
b) Turbine-driven AFW pump - b) Manually open steam supply ,i valves. -:
RUNNING i
j
[10.] VERIFY CONTAINMENT ISOLATION PHASE A:
a) Phase A - ACTUATED a) Manually initiate both trains of Phase A. i, b) Initiate Attachment 1
. [11.]_ VERIFY LHSI PUMPS STATUS:
a) Two LHSI pumps - RUNNING a) Manually start pumps.
GO TO Step 3 b) RCS pressure - LESS THAN b) 175 PSIG c) LESI pump flow - INDICATED c) Manually open LHSI valves:
FI-1945
MOV-1864A
FI-1946
MOV-1864B
MOV-1890C
MOV-1890D
[12.] VERITY SERVICE WATER PUMPS - Manually start pumps as
, RUNNING: required.
1-SW-P-1A - RUNNING S.R, 1-SW-P RUNNING l^
l
1-SW-P-1B - RUNNING l.
_._--.----___Q
f . A . ;> ,)
.N 'I
, g j , .'
~
T .,yh ] *.
L -
.V "
1
. . .>G ,
's
.' 1 A. 1
',s s l [ d 3 U ; . .A ' ,
\
s. .
<f ,
i Q', ,. t[{ l6
/' FOLD 01';. gor EP-0 A_b!D ES-0 PROCEDURES _ _
) ;.
pn , t 1, 3- t
> , 1 I .[
,i
[
L 1 A- 1. , .. CP TR 8'RITERIA
.M ip all RCPs if BOTH conditions listed below exf.stt t h,".
I, d ' [s ' *JCn'arging/SI pumps - AT LEAST OE RUNNING,
. .i .
h t.- '
'[
+
-:)
i gp dt .
i
iid 1subceci.ing based on Cora Er.it TCs - LESS TRAN 25*7 (70*F].
^ ,
i;2 . i 5
, 2. ' DI :RE".7ITIATION CRITERIA . .
5 4l /
Li Manenly 'iniWate both trair.c of SI ,A_N_D, GO TO EP-0, PIACTOR TRIP OR SAFETY 1 INECTIOL;, Sh?,J, if dther condition listed telov occurs: '
t
(,# j ,
\ J'
ACSisubcoo1Ln3 hased oa Core Exit TCs - LESS THAN 30*7 (80*F].
t .
'l SR
\ [
l ,
A VR2R 1[ vel - CANNOT BE MAINTAIND GREATER THAN 15'.150?d .
. i 4 .
'13. CHARGING /SI PUMP RECIRC PATH .CDI._T.U_ . .I.2
- 2, .Q, (, a) Isolate the Charging /FI pumit re~ ire.I path MOVs if - RCS PRESSUiG t.
< ' DECREASES TO LESS TU3'i 1275 PSIG (1575 PSICl, d ',1.
b) Open the Charging /S~i pump *iecira. path E 7s if - RCS PRI.SSURE '
INCREASCT 101200 TSIG.
4
-( 4. RED l'ATH
SUMMARY
i ',
s l A) SUpCRITICALITi!-Nda ar power greater than 5%
4
b) CORE COOLING -LCors Exin TCs grea:ar than 1200*F l b s
, t v g,
, i , ,
,; < Core Exit TCc kreatsti'than 700*F AND RVLIS. full range i,
less than 16: 61th.c.o RCPs running
, s.
4) HEAT SINK a Narrow Range'liveJ. in all SGs less than 10: (J2';] ~AND ~
^
total G 3 dvatz: fl,cv less thaa 340 gpm dl INTEGRITY - Cold 1,eg ter.neratara decrease greater than 100*F in last 60 minutes AND RCS xold leg temperature less;than,285'F
1) CONTA3tMENT 3Cantain=ent riesst.re greater than 60 PSDi
5. ECS,T LT'VE, CRI,? erb .
f Make-up to 'dq CCS*. 'frbe the CET pr provide alteimate r,ources for AIW I .- isuction, (SW or FP',, .when I' cst level decreases to 40%.
/
V w s
w' I. I *
?'
l I wo.s7ss7 10 NUMBER PROCEDURE TITLE ~ REVISION
. .00-
, 1-EP-0' REACTOR TRIP OR SAFETY INJECTION PAGE 7 of 16
- STEP ACTIONMXPECTED RESPONSE RE9ONSENOT08TAINED l [13.] CHECK IF MAIN STEAMLINES SHOULD BE ISOLATED:
a) Annunciator 2D-E3 - a) CO TO Step H.
LIT b) Verify MSTVs and b) Manually close valves.
bypass valves - CLOSED
, [14.] CHECK CONTAINMENT PPISSURE:
a) Containment pressure - a) Perform the following:
HAS kEMAINED LESS THAN 28 PSIA ON P-LM-110B 1) Hanually actuate BOTH trains of quench spray.
~
. 2) Initiate Attachment 1,.
3) Verify CCW pumps tripped.
1 l 4) Stop all.RCPs.
b) Containment pressure - b) Verify MSTVs and bypass i HAS REMAINED LESS THAN valves closed, E NOT,
l. 17.8 PSIA ON P-LM-1103 THEN manually close valves.
l
4 1
POLDOUT POR EP-0 AND ES-0 PROCEDURES L
1; RCP TRIP CRITERIA' Trip,all RCPs if BOTH' conditions listed below exist:-
Charging /SI pumps - AT LEAST ONE RUNNING,
.AND 'l
RCS subcooling based'on Core Exit TCs - LESS THAN 25*F'[70*F].
2.. SI REINITIATION CRITERIA Manually initiate both trains of SI AND GO TO EP-0,, REACTOR TRIP OR SAFE I!iJECTION, Step 1 if either condition listed below occurs:
RCS subcooling btsed on Core Exit TCs - LESS THAN 30*F [80*F].
S.R,
PRZR level - CANNOT BE MAINTAINED GREATER 1 TRAN 15% [50:
3.
CHARGING /SI PUMP RECIRC-PATH CRITERIA a)
' Isolate the Charging /SI pump recire. path MOVs if - RCS PRESSURE b) > DECREASES TO LESS THAN 1275. PSIG (1575= PSIG].
Open the Charging /SI pump recire. path MOVs if - RCS PRESSURE INCREASES TO 2000 PSIC.
4. RED PATH
SUMMARY
a) b) SUBCRITICALITT . Nuclear power greater than 5%
CORE COOLING - Core Exit TCs greater than 1200*F OR-1 Core Exit TCs g eater than 700*F AND RVLIS full range c)- less than 463 with no RCPs running -l
' HEAT SINK - Narrow Range level in all SGs less than 101 (32%] AND d)' total feedwater flow less than ',40 gpm INTEGRITY - Cold leg temperature decrease greater.than 100*F in-last e)
CONTAINMENT - Containment pressure greater than 60 JSIA6 ,
5.- ECST LEVEL CRITERIA Make-up to the ECST from the CST or provide alternate sources for AFW suction (SW or FP) when ECST level decreases to 40%.
I i
a e \
i i
_ _ _ _ _ . _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ . _ . _ _ _ _ _ _ . _ _ _ _ I
No. 9720?219 -
. NUMBER PROCEDURE TITLE REVISION
['
' ' .00 1-EP-0 REACTOR TRIP OR SAFETY INJECTION PAGE 8 of=16
,. ~ ' STEP ACTION / EXPECTED RESPONSE RESPONSENOTOBTAINED ,
-1: -
15. VERIFY AFW FLOW: -)
a). AW f3ow - INDICATED a) Manually align AW valves
FI-FW-100A OR
FI- N-100B
FI-FW-1000- Manually start pumps, b) Verify total flov - b) E SG NR level greater GREATER THAN 340 GPM than 10% [32%) in any SG, THEN control feed flow to maintain NR level.
IF NR l'evel less than 10%-
T32%)inallSGs,ANDIF AFW flow greater than 340 gym can NOT be established, THEN GO.TO 1-FRP-H.1, .
LOSS OF SECONDARY HEAT SINK, Step 1,.
16. DIRECT UNIT 2 OPERATOR TO INITIATE 1-AP-47, UNIT OPERATION WITH OTHER UNIT EMERGENCY
(.
l
)
iPOLDOUT FOR EP-0 AND ES-0 PROCEDURES
1. 'tCP TRIP CRITERIA Trip'all RCPs if BOTH conditions listed.below exist:. .
Charging /SI pumps.- AT LEAST ONE RUNNING, .'
-1 i
AND
]
l
'* RCS subcooling based:en Core Exit TCs;- LESS THAN 25*F [70*F].
2. SI REINITIATION CRITERIA Manually initiate both trains of SI AND GO TO EP-0,. REACTOR TRIP OR SAFETY '
INJECTION, Step l if either condition listed below occurs:-
~
RCS subcooling based on Core Exit TCs - LESS THAN.30*F~[80*F].
0,,R
PRZR-level - CANNOT BE MAINTAINED GREATER THAN 15%-[50%].
3. CHARGING /SI PUMP RECIRC PATH CRITERIA.
a) Isolate the Charging /SI pump recire. path MOVs if - RCS PRESSURE DECREASES TO LESS THAN 1275 PSIG [1575 PSIG].
'b) Open the' Charging /SI pump recire path MOVs if - RCS PRESSURE INCREASES-TO 2000 PSIG.
6. RED PATH
SUMMARY
a) SUBCRITICALITY - Nuclear power greater than 5%
b) CORE COOLING.- Core Exit TCs greater than 1200*F 0,,fR, Core Exit TCs greater than 700*F AND RVLIS full range less than 46 with no RCPs running c) HEAT SINK - Narrow Range level'in all SGs less than 10% [32:] AND
, total feedwater flov less than 340 gym d) INTEGRITY - Cold leg temperature decrease greater than 100*F in last 60 minutes AND RCS cold leg temperature less than 285'T e) CONTAINMENT - Containment pressure greater than 60 PSIA
5. ECST LEVEL CRITEkIA i Make-up to the ECST from the CST or provide alternate sources for AFU '
suction (SW or FP) when ECST level decreases to 40%.
I
__..___________________._______m____ _ _ . _ _ _ _ _ _ _ _ _ _
me. ores 7:13
' nun 90ER . PROCEDURE TITLE REVISION
.00 1-EP-0 REACTOR TRIF OR SAFETY INJECTION PAGE .
I' 9 of 16
- -STEP' ACTIONNXMCTEC RESPONSE RESPONSENOTOCTAINED
'17. CHECK RCS TEMPERATURE - IF temperature less than 547'F, STABLE AT OR TRENDING TO THEN stop dumping steam.
'547'F F cooldown continues, THEN:
a) Adjust tots 1 AFU flow to 340 gpm until at least one SG NR level is greater.than 10% [32%].
IF cooldown continues THEN b) . close MSTVs, and bypass valves.
_ IF, temperature greater that 547'F and increasing, THEN:
Dump steam to the co- Suser pR Dump steam using SG PORVs.
FOLDOUT FOR EP-0 AND ES-0 PROCEDURES
1. RCP TRIP CRITERIA Trip all RCPs if BOTH conditions listed below exist: }
Charging /SI pumps - AT LEAST ONE RUNNING, 1
AND
RCS subcooling based on Core Exit TCs - LESS THAN 25*F [70'F]. !
2. SI REINITIATION CRITERIA Manually initiate both trains pf SI AND GO TO EP-0,. REACTOR TRIP OR SAFETY INJECTION, Step 1 if either condition listed below occurs:
RCS subcooling based on Core Exit TCs - LESS THAN 30*F [80'F].
2
PRZR level - CANNOT BE MAINTAINED GREATER (50:1 THAN 15:
3. l CHARGING /SI PCMP RECIRC PATH CRITERIA a) l Isolate the Charging /SI pump recire. path MOVs if - RCS PRESSURE b) DECREASES TO LESS THAN 1275 PSIG (1575 PSIG]. {
Open the Charging /SI pump recire. path MOVs if - RCS PRESSURE INCREASES TO 2000 PSIC.
1
4. RED PATH
SUMMARY
a)
SUBCRITICALITY - Nuclear power greater than 5:
b) CORE COOLING - Core Exit TCs greater than 1200*F s E Core Exic TCs greater than 700*F AND RVLIS full range c) less than 46: with no RCFs running HEAT SINK - Narrow Range level in all SGs less than 10: (32:] AND d) total feedvater flow less than 340 gpm INTEGRITT - Cold leg temperature decrease greater than 100*F in last e) 60 minutes AND RCS cold leg temperature less than 285'T CONTAINMENT - Containment pressure greater than 60 PSIA
5. _ECST LEVEL CRITERIA Make-up to the ECST from the CST or provide alternate sources for AIW suction (FW or FP) when ECST level decreases to 40%.
n, ovesun '
PROCEDURE TITLE REV!$10N-NU:8ER 1.00 [
1-EP-0 REACTOR TRIP OR SAFETY INJECTION PAGE -
10 of 16 i I' ;
- STEP ACTIOMMXMCTED RESPONSE RESPONSE NOTGETAINED 1
18. CHECK PRZR PORVs AND SPRAY VALVES:
a) -Master controller, a) Take manual control of
'PC-1-444J.- NOT FAILED PC-1-444J.
'b) PORVs.- CLOSED' b) IF,,PRZR pressure less than 2335 psig, THEN manually
PCV-1455C close PORVs.
PCV-1456 IF any PORY can NOT be-closed, THEN manually, close its block MOV.
IF the block MOV can NOT be Hosed, THEN GO TO 1-EP-1-,
LOSS OF REACTOR OR SECONDARY COOLANT, Step 1,.
c) PRZR spray valves - CLOSED c) IF PRZR pressure less than 2260 psig, THEN manually
PCV-1455A close valves.
PCV-1455B IF valves can NOT be H osed, THEN stop RCP(s) supplying failed spray valve (s):
"A" RCP - PCV-1455A "C" RCP - PCV-1455B
FOLDOUT FOR EP-0 AND ES-0 PROCEDURES
1. RCP TRIP CRITERIA ~
Trip all RCPs if BOTH conditions listed below exist:
Charging /SI pumps - AT LEAST ONE RUNNING, i AND l
RCS subcooling based on Core Exit TCs - LESS THAN 25'F [70*F).
2. SI REINITIATION CRITERIA Manually initiate both trains of SI AND GO TO EP-0,. REACTOR TRIP OR SAFETY INJECTION, Step 1 if either condition listed below occurs:
RCS subcooling based on Core Exit TCs - LESS THAN 30*F [80*F].
E 1 k
i
PRZR level - CANNOT BE MAINTAINED GREATER THAN 15% [50%]. j 3.
CHARGINC/SI PUMP RECIRC PATH CRITERIA a)
Isolate the Charging /SI pump recire. path MOVs if - RCS PRESSURE DECREASES TO LESS THAN 1275 PSIG (1575 PSIG]. j b) )
Open the Charging /SI pump recire, path MOVs if - RCS PRESSURE INCREASES TO 2000 PSIG. !
l
4. RED PATH SU19 FART J a) SUBCRITICALITY - Nuclear power greater than 5%
b) CORE COOLING - Core Exit TCs greater than 1200*F E
Core Exit TCs greater than 700*F AND RVLIS full range c) less than 46* with no RCPs running HEAT SINK - Narrow Range level in all SGs less than 10" [32%] AND d) total feedvater flow less than 340 gpm INTEGRITY - Cold leg temperature decrease greater than 100*F in last e) 60 minutes AND RCS cold leg temperature less than 285'T CONTAINMENT - Containment pressure greater than 60 PSIA
5. ECST LEVEL CRITERIA l
l Make-up to the ECST from the CST or provide alternate scurces for AFW 1 suction (SW or FP) when ECST level decreases to 40*.
1
6 nesnto PROCEDURE TITLE REVISION NU." DER
.00 .j
.1-EP-0 REACTOR TRIP OR SAFETY INJECTION PAGE 11 of 16
- STEP ACTION / EXPECTED RESPONSE ' RESPONSE NOTODTAINED eo*************************************
CAUTION: To prevent Emergency Diesel Generator overload, the #1 or #4 PR2R heater banks should not be re-energized until the respective Emergency Diesel Generator load is less than 2750 KW.
oo*************************************
NOTE: Loss of seal ~ injection flow can cause RCP seal 4 degradation. l l
19, CHECK IF RCPs SHOULD BE STOPPED:
a) Charging /SI-pumps - a) GO TO Step H.
AT LEAST ONE RUNNING b) RCS subcooling based on b) GO TO Step H.
Core Exit TCs - LESS THAN 25'F (70'F]
c) Stop all RCPs eo*************************************
CAUTION: Charging /SI pump recire valve must be open at 2000 psig RCS pressure to prevent possible pump damage.
ooe************************************
20. CHECK IF CHARGING /SI PUMP RECIRC MOV(s)-
SHOULD BE CLOSED:
a) RCS pressure - a) GO TO Step H.
LESS THAN 1275
[1575 PSIG] ,
b) Close Charging /SI pump recire MOV(s): l
MOV-1275A 1-CH-P-1A
MOV-1275B 1-CH-P-1B
MOV-1275C 1-CH-P-1C
1 1
l FOLDOUT FOR EP-0 AND ES-0 PROCEDURES i
1. RCP TRIP CRITERIA Trip all RC?s if BOTH conditions listed below exist:
Charging /SI pumps - AT LEAST CNE RUNNING, AND
RCS subcooling based on Core Exit TCs - LESS THAN 25'F [70*F].
2. SI REINITIATION CRITERIA Manually initiate both trains of SI AND GO TO EP-0,, REACTOR TRIP OR SAFETY INJECTION, Step J_ if either condition listed below occurs: '
RCS subcooling based on Core Exit TCs - LESS THAN 30*F [80*F]. '
E
PRZR level - CANNOT BE MAINTAINED GREATER TRAN [50:].15:
3.
CHARGING /SI PUMP RECIRC PATH CRITERIA a)
Isolate the Charging /SI pump recire, path MOVs if - RCS PRESSURE b) DECREASES TO LESS THAN 1275 PSIG [1575 PSIG].
Open the Charging /SI pump recire. path MOVs if - RCS PRESSURE INCREASES TO 2000 PSIG.
4. _ RED PATH
SUMMARY
a) SU3 CRITICALITY - Nuclear power greater than 5 b) CORE COOLING - Core Exit TCs greater than 1200*F S
Core Exit TCs greater than 700*F AND RVLIS full range c) less than 46 vich no RCPs running HEAT SINK - Narrow Range level in all SGs less than 10 [32 ] AND d) total feedwater flow less than 340 gpm INTEGRITT - Cold leg temperature decrease greater than 100*F in last e) 60 minutes AND RCS cold leg temperature less than 283*F CONTAINMENT - Containment pressure greater than 60 PSIA
5. ECST LEVEL CRITERIA Make-up to the ECST from the CST or provide alternate sources for AFW suction (SW or FP) when ECST level decreases to 40%.
no.neont$
NU:BER PROCEDURE TITLE REVISION
.00 1-EP-0 REACTOR TRIP OR SAFETY INJECTION PAGE 12 of 16
- STEP ACTION / EXPECTED RESPONSE RESPONSE NOTOBTAINED
21. VERIFY NOTIFICATIONS:
a) STA - NOTIFIED l .. b) EPIP - INITIATED
22. CHECK THAT SGs ARE NOT FAULTED: GO TO 1-EP-2, FAULTED STEAM GENERATOR ISOLATION, Step 1.
NO SG PRESSURE DECREASING IN AN UNCONTROLLED MANNER
NO SG COMPLETELY DEPRESSURIZED
23. CHECK THAT SG TUBES ARE NOT GO TO 1-EP-3, STEAM GENERATOR RUPTURED: TUBE RUPTURE, Step 1.
Condenser air ejector radiation - NORMAL
SG main steamline radiation - NORMAL
SG blowdowit radiation -
NORMAL
24. CHECK THAT RCS IS INTACT: GO TO 1 57-1, LOSS OF REACTOR OR SEC00ARY COOLANT, Step 1
Containment radiation -
NORMAL
Containment pressure -
NORMAL
Containment Recirculation Spray sump level - NORMAL t
i i
1 POLDOUT POR EP-O AND ES-0 PROCEDURES
1. RCP TRIP CRITERIA Trip all RCPs if BOTH conditions listed below exist:
Charging /SI pumps - AT LEAST ONE RUNNING, I b
'i
RCS subcooling based on Core Exit TCs - LESS THAN 25'F (70*F].
2. SI REINITIATION CRITERIA Manually initiate both trains of SI AND GO TO EP-0, REACTOR TRIP OR SAFETY ,
INJECTION, Step 1 if either condition listed below occurs)
RCS subcooling based on Core Exit TCs - LESS THAN 30*F (80*F].
_OR
PRZR level - CANNOT BE MAINTAINED GREATER THAN 15 [50:].
3. _ CHARGING /SI PUMP RECIRC PATH CRITERIA a) Isolate the Charging /SI pump recire. path MOVs if - RCS PRESSURE b) DECREASES TO LESS THAN 1275 PSIG (1575 PSIG].
Open the Charging /SI pump recire. path MOVs if - RCS PRESSURE INCREASES TO 2000 PSIG.
1
4. RED PATH
SUMMARY
a) SUBCRITICALITY - Nuclear power greater than 5:
b) CORE COOLING - Core Exit TCs greater than 1200'F 9.R Core Exit TCs greater than 700*F AND RVLIS full range less than 46: with no RCPs running c) HEAT SINK - Narrow Range level in all SGs less than 10 (32 ] AND total feedvater flow less than 340 gpm d) INTEGRITY - Cold leg temperature decrease greater than 100*F in last 60 minutes AND RCS cold leg temperature less than 285'T e) CONTAINMENT - Containment pressure greater than 60 PSIA
5. ECST LEVEL CRITERIA .
Make-up to the ECST from the CST or provide alternate sources for AFW suction (SW or FP) when ECST level decreases to 40%.
\ .
, i/
n orestsar I' ::UNDER PROCEDURE TITLE REVISION
.00
1-EP REACTOR TRIP OR SAFETY INJECTION PAGE ,
N 13 of 16
- STEP ACTIONtEXPECTED RESPONSE RESPONSENOTOBTAINED L 25. CHECK IF SI CAN BE TERMINATED:
I a) 'RCS subcooling based on a) DO NOT STOP S1 PUMPS.
t' < Core Exit TCs - GREATER GO TO Step E.
THAN-30*F.
b)- Secondary heat sink: b) IF neither condition satisfied, THEN D_O NOT STOP Total AFW flow to SGs - SI PUMPS GO TO Step.,2_7,.
'CREATER THAN 340 GPM pR, At least-one SG Narrow Range level - GREATER
- THAN 10%
c) RCS pressure - STABLE c) DO,NOT STOP SI PUMPS.
OR INCREASING GO TO Step E.. .
d) PRZR level - GREATER d) DO NOT STOP SI PUMPS.
THAN 15% Fry to stabilize RCS i pressure with normal PRZR spray. Return To Step 25a.
26. GO TO 1-ES-1,1, SI TERMINATION, Step 1,
27. INITIATE MONITORING OF Monitor CSF Status Trees with 1 CRITICAL SAFETY FUNCTION F-Series procedures.
STATUS TREES ON SPDS-e**************************************
f CAUTION: Alternate water sources.(CST or 1-AP-22.7) to prevent loss of AFW ,
L -pump suction pressure will be necessary if ECST decreases to 40%.
28. CHECK SG LEVELS: j l-a) Narrow Range level - a) Maintain total feed flow l
GREATER THAN 10% greater than 340 gpm until NR level is greater than 10%.
(STEP 28 CONTINUED ON NEXT PAGE) -
FOLDOUT FOR EP-0 AND ES-0 PROCEDURES
1. RCP TRIP CRITERIA Trip all RCPs if BOTH conditions listed below exist:
Charging /SI pumps - AT LEAST ONE RUNNING, AND
RCS subcooling based on Core Exit TCs - LESS THAN 25*F {70*F].
2. SI REINITIATION CRITERIA Manually initiate both trains of SI AND GO TO EP-0, REACTOR TRIP OR SAFETY INJECTION, Step 1 if either condition listed below occurs: !
j
RCS subcooling based on Core Exit TCs - LESS THAN 30*F [80*F]. j E I t
PRER level - CANNOT BE MAINTAINED GREATER THAN ISI [501]. l
3. CHARGING /SI PUMP RECIRC PATH CRITERIA a) Isolate the Charging /SI pump rectre. path MOVs if - RCS PRESSURE DECREASES TO LESS THAN 1275 PSIG [1575 PSIG).
b) Open the Charging /SI pump recire, path MOVs if - RCS PRESSURE INCREASES TO,2000 PSIG.
6. RED PATH
SUMMARY
a) SUBCRITICALITY - Nuclear power greater than 57.
b) CORE COOLING - Core Exit TCs greater than 1200*F E
Core Exit TCs greater than 700*F AND RVLIS full range less than 46I with no RCPs running c) HEAT SINK - Narrow Range level in all SGs less than 10" [32%] AND total feedvater flow less than 340 gpm d) INTEGRITY - Cold leg temperature decrease greater than 100*F in last 60 minutes AND RCS cold leg temperature less than 285*F e) CONTAINMENT - Containment pressure greater than 60 PSIA
5. ECST LEVEL CRITERTA Make-up to the ECST from the CST or provide alternate sources for AFW i suction (SW or FP) when ECST level decreases to 401. !
l
No. 97887213 PROCEDURE TlTLE REVISION NUMBER 1-EP-0 itEACTORTRIPORSAFETYINJECTION PA GE .
14 of 16 l
ACTIONMXPECTED RESPONSE. RESPONSENOTOBTAINED STEP I
28. CHECK SG LEVELS: (CONTINUED) b) Control feed flow to b) IF,NR level in any SG con-maintain Narrow Range tinues to increase in an level between 10% uncontrolled manner, THEN and 50% GO TO'1-EP-3, STEAM GENER-ATOR TUBE RUPTURE, Step 1.
29.- .
RESET SI
'30. RESET CONTAINMENT ISOLATION PHASE A AND PHASE B
31. VERIFY CONTAINMENT Manually open valves.
INSTRUMENT AIR VALVES - OPEN
TV-IA-102A
TV-IA-102B
32. CHECK SECONDARY RADIATION:
- a) Reset SI and align systems for sampling as required b) Secondary radiation- b) GO TO 1-EP-3, NORMAL STEAM GENERATOR TUBE RUPTURE, Step 1.
Condenser air ejector radiation - NORMAL
SG main steamline radiation - NORMAL
SG blowdown radiation -
NORMAL l
- _u._-._m__________ _ _ _ _ _ _
FOLDOUT FOR EP-0 AND ES-C PROCEDURES
1. RCP TRIP CRITERIA Trip all RCPs if BOTH conditions listed below exist:
Charging /SI pumps - AT LEAST ONE RUNNING, AND
RCS subcooling based on Core Exit TCs - LESS THAN 25'F [70'F].
2. SI REINITIATION CRITERIA Manually initiate both trains of SI AND GO TO EP-0, REACTOR TRIP OR SAFETY j INJECTION, Step 1 if either condition listed below occurs: I
RCS subcooling based on Core Exit TCs - LESS THAN 30*F [80'F].
E
PRZR level - CANNOT BE MAINTAINED GREATER THAN IS: (50 ].
3. CHARGING /SI PUMP RECIRC PATH CRITERIA a) Isolate the Charging /SI pump recire path MOVs if - RCS PRESSURE b) DECREASES TO LESS THAN 1275 PSIG (1575 PSIG].
Open the Charging /SI pump recire. path MOVs if - RCS PRESSURE INCREASES TO 2000 PSIG.
4 RED PATH
SUMMARY
a) SUBCRITICALITY - Nuclear power greater than 5 b) CORE COOLING - Core Exit TCs greater than 1200*F S
Core Exit TCs greater than 700*F AND RVLIS full range c) less than 46 with no RCPs running HEAT SINK - Narrow Range level in all SGs less than 10 (32 ] AND a d) total feedvater flow less than 340 gym INTEGRITY - Cold leg temperature decrease greater than 100*F in last e) 60 minutes AND RCS cold leg temperature less than 265'T CONTAINMENT - Containment pressure greater than 60 PSIA
5. ECST LEVEL CRITERIA Make-up to the ECST from the CST or provide alternate sources for AFW suction (SW or FP) when ECST level decreases to 40%.
No,17847210 NUMBER PROCEDURE TITLE REVISION
.00 l-EP-0 REACTOR TRIP OR SAFETY INJECTION PAGE 15 of 16
- STEP ACTION / EXPECTED RESPONSE RESPONSE NOTOBTAINED
33. CHECK FOR OUTSIDE CONTAINMENT Evaluate cause of abnormal-INVENTORY LOSS: conditions.
IF cause is a loss of RCS a) Safeguard sump inventory outside containment, level annunciators - THEN GO TO 1-ECA-1.2, LOCA l
NOT LIT OUTSIDE CONTAINMENT, Step 1.
"E" Panel F-8
"A" Panel C-1 b) Safeguards radiation -
NORMAL
34. CHECK PRT CONDITIONS - NORMAL Evaluate abnormal conditions as a possible source of RCS inventory loss:
Letdown relief valve
Sealvater return relief valve
Excess letdown relief valve j
i when aligned to VCT
RER relief valve (Intersystem l LOCA).
0 l
l l
l l
l FOLDOUT FOR EP-O AND ES-0 PROCEDURES i
1. RCP TRIP CRITERIA Trip all RCPs if BOTH conditions listed below exist:
Charging /SI pumps - AT LEAST ONE RUNNING, AND
RCS subcooling based on Core Exit TCs - LESS THAN 25'F (70*F].
2. SI REINITIATION CRITERIA Manually initiate both trains of SI AND GO TO EP-0,. REACTOR TRIP OR SAFET INJECTION, Step ,1_ if either condition listed below occurs: ' *
RCS subcooling based on Core Exit TCs - LESS THAN 30*F [80*F].
S.R_
PRZR level - CANNOT BE MAINTAINED GREATER THAN 15% [50%
3.
CHARGING /SI PUMP RECIRC PATH CRITERIA a)
LIsolate the Charging /SI pump recire. path MOVs if - RCS PRESSURE b) DECREASES TO LESS THAN 1275 PSIG (1575 PSIG].
Open the Charging /SI pump recire, path MOVs if - RCS PRESSURE INCREASES TO 2000 PSIC.
6. RED PATH
SUMMARY
a)-
SUBCRITICALITY - Nuclear power greater than 5:
b) _
CORE COOLING - Core Exit TCs greater than 1200*F pR Core Exit TCs greater than 700*F AND RVLIS full range c) less than 46 with no RCPs running HEAT SINK - Narrow Range level in all SGs less than 10 total feedwater flov less than 340 gpm (32 ] AND d)
INTEGRITY - Cold leg temperature decrease greater than 100*F in last e)
CONTAINMENT - Containment pressure greater than 60~ PSIA
5. ECST LEVEL CRITERIA Make-up to the ECST from the CST or provide alternate sources for AFW suction (SW or FP) when ECST level dacreases to 40%. )
i i
no.creann NUMBER PROCEDURE TITLE REVISION
.00 1-EP-0 REACTOR TRIP OR SAFETY INJECTION PAGE 16 of 16
~ STEP - - - ACTION / EXPECTED RESPONSE RESPONSENOTOBTAINED o**************************************
-CAUTION: If RCS pressure decreases to less than 250 psig, then the LHSI pumps must be manually restarted to supply water to the RCS.
o**************************************
35. CHECK IF LHSI PUMPS SHOULD BE STOPPED:
a) Check RCS pressurc:
1) Pressure - GREATER 1) GO TO 1-EP-1, LOSS OF TRAN 250 PSIG REACTOR OR SECONDARY COOLANT, Step 1.
2) Pressure - STABLE OR 2) GO TO Step 36,.
INCREASING b) Stop LHSI pumps and place in Auto-Standby
36. CHECK IF DIESEL GENERATORS SHOULD BE STOPPED:
a) Verify AC emergency busses - a) Initiate 1-AP-10.1 to ENERGIZED BY OFFSITE POWER restore offsite power.
b) Stop.any unloaded diesel generator as per 1-OP-6.1 and/or 1-0P-6.2
37. RETURN TO STEP E END l
No.97887220 NUMBER A TTACHMENT TITLE REVISION 1-EP-0 1.00 VERIFICATION OF AII######I ####
PHASE B ISOLATION 1 1 of 4
1. VERITt O_R, R MANUALLY PERFORM THE FOLLOWING AUTOMATIC OPERATIONS ON "H" SAFEGUARDS PANEL:
a) Verify Phase "B" isolation valves - CLOSED (located on the lower right corner of the panel)
TRIP VALVES (TV) - CLOSED (GREEN)
CC- CC- CC- CC-105A 102A 104A-1 _ 101A CC- CC- CC- CC-105B 102C 104B-1 -
103A CC- CC- CC- IA-105C 102E 104C-1 102A b) Verify Quench Spray - ALIGNED AND RUNNING RUNNING (RED) OPEN (RED) 1-QS-P-1A MOV-QS101A MOV-QS100A c) Verify SW - ISOLATED TO CCW 11 EAT EXCHANGERS l CLOSED (GREEN) l l MOV-SW-108A d) Verify SW - ALIGNED TO RS RXs l
OPEN (RED) OPEN (RED) OPEN (RED) OPEN (RED)
MOV-SW-103A MOV-SW-103D MOV-SW-104A MOV-SW-104D MOV-SW-101A MOV-SW-101C MOV-SW-105A MOV-SW-105C e) Verify Recire Spray - ALIGNED AND RUNNING (Note time delays)
RUNNING (RED) RUNNING (RED) OPEN (RED)
MOV-RS156A 1-RS-P-1A (3k min. T.D.) 1-RS-P-2A (3 min. T.D.) MOV-RS155A
J I'
% . nserano NUMBER A TTACHMENT TITLE. REVISION 1-EP-0L 1.00 A TTACHMENT PAGE PHASE B ISOLATION 1 2 of'4
. 2. VERIFY OR MANUALLY PERFORM THE FOLLOWING AUTOMATIC OPERATIONS ON "J" SAFEGUAES PANEL:
a) Verify Phase "B" isolation valves - CLOSED (located on the lower right corner of the panel).
. TRIP VALVES (TV) - CLOSED (GREEN)
CC- CC- CC- CC-
, 100A 1023 104A-2 101B CC- CC- CC- CC-100B '102D 104B-2 103B CC- CC- CC- IA-100C 102F 104C-2 102B b) Verify Quench Spray - ALIGNED AFD RUNNING RUNNING (RED) OPEN (RED) 1-QS-P-1B MOV-QS101B MOV-QS100B c) Verify SW - ISOLATED TO CCW HEAT EXCHANGERS CLOSED (GREEN)
MOV-SW-108B d) Verify SW - ALIGNED TO RS EXs OPEN (RED) OPEN (RED) OPEN (RED) OPEN (RED)
MOV-SW-103B MOV-SW-103C MOV-SW-104B MOV-SW-104C MOV-SW-101B MOV-SW-101D MOV-SW-105B MOV-SW-105D e) Verify Recire Spray - ALIGNED AND_ RUNNING (Note time delays)
RUNNING (RED) RUNNING (RED) OPEN (RED)
MOV-RS156B 1-RS-P-1B (3k min. T.D.) 1-RS-P-2B (3h min. T.D.) MOV-RS155B e
No.9TSS7220 NUMBER A TTACHMENT TITLE REVISION 1-EP 1.00 A TTACHMENT PAGE PHASE B ISOLATION 1: 3 of 4
3. VERIFT OR MANUALLY PERFORM THE FOLLOWING AUTOMATIC OPERATIONS ON THE UNIT 1 VENTILATION PANEL:
a) Verify all Containment Air Recirc Fans TRIPPED (AMBER) OR OFF (GREEN) 1-HV-F-1A 1-HV-F-1C 1-HV-F-1B 1-HV-F-1C b) Verify all shroud cooling fans OFF (GREEN) 1-HV-F-37A 1-HV-F-37B 1-HV-F-37C 1-HV-F-37D 1-HV-F-37E 1-HV-F-37F c) Verify Air Cirs Emer Supply Valves - CLOSED (GREEN)
CLOSED (CREEN) CLOSED (GREEN)
SW-TV-101A-1 SW-TV-101A-2 SW-TV-101B-1 SW-TV-101B-2 d) Verify that the following filters - DIVERTED TO THE IODINE FILTER FILTER (RED) FILTER (RED)
A0D-HV-107A1,2,3,4 A0D-HV-107B1,2,3,4 A0D-HV-128-1,2,3,4 A0D-HV-128-1,2,2,4 l
1
l S
' No. 9781722I I L) i g
' NUMBER A TTACHMENT TITLE REVISION -
1-EP-0 ; .
1.00
-VERIFICATION OF A TTAC# MENT PAGE PHASE B ISOLATION.
1 4 of'4
'I l
4. VERIFY OR ~
MANUALLY PERFORM THE FOLLOWING AUTOMATIC OPERATIONS ON THE -!
UNIT 1 RADIATION MONITORING PANEL:
a) Verify the'following sample pump's RED " Low Flow" light - NOT LIT (Note: 2 minute Time Delay)
.NOT LIT NOT LIT NOT LIT NOT LIT 1-SW-P-5 1-SW-P-8 1-SW-P-6 1-SW-P l 1
5. VERIFY OR MANUALLY PERFORM THE FOLLOWING AUTOMATIC OPERATIONS ON THE
~
-1 UNIT 1 CASING COOLING PANEL LOCATED BEHIND THE UNIT 1 BACKBOARDS: .l a)' Verify Casing Cooling Pumps - ALIGNED AND RUNNING l
"H" PANEL (left)
OPEN-(RED) OPEN (RED) RUNNING =(RED) ;
MOV-RS1013 MOV-RS100A 1-RS-P-3A I "J" PANEL (Right) ;
i OPEN (RED) OPEN (RED) RUNNING (RED) =l MOV-RS101A -
MOV-RS100B 1-RS-P-3B ,
I I
, 4 .
_ me.etastazo L ,
NUMBER ATTACHMENT TITLE REVISION 1-EP 1.00
' A TTACHMENT, PAGE ISOLATION 2 1 of'4 g
l-l- .
f 1. VERIFY OR MANUALLY PERFORM THE FOLLOWING AUTOMATIC OPERATIONS ON THE UNIT 1-l' "H" SAFEGUARDS PANEL:
CLOSED'(GREEN) OPEN'(RED)
TY-1884C MOV-1867C ^ OPEN (RED) OPEN (RED) CLOSED (GREEN)
TV-1884-A MOV-1867A MOV-SW-121A MOV-SW-122A MOV-SW-123A 0FF (GREEN) CLOSED (GREEN) 1-CV-P-3A MOV-1380 Trip Valve (TV) - CLOSED (GREEN) i BD- CV- DA- LM- LM- RM- SI- SS- SS- SS-100A 150A 100A 100C 101A&C 100A 100A 100A- 103A 112A BD- CV- DG- LM- VG - PM- MS- SS- SS-100C 150C 100A 100E 100A 100B 109A 101A 104A
BD SI- LM- LM- MS- TV- TT- SS - SS- TV-100E 101 100A 100G 110A 1204A 1859 102A 106A 1519A' SV- SV-102-1. 102-2 f
t
____________.__m._____.____._________
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No.97887220 '/'
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NUMBER Q . (gi t A TTACHMENT TITLE , REVISION .
1-EP-O' '-
(d 1.00 -l A TTACHMENT yn PAGE ,
[ z '
2 $1[ 2 of 4 ,
a l
2' . VERIFT OR MANUALLY PERFORM THE FOLLOWING AUTOMATIC OPERATIONS ON.TRE UNIT 1 7" SAFEGUARDS PANEL:
CLOSED (GREEN) OPEN (*tED) OPEN (RED) OPEN (RED). CLOSE _D,G (GRE_E]N MOV-1867D SW-MOV-121B' SW-MOV-1223 SWMOV-123B t TV-1884B MOV-1867B .
r OFF (GREEN) CLOSED'(GREEN) 1-CV-P-3B MOV-1381 Trip Valves (TV) - CLOSED (GREEN)
/
j p' BD- CV- DA- '
'lM- LM- RM- SI- SS- SS- SS-100B 150B . 1003 100D 101B&D 100C 100B 1003 1033 1123 i i
'f BD- CV-1 DG- LM- VG- RM- MS- SS - SS- l 100D 150D . 100B 100F 100B 100D 109 101B 104B j
.i
-BD- HCV-
LM- LM- MS- TV- TV- SS- SS- l 100F 1936 100B 100E 110 1204B 1842 1023 1063 i SV-
,_ ,103 i
3. .VERIFT CLOSED O_R R MANUALLY CLOSE THE FOLLOWING VALVES ON THE POST ACCIDENT 1 MONITORING (FAM) FANEL: .
CLOSED (GREEN)/ CLOSED (GREEN) ;
TV-DA103B TV-DA103A 4 44ps
~ - _ .
NO.97887220
)
NUMBER A TT/CnW.8NT TITLE REVISION 1-EP-0 1.00 VERIFICATION OF PHASE A A TTACHMENT '^ #'
ISOIJCION 2 3 of 4 I
/
4. VERIFY OK P12 FORM THE FOLLOWING AUTOMATIC OPERATIONS LOCATED AT THE BOTTOM 'OT THE UNIT 1 VINTILATICN PAHEL:
CLOSG) (GREEN)'- 0FF (GREEN) --
CLOSED (GREZN)
, ,i HV-Act-160-1 1-EV-F-15 HV-AOD-161-1
{ 5. Secura Vaste Gas ReIensee!
_ a) FCV-GW 101 - CLOSED
_ b) Inform unaffected unit to secure containment purge or hogging operations.,
6. VERIFTORMAM7ALLYPERFORh!THEFOLLOWINGAUTO:#.TICOPERATIONSLOCATED AT THE BOTTOM OF THE UNIT 2 VENTILATION PANEL:
I CLOSED ,(GREEN) CLO$ g fGREFN_)
HV-AOD-160-2 67 l,WD-161-2 l MOD MOD
/
/
i L . _ . . _ _ _ _ _ _ _ _
we. ores 7:so 1
-NUMBER A TTACHMENT TITLE REVISION 1-EP-0 1.00.
A TTACHMENT PAGE ISOLATION 2 4 of 4 7.. VERITY OR MANUALLY PERFORM THE FOLLOWING AUTOMATIC OPERATIONS ON THE UNIT 2 TAFEGUARDS PANELS:
"H" Panel "J" Panel RUNNING-(RED) RUNNING (RED) 2-SW-P-1A 2-SW-P-1B S.R 2-SW-P-4 ON (RED) (5 min T.D.) ON (RED) (5 min T.D.)
H, Analyzer Heat H y Analyzer Heat Tracing Train A- Tracing Train B
8. VERITY AUTOMATIC INITIATION OF BOTTLED FRESH AIR SUPPLY TO THE CONTROL ROOM:
,_ PI-HV-1311 PI-HV-2311 (Located behind the Unit 1 Post Accident Monitoring (PAM) Panel).
9. VERIFT O, R, PLACE HYDROGEN ANALTZER IN SERVICE AS PER 1-OP-63.2.
10. NOTIFY THE STA TO REVIEW 1.97 VARIABLES ON GROUPS 36 AND 37 0F THE SPDS.
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I ATTACimLNT 6 EMERGENCY OPERATINb PROCEDURf EP-3, STEAM GENERATOR TLBE RUTTURE Y
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.sesta s NORTH ANNA POWER STATION ,
EMERGENCY PROCEDURE j Number Procedure Title Revision 1.00 1-EP-3 STEAM GENERATOR TUBE RUPTURE Page (WITH ONE ATTACHMENT) 1 of 26 Purpose The purpou of this procedure is to provide instructions for identifying a ruptured S4(s) . The procedure includes isolating the ruptured SG(s) followed by RCS coo?.down and depressurization to the point of SI termination.
User NAPS Operations Personnel Entry Conditions This procedure is entered from: ~. .. ._ ;
I
1) 1-EP-0, REACTOR TRIP OR SAFETY INJECTION,
2) 1-EP-1,. LOSS OF REACTOR OR SECONDARY COOLANT, ,
3) 1-EP-2, PAULTED STEAM GENERATOR ISOLATION,
~
4) 1-FRP-H.3, RESPONSE TO STEAM GENERATOR HIGH LEVEL, POST LOCA COOLDOWN AND DEPRESSURIZATION, L-
5) 1-ES-1.2
0) 1-ES-3.1, POST-SGTR COOLDOWN USING BACKFILL,
7) 1-ES-3.2, POST-SGTR C00LDOWN USING BLOWDOWN,
8) 1-ES-3.3, POST-SGTR C00LDOWN USING STEAM DUMP,
9) 1-ECA-3.1, SGTR WITH LOSS OF REACTOR COOLANT - SUBC00 LED RECOVERY DESIRED, l 1-ECA-3.2, SGTR WITH LOSS OF REACTOR COOLANT - SATURATED 10)
RECOVERY DESIRED,
11) 1-ECA-3.3, SGTR WITHOUT PRESSURIZER PRESSURE CONTROL, or
12) 1-EP-1 SERIES FOLDOUT PAGE.
SA riTY R E _A- EJ Revision Record REV. 1.01 PAGES(S): 2,9,10,11,13,14,17,18,23,att 1 DATE: 06-12-87 REV. PAGES(S): DATE:
REV. PAGES(S): DATE:
REV. PAGES(S): DATE:
REV. PAGES(S): DATE:
REV. PAGES(S): DATE:
Approval Recommended Approved Date l f' [ Y' Chairrnan Station Nuc r Safety 06m12-87 and Operating Committee .
l L__ - _
a.
.m
_ 7 +
m ,
a
,I,i.',
f', DJ .
FOLDOUT FOR EP -3 AND ES-3 PROCEDURES w ..
.1... SI REINITIATION CRITERIA-
'. ' Manually operate Charging /SI pumps and align BIT as required and GO TO
.ECA-3.1, SGTR WITH LOSS;0F~ REACTOR COOLANT - SUBC00 LED RECOVERY DESIRED,.
-Step 1,if either condition listed below occurs: ,
RCS- subcooling; based on Core Exit TCs - LESS THAN 30*F (80*F].
ER.
1
' .* PRZR'levelL- CANNOT BE MAINTAINED GREATER THAN 15% [50%).
2. RED PATH
SUMMARY
a) SUBCRITICALITY - Nuclear power greater than 5%
b) CORE COOLING - Core Exit TCs greater than 1200*F pR Core Exit TCs greater than 700*F AND RVLIS full range less than 46% with no RCPs running-c)- HEAT SINK - Narrow Range level in-all SGs less than 10% [32%) AND total feedvater. flow less than 340 gpm
'd) INTEGRITY - Cold-leg temperature decrease greater than 100*F in last 60 minutes AND RCS cold leg temperature less than 285'F.
e) CONTAINMENT - Containment pressure greater than 60 PSIA
3. SECONDARY INTEGRITY CRITERIA C0 TO EP-2, FAULTED STEAM GENERATOR ISOLATION, Step 1. if any SG pressure is decreasing in an uncontrolled manner or has completely depressurized, and has not been isolated, unless needed for RCS cooldown.
t
.4. COLD LEG RECIRCULATION SWITCHOVER CRITERION Go To ES-1.3, TRANSFER TO COLD LEG RECIRCULATION, Step 1, if RWST level )
_J decreases to less than 29%.
! 5. ECST LE7EL CRITERIA Make-up to the ICST from the CST or provide alternate sources for AFW l suction (SW or FP) when ECST leve1' decreases to 40%.
i
.g 1
No.97887219 PROCEDURE TITLE REVISION NUMBER 1.00 1-EP-3 STEAM GENERATOR TUBE RUPTURE PAGE 2 of 26-I
- STEP ACTION / EXPECTED RESPONSE RESPONSENOTOBTES'i:
[-
1 NOTE: Setpoints in brackets [ ] are for adverse containment atmosphere (20 psia containment pressure or 10 R/HR containment radiation.)
NOTE: Personnel should be available for sampling during this procedure.
NOTE: Seal injection flow should be maintained to all RCPs.
1. CHECK IF RCPs SHOULD BE STOPPED:
i
=
a) Charging /SI pumps - a) GO TO Step 3.
AT LEAST ONE RUNNING b) RCS 'aubcooling based on b) GO TO Step 3.
Core' Exit TCs - LESS THAN 25'F [70*F) c) Stop all RCPs o**************************************
I CAUTION: Charging /SI pvmp recire valve must be open at 2000 psig RCS pressure to prevent possible pump damage, o**************************************
2. CHECK IF CHARGING /SI PUMP RECIRC MOV(s) SHOULD BE CLOSED:
a) RCS pressure - a) GO TO Step 3.
LESS THAN 1275 PSIG
[1575 PSIG) b) Close Charging /SI pump recire MOV(s):
MOV-1275A 1-CH-P-1A
MOV-1275B 1-CH-P-1B i
MOV-1275C 1-CH-P-1C I
r 1
FOLD 00T FOR EP-3'AND ES-3 PROCEDURES
1. -SI REINITIATION CRITERIA Manually operate Charging /SI' pumps and align BIT as required and GO TO j ECA-3.1, SGTR WITH LOSS OF REACTOR COOLANT ' SUBC00 LED RECOVERY DESIRED, ;
- Step J, if either condition listed below occurs: j
(
RCS subcooling based on Core Exit'TCs - LESS THAN 30*F [80*F].
1' 0,,R
PRZR level - CANNOT BE MAINTAINED GREATER THAN 15% [50%].
- 2. RED PATH
SUMMARY
q a) SUBCRITICALITY - Nuclear power greater than 5 b) CORE COOLING - Core Exit TCs greater than 1200*F ,
i Core Exit TCs greater than 700*F AND RVLIS full range less than 46*. vich no RCPs running c) EEAT SINK - Narrow Range level in all SGs less than 10: [32"] AND j' total feedwater flow less than 340 gym .
d) INTEGRITY - Cold leg temperature decrease greater than 100*F in last 60 m1nutes AND RCS cold leg temperature less.than 285'F j e) CONTAINMENT - Containment pressure greater than 60 PSIA l
3. SECONDARY INTECRITI CRITERIA GO TO EF-2. FAULTED STEAM GENERATOR ISOLATION, Step 1, if any SG pressure is decreasing in an uncontrolled manner or has completely depressuri:ed, and has not been isolated, unless needed for RCS cooldown. ,
i l 4.s COLD LEG RECIRCULATION SWITCHOVER CRITERION l
GO TO ES-1.3, TRANSFER TO COLD LEG RECIRCULATION, Step J_, if RWST level j decreases to less than 29I.
5. ECST LEVEL CRITERIA Make-up to the ECST from the CST or provide alternate sources for /JW suction (SW or FP) when ECST level decreases to 40%. ,
l
07ns: nan -
PROCEDURE TITLE REVISION
l. .NU."BER. 1.00 l_
i
~1-EP-3: STEAM GENERATOR TUBE RUPTURE PAGE 3 of 26
. STEP ACTION / EXPECTED RESPONSE RESPONSENOTO8TAINED
-3. IDENTIFY RUPTURED SG(s): JF, ruptured SG(s) can NOT be immediately identified, THEN-Unexpected increase in continue with Steps 6 thru 13.-
SG Narrow Range level WHEN ruptured SG(s) identified, THEN do Steps 4 and 5.
pR.
High radiation from any SGBD monitor:
"A" SG RM-SS-122 "B" SG- RM-SS-123 "C" SG RM-SS-124~
pR High radiation from any SG steamline:
"A" SG RI-MS-170 "B" SG RI-MS-171 "C" SG RI-MS-172 SR High radiation from any SG sample i 1
e l
' j 4
f i
FOLDOUT FOR EP-3 AND ES-3 PROCEDURES
1. SI REINITIATION CRITERIA Manually operate Charging /SI pumps and align BIT as required and CO TO i q
ECA-3.1, SGTR WITH LOSS OF REACTOR COOLANT - SUBC00 LED RECOVERY DESIRED, Step 1 if either condition listed below occurs-
)
RCS subcooling based on Core Exit TCs - LESS THAN 30*F [80*F]. .!
pR, i
PRZR level - CANNOT BE MAINTAINED GREATER THAN 15% [50%].
2. RED PATH
SUMMARY
a) SUBCRITICALITY - Nuclear power greater than 5%
b) CORE COOLING - Core Exit TCs greater than 1200*F Core Exit TCs greater than 700*F AND.RVLIS full range less than 46% with no RCPs running c) HEAT SINT. - Narrow Range level in all SGs less than 10 [32%] A'4D total feedwater flow less than 340 gym d). INTEGRITY - Cold leg temperature decrease greater than 100*F in last 60 minutes AND RCS cold leg temperature less than 285'F e) CONTAINMENT - Containment pressure greater than 60 PSIA
3. SECONDARY INTEGRITY CRITERIA GO TO EP-2, FAULTED STEAM GENERATOR ISOLATION, Step 1, if any SG pressure is decreasing in an uncontrolled manner or has completely depressurized, and has not been isolated, unless needed for RCS cooldown.
4. COLD LEG RECIRCULATION SWITCHOVER CRITERION GO TO ES-1.3, TRANSFER TO COLD LEG RECIRCULATION, Step 1, if RWST level decreases to less than 29I.
5. ECST LEVEL CRITERIA L Make-up to the ECST from the CST or provide alternate sources for AFW suction (SW or FP) when ECST level decreases to 40%.
d.C7887213' PROCEDURE TITLE REVISION NuntBER 1.00 1-EP-3 STFAM GENERATOR TUBE RUPTURE PAGE 4 of 26 RESPONSENOTOBTAINED
- STEP ACTION / EXPECTED RESPONSE oa*************************************
C_AUTION: If the Turbine-Driven AFW pump is the only available source of feed flow, then steam supply to the Turbine-Driven AFW pump must be maintained from at least one SG.
.oo*************************************
CAUTION: To maintain secondary heat sink, at least one SG must be maintained available for RCS cooldown, r
oo*************************************
4. ISOLATE FLOW FROM RUPTURED SG(s):
a). Verify ruptured SG(s)
PORV controller setpoint -
AT 1025 PSIG (Pot setting at 5.3) b) Check ruptured SG(s) b) WHEN ruptured SG(s) .
PORVs - CLOSED pressure less than 1025 ,
psig, THEN verify SG l PORV(s) closed. l F NOT closed, THEN manually close.
IF PORV(s) canNOT be closed, THEN locally close PORV.
c) Close ruptured SG(s) steam supply valve to Turbine Driven AFW pump:
"A" SG 1-MS-18 "B" SG 1-MS-57 "C" SG 1-MS-95 d) Check decay heat release e) Manually close valve.
valve - CLOSED (Step 4 CONTINUED ON NEXT PAGE)
\
l l
FOLDOUT FOR EP-3 AND ES-3 PROCEDURES i
1. SI REINITIATION CRITERIA i
l Manually operate Charging /SI pu=ps and align BIT as required and GO TO i ECA-3.1, SGTR WITH LOSS OF REACTOR COOLANT - SUBC00 LED RECOVERY DESIRED, I Step 1 if either condition listed below occurs:
RCS subcooling based on Core Exit TCs - LESS THAN 39'T [80*F].
S.R
PRZR level - CANNOT BE MAINTAINED GREATER THAN 15% [50%).
2. RED PATH
SUMMARY
a) SUBCRITICALITY - Nuclear power greater than 5 b) CORE COOLING - Core Exit TCs greater than 1200*F 0-Core Exit TCs greater than 700'F AND RVLIS full range less than 46: with nc RCPs running c) HEAT SINK - Narrow Range level in all SGs less than 10% [32%] AND !
j total feedvater flow less than 340 gpm INTEGRITY - Cold leg temperature decrease greater than 100*F in last j d) 60 minutes AND RCS cold leg temperature less than 285'F e) CONTAINMENT - Containment pressure greater than 60 PSIA l
3. SECONDARY INTEGRITY CRITERIA '
j GO TO EP-2, FAULTED STEAM GENERATOR ISOLATION, Step 1, if any SG pressure is decreasing in an uncontrolled manner or has completely depressurized, '
l and has not been isolated, unless needed for RCS cooldown.
4. COLD LEG RECIRCULATION SWITCHOVER CRITERION GO TO ES-1.3, TRANSTER TO COLD LEG RECIRCULATION, Step 1, if RWST level decreases to less than 29%.
J
5. ECST LEVEL CRITERIA Make-up to the ECST from the CST or provide alternate sources for AFW suction (SW or FP) when ECST level decreases to 40%.
i l
m. c7santo q l
1 PROCEDURE TITLE REVISION j NUMBER 1.00 ;
I 1-EP-3 STEAM GENERATOR TUBE RUPTURE PAGE 5 of 26 l
- STEP ACTION / EXPECTED RESPONSE RESPONSE NOTOBTAINED l 1
I
)
4. ISOLATE FLOW FROM RUPTURED SG(s) (CONTINUED):
e) Verify ruptured SG blow- e) IF NOT open for sampling down TVs - CLOSED procedure, THEN manually close ruptured SG blow-down trip valves.
f) Close ruptured SG(s) f) Close ruptured SG(s) NRV(s) J MSTV(s) and bypcss and bypass NRV(s). IF i valve (s) NRV(s) can NOT be closed, THEN:
1) Close int.act SG(s)
MST7s and bypass valves (s).
2) Use intact SG(s) PORVs for steam dump.
1 E any ruptured SG can NOT be isolated from at least one intact SG, THEF GO TO 1-ECA-3.1, SGTR WITH LOSS OF REACTOR COOLANT -
SUBC00 LED RECOVERY DESIRED, Step 1.
l oo**************** ********************* >
s CAUTION: If any ruptured SG is faulted, then feed flow to that SG should remain isolated during subsequent recovery actions unless needed for RCS cooldown. j i
oo**************** ********************* J
5. CHECK RUPTURED SG(s) LEVEL:
a) Narrow Range level - a) Maintain feed flow until GREATER THAN 10% [32%] ruptured SG NR level greater than 10% [32%). <
l l I
b) Control feed flow to maintain Narrow Range l level between 10%
[32%] and 50% !
_ - _ - - - - - - - .- 4
_7 I
t FOLDOUT FOR EP-3 AND ES-3 PROCEDURES-
.n
\
~
1. SI~REINITIATION CRITERIA. ,
i Manually operate Charging /SI pumps and' align BIT as required and GO TO j
..ECA-3.1,.SGTR WITH LOSS OF' REACTOR COOLANT - SUBC00 LED RECOVERY DESIRED, j Step 1 if-either condition listed;below occurs:.-
RCS'subcooling based on Core Exit TCs - LESS THAN 30*F [80*F].
E
PRZR level - C.WNOT BE MAINTAINED GREATER THAN' 15% [50%).
2. - ' RED PATE SUNMARY a)- SUBCRITICALITY - Nuclear power greater than 5% ,
b)- CORE. COOLING - Core Exit TCs greater than 1200'F 3 )
1 Core Exit TCs greater than 700*F AND RVLIS full range less than-46% vich no RCPs running. L c) HEAT SINK - Narrow Range level'in all SGs less than 10% [32%)' AND '
. total.feedwater flow less than'340' gym-d): INTEGRITT - Cold leg. temperature decrease greater than 100*F in .last i 60 minutes AND RCS cold leg temperature less than 285'F e) CONTAINMENT - Containment pressure greater than 60 PSIA
3. SECONDARY INTEGRITT CRITERIA GO TO EP-2, FAULTED STEAM GENERATOR ISOLATION, Step 1, if any SG pressure-is decreasing in an uncontrolled manner or has completely depressurized, and has not been isolated, unless needed for RCS cooldown.
1
4. COLD LEG RECIRCULATION SWITCHOVER CRITERION GO TO ES-1.3, TRANSFER TO COLD LIG RECIRCULATION, Step 1, if RWST level l decreases to less than 29%.
5. ECST LEVEL CRITERIA l-Make-up to the ECST from the CST or provide alternate sources for AFW
- suction-(SW or FP) when ECST level decreases to 40%.
ree.e7ss7st3; ,
= NUMBER; PROCEDURE TITLE REWSION 1.00.
'1-EP-3 STEAM GENERATOR TUBE RUPTURE pA0E 6 of:26 STEP ACTION / EXPECTED RESPONSE RESPONSENOTOBTAINED ee*********.*******
CAUTION: If=any PRZR PORV opens because of high PRZR pressure, then Step"
,6_b,should b be repeated after RCS pressure decreases to less than 2335'psig.
-*o'**************** *********************
6. CHECK PRZR PORVs AND BLOCK VALVES:
a); ' Power to block valves - a)' Restore power to block AVAILABLE MOVs.
'b)- PORVs - CLOSED b) IF,PRZR pressure less than 2335 psig, THEN manually.
PCV-1455C close PORVs.
PCV-1456 I_F any valve can NOT be closed, THEN manually close its block valve.
IF block valve can NOT be Hosed, THEN GO TO 1-ECA-3.1, SGTR WITH LOSS OP REACTOR COOLANT -
SUBC00 LED RECOVERY DESIRED, Step 1.
c) PORY block valves - c) Open one block valve unless AT LEAST ONE OPEN it was closed to isolate an open PORV.
MOV-1535
MOV-1536 L
b, '
! , l
-s, 4 ;
~d b
,' FOLDOUT FOR EP-3'AND ES-3 PROCEDURES 4{
)
P
. 1. ' 'SI REINITIATION CRITERIA' ,
h . I l Manually operate Charging /SI pumps and align BIT as required'and GO TO
' ECA-3.1,.SGTR WITH LOSS OF. REACTOR COOLANT .SUBC00 LED RECOVERY DESIRED,'
' Step J,if either condition listed below-occurs:-
'_ RCS subcooling based on' Core Exit TCs - LESS' TRAN 30*F [80*F]. -
a
'd T '*;FRZRl level - CANNOT BE MAINTAINED GREATER THAN 15% (50%).
.2. RED PATH SUWARY a) .SUBCRITICALITY - Nuclear power greater.than 5 b)~ CORE COOLING - Core Exit TCs greater than 1200*F E
Core Exit TCs greater than 700*F AND RVLIS full range-
-less than 46% with no RCPs running
-HEAT SINK --Narrow Range level in all SGs less than110% (32%) AND c) total feedwater flow less.than 340 gpm
d)= INTEGRITY - Cold leg temperature decrease greater than-100*F in last 60 minutes AND RCS cold leg temperature less than 285*F-e) ' CONTAINMENT - Containment pressure greater than 60 PSIA -
J. SECONDART INTEGRITY CRITERIA GO TO.EP-2, FAULTED STEAM GENERATOR ISOLATION, Step 1, if any SG pressure
,is decreasing in an uncontrolled manner or has completely depressurized, and.has not been isolated, unless needed'for RCS cooldown. !
j
4. COLD LEG RECIRCULATION SWITCHOVER CRITERION' !
GO TO ES-1.3, TRANSFER TO COLD LEG RECIRCULATION, Step 1, if RWST level decreases to less than 29%.
5. ECST LEVEL CRITERIA Make-up to the ECST from the CST or provide alternate sources for AFW
-suction (SW or FP) when ECST level decreases to 40%.
No.57887210 PROCEDURE TITLE . REVISION
, L NUntBER '
1.00 EP-3 STEAM GENERATOR TUBE RUPTURE PAGE 7 of 26 ACTION / EXPECTED RESPONSE RESPONSENOTOBTAINED
- -STEP
7. CHECK THAT SGs ARE.NOT Verify all faulted SGs FAULTED: isolated unless required for RCS cooldown:
NO SG PRESSURE.
DECREASING IN AN
Steam 11nes UNCONTROLLED MANNER
Feed 11nes
NO SG COMPLETELY IF,NOT, THEN GO TO DEPRESSURIZED 1-EP-2, FAULTED STEAM GENERATOR ISOLATION, Step 1 e***************** *********************
CAUTION: Alternate water sources (CST or 1-AP-22.7) to prevent loss of AFW pump suction pressure vill be necessary if'ECST decreases
-to 40%.
e * * * * * * * * *-* * * * * * * * *********************
8. CRECK INTACT SG LEVEL:
a)- Narrow Range level - a) . Maintain total feJd flow GREATER THAN 10% [32%] greater than 340 gpm until NR level in at least one SG l is greater than 10% [32%].
b) Control feed flow to b) I_FF NR level in any intact l- maintain Narrow Range SG continues to increase level between 10% [32%] in an uncontrolled manner, and 50% THEN return to Step 1 i
9. RESET SI
10. RESET CONTAINMENT ISOLATION PHASE A AND PHASE B
11. VERIFY CONTAINMENT Manually open valves.
INSTRUMENT AIR VALVES - OPEN
TV-IA-102A
TV-IA-102B
_______________m___ _ _ _ _ _ _ _ _ _ _ _ _ . _ _
i l
4 FOLDOUT FOR EP-3 AND ES-3 PROCEDURES l
1 l
1. SI REINITIATION CRITERIA j Manually operate Charging /SI pumps and align BIT as required and GO TO f ECA-3.1, SGTR WITH LOSS OF REACTOR COOLANT - SUBC00 LED RECOVERT DESIRED, Step 1 if either condition listed below occurs: <
RCS subcooling based on Core Exit TCs - LESS THAN 30*F [80*F].
0,,R,
PR2R level - CANNOT BE MAINTAINED GREATER THAN 15% [50%).
2. RED PATH
SUMMARY
a) SUBCRITICALITY - Nuclear power greater than 5:
b) CORE COOLING - Core Exit TCs greater than 1200'F 0,R,,
Core Exit TCs greater than 700*F AND RVLIS full range less than 46% with no RCPs running c) HEAT SINK - Narrow Range level in all SGs less than 10". [32*] AND total feedwater flow less than 340 gpm d) INTEGRITY - Cold leg temperature decrease greater than 100*F in last 60 minutes AND RCS cold leg temperature less than 285*F e) CONTAINMDrr - Containment pressure greater than 60 PSIA
3. SECONDARY INTEGRITY CRITERIA GO TO EP-2, FAULTED STEAM GENERATOR ISOLATION, Step 1, if any SG pressure is decreasing in an uncontrolled manner or has cempletely depressurized, and has not been isolated, unless needed for RCS cooldown.
4. COLD LEG RECIRCULATION SWITCHOVER CRITERION GO TO ES-1.3, TRANSFER TO COLD LIG RECIRCULATION, Step 1, if RWST level decreases to less than 29%.
5. ,E,C,ST LEVEL CRITERIA Make-up to the ECST from the CST or provide alternate sources for AFW suction (SW or FP) when ECST level decreases to 40".
i
- _. . - _ _ - - - - _ . __ . - . - - - - _ - _ - - - _ - _ = _ _ . ._. ._- - - - _ - . , _ - - -
b ensn13 PROCEDURE TITLE. REVISION NUMBER. 1.00 1 1-EP-3 STEAM GENERATOR TUBE RUPTURE pA0E 8 of 26
~
- STEP ACTION / EXPECTED RESPONSE. RESPONSENOTQBTAINED j 12., VERIFY ALL AC Initiate 1-AP-10.1 to restore-BUSSES - ENERGIZED offsite power. ;
BY OFFSITE POWER IF_ required, THEN manually load the following equipment on the AC Emergency Busses:
Shroud Cooling fans.
Containment Air Recire fans.
PRZR heaters, e*****************
~
CAUTION: If RCS pr' essure decreases to less than 250 psig [525.psig],
then the LESI pumps must be manually restarted to supply water to the RCS.
ee**************** *********************
13. CHECK IF LESI PUMPS SHOULD BE STOPPED:
a) ~RCS pressure - a) GO TO Step 14.
GREATER THAN 250 PSIG [525 PSIG) b) Stop LHSI pumps and place in Auto-Standby
14. VERIFY FLOW FROM RNPTURED SG(s) - ISOLATED a) Step 4 - COMPLETE a) Return to Step 4_, UNLESS ruptured SG reouired for RCS cooldown.
b) Check ruptured SG(s) b) GO TO 1-ECA-3.1, SGTR WITH pressure - GREATER LOSS OF REACTOR COOLANT -
TRAN 350 PSIG SUBC00 LED RECOVERY DESIRED, Step 1. .
O'h ,
j f
~
. FOLDOUT FOR EP-3-AND ES-3 PROCEDURES o
. 1..'SI REINITIATION CRITERIA'
~
Manually operate Charging /SI pumps and align BIT as required and GO TO
'ECA-3;1'. SGTR WITH LOSS OF REACTOR COOLANT.- SUBC00 LED RECOVERY DESIRED,;
Step J,,1f either condition-listed below occurs:.
}
RCS subcooling based on' Core Exit TCs - LESS THAN 30*F [80*F]. -
.l 3
PRZR level'- CANNOT BE MAINTAINED GREATER THAN 15% [50%).
. 2. RED PATH'
SUMMARY
> a) SUBCRITICALITY - Nuclear power greater than 5% i
.b) CORE COOLING - Core Exit TCs greater than 1200*F 9.R, J
~ Core Exit TCs greater than 700*F AND RVLIS full range 1ess than 46" with no RCPs running c) HEAT SINK.- Narrow Range. level.in all SGs less than 10% [32"] AND-total'fsedwater flow less than 340 gym ;
. d) . INTEGRITY - Cold lag temperature decrease greater.than 100'F in last 60 minutes AND RCS. cold leg temperature less than 285'T e) CONTAINMENT - Containment pressure greater than 60 PSIA
3. SECONDARY INTEGRITY' CRITERIA GO TO EP-2,. FAULTED STEAM GENERATOR ISOLATION, Step 1, if any SG pressure is decreasing'in an uncontrolled manner or has completely depressurized, and has not been isolated, unless needed for RCS cooldown. ,.
4. COLD LEG RECIRCULATION SWITCHOVER CRITERION d GO TO'ES-1..3, TRANSTER'TO COLD LEG RECIRCULATION, Step 1, if RWST level j decreases to'less chan 29%. ,
. l
5. ECST LEVEL CRITERIA Make-up to the ECST from the CST or provide alternate sources for AW .1 L . suction (SW or FP) when ECST level decreases to 40". 1 l
t peo. 97447810 -
PROCEDUME TITLE REVISION
-- NCgER 1.00 1-EP-3' ~ STEAM GENERATOR TUBE RUPTURE PAGE' 9.of-26' i ' ACTION / EXPECTED RESPONSE RESPONSE NOTOBTAINED
STEP
' NOTE: . Low PRZR' pressure SI should be blocked when PRZR pressure is less than 2000 psig.
NOTE: ' Low steam line pressure SI should be blocked when PRZR pressure is.less than 2000 psig and RCS Tavg is less.than 543'P.
15. ' INITIATE RCS COOLDOWN:
.a) Determine required Core Exit
-temperature based on closest SG pressure:
INTACT LOOP RUPTURED SG PRESSUREL(psig) CORE EXIT TEMPERATURE ('P) 1100.............. 510-_[460]
1000.............. 495 [445]
900.............. 485-[435]
800............'.. 470 [420]
700.............. 455 [405]
600............... 440'[390]
500.............. 420 [370]
400.............. 400 [350]
340.............. 385.[335]
b) Dump ateam to main b) Manually or locally condenser from intact. dump steam at' maximum SG(s) at maximum rate from SG(s):
controllable rate Intact SG PORV(s) 9.E.
Decay heat release valve !
\
IF no intact SG available, EEN perform the following:
Use faulted SG l 0, R, l
GO TO l-ECA-3.1, SGTR {
j WITH LOSS OP REACTOR I
COOLANT- SUBC00 LED RECOVERY DESIRED, Step 1.
'(STEP 15 CONTINUED ON NEXT PAGE)
'- ~ -~~-
u: >
~~'-} -~~- }
m ,
L_ ' ' ,
i
. i
-FOLDOUT FOR EP-3 AND ES-3 PROCEDURES i
1.. SI'REINITIATION' CRITERIA-Manually operate Charging /SI pumps andl211gn' BIT as required and GO TO
'ECA-3.1, SGTR.WITH LOSS OF REACTOR COOLANT - SUBC00 LED REC 0 VERT DESIRED,
Step.1' if either condition listed!below occurs
i
RCS subcooling based on Core Exit TCs - LESS THAN 30*F'.[80*F].- .l J
9R ]
,
PRZR level - CANNOT BE MAINTAINED GREATER THAN 15%'[50%).
2. . RED PATH
SUMMARY
s) SU3 CRITICALITY - Nuclear power greater than 5%'
-b) CORE COOLING.- Core Exit TCs greater than 1200'F
.gR,,
Core Exit'TCs greater than 700*F AND RVLIS; full 1 range.
less than 46". with no RCPs running c) HEAT SINK.- Narrow Range level in all SGs less than 10% [32*]'AND total'feedvater flow lass.than 340 gym d)- INTEGRITT - Cold leg temperature decrease. greater than 100*F in last 60 minutes AND RCS cold leg temperature less than 285'F' e) CONTAINMENT -. Containment pressure greater than 60 PSIA
3. SECONDART INTEGRITY CRITERIA GO.TO EP-2, FAULTED STEAM GENERATOR ISOLATION, Step 1, if any SG pressure is decreasing in an uncontrolled manner or has. completely depressurized, and has:not been isolated, unless needed for RCS cooldown.
4~. COLD LEG RECIRCULATION SWITCHOVER CRITERION GO TO ES-1,3, TRANSFER TO COLD LEG RECIRCULATION, Step 1, if RWST level decreases to less than 29%.
~
5.- ECST LEVEL CRITERIA Make-up to the ECST from the CST or provide alternate sources for AFW sucts.on (SW or FP) when ECST level decreases to 40%..
l
~ i i
l i
.i
I,.
4 , 4 7
a. _
N.. weenzo l PROCEDURE TITLE . REVl3ON JNUMBER 1-EP-3 STEAM GENERATOR TUBE RUPTURE PA GE - .
' 10 of 26
)
[.: '
- ACTION / EXPECTED RESPONSE RESPONSENOTOBTAINED l: : STEP p
I h
1
' 15. INITIATE RCS COOLDOWN: (CONTINUED)':
t, . c) Core Exit TCs - LESS- c) Return to Step 15b. j '
THAN REQUIRED TEMPERATURE d) -Stop RCS cooldown and maintain required RCS temperature i
16. : CHECK RUPTURED SG(s) IF pressure continues to PRESSURE - STABLE OR decrease to less than 100 ps1 INCREASING above intact SG(s) pressure, THEN GO TO 1-ECA-3.1,-
SGTR WITH LOSS OF REACTOR' COOLANT - SUBC00 LED RECOVERY DESIRED, Step 1_.
~17.- CHECK RCS SUBC00 LING GO TO.1-ECA-3.1, SGTR WITH LOSS l BASED ON CORE EXIT TCs - 0F REACTOR COOLANT - SUBC00 LED GREATER TRAN 50*F [100*F] RECOVERY DESIRED, Step 1_.
18. . DEPRESSURIZE RCS TO MINIMIZE BREARFLOW AND REFILL PRZR:
a) Normal PRZR spray - a) GO TO Step H. OBSERVE AVAILABLE' CAUTIONS AND NOTE PRIOR l TO STEP H. !
b) Spray PRZR with maximum available spray i
(STEP 18 CONTINUED ON NEXT PAGE) l ll l
1 i
1 FOLDOUT FOR EP-3 AND ES-3 PROCEDURES
{
1. SI REINITIATION CRITERIA ;
Manually operate Charging /SI pumps and align BIT as required and GO TO ECA-3.1, SGTR WITH LOSS OF REACTOR FOLANT - SUBC00 LED RECOVERY DESIRED, Step 1 if either condition listed beAov occurs:
RCS subcooling based on Core Exit TCs - LESS THAN 30*F [80*F). !
13!
1
PRZR level - CANNOT BE MAINTAINED GREATER THAN 15% [50%). l
2. RED PATH
SUMMARY
SUBCRITICALITY - Nuclear power greater than 5% l a) b) CORE COOLING - Core Exit TCs greater than 1200*F i
_OR Core Exit TCs greater than 700*F AND RVLIS full range l less than 46" with no RCPs running c) HEAT SINK - Narrow Range level in all SGs less than 10% [32 ] AND total feedwater flow less than 340 gym d) INTEGRITT - Cold leg temperature decrease greater than 100*F in last 60 minutes AND RCS cold leg temperature less than 285*F e) CONTAINMENT - Containment pressure greater than 60 PSIA
3. SECONDARY INTEGRITY CRITERIA GO TO EF-2, FAULTED STEAM GENERATOR ISOLATION, Step 1, if any SG pressure is decreasing in an uncontrolled manner or has completely depressurized, and has not been isolated, unless needed for RCS cooldown.
4. COLD LEG RECIRCULATION SWITCHOVER CRITERION GO TO ES-1.3, TRANSFER TO COLD LEG RECIRCULATION, Step 1, if RWST level decreases to less than 29%.
5. ECST LEVEL CRITERIA Make-up to the ECST from the CST or provide alternate sources for AFW l
suction (SV or FP) when ECST level decreases to 40".
l l
l l
r p,
I . fee.C7887210 PROCEDURE TITLE RE IS N
. NUMBER
'1-EP-3 . STEAM GENERATOR TUBE RUPTURE PAGE 11 of 26 ACTION / EXPECTED RESPONSE RES!0NSENOTORTAINED
- STEP l'
18. DEPRESSURIZE RCS TO MINIMIZE' BREAKFLOW AND REFILL PRZR: (CONTINUED) c) Verify PRZR pressure c) GO TO Step g. OBSERVE o satisfactorily decreasing CAUTIONS AND NOTE PRIOR until ANY of the following. TO STEP g.
satisfied:
PRZR level - GREATER THAN 70% [65%)
ER L
-RCS subcooling based on' ..!
Core Exit TCs - LESS THAN 30*F'[80*F]
3 BOTH of the following:
1) RCS pressure -
LESS THAN RUPTURED SG(s)~ PRESSURE AND
2) PRZR level -
GREATER THAN 15% [50%)
d) Close spray valve (s):
1) Nomal spray valve (s) 1) Stop RCP(s) supplying failed spray valve (s):
PCV-1455A "A" RCP PCV-1455B "C" RCP
2) Auxiliary spray valve 2) Isolate normal HCV-1311 letdown and charging.
e) GO TO Step g. OBSERVE CAUTION PRIOR TO STEP g .
i p
i FOLDOUT FOR EP-3 AND ES-3 PROCEDURES SI REINITIATION CRITERIA 1.
Manually operate Charging /SI pumps and align BIT'as required and GO TO- .f ECA-3.1,'SGTR WITH LOSS OF REACTOR COOLANT - SUBC00 LED REC 0 VERT DESIRED, .
Step 1 if'either condition listed below occurs:
.* RCS subcooling based on Core Exit TCs - LESS THAN 30*F-[80*F]..
QR, .
l
PRZR level - CANNOT BE' MAINTAINED GREATER THAN 15% [50%). l f
2. RED PATE
SUMMARY
- a) .SUBCRITICALITY - Nuclear power greater than 5%
b) CORE COOLING - Core Exit TCs greater than 1200*F f
_p_R Core Exit TCs greater than 700*F AND RVLIS full range less than 46" with no RCPs running
~
c) , HEAT SINK - Narrow Range level in'all SGs less than 10% [32%]'AND total feedwater flow less than 340 gpm d) INTEGRITY -' Cold leg' temperature decrease greater than 100*F.in last 60 minutes AND RCS cold leg' temperature less-than 285'F ~)
e) . CONTAINMENT - Containment pressure greater than'60 PSIA 3.- SECONDARY INTEGRITY CRIT".IA GO TO EP-2, FAULTED STEAM GENERATOR ISOLATION, Step 1, if any SG pressure i is decreasing in an uncontrolled manner or has completely depressurized, and has not been isolated, unless needed for RCS cooldown.
4. COLD LEG RECIRCULATION SWITCHOVER CRITERION GO TO.ES-1.3, TRANSFER TO COLD LIG RECIRCULATION, Step 1, if RWST level 3 decreases-to less than 29".
5. ECST LEVIL CRITERIA ;
Make-up to the ECST from the CST or provide alternate sources for AFW suction (SW or FP) when ECST level decreases to 40%.
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,C L: No.97887210 -
PROCEDURE TITLE REVISION NUMBER 1.00 j i- 1-EP-3 STEAM GENERATOR TUBE RUPTURE FACE 12 of 26
- STEP ACTION / EXPECTED RESPONSE RESPONSE NOT OBTAINED l
e***************** ********k ************
CAUTION: ' The PRT may rupture if a PRZR PORV is used for RCS 1 depressurization. This may result in abnormal containment conditions.
o***************** * **=*****************
CAUTION: To prevent possible valve failure, cycling of PRZR PORVs should be minimized.
NOTE: The upper head region may void during RCS depressurization if RCPs are not running. This will result in a rapidly increasing PRZR level.
19. DEPRESSURIZE RCS USING PRZR PORV TO MINIMIZE BREAK FLOW AND REPILL PRZR: .
a) PRZR PORV - AT LEAST a) Establish auxiliary spray ONE AVAILABLE and return to Step 18b.
t IF auxiliary spray can NOT be established, THEN GO TO 1-ECA-3.3, SGTR WITHOUT PRESSURIZER PRESSURE
! CONTROL, Step 1.
l (STEP 19 CONTINUED ON NEXT PAGE) l l )
l 1
u__
l FOLDOUT FOR EP-3 AND ES-3 PROCEDURES
.1. SI REINITIATION CRITERIA i
Manually operate Charging /SI pumps and align BIT as required and GO TO ECA-3.1, SGTR WITH LOSS OF REACTOR COOLANT - SUBC00 LED RECOVERY DESIRED, Step.1 if.either condition listed below occurs: 1
RCS subcooling based on Core Exit TCs - LESS THAN 30*F [80'F].
gR
PRZR level.-lCANNOT BE MAINTAINED GREATER THAN 15% [50%].
2. RED PATH
SUMMARY
a) SUBCRITICALITY - Nuclear power greater'than 5%
b) CORE COOLING . Core Exit TCs greater than~1200*F b
Core Exit TCs greater than 700*F AND RVLIS full rhnge -j
.. less than 46 with no RCPs running I c) . HEAT SINK - Narrow Range level in all SGs less.than 10% [32 ] AND ;
total feedwater flow less than 340 gpm -i d) INTEGRITY - Cold leg temperature decrease greater than 100*F in last -}
60 minutes AND RCS cold leg temperature less than 285'F 1 e)' CONTAINMENT - Containment pressure greater.than 60 PSIA i J
3. SECONDARY INTEGRITY CRITERIA .
GO TO EF-2. FAULTED STEAM GENERATOR ISOLATION, Step 1. if any SG pressure is decreasing in an uncontrolled manner or has completely depressurized, and has not been isolated, unless needed for RCS cooldown. l
4. COLD LEG RECIRCULATION SWITCHOVER CRITERION GO TO ES-1.3, TRANSFER TO COLD LEG RECIRCULATION, Step 1, if RWST level decreases to less than 29%.
5. ECST LEVEL CRITERIA Make-up to the ECST from the CST or provide alternate sources for AFW suction (SW or FP) when ECST level decreases to 40%.
a-_______- _ _ - - -#
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No. 97887210 :-
, u ,
PROCEDURE TITLE REVIS ON NUMBER' 1-EP-3 .; STEAM GENERATOR TUBE RUPTURE- pAGE 13 of 26 1
-. STEP ACTION /EXPECTC[ RESPONSE - RESPONSENOTQBTAINED . .,
em-etah j
}
19. DEPRESSURIZE RCS USING PRZR PORV TO MINIMIZE BREAK FLOW AND REFILL PR2R (CONTINUED):
b) 'Open one PRZR'PORY until ANY of the following conditions satisfied:-
PRZR level - GREATER THAN 70% [65%]
RCS subcooling based on i, Core Exit TCs - LESS THAN 30*F [80*F) pR BOTH of the following:
1) .RCS. pressure - ..
1.ESS THAN RUPTURED I
f SG(s) PRESSURE AND
2) PRZR level - .
GREATER THAN 15% [S0:]
c) Close PRZR PORV c) Close PRZR PORV block MOV.
i O
_ W_
i FOLDOUr__ FOR EP-3_g ES-3 PROCEDURES
1. SI REINITIATION CRIT GIA ,
i Manually operate Charging /SI pumps' and align BIT as required and GO TO ECA-3.1, SGTR WITH LOSS OF REACTOR COOLANT - SUBC00 LED RECOVERY DESIRED, Step i if eit!1er condition listed below occurs:
RCS subcooling based on Core Exit TCe - LESS THAN 30*F [80*Fl. l l
CD .
1
PRZR level - CAMiOT BE MAINTAINED GREATER THAN IS: {50%).
2. RED PATH SUW.ARY a) SUBCRITICALITY - Nuclear power greater than 5 b)- CORE COOLING - Core Exit TCs greater than 1200*F l
C
-.R Core Exit TCs greater than 700*F AND RVLIS full range less than 46*. with no RCPs running c) . HAT SINil - Narrov Range level in all SGo less than 10% [32%) AND total feedwater. W u less than 340 gpm d') INTEGRITY - Cold leg temperature decrease greater than 100*F in last 60 minutes g RCS cold leg temperature less chan 285*F ,
e) C0hTAINMENT - Containment pressure greater than 60 PSIA j
3. jECONDARY INTEGRITY CRITERIJ GO TO EF-2, FAULTE3 STEAM GENERATOR ISOLATION, Step 1, if any SG pressure ;
is decreasing in an uncontrolled manner or has ccepletely deptessurized, l and has not been teolated, unless needed for RCS cooldown. j
4. COLD LEC 3ECTRCULATIONECTCHOVER_CRI"pj03 CD TO ES-1.3,, TRANSFER TO COLD LIG REC 3CCLATION, Step 1, if RWST level decreases to less than 29%.
\
5. ECST L g jRITERIA l
Make-up to the ECST from the CST or provide altornate sources for AFW l suction (SW or FF) vhen ECST level decreaser. t:0 40".
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r , No 97887210 NuntBER PROCEDURE TITLE RE ISyN
(
1-EP-3 STEAM GENERATOR TUBE RUPTURE PAGE
< 14 of 26' I
- STEP ACTION / EXPECTED RESPONSE RESPONSE NOTOBTAINED
20. CHECK RCS PRESSURE - Close PRZR PORY block MOV.
INCREASING IF pressure continues to decrease, THEN perform the following:
1) Monitor the following for indication of leakage from PRZR FORV:
PORY discharge temperature.
PRT pressure.
PRT temperature.
2) GO TO 1-ECA-3.1, SGTR WITH LOSS OF REACTOR COOLANT -
SUBC00 LED RECOVERY DESIRED, Step 1,.
o***************** *********************
CAUTION: SI must be terminated when termination criteria are satisfied to prevent overfill of the ruptured SG(s).
o***************** *********************
21. CHECK IF SI FLOW SHOULD BE TERMINATED:
a) RCS subcooling based on a) DO NOT STOP SI PUMPS. GO Core Exit TCs - GREATER TO 1-ECA-3.1, SGTR WITH THAN 30'F [80*F) LOSS OF REACTOR COOLANT -
SUBC00 LED RECOVERY DESIRED, Step 1.
(STEP 21 CONTINUED ON NEXT PAGE)
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. F-.OLDO..CT. FOR EP-3 aND..ES-3 --
Pi!O.CED"P.ES J
/
/ 1l SI-~REINITIATION CRITERIA ,
?
Manually operate Chargin;/SI pumps and align BIT as required and CO TO ECA-3. I , SGTR WITH LOS3 JP REACTOR COOLANT - FJE00 LED RECOVERY. PJ. SIRED, i
Step 1, if either condi*.ica listed below occurs:
j"
ECS subcooling basce en Core Exit TCs - LESS TPJN 30*F [80*F].
j GR
>
PRZR level - CE!NOT BE MAIWAINED GRJ),TER T2AN 15% [50 ] .
i 2. p PATH
SUMMARY
.. , ' a) SUBCRITICALITT - Nuclear power greater than 5%'
ch) CORE COOLING - Core Exit TCs greater than 1200*F SR.
Core Exit TCs greater than 700*F AND RVLIS full range less than 46% with no RCPs running c/
HEAT SJK - Narrow Range level in all SGs less than 10% (32 ] AND total feedwater flow less than 340 gpm d) INTEGRITY - Cold leg tem p rature decrease greater than 100*F in last 60 minutes AND RCS cold leg temperature less than 285*F e) CONTAUMENT - Containment pressure greater than 60 PSIA 3.
SECONDABY_ INTEGRITY CRITERIA GO TO EP-7,' FAULTED STEAM GENERATOR ISCLATION,' Step 1, if any SG pressura is decreesidg in an unctnerolled manner or has completely depressurized, and has not been isolated, unless needed for RCS cooldown.
4. COLD LEC RECIRCULATION SWITC110VER CRITERION GO TO ES-1.3, TPaSSFER TO COLD LEG RECIRCULATION, Step 1, if RWST level decreases to less than 29%.
'k
, f, CST LIVEL CRITERIA Make-up to the ECST frem the CST ce provide alternate sourcas for AR
,, y suction (W or Fi) when ECST level de creases to 40%.
}$ %
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No. 97887210 NUMBER PROCEDURE TITLE REflSfN 1-EP-3 STEAM GENERATOR HTBE RUPTURE PACE 15 of 26 RESPONSE NOT OBTAINED STEP ACTION / EXPECTED RESPONSE
21. CHECK IF SI FLOW SHOULD BE TERMINATED (CONTINUED):
b) Secondary heat sink: b) IF neither condition is satisfied, THEN DO NOT STOP Total feed flow to SI PUMPS. GO TO 1-ECA-3.1, SG(s) - GREATER THAN SGIR WITH LOSS OF REACTOR 340 CPM AVAILABLE COOLANT - SUBC00 LED RECOVERY DESIRED, Step 1_.
0,,,R, Narrow Range level in at least one intact SG - GREATER THAN 10% [32%]
c) RCS pressure - STABLE OR c) DO NOT STOP SI PUMPS. GO INCREASING TO 1-ECA-3.1, SGTR WITH LOSS OF REACTOR COOLANT - SUBC00 LED '
RECOVERY DESIRED, Step 1.
d) PRZR level - GREATER d) DC,NOT STOP SI PUMPS.
THAN 15% [50%) Return to Step 1,4,,.
,? 2 . STOP ALL BUT ONE CHARGING /SI PUMP AND PLACE IN STANDBY
23. VERIFY CHARGING /SI PUMP RECIRC:
a) Check MOV-1373 - OPEN a) Manually open valve, b) Check recire valve for b) Manually open valves.
Charging /SI pumps - OPEN
MOV-1275A 1-CH-P-1A
MOV-1275B 1-CH-P-1B
MOV-1275C 1-CH-P-1C
4 L.
p.;
\ l POLDOUT FOR EP-3 AND<ES-3 PROCEDURES I
1.. SI REINITIATION CRI'TERIA tt Manually operate Charging /SI pumps and align BIT as required and GO TO
ECA-3.1,.SGTR.WITE LOSS OF' REACTOR COOLANT - SUBC00 LED RECOVERY DESIRED, L -Step'1,if either' condition listed below' occurs:
~* RCS subcooling based on Core Exit TCs - LESS TRAN 30*F-[80*F]. j g i E
PRZR. level - CANNOT BE MAINTAINED GREATER THAN 15%-[50 ].
2.1 RED PATH
SUMMARY
a)~ - SUBCRITICALITY - Nuclear power greater than.5 CORE COOLING - Core Exit TCs greater than 1200*F b) pR, Core Exit TCs greater'than 700*F AND RVLIS full range less than 46% vith no RCPs running
'c) - HEAT SINK - Narrow Range' level in all SGs less than 10". [31".] AND total feedvater flow less than 340 gym d) INTEGRITY - Cold leg temperature decrease greater than 100*F in last-60 minutes AND RCS cold leg camperature less than'285'T e) CONTAINMENT - Containment pressure greater than 60 PSIA
3. SECONDARY INTEGRITY CRITERIA GO TO EP-2,. FAULTED STEAM GENERATOR ISOLATION, Step 1, if any SG pressure is decreasing in an uncontrolled manner or has completely-depressurized..
.and has not been isolated, unless neided for RCS cooldown.
.. 4. - ' COLD' LEG RECIRCULATION SWITCHOVER CRITERION GO TO ES-1.3,. TRANSFER TO COLD LEG RECIRCULATION, Step 1, if RWST level decreas'es to less than 29%.
$~. ECST LEVEL CRIIERIA Make-up to the ECST from the CST or provide alternate sources for AFW-suction (SW or FP) when ECST level decreases to 40%. l l
=___--___ _ _ _ _ __ _ _. __ - - - - _-_--_-_-_---___ _ _ _ _ - -
No. 97887210 PROCEDURE TITLE RE ISION NUMBER 1-EP-3 STEAM GENERATOR TUBE RUPTURE pAGE 16 of 26 RESPONSENOTOBTAINED
- STEP ACTION / EXPECTED RESPONSE
24. ISOLATE BIT:
a) Close inlet isolation valves:
MOV-1867A
MOV-1867B b) Close outlet isolation valves:
MOV-1867C
MOV-1867D
25. ESTABLISH CHARGING:
a) Place controller for FCV-1122 in manual and close FCV-1122 b) Check auxiliary spray, b) Manually close valve.
BCV-1311 - CLOSED ,
c) Open charging line isolation valves:
' MOV-1289A
HCV-1310
MOV-1289B d) Open charging flow control valve, FCV-1122, to establish 25 spm charging flow e) Adjust seal injection as required
26. CONTROL CHARGING FLOW TO MAINTAIN PRZR LEVEL
t
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bil FOLDOUT FOR EP-3 AND ES-3 PROC EURES a
1. SI REINITIATIONICRITERIA-R
Manually operate l Charging /SI pumps and align

BIT as required;and C' TO i ECA-3.1 .SGTR WITH LOSS OF REACTOR COOLANT - SUBCOOLE RECOVERY EdiTRED -
Step 1,if either' condition listed.below occurs: ' ;
RCS subcooling based on Core Exit TCs.- LESS THAN 30*F_-[80*F].
0,, R ,,
-1 1
PRZR level - CANNOT BE MAINTAINED GREATER THAN 15% [50%). I j
1
.- 2. RED -PATH SUMMAllT -
l a) SUBCRITICALITY - Nuclear power greater than 5% -)
'b) .C. ORE COOLING - Core Exit TCs greater than 1200*F- ;
j lr _OR_ }
Core Exit TCs greater than 700*F AND RVLIS full range less than 46% with no RCPs running c) HEAT SINK - Narrow Range level in all SGs less than 10%.[32%) AND total feedwater flow less than 340 gym
'd) > INTEGRITY - Cold leg temperature decrease greater than 100'F in last 60 minutes AND RCS cold leg temperature less than 285'F e) ' CONTAINMENT - Containment pressure greater than 60 PSIA
3. SECONDARY INTEGRITY CRITERIA GO TO EP-2, FAULTED STEAM GENERATOR ISOLATION, Step 1, if any SG pressure is decreasing in an uncontrolled manner or has completely depressurized, and has not been isolated, unless needed for RCS cooldown.
4. COLD LEG RECIRCULATION SWITCHOVER CRITERION GO TO ES-1.3, TRANSFER TO COLD LEG RECIRCULATION, Step 1, if RWST level decreases to less chan 29%. ,
54.ECST LEVEL CRITERIA Make-up to the ECST from the CST or provide alternate sources for AFW ]
suction (SW or FP) when ECST level decreases to 40%. l l
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Qnamn PROCEDURE TITLE REVISION NUMBER 1.00 1-EP-3 STEAM GENERATOR TUBE RUPTURE pAGE 17 of 26
- . STEP ACTION / EXPECTED RESPONSE RE90NSENOT08TAINED
27. VERITY SI FLOW NOT REQUIRED:
a) -RCS subcooling based a) . Manually operate on Core Exit TCs - Charging /SI pumps and align GREATER THM 30*F [80'F] BIT as necessary. ~ GO TO 1-ECA-3.1, SGTR WITH LOSS OF REACTOR COOLANT -
SUBC00 LED RECOVERY DESIRED, Step 1 b) PRZR level - GREATER b) Increase charging flow THAN 15% (50%] and operate Charging /SI pumps as necessary.
IF level canNOT be- -
Eintained, THEN manually operate Charging /SI pumps and align BIT as necessary.
GO TO 1-ECA-3.1, SGTR WITH LOSS OF REACTOR COOLANT -
SUBC00 LED RECOVERY DESIRED, Step 1.
28. CHECK VCT MAKEUP CONTROL Adjust controls as necessary.
_ SYSTEM:
a)- Makeup set at cold shutdown concentration b) Makeup set for automatic operation i
l
_ . _ _ _ - _ _ - - _ . _ - _ - _ - 2
FOLDOUT FOR EP-3 AND ES-3 PROCEDURES 1
1. SI REINITIATION CRITERIA Manually operate Charging /SI pu=ps and align BIT as required'and GO TO ECA-3.1, SGTR WITH LOSS OF REACTOR COOLANT - SUBC00 LED RECOVERY DESIRED, Step 1,if either condition listed below occurs:
RCS subcooling based on Core Exit TCs - LESS THAN 30*F [80'7].
$3! J
\
i
PRZR level - CANNOT BE MAINTAINED GREATER TEAN 15% [50%].
l
2. RED PATH
SUMMARY
a) SUBCRITICALITY - Nuclear power greater than 5:
b) CORE COOLING - Core Exit TCs greater than 1200*F l l
2R a Core Exit TCs greater than 700*F AND R7LIS full range l less than 46 with no RCPs running i c) HEAT SINK - Narrow Range level in all SGs less than 10" [32%) AND ;
total feedwater flow less than 340 gym d) 'INTEGRITT - Cold leg temperature decrease greater than 100*F in last 60 minutes AND RCS cold leg temperature less than 285'F e) CONTAINMENT - Containment pressure greater than 60 PSIA
.3. SECONDARY INTEGRITY CRITERIA GO TO EP-2, FAULTED STEAM GENERATOR ISOLATION, Step 1, if any SG pretsure is decreasing in an uncontrolled manner or has completely depressurized, and has not been isolated, unless needed for RCS cooldown.
4. COLD LEG RECIRCULATION SWITCHOVER CRITERION GO TO ES-1.3, TRANSFER TO COLD LEG RECIRCULA!!CN, Step 1, if RWST level decreases to less than 29%.
5. ECST LEVEL CRITERIA Make-up to the ECST from the CST or provide alternate sources for AFW '
suction (SW or FP) when ECST level decreases to 40%.
!\
No.97887213 PROCEDURE TITLE. REVISION NUMBER 1.00-1-EP-3 STEAM GENERATOR TUBE RUPTURE PAGE 18 of'26 l'
- STEP ACTION / EXPECTED RESPONSE . RESPONSE NOTOBTAINED 1
29.. CHECK IF LETDOWN CAN BE ESTABLISHED:
a) PRZR level - GREATER- a) Continue with Step 30,.
THAN 30% [55%) WHEN PRZR level increases to greater than 30%'[55%),
THEN perform Step 29b.
b) Establish letdown: b) Establish excess letdown as per 1-OP-8.5.
1) Place PCV-1145 in manual and open.to 50%-
2) Open the following:
TV-1204A
TV-1204B
.
LCV-1460A
LCV-1460B
3) Open HCV-1200A, 1200B, or 1200C 2
'4) Adjust PCV-1145 to obtain 300 psig letdown pressure and place PCV-1145 in auto
5) Plice additional orifice valves in service as required l
1 1
1
- - - - - - - - - - _ - - - - - - - - - - - - - - - - - - - - - - - - - - - - -- - - -- J
0'
']
i FOLDOUT FOR EP-3 AND ES-3 PROCEDURES 1
,' ;1. SI REINITIATION CRITERIA i>
Manually operate Charging /SI pumps'and align BIT as required and GO TO
~
j
. ECA-3.1, SGTR WITH LOSS OF REACTOR COOLANT - SUSC00 LED RECOVERY DESIRED, j Step'J,if either condition listed below occurs: .1
RCS subcooling based on Core Exit TCs - LESS THAN 30*F [80*F].
I OR
PRZR level - CANNOT BE MAINTAINED GREATER TRAN 15% [50%).
2. RED PATH
SUMMARY
a) SUBCRITICALITY - Nuclear power greater than 5%
b) CORE COOLING - Core Exit TCs greater than 1200*F 0,,,R Core Exit TCs greater than 700*F AND RVLIS full range less than 46% vith no RCPs running c) HEAT SINK - Narrow Range level in all SGs less than 10% (32%) AND ,
total feedwater flow less than 340 gpm l d) INTEGRITY - Cold leg temp,erature decrease greater than 100*F in last ;
60 minutes AND RCS cold leg temperature less than 285'F 1 e) CONTAINMENT - Containment pressure greater than 60 PSIA
3. SECONDARY INTEGRITY CRITERIA-i' CO TO EF-2, FAULTED STEAM GENERATOR ISOLATION, Step 1, if any SG pressure is decreasing in an uncontrolled manner or has ccepletely depressurized, 1 and has not been isolated, unless needed for RCS cooldown.
4. COLD LEG RECIRCULATION SWITCHOVER CRITERION GO TO ES-1.3, TRANSFER TO COLD LEG RECIRCULATION, Step 1, if RWST level decreases to less than 29%.
5. ECST LEVEL CRITERIA Make-up to the ECST from the CST or provide .iternate sources for AFW I suction (SW or FP) when ECST level decreases to 40%.
No. 97887210 .
PROCEDURE TITLE REVISION NUMBER 1.00 1-EP-3 STEAM GENERATOR TUBE RUPTURE PAGE 19 of 26 ACTION / EXPECTED RESPONSE RESPONSENOTOBTAINED
- STEP s
30. ALIGN CHARGING /SI PUMP SUCTION TO VCT:
a) Open VCT Suction valves:
MOV-1115C
MOV-1115E b) Close RWST Suction valves:
MOV-1115B
MOV-1115D o***************** *********************
CAUTION: To prevent Emergency Diesel Generator overload, the #1 or #4 PRZR heaters should not be re-energized until the respective Emergency Diesel Generator load is less than 2750 KL oe**************** *********************
{
E FOLDOUT FOR EP-3 AND ES-3 PROCEDURES
1. SI REINITIATION CRITERIA Manually operate Charging /SI pumps and align BIT as required and GO TO ECA-3.1, SGTR WITH LOSS OF REACTOR COOLANT - SUBC00 LED RECOVERY DESIRED, Step 1 if either condition listed below occurs:
RCS subcooling based on Core Exit TCs - LESS THAN 30*F (80*F].
8
PRZR level - CANNOT BE MAINTAINED GREATER THAN 15% [50%].
2. RED PATH
SUMMARY
\
a) SUBCRITICALITY - Nuclear power greater than 5%
b) CORE COOLING - Core Exit TCs greater than 1200*F E
Core Exit TCs greater than 700*F AND RVLIS full range less than 46% vith no RCPs running c) HEAT SINR - Narrow Range level in all SGs less than 10% [32%] AND total feedvater flow less than 3A0 gpm d) INTEGRITT - Cold leg temperature decrease greater than 100*F in last 60 minutes AND RCS cold leg temperature less than 285'F e) CONTAINMENT - Containment pressure greater than 60 PSIA ,
3. SECONDARY INTEGRITY CRITERIA, GO TO EP-2, FAULTED STEAM GENERATOR ISOLATION, Step 1, if any SG pressure is decreasing in an uncontrolled manner or has completely depressurized, and has not been isolated, unless needed for RCS cooldown,
4. COLD LEG RECIRCULATION SWITCHOVER CRITERION GO TO ES-1.3, TRANSFER TO COLD LEG RECIRCULATION, Step 1, if RWST level decreases to less enan 29%.
5. ECST LEVEL CRITERIA Make-up to the ECST from the CST or provide alternate sources for AFW suction (SW or FP) when ECST level decreases to 40%.
- ~ - _ - - - _ - _ _ _ _ . _ , _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
Ns.97847210 PROCEDURE TITLE REVISION NUMBER 1.00 1-EP-3 STEAM GENERATOR TUBE RUPTURE PAGE 20 of 26 ACTIGN/ EXPECTED RESPONSE RESPONSENOT OBTAINED
-- STEP =
CAUTION: RCS and ruptured SG(s) pressures must be maintained less than 1025 psig to prevent lifting ruptured SG(s) PORV.
31. _ CONTROL RCS PRESSURE AND MAKEUP FLOW TO MINIMIZE RCS-TO-SECONDARY LEAKAGE:
a) Perform appropriate action (s) from table:
PRZR L'EVEL RUPTURED SG(a) LEVEL INCRMSING DECREASING OFFSCALE HIGH LESS THAN
Increase RCS Increase RCS
Increase RCS 30% [55%) Makeup. Flow Makeup Flow Makeup Flow
Depressurize
Maintain RCS_
RCS Using and Ruptured Step 31b SG(s) Pressure Equal BETWEEN Depressurize Turn On Maintain RCS 30% [55%] RCS Using PRZR and Ruptured AND 60% Step 31b Heaters SG(s) Pressure Equal BETWEEN
Decrease RCS Turn On Maintain RCS 60% AND Makeup Flow PRZR and Ruptured 70% [65%] Heaters SG(s) Pressure
Depressurize Equal RCS Using Step 31b GREATER THAN Decrease RCS Turn On Maintain RCS 70% [65%] Makeup Flow PRZR and Ruptured Heaters SG(s) Pressure Equal b) Use normal spray b) E letdown is in service, THEN use auxiliary spray. IF NOT, THEN use one
, u, .
-4
s 4 (
{- 1
?
t FOLDOUT FOR EP AND ES-3 PROCEDURES
' 1. SI REINITIATION CRITERIAI hq Manus 11yloperate. Charging /SI pumps and' align. BIT-as required and GO TO.
ECA-3.1~,LSGTR WITH LOSS'0F REACTOR COOLANT - SUBC00 LED RECOVERY DESIRED, j r ', Step'l-ifneither. condition. listed below occurs: >!
p .. '
'RCS'subcooling' based on Core Exit TCs - LESS THAN 30*F [80*F]. .
q pR .]
1
/
'* PR2R' level - CANNOT BE MAINTAINED GREATER THAN 15% [50%).
22 IRED PATH'5UMMARY
- a) .SUBCRITICALITY - Nuclear power greater than 5% j CORE COOLING - Core Exit TCs greater than 1200*F j b) l OR f Core Exit TCs greater than 700*F AND RVLIS full range less-than 46 vith no RCPs running .
. c) ' HEAT SINK. Narrow Range level in all SGs less than 10% [32%] AND total feedwater flow less than 340 gpm
-d) INTEGRITY - Cold leg temperature decrease-greater than 100*F.in last -i 60 minutes AND RCS cold leg: temperature less chan-285*F a). : CONTAINMENT - Containment pressure greater than 60 PSIA
.. . '1
3. SECONDARY INTEGRITI CRITERIA GO TO EP-2, FAULTED STEAM GENERATOR ISOLATION, Step 1_, if any SG pressure is decreasing in an uncontrolled manner.or has completely depressurized, and ha's~not been isolated, unless needed for RCS cooldown. i
'I
4. COLD LEG RECIRCULATION SWITCHOVER CRITERION ]
.C0=TO ES-l'3,. TRANSFER TO COLD LEG RECIRCULATION, Step 1, if RWST_ level-
' decreases.co less chan 29%.
5. ECST LEVEL CRITERIA Make-up to the ECST from the CST or provide alternate sources for AFW !
-suction (SW or FP) when ECST level decreases to 40%. "!
t i-,_. - - - - - . - .
feo. 97Q87210 PROCEDURE TITLE REISON NUMBER g 1-EP-3 STEAM GENERATOR TUBE RUPTURE PAGE 21 of 26 ACTION / EXPECTED RESPONSE RESPONSE NOT OBTAINED
- STEP
32. CHECK IF DIESEL GENERATORS SHOULD BE STOPPED: .. _
a) Verify AC emergency a) Initiate 1-AP-10.1 to busses - ENERGIZED BY restore offsite power.
OFFSITE POWER b) Stop any unloaded diesel generator as per 1-0P-6.1 and/or 1-OP-6.2
33. MINIMIZE SECONDARY SYSTEM CONTAMINATION:
Isolate Hotvell high level divert
Bypass Powdex System
Transfer Auxiliary Steam to Unit 2 pR Place auxiliary boiler in service
34. TURN ON PRZR HEATERS AS NECESSARY TO SATURATE PRZR WATER AT RUPTURED SG(s)
PRESSURE
FOLDOUT FOR EP-3 AND ES 3 PROCEDURES
1. SI REINITIATION CRITERIA Manual!.7 enerate Charging /SI pumps and align BIT as required and GO TO ECA-3.1, l',TR WITH LOSS OF REACTOR COOLANT - SUBC00 LED RECOVERY DESIRED, Step 1,,if either condition listed below occurs:
RCS subcooling based on Core Exit TCs - LESS THAN 30*F [80*F].
9R
PRZR level - CANNOT BE MAINTAINED GREATER THAN 15% [50%].
2. RED PATH
SUMMARY
a) SUBCRITICALITY - Nuclear power greater than 5%
b) CORE COOLING - Core Exit TCs greater than 1200*F S.R, Core Exit TCs greater than 700*F AND RVLIS full range less than 46: vich no RCPs running c) HEAT SINR - Narrow Range level in all SGs less than 10: [32") AND total feedvater flov less than 340 gpm d) INTEGRITY - Cold leg temperature decrease greater than 100*F in last
60 minutes AND RCS cold leg temperature less than 285'F e) CONTAINMENT - Containment pressure greater than 60 PSIA
3. SECONDARY INTEGRITY CRITERIA GO TO EP-2, FAULTED STEAM GENERATOR ISOLATION, Step 1,, if any SG pressure is decreasing in an uncontrolled manner or has completely depressurized, and has not been isolated, unless needed for RCS cooldown.
4. COLD LEG RECIRCULATION SWITCHOVER CRITERION.
GO TO ES-1.3, TRANSFER TO COLD LEG RECIRCULATION, Step 1, if RWST level decreases to less than 29%.
5. ECST LEVEL CRITERIA Make-up to the ECST from the CST or provide alternate sources for AFW suction (SW or FP) when ECST level decreases to 40%.
feo.97887210 PROCEDURE TITLE REVIS ON HUMBER 1-EP-3 STEAM GENERATOR TUBE RUPTURE PAGE 22 of 26 ACTION / EXPECTED RESPONSE RESPONSE NOTOBTAINEO
- STEP CHECK RCP COOLING FLOW - Establish flow as required.
35.
NORMAL
Upper Bearing
Lower Bearing
Stator
36. CHECK RCP SEAL COOLING: I_F F either flow indicated, THEN re-establish the other flow.
a) Thermal barrier - IF,no flow indicated, THEN FLOW INDICATED initiate 1-AP-33.2 to ,
re-establish seal cooling.
b) Seal injection -
FLOW INDICATED
37. CHECK IF R,CP SEAL WATER RETURN CAN BE ESTABLISHED:
a) RCS pressure - GREATER a) GO TO Step 38,.
THAN 100 PSIG b) verify seal injection b) GO To Step 28_.
flow - INDICATED c) Open seal water return MOVs
MOV-1380
MOV-1381 I
i
I- ~/
FOLDOUT FOR EP-3 AND ES-3 PROCEDURES
1. SI REINITIATION CRITERIA Manually operate Charging /SI pumps and align BIT as required and GO TO ECA-3.1, SGTR WITH LOSS OF REACTOR COOLANT - SUBC00 LED RECOVERY DESIRED, Step 1 if either condition listed below occurs:
RCS subcooling based on Core Exit TCs - LESS THAN 30*F [80*F].
(
PRZR level - CANNOT BE MAINTAINED GREATER THAN 15% [50%).
2. RED PATH
SUMMARY
a) SUBCRITICALITY - Nuclear power greater than 5:
b) CORE COOLING - Core Exic TCs greater than 1200*F 0,,R Core Exit TCs greater thc.n 700*F AND RVLIS full range less than 46% with no RCPs running c)
HEAT SINK - Narrow Range level in all SGs less than 10" [32%] AND d) total feedwater flow less than 340 gpm INTEGRITY - Cold leg temperature decrease greater than 100*F in last e) 60 minutes AND-RCS cold leg temperature less than 285'F CONTAINMENT - Containment pressure greater than 60 PSIA
3. SECONDARY INTEGRITY CRITERIA GO TO EP-2, FAULTED STEAM GENERATOR ISOLATION, Step 1, if any SG pressure is decreasing in an uncontrolled nanner or has completely depressuri::ed, and has not been isolated, unless needed for RCS cooldown.
4.
COLD LEG RECIRCULATION SWITCHOVER CRITERION GO TO ES-1.3 TRANSFER TO COLD LEG RECIRCULATION, Step ~1, if RWST level decreases to less than 29%. '
5. ECST LEVEL CRITERIA Make-up to the ECST from the CST or provide alternate sources for AFW suction (SW or FP) when ECST level decreases to 40".
No.97867210 PROCEDURE TITLE REVISION EduMBER 1.00
~
1-EP-3 STEAM GENERATOR TUBE RUPTURE PACE 23 of 26 ACTION / EXPECTED RESPONSE RESPONSE NOTOBTAINED
- STEP _
o***************** *********************
CAUTION: If all seal cooling had been previously lost, then to prevent any further seal damage, the affected RCP(s) should not be started without prior status evaluation.
o***************** *********************
CAUTION: Due to reduced RTD bypass flow on natural circulation, RTD bypass temperatures and associated interlocks vill be inaccurate.
o***************** *********************
CAUTION: If an Emergency Diesel Generator is paralleled to the same RSS bus as a Reactor Coolant pump, then to prevent voltage oscillations, that Reactor Coolant pump should not be started, o***************** *********************
NOTE: Normal PRZR spray should be islotated from any RCP that is stopped.
NOTE: RCPS should be run in order of priority to provide normal PRZR spray.
38. CHECK RCP STATUS:
a) At least one RCP - a) Try to start one RCP:
- RUNNING
1) IF RVLIS upper plenum range indication less than 95%, THEN perform the following:
Increase PR2R level to greater than 72%
[60%]
l l
Increase RCS sub-cooling based on Core Exit TCs to greater than 55'F
[105*7]
2) Try to start one RCP as per 1-0P-5.2. I_F, an RCP canNOT be started, THEN initiate i
Attachment 1.
b) Stop all but one RCP
l
.,/
FOLDOUT FOR EP-3 AND ES-3 PROCEDURES
1. SI REINITIATIO_N CRITERIA Manually operate Charging /SI pumps and align BIT as required and GO TO ECA-3.1, SGTR WITH LOSS OF REACTOR COOLANT - SUBC00 LED RECOVERY DESIRED, Step 1 if either condition listed below occurs:
RCS subcooling based on Core Exit TCs - LESS THAN 30*F [60*F].
E
PRZR level - CANNOT BE MAINTAINE'D GREATER THAN 15% [50%].
2. RED PATH SLTd.ARY a) SUBCRITICALITY - Nuclear power greater than 5%
b) CORE COOLING - Core Exit TCs greater than 1200*F S
Core Exit TCs greater than 700'F AND RVLIS full range less than 46% vith no RCPs running c) HEAT SINK - Narrow Range level in all SGs less than 10 [32".] AND cotal feedwater flov less than 340 gpm d) INTEGRITY - Cold leg temperature decrease greater than 100'F in last 60 minutes AND RCS cold leg temperature less than 285'T e) CONTAINMENT - Containment pressure greater than 60 PSIA
3. SECONDART INTEGRITY CRITERIA GO TO EP-2, FAULTED STEAM GENERATOR ISOLATION, Step 1 if any SG pressure is decreasing in an uncontrolled manner or has completely depressurized, and has not been isolated, unless needed for RCS cooldown.
4. COLD LEG RECIRCULATION SWITCHOVER CRITERION GO TO ES-1.3, TRANSFER TO COLD LEG RECIRCULATION, Step 1, if RWST level decreases to less than 29%.
5. ECST LEVEL CRITERIA Make-up to the ECST from the CST or provide alternate sources for AFW suction (SW or FP) when ECST level decreases to 40%.
No. 97 8f.7210 NUMBER PROCEDURE TITLE REVISION 1.00 1-EP-3 STEAM GENERATOR TUBE RUPTURE PAGE 24 of 26
- STEP ACTION / EXPECTED RESPONSE RESPONSE NOT O8TAINED
39. . CHECK INTERMEDIATE RANGE FLUX:
~
a) Flux - BELOW 5x10 " ON a) Continue vitit Step M.
N-35 AND N-36 WHEN bo*h conditions satisfied, THEN AND do Step 39b and c.
P-6 (Both channels) - NOT LIT
IL-Fi
IL-F2 b) Verify both N-31 and N b) Initiate 1-AP-4.1.
RE-ENERGIZED c) Transfer racorder NR-45 to N-31 and N-32
40. ALIGN RUPTURED SG(s) FOR SAMPLING:
a) Rack in one Main Feedwater pump breakers to the test position b) Place the Main Feedwater pump switches in the start position
~' ---- _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
/
FOLDOUT FOR EP-3 AND ES-3 PROCEDURES
1. ,ST REINITIATION CRITERIA Manually operate Charging /SI pumps and align BIT as required and GO TO ECA-3.1, SGTR WITH LOSS OF REACTOR COOLANT - SUBC00 LED RECOVERY DESIRED, Step 1 if either condition listed below occurs:
RCS subcooling based on Core Exit TCs - LESS THAN 30*F (80*F).
S
PRZR level - CANNOT BE MAINTAINED GREATER THAN 15% [50%) .
2. RED PATH SU WARY a) SUBCRITICALITY - Nuclear power greater than 5" b) CORE COOLING - Core Exit TCs greater than 1200'F S
Core Exit TCs greater than 700*F AND RVLIS full range less than 46% with no RCPs running c) HEAT SINK - Narrow Range level in all SGs less than 10% (32"] AND total feedwater flow less than 340 gpm d) INTEGRITY - Cold leg temperature decrease greater than 100*F in last 60 minutes AND RCS cold leg temperature less than 285'F e) CONTAINMENT - Containment pressure greater than 60 PSIA
3. SECONDARY INTEGRITY CRITERIA GO TO EF-2, FAULTED STEAM GENERATOR ISOLATION, Step 1, if any SG pressure is decreasing in an uncontrolled manner or has co=pletely depressurized, and has not been isolated, unless needed for RCS cooldown.
4. COLD LEG RECIRCULATION SWITCHOVER CRITERION GO TO ES-1.3, TRANSFER TO COLD LEG RECIRCULATION, Step '1, if RWST level ~
decreases to less than 29".
5. ECST LEVEL CRITERIA Make-up to the ECST from the CST or provide alternate sources for AFW suction (SW or FP) when ECST level decreases to 40".
No. 97887210 PROCEDURE TITLE REVISION NUMBER 1.00 1-EP-3 STEAM GENERATOR TUBE RUPTURE PAGE 25 of 26 ACTION / EXPECTED RESPONSE RESPONSE NOT OBTAINED
- STEP
41. SHUT DOWN UNNECESSARY PLANT EQUIPMENT:
Check station service NOT a) Establish load shedding as a) being supplied from per 1-0P-26.7.
reserve station service b) Check main generator removed from service as per 1-0P-15.2 c) Check main turbine:
1) Turning gear oil pump 1) Manually start pump.
starts at 12 psig oil pressure
2) Seal oil back-up pump 2) Manually start pump, starts at 12 psig oil pressure d) All turbine drains - OPEN d) Manually open valves.
e) Two main feed pumps -STOPPED e) Manually stop all but one pump.
f) Two main condensate pumps - f) Manually stop all but one l STOPPED pump.
g) Low pressure heater drain g) Manually stop pumps.
pumps - STOPPED h) High pressure heater drain h) Manually stop pumps.
pumps - STOPPED
/
FOLDOUT 70R EP-3 AND ES-3 FROCEDURES
1. SI REINITIATION CRITERIA Manually operate Charging /SI pumps and align BIT as required and GO TO ECA-3.1, SGTR WITH LOSS OF REACTOR COOLANT - SUBC00 LED RECOVERY DESIRED, Step J,, if either condition listed below occurs:
RCS subcooling based on Core Exit TCs - LESS THAN 30*F [80*F] .
l 0,,R,
PRZR level - CANNOT BE MAINTAINED GREATER TEAN 15I [50 ].
2. RED PATH
SUMMARY
a) SUBCRITICALITY - Nuclear power greater than 5 b) CORE COOLING - Core Exit TCs greater than 1200*F pR, Core Exit TCs greater than 700*F AND_ RVLIS full range less than 46I vich no RCPs running c) HEAT SINK - Narrow Range level in all SGs less than 10I (32I] AND total feedvater flov less than 340 gym d)
INTEGRITY - Cold leg temperature decrease greater than 100'F in last 60 minutes AND_RCS cold leg temperature less than 285*F e)
CONTAINMENT - Containment pressure greater than 60 PSIA
3. SECONDARY INTEGRITY CRITERIA GO TO EP-2, FAULTED STEAM GENERATOR ISOLATION, Step J,, if any SG pressure is decreasing in an uncontrolled manner or has completely depressurized, and has not been isolated, unless needed for RCS cooldown.
4. COLD LEG RECIRCULATION SWITCHOVER CRITERION GO TO ES-1.3, TRANSFER TO COLD LIG RECIRCULA* ION, Step ~1, ~
if RWST level decreases to less than 29I.
5. ECST LEVEL CRITERIA Make-up to the ECST from the CST or provide alternate sources for AFW suction (SW or FP) when ECST level decreases to 40I.
P$o.97887210 WUMBER PROCEDURE TITLE REflSfN 1-EP-3 STEAM GENERATOR TUBE RUPTURE 2[oY26 ACTION / EXPECTED RESPONSE RESPONSENOTOBTAINED
- STEP
42. GO TO APPROPRIATE POST-SGTR C00LDOW METHOD:
GO TO 1-ES-3.1, POST-SGTR -
C00LDOW USING BACKFILL Step 1 S
GO TO 1-ES-3.2, POST-SGTR C00LDOWN USING BLOWDOW Step 1 8
GO TO l-ES-3.3, POST-SGTR C00LDOWN USING STEAM DUMP Step 1 END
No. 97887280 NUMBER ATTACHMENT TITLE REVISION 1-EP-3 .
1.00 NATUFJd, CIRCULATION ATTACHMENT VERIFICATI0y PAGE 1
1 of 1 STEP ACTION / EXPECTED RESPONSE RESPONSE NOT OBTAINED NOTE: The following conditions support or indicate natural circulation flow.
1. VERIFY NATURAL CIRCULATION IF natural circulation NOT FLOW: verified, THEN notify the Shift Supervisor, a) RCS subcooling based on Core Exit TCs - GREATER THAN 30*F [80*F1 b) SG pressures - STABLE ,0_R R DECREASING c) RCS hot leg temperatures -
STABLE OR DECREASING d) Core Exit TCs - STABLE OR DECREASING e) RCS cold leg temperatures -
AT SATURATION TEMPERATURE FOR SG PRESSURE
- -- - - _ _ ~ _ _ . - _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . __ _ _ _ _ _ _ _
, [.' )
. c
,.? ,
't
/
) '
.. )
i
, ATTACHMENT 7 ,
if)
EMERGENCY OPERATING PROCEDURE ES-3.1. POST STEAM CENERATOR TUBE RUPTURE C00LDOWN USING BACKFILL
.t i)
' (
il
)
/
f f VIRGINtA POWER '
N,.u')I ' NORTH ANNA POWER STATION
o. EMERGENCY PROCEDURE
]
p' Procedure Title Revision Number 1.00 1-ES-3.1 POST-SGTR C00LDOWN Page USING BACKFILL (WnTI NO ATTACT01ENTS) 1 of 6
'l .=. :
Purpose To provide guidance for operations persom.el to cooldown and depressurize the RCS to CSD conditions following a SGTR. This recovery method depressurizes therupturedSG(s)bydrainingthroug)therupturedSG(s) tube (s)intothe RCS. . ,
User ,
i-NAPS Oparations Personnel Entry Conditions This procedure is entered from:
1) 1-EP-3, STEAM GENERATOR TUBE RUPTURE, or
2) 1-ES-3.2, POST-SCTR C00LDOWN USING BLOWDOWN.
s SAEY HATED:
RIsvision Record REV. 1.01 PAGi:S (S): 2&5 DATE: 06-12-87 REV. PAGES(S): DATE:
REY. PACES (S): DATE:
REV. PAGES(S): DATE:
REV. PAGES(S): DATE:
REV. PAGES(S): DATE:
Approval Recommended Approved Date s
O Chairman Station Nuclear Safety 06-12-87 and Operating Committee h
FOLDOUT FOR EP-3 AND ES-3 PROCEDURES
1. SI REINITIATION _ CRITERIA Manually operate Charging /SI pumps and align BIT as required and GO TO ECA-3.1, SGTR WITH LOSS OF REACTOR COOLANT - SUBC00 LED RECOVERY DESIRED, Step 1 if either condition listed below occurs:
RCS subcooling based on Core Exit TCs - LESS THAN 30*F [80*F].
8
PRZR level - CANNOT BE MAINTAINED GREATER TEAN 15: [50%].
2. RED PATH SU19.ARY a) SUBCRITICALITT - Nuclear power greater than 5%
b) CORE COOLING - Core Exit TCs greater than 1200*F E
Core Exit TCs greater than 700*F AND RVLIS full range less than 46* with no RCPs running c) HEAT SINK - Narrow Range level in all SGs less than 10% [32"] AND total feedvater flow less than 340 gpm d) INTEGRITY - Cold leg temperature decrease greater than 100*F in last 60 minutes AND RCS cold leg temperature less than 285'F e) CONTAINMENT - Containment pressure greater than 60 PSIA
3. SECONDARY INTECRITY CRITERIA GO TO EP-2, FAULTED STEAM GENERATOR ISOLATION, Step 1, if any SG pressure is decreasing in an uncontrolled manner or has cocpletely depressurized, and has not been isolated, unless needed for RCS cooldown.
4. COLD LEG RECIRCULATION SWITCHOVER CRITERICN GO TO ES-1.3 TRANSFER TO COLD LEG RECIRCULATION, Step 1, if RWST level decreases to 12ss than 29 .
5. ECST LEVEL CRITERIA Make-up to the ECST from the CST or provide alternate sources for AIV suction (SW or FP) when ECST level decreases to 40%.
t i
s,. s
',r s
,b
.g .
r if . ,
No.97887210.
j ' _f - .
i
USING EACKFILL '
y- , !< l l -
-~
1 g_.-i=. j
- 3 m
- STEF ACTION / EXPECTED RE3PONSE RESPONSE NGTORTAINED j i 4 .
NOTE: ' $stpc'nta in brackets [ ] are for adverse co$tginment staesphere (20 psia containment pressurc'or 10 R/HR >
containment radiation.)
f i
s 1. ~'
TURN ON PRZE HEATERS AS
, 'NECESSARY TO SATURATE PR2R '
!>ATER AT RUPTURED S7(n)
PkESSURE s
2. CHECK IF SI ACCUMULATORS
/
SHOULD BE ISOLATED:
a)' Check the following: a) IF,eith'er condition NOT ,
satisfied, THEN 00 TO j 4
RCS subcooling basad 1-TCA 3.1, 5Idi VITH LOSS on Core Exic TCs - 0F P.EACTOR C60LsS7,' - SUB-GREATER P!AN 30*F (80*F] COOLED RfC0VER'ifDESIRED,
PRZR level-GREATER THAN 15% [50%)
i b) Accumulator discharge b) Restore power _to discharge MOVs - ENERGIZED MOVa.
'e ) ' Close all SI accumulator c) Vent any accumulator that discharge MOVs can NOT be isolated 4.s por 1-OP-7.3. ' -
t
3. _
VERIFY ADEQUATE SHUTDOWN MARGIN AS PER 1-PT-10: ,
a) Sample rureend SMaY
^
b) Sample RCS M c) Shutdown Margin- c) Borate as required.
4 '
ADEQUATE q J V
t e
- - - -------_--___.__._m_._ _ . _ _ _ . _ _ _ . _ _._._____i _ _ _ _ _ _ _ __ __
FOLDOUT FOR EP-3 AND ES-3 PROCEDURES
1. SI REINITIATION CRITERIA Manually operate Charging /SI pumps and align BIT as required and GO TO ECA-3.1, SGTR WITH LOSS OF REACTOR COOLANT - SUBC00 LED RECOVERY DESIRED, Step 1,if either condition listed below occurs:
RCS subcooling based on Core Exit TCs - LESS THAN 30*F [80*F].
S
PRZR level - CANNOT BE MAINTAINED GREATER TRAN 15 [50%].
2. RED PATH SU19.ARY a) SUBCRITICALITY - Nuclear power greater than 5%
b) CORE COOLING - Core Exit TCs greater than 1200*F 9.E.
Core Exit TCs greater than 700*F B3 RVLIS full range less than 46: with no RCPs running c) HEAT SINK - Narrow Range level in all SGs less than 10% [32%] AND total feedwater flow less than 340 gpm d) INTEGRITY - Cold leg temperature decrease greater than 100*F in last 60 minutes AND RCS cold leg temperature less than 285'T e) CONTAINMENT - Containment pressure greater than 60 PSIA
-3. SECONDARY INTEGRITY CRITERIA GO TO EP-2, FAULTED STEAM GENERATOR ISOLATION, Step 1. if any SG pressure is decreasing in an uncontrolled manner or has completely depressuri::ed, '
and has not been isolated, unless needed for RCS cooldovu.
4. COLD LEG RECIRCULATION SWITCHOVER CRITERION GO TO ES-1.3, TRANSFER TO COLD LEG RECIRCULATION, Step 1 if RWST level decreases to less than 29%.
.5 . ECST LEVEL CRITERIA Make-up to the ECST from the CST or provide alternate sources for AFW suction (SW or FP) when ECST level decreases to 40%.
l 4
l
)
l- No.97987210.
' PROCEDURE TITLE REVISION
NUMBER 1.00
, 1-ES-3.1 POST-SGTR C00LDOWN PAGE
.USING BACKFILL 3 of 6 ACTION / EXPECTED RESPONSE RESPONSE NOT OBTAINED
- STEP e**************************************
CAUTION: Alternate water sources (CST or 1-AP-22.7) to prevent loss of AFW pump suction pressure will be necessary if ECST decreases to 40%.
4. CHECK INTACT SG(s) LEVEL:
a) Narrow Range level - a) Maintain total feed flow GREATER THAN 10% (32%] greater than 340 gpm until NR level in at least one SG is greater than 10% {32%).
b)- Control feed flow to b) IJ[ NR level in any maintain Narrow Range intact SG continues to level between increase in an uncontrolled 10% [32%) and 50% manner, ))II@[ GO TO 1-EP-3, STEAM GENERATOR TUBE RUPTURE, Step 1 NOTE: Since ruptured SG(s) may continue to depressurize to less than the minimum RCS pressure required for'RCP operation, cooldown L to CSD should be completed as quickly as possible within Tech l
Spec cooldown restrictions.
l S. INITIATE RCS C00LDOWN TO COLD SHUTDOWN:
a) Maintain cooldown rate in RCS cold Icgs'- LESS THAN 100'F/HR b) Use RHR system if in service
-(STEP 5 CONTINUED ON NEXT PAGE)
FOLDOUT FOR EP-3 AND ES-3 PROCEDURES
1. SI REINITIATION CRITERIA Manually operate Charging /SI pumps and align BIT as required and GO TO ECA-3.1, SGTR WITH LOSS OF REACTOR COOLANT - SUBC00 LED RECOVERY DESIRED, Step 1 if either condition listed below occurs:
RCS subcooling based on Core Exit TCs - LESS THAN 30*F [80*F].
O,,R_
PRZR level - CANNOT BE MAINTAINED GREATER THAN 15% [50%).
2. RED PATH SUlPJJtY a) SUBCRITICALITY - Nuclear power greater than 5%
b) CORE COOLING - Core Exit TCs greater than 1200*F OR Core Exit TCs greater than 700*F AND RVLIS full range less than 46 with no RCPs. running c) HEAT SINK - Narrow Range level in all SGs less than 10% [32%] AND total feedwater flow less than 340 gpm d) ~ INTEGRITY 60 - Cold leg temperature decrease greater than 100*F in last minutes AND RCS cold leg temperature less than 285*F e) CONTAINMENT - Containment pressure greater than 60 PSIA
3. SECONDARY INTEGRITY CRITERIA GO TO EP-2, FAULTED STEAM GENERATOR ISOLATION, Step 1, if any SG pressure is decreasing in an uncontrolled manner or has completely depressurized, and has not been isolated, unless needed for RCS cooldown. l
4. COLD LEG RECIRCULATION SWITCHOVER CRITERION l GO TO ES-1.3, TRANSFER TO COLD LEG RECIRCULATION, Step ~1, if RWST level decreases to less than 29%.
5. ECST LEVEL CRITERIA Make-up to the ECST from the CST or provide alternate sources for AFW suction (SW or FP) when ECST level decreases to 40%.
4 e
ia,97ss7:1o
? PROCEDURE TITLE REVISION _
' fLUMBER .
1.00 1-ES-3.l' POST-SGTR C00LDOWN PADE USING BACKFILL ,4 of 6-I' x
- STEP ACTION / EXPECTED RESPONSE . RESPONSENOTOBTAINED 5.- INITIATE RCS C00LDOWN TO COLD SHUTDOWN: (CONTINUED) c) Dump steam to c) Manually or locally dump condenser from intact steam from intact SG(s):
SG(s),
SG PORV(s)
E Decay heat release valve.
IF no intact SG available, THEN perform the following:
Use f attited SG E
GO TO 1-ECA-3.1, SGTR-WITH LOSS OF REACTOR COOLANT - SUBCOOLED RECOVERY DESIRED, Step 1,.
6. . CHECK RUPTURED SG(s) Refill ruptured SG co NARROW RANGE LEVEL - 75% [60%) using feed flow.
GREATER THAN 10% [32%] IF either of the following occurs, THEN stop feed flow l co the ruptured SG:
Ruptured SG pressure decreases in an 'i uncontrolled manner 1
E !
l Ruptured SG pressure )
increases to 1000 psig. l l
l l
) , ,
l:
FOLD 00T FOR EP-3 AND ES-3 PROCEDURES
.1. SI REINITIATION CRITERIA-Manually operate Charging /SI pumps and align BIT.as. required and GO TO
~
ECA-3.1, SGTR WITH LOSS OF REACTOR COOLANT - SUBC00 LED RECOVERY DESIRED, Step 1 if either condition listed below occurs:
RCS subcooling based on Core Exit TCs - LESS THAN 30*F (80*F].
0,, R,
PRZR level - CANNOT BE MAINTAINED GREATER THAN 15% [50%).
2. RED PATH
SUMMARY
a) SUBCRITICALITY - Nuclear power greater than 5:
b) CORE COOLING - Core Exit TCs greater than 1200*F 9.R Core Exit TCs. greater than 700*F AND RVLIS full range less than 46% with no RCFs running c) HEAT SINK - Narrow Range level in all SGs less than 10 (32%) AND total feedwater flow less than 340 gpm d) INTEGRITY - Cold leg temperature decrease greater-than.100*F in last 60 minutes AND RCS cold leg temperature less than 285'T
- e)~ CONTAINMENT - Containment pressure. greater'than 60 PSIA
3. SECONDARY INTEGRITY CRITERIA ,
J CO TO EP-2, FAULTED STEAM GENERATOR ISOLATION, Step 1, if any SG pressure {
is decreasing in an uncontrolled manner or has completely depressurized, and has not been isolated, unless needed for RCS cooldown.
4'
4. COLD LEG RECIRCULATION SWITCHOVER CRITERION GO TO ES-1,3, TRANSFER TO COLD LEG RECIRCULATION, Step 1, if RWST level decreases to less than 29%.
5. ECST LEVEL CRITERIf Make-up to the ECST from the CST or provide alternate sources for AFW 1
suction (SW or FP) when ECST level decreases to 40%. i
. 9 i
4 I
L I
L . - _ _ _ _ _ _ _
5 nsanto PROCEDURE TITI.E REVIS N l : NU::BER . .
1-ES-3.1 POST-SGTR C00LDOWN pAGE
- USING BACKFILL 5 of 6-ACTION / EXPECTED RESPONSE RESPONSE NOT OSTAINED .
- STEP
7. CONTROL RCS MAKEUP FLOW TO MAINTAIN PRZR LEVEL:
a) PRZR level - GREATER a) Increase RCS makeup flow as-THAN 30% [55%] required. GO To Step 8.
b) PRZR level - LESS b) Decrease RCS makeup flow as THAN 70% [65%] required. GO TO Step .9_.
' NOTE: The upper head region may void during RCS depressurization if ,
RCPs are.not running. This may result in a rapidly increasing I PRZR level.
8. DEPRESSURIZE RCS TO BACK - ,
FILL FROM RUPTURED SG(s):
a) Use normal _PRZR spray a) IF, letdown in service, THEN use auxiliary spray. IF, _l NOT, THEN use one PRZR PORV.
b) Turn on PRZR heaters as necessary c) Maintain RCS subcooling based on Core Enit TCs - ]
GREATER THAN 30 'F [80 'F]
9. CHECK IF RHR CAN BE PLACED IN SERVICE:
a) Check the following: a) GO TO Step 3 i
RCS WR T - l LESSTHAN350*F f
RCS pressure -
LESS THAN 400 PSIG
[225 PSIG) b) Place RHR in service 3 as per 1-0P-14.1 i
1
(
l FOLDOUT FOR EP-3 AND ES-3 PROCEDURES
1. SI REINITIATION COITERIA Manually operate Charging /SI pumps and align BIT as required and GO TO ECA-3.1, SGTR WITH LOSS OF REACTOR COOLANT - SUBC00 LED RECOVERY DESIRED, Step 1 if either condition listed below occurs:
I
RCS subcooling based on Core Exit TCs - LESS THAN 30*F [80*F].
$$ (
PRZR level - CANNOT BE MAINTAINED GREATER THAN 15% [50%).
2. RED PATH
SUMMARY
a) SUBCRITICALITY - Nuclear power greater than 5%
b) CORE COOLING - Core Exit TCs greater than 1200*F
. pR Core Exit TCs greater than 700*F AND RVLIS full range less than 46% with no RCPs running c) HEAT SINK - Narrow Range level in all SGs less than 10% [32%) i.ND total feedwater flow less than 340 gpm d) INTEGRITY - Cold leg temperature decrease greater than 100*F in last 60 minutes AND RCS cold leg temperature less than 285'F e) CONTAINMENT - Containment pressure greater than 60 PSIA
3. SECONDARY INTEGRITY CRITERIA GO TO EP-2, FAULTED STEAM GENERATOR ISOLATION, Step 1, if any SG pressure is decreasing in an uncontrolled manner c: has completely depressurized, and has not been isolated, unless needed for RCS cooldown.
4. COLD LEG RECIRCULATION SWITCHOVER CRITERION GO TO ES-1.3, TRANSFER TO COLD LEC RECIRCULATION, Step 1 if RWST level decreases to less than 29%.
5. ECST LEVEL CRITERIA Make-up to the ECST from the CST or provide alternate sources for AFW suction (SW or FP) when ECST level decreases to 40%.
)
-1 n e_7 es7:10 .,
PROCEDURE TITLE REVIS N <
^NU::8ER 1-ES-3.1- POET-SGTR C00LDOW PACE USING BACKFILL 6 of 6 .
ACTION / EXPECTED RESPONSE ' RESPONSE NOTOBTAINED
- STEP
10. CHECK IF RCPs MUST BE STOPPED:
a). Monitor the following: a) GO TO Step H.
Number 1 seal differ-
-ential pressure -
LESS THAN 210 PSID pR Number 1 seal leakoff flow .LESS THAN 0.3 GPP b) Stop affected RCP(s)
11. CHECK RCS WR T -
Return to Step ~3.
LESSTHAN200*f
.' 12. _ EVALUATE LONG TERM PLANT STATUS:
a) Maintain cold shutdown b) Consult TSC personnel END
_ _ _ - _ -

ML20238F616

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