ML17261A332
| ML17261A332 | |
| Person / Time | |
|---|---|
| Site: | Ginna  |
| Issue date: | 04/12/1982 |
| From: | ROCHESTER GAS & ELECTRIC CORP. |
| To: | |
| Shared Package | |
| ML17256A810 | List: |
| References | |
| NUDOCS 8204160281 | |
| Download: ML17261A332 (275) | |
Text
Incident. Evaluation Ginna Steam Generator Tube Failure Incident January 25, 1982 R.E. Ginna Nuclear Power Plant Docket No. 50-244 April 12, 1982
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PDR ADOCK 8 'DR 8204i6028i 820413 05000244
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TABLE OF CONTENTS PAGE
1.0 INTRODUCTION
1 ~ 0-1 2.0 NOTIFICATIONS 2 '-1 3.0 SEQUENCE OF EVENTS 3.1 Summary 3 '-l 3.2 Cooldown 3 '-1 3.3 Draindown 3 ~ 3-1 4' OPERATOR RESPONSE 4.1 Procedures 4 '-l 4 ' Evalua tion 4.2-1 4 2 1 Reactor Coolant Pump Trip 4.2-1
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4' '
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Verification of Natural Circulation 4 '-1 4.2.3 Safety Injection and Containment Isolation Reset 4.2-2 4' ' Restart of Charging Pumps 4 '-2 4' ' Isolation of "B" S/G Power Operated Relief Valve 4.2-2 4.2.6 Operation of Pressurizer Power Operated Relief Valve 4 '-2
'-3 4~2~7 Safety Injection Termination 4 4~2~8 Isolation of Condenser 4 '-3 4.2-4 4~2~9 Safety Injection Re-established 4.2 'l 4.F 10 Reactor Coolant Pump Restart Pressurizer Level Control with Safety Injection Pump 4 '-4 4 '-4 4.2 '2 Reactor Coolant Pump Trip (January 26) 4 '-4 4.3 Conclusions 4 '-1 5 ' EQUIPMENT PERFORMANCE 5.1 B Steam Generator Tube Failure Analyses* 5 '-1 5 ' Pressurizer Power Operated Relief Valves 5 '-1 5.2.1 System Description 5 '-1 5.2.2 Operational Sequence 5 '-3 5.2.3 Inspection and Repair 5.2-4 5.2.4 Solenoid Valve 5.2-5 5.2.5 Modifications 5 '-8
- to be submitted separately.
5 ' Pressurizer PORV Block Valve Performance '5 3-1 5~3~1 Description 5.3.2 EPRI Program Results (Block Valves) 5 '-1
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'-1 5
5.3.3 Inspection 5 '-2 5 ' B Main Steam System 5 '-1 5.4.1 Description 5 '-1 5 '.2 Overfill Sequence of Events 5 '-4 5.4.3 Inspection and Repair 5 '-6 5 ' Letdown Isolation 5 '-1 5.6 Effluent Monitoring System 5.6-1 5.6.1 Main Steam Radiation Monitors 5.6.2 Air Ejector and Gland Seal Exhaust Monitor 5 '-1 (R-15) 5 '-2 5.6.3 SPING Air Ejector and Gland Seal Exhaust Monitor (R-15A) 5.6-2 5.6.4 Plant Ventilation Effluent Monitors 5 '-2 5.7 Sump A Level Indicator 5 '-1 5' Safety Injection Pump 1C 5 '-1 6.0 ANALYSIS 6 ' Comparison of Plant Response with Previous Analysis 6 '-1 6 ' Steam Void Formation 6 '-1 6 ' Calculation of Leak Rate 6 '-1 6 ' Thermal Transient on Reactor Coolant System 6 '-1 6.4.1 Description of Transients 6 '-1 6.4.2 Material Properties and Irradiation Effects 6 F 4-1 6.4.3 Results 6.4-2 6 ' Hydrogen Transfer 6 '-1 6 ' Fuel Per formance 6 '-1 6-F 1 Mechanical Design Considerations 6 '-1 6.6.2 Core Transient Considerations 6 '-1 6 ' Steam Generator Overfill 6 '-1 6.7 ' Structural Analysis 6 '-1 6' ' Water Hammer Potential 6 '-3 6' ' Effect of Boric Acid Ingress 6 '-8 6' ' Thermal and Hydraulic Effects on the Steam Generator 6.7-9
6' Pressurizer Power Operated Relief Valve 6.8-1 6.8.1 Structural Analysis 6 '-1
'-2 6.8.2 Qualification 6 6 ' Plant Water Inventory 6 '-1 6.9.1 Reactor Coolant System Inventory 6 '-1 6.9.2 B Steam Generator 6.9-3 6.9.3 Uncertainties 6 '-5 6.9.4 Conclusions 6 '-7 7.0 RADIOLOGICAL ASSESSMENT 7 ' Reactor Coolant System and Steam Generator Radionuclide Inventories 7.1.1 Radionuclide Concentrations in RCS 7
7
'-l
'-l 7 '.2 Radionuclide Concentrations in "B" Steam Generator 7 '-l 7 ' Radiological Releases 7~2 1 7.2.1 Noble Radioactive Gases Released from t'e Condenser Air Ejector and Gland Seal Exhaust 7.2-1 7.2.2 Noble Gases Released from Turbine Driven Auxiliary Feedwater Pump 702-3 7.2.3 Noble Radioactive Gases Released from the Sa fety Valve 7~2 3 7' ' Radioiodines and Particulates Released in Off-Gas 7 2-6 7 '-5
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Radioiodine, Particulate and Tritium Releases from Safety Valve 7~2 7 7 ' Meteorological Data 7 ~ 3-1 7.4 Survey Teams 7 '-1 7.5 Sampling (Air, Snow, Water) 7 5-1 7 '-1
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7.5.1 Air -Samples 7.5.2 Measurements of Radionuclides in Samples of Snow 7 '-2 7.5.3 Drinking Water Samples 7 '-3 7 ' TLD Measurements 7 '-1 7 ~7 Estimated Offsite Doses 7.7-1 7.7.1 Plume Exposure Pathways 7~7 1 7.7.2 Maximum 40 Mile Population Dose 7~7 3 7.7.3 Potential Ingestion Pathways 7~7 3 7.7.4 Comparison of Predicted and Measured Dose Rates Near the ESC 7 '-4 7-7.5 Comparison of Measured and Predicted Activities Near the ESC 7 '-5 7 ~8 Additional Radiological Information 7 '-1 7 8 1
~ ~ Comparison of Releases Due to Tube Rupture Event With Ginna Technical Specifications 7 ~ 8-1 3.11
7.9 Recommendations 7 '-1 8 ' RECOMMENDATIONS 8.1 Procedures F 1-1 8.1.1 Short-Term Procedure Changes 8.1-1 8.1.2 Long-Term Procedure Changes and Areas of Recommended Study F 1-3 8.2 Equipment 8 '-1 8.2.1 Short Term 8 '-1
'-1 8~2~2 Long Term 8 APPENDICES A. Chronology B. Plots of Data
1.0 INTRODUCTION
At 9:25 a.m. on January 25, 1982, the R. E. Ginna B Steam Generator experienced a tube failure. Prior to the transient, the plant was operating at full power with no primary to secondary leakage.
The plant transient resulting from the tube failure included a significant primary system depressurization, actuation of the safety injection system, and minor releases of radioactive materials from the plant. This report summarizes the sequence of events, reviews operator actions including plant procedures, discusses performance of selected pieces of equipment,'resents results of analysis including a radiological assessment, and provides recommendations for future actions. A report on the steam generator inspection, evaluation, and repair program will be submitted separately.
2.0 NOTIFICATIONS The incident led to implementation of the Ginna Radiological Emergency Plan and its associated procedures including noti-fication of governmental agencies'his section describes selected notifications. Numerous other discussions took place between RGSE representatives and Federal, State, Local and industry organizations throughout and following the incident.
As presented in Section 3.0, Sequence of Events, the incident began at 9:25 a.m., with reactor trip and safety injection occurring at approximately 9:28 a.m. The NRC Operations Center was informed via the Emergency Notification System (ENS) at 9:33 a.m. The Site Contingency Plant Assessment Manager manned the Technical Support Center at approximately 9:35 a.m. NRC Region I was in contact with the plant at 9:38 a.m. An Alert Condition was declared at 9:40 a.m. Governmental organizations, including New York State, Wayne County, and Monroe County were notified at 9:47 a.m. by means of a "hot line" among these and other governmental agencies and RGEE. The onsite Technical Support Center was fully staffed and declared operational at 9:58 a.m.
At 10:16 a.m., the governmental organizations were informed of pressurizer and steam generator levels and pressures.
The governmental organizations were updated concerning steam generator levels and pressures, safety injection flows and reactor coolant system pressure at 10:35 a.m. At 10:44 a.m., a Site Emergency was declared. The governmental organizations were notified of a release to the atmosphere and of the escalation to a Site Emergency at 10:45 a.m. Also, at 10:45 a.m., the governmental organizations were updated on RCS pressure. The INPO Emergency Response Center was notified at 10:55 a.m. that a Site Emergency was declared. The governmental organizations were updated on the release to atmosphere at 11:00 a.m. The Offsite Emergency Operations Facility was declared operational at ll:25 a.m. At approximately 4:15 p.m ~ , the NRC Region I Incident Response Team arrived on site. The event was downgraded to Alert at 7:17 p.m. At 10:45 a.m. on January 26, 1982, the event was downgraded from an Alert to recovery phase.
2 '-1
3.0 SEQUENCE OF EVENTS
- 3. 1 ~Summa r The following chronology is a summary of the key steps in the overall sequence of events. All times are accurate to the minute.
A detailed chronology and plots of key system parameters are presented in Appendices to this report.
0925 January 25 Charging pump speed alarm; B Steam Generator (S/G) level deviation alarm; steam flow-feed flow mismatch B S/G; air ejector radiation monitor alarm; pressurizer low pressure alarm 2169 psig.
0926 Overtemperature aT Turbine runback of approxi-mately 5% due to decreasing pressure. Commenced manual load reduction.
0928 Automatic reactor trip on low pressurizer pressure; nuclear power at time of trip approximately 708; automatic safety injection (S.I.); automatic containment isolation on S.I.
0929 Pressurizer level near zero; both reactor coolant pumps manually tripped. Natural circulation established.
0933 NRC Operations Center informed via Emergency Notification System.
0935 Manning of Technical Support Center commenced.
0938 NRC Region I in phone communications with the site ~
0940 "B" Main Steam Isolation Valve manually closed. Alert declared.
0947 New York State, Monroe County and Wayne County notified.
0951-0953 "B" Steam Generator power operated relief valve (PORV) isolated.
0957 Safety Injection reset; Containment Isolation reset (to re-establish instrument air to containment).
0958 On site Technical Support. Center fully staffed and operational.
1004 Charging pumps manually restarted.
1006 1007 RCS pressure 1270 psig; pressurizer level 5% and increasing.
1007 Pressurizer PORV manually opened two times to reduce primary pressure and hence reduce leak rate.
1008 Pressurizer PORV manually opened; letdown isolation automatically reset as pressurizer level increased above 10.6%.
1009 Pressurizer PORV manually opened. PORV started closed, reopened, and stayed open; pressurizer level increasing.
1010 Minimum pressurizer pressure approximately 830 psig. (Conditions existed for steam void in reactor head.) Pressurizer Relief Tank (PRT) high temperature alarm; Pressurizer PORV block valve shut. Safety Injection Pumps increased RCS pressure to 1350 psig over the next 5 minutes.
1019 Indication that "B" S/G safety valve safety .valve setting is 1085 psig.)
lifted'First 1028 Indication that "B" S/G safety valve lifted.
1037 Indication that "B" S/G safety valve lifted.
Safety injection pumps secured to reseat the "B" S/G safety valve.
1040 Condensate system secured; air ejector secured; "A" S/G power operated relief valve throttled open.
1044 Site Emergency declared.
1051 Pressurizer Relief Tank Pressure indicates that rupture disc has blown.
1107 One Safety Injection pump restarted.
1119 Indication that "B" S/G safety valve lifted.
1122 "A" Reactor Coolant pump restarted.
1135 Safety Injection Pump throttled and secured.
1137 Indication that "B" S/G safety valve lifted.
1152 Pressurizer level channels coming back on scale 1202 Normal letdown restored.
F 1-2
1203 Pressurizer level < 87%.
1213 Restart then stop one S.I. pump to control pressurizer level.
1219 Restart then stop one S.I. pump to control pressurizer level.
1227 Restart then stop one S.I. pump to control pressurizer level.
1230 "B" S/G pressure greater than reactor coolant system pressure.
1840 Re-established level in "B" S/G. Plant cooling down via forced "A" circulation and dumping steam from the S/G to atmosphere.
"B" S/G secondary side pressure maintained at about 20 psi above primary. "B" S/G being fed by Auxiliary Feedwater and bled via the ruptured tube to the RCS.
1917 Downgraded event. from a Site Emergency to an Alert.
0658 January 26 RHR cooling initiated'045 Downgraded event from an Alert to recovery status.
1853 Cold shutdown achieved.
3 ~ 1-3
3.2 Cooldown Due to the Overtemperature LT runback at 0927 on January 25 and subsequent manual load reduction, the condenser steam dump valves were open prior to the reactor trip at 0928. Both reactor coolant pumps were manually tripped in accordance with procedures and an initial cooldown of 50oF was accomplished by safety injection and condenser steam dump between 0934 and 0942. The "B" loop main steam isolation valve was closed at 0940. Natural circulation was employed utilizing condenser steam dump from the "A" steam generator only.
A rapid cooldown was accomplished with this method, as can be seen in Figure B-8. By 1000, the A and B loop cold leg temperatures were 482 F and 360 F, respectively. At 1030, the A and B loop cold leg temperatures were 436 F and 330 F, respectively.
At 1040, the condensate system was secured (see Section 4.2.8) and the "A" steam generator power operated relief valve was used to continue the cooldown. To further enhance the cooldown, the "A" reactor coolant pump was restarted at 1122. Immediately prior to RCP restart, the A and B loop cold leg temperatures were 417oF and 360oF, respectively, while at 1135 the temperatures were 418oF and 414oF, respectively. Decay heat removal continued via this method with A and B cold leg temperatures at 373oF and 370oF, respectively, by 1230 on January 25.
Between 1400 on January 25 and 0700 on January 26, when the residual heat removal system was placed in service, the cold leg temperatures were reduced from approximately 364oF to approxi-mately 340 F. The cooldown rate was limited because, with the low pressure of the "A" steam generator ( 100 psig), the combination of decay heat and pump heat began to approach the heat removal capacity of the "A" S/G power operated relief valve. Because the cooldown rate was limited by early afternoon of January 25, another means of reducing primary system temperature was developed. After reducing the primary system pressure below that of the "B" steam generator, the water in the "B" S/G could be forced through the ruptured tube and back into the primary system. The "B" S/G was then refilled by the auxiliary feedwater system with the cold auxiliary feedwater cooling the system.
The excess primary water was removed using the normal primary letdown system. Due to the diluting of the primary system by auxiliary feedwater, the primary system boron concentration was frequently monitored. This method was used frequently to further cool the RCS.
By 0650 on January 26 the primary system temperature had decreased to 340oF, which is low enough to initiate residual heat removal (RHR). RHR was initiated at 0658, although cooldown on RHR was delayed until 1215 to allow for an initial degassing of the primary system. With RHR in service, a cooldown rate of 35oF/hr was achieved, leading to a cold shutdown condition at 3 '-1
1853. The "A" reactor coolant, pump was stopped at 2008 and the system cooldown continued using RHR.
3~2 2
3.3 Draindown After achieving cold shutdown, RHR was used to maintain cold shutdown conditions. The RCS was solid except for a steam void in the top of the "B" steam generator. Sampling of the gas in the "B" S/G indicated the presence of radioactive gases and hydrogen. Temperature and pressure in the "B" S/G were higher than. that of the RCS. Hydrogen gas found via sampling of the generator was not removable by normal methods.
An estimate of the gas and steam volume in the "B" steam generator was 2500 ft3. An initial gas sample indicated gaseous activity of 3.6 Ci/cd A second sample indicated 6.4 Ci/cc gaseous activity.
Normal draindown of the primary system was not possible because the B S/G gas pressure would force water out of the pressurizer vent into containment causing additional contamination'. Methods discussed to vent the S/G and then drain the primary system included:
Ventin the Steam Generator to Containment, Gaseous activity precluded this option. The containment would have been contaminated above levels desirable for further work until activity had decayed (estimated to be 40-45 days).
- 2. Ventin the Steam Generator to the Reactor Head Vent.
Eductor-This venting would have limited contamination in contain-ment as the gas would have gone to the containment purge exhaust. This choice was rejected because of activity that would have been released.
- 3. Ventin the Steam Generator to the Gas Deca Tanks Thxs method was selected to minimize offsxte releases.
Alignment to achieve this transfer incorporated a temporary 3/8" line from the Main Steam piping above the "B" S/G to the Pressurizer Relief Tank (PRT). The PRT was, in turn, lined up to the Vent Header with the Waste Gas Compressor, thereby trans-ferring gas to the "D" Gas Decay Tank. Purging would be complete when PRT water level began to increase.
A charging pump, taking suction from the refueling water storage tank, was used to fill the generator from primary side via the tube rupture. Level in the "B" S/G increased from 432" to 500" wide range indication with no apparent change in the system pressure ( 7000 gal. added). PRT pressure still showed no increase after 18,000 gallons of charging flow. At this time it was evident that much of the volume originally thought to be noncondensable gases was, in fact, a steam void. As cool charging flow raised level on the S/G secondary side via the tube rupture, this steam was being quenched'
'-1
After charging 18,175 gallons into the RCS, wide range pressure indication (PI 420) indicated 45 psig and charging was secured-Pressure was then allowed to bleed off through the temporary S/G vent line to the PRT. When PRT level showed an increase
>1.5$ level, venting was secured.
Degasing of the primary system had been performed while using the RHR system for decay heat removal but did not include degasing of water in the "B" steam generator. Also, there was a possibility of gas pockets still present in RCS. A nitrogen blan'ket was next placed on the secondary side of the "B" S/G. Nitrogen pressure was used to force water back through the ruptured tube while a Reactor Coolant Drain Tank (RCDT) Pump was run to transfer water from the RCS to a CVCS Holdup tank.
Draindown was temporarily stopped at 140" wide range S/G level.
A nitrogen overpressure of 40 psig precluded draining the pressurizer and the "A" Steam Generator primary side.
To equalize nitrogen pressure throughout the RCS and allow draining of the pressurizer:
1 The PRT was isolated from the Vent Header 2 ~ The valves in the temporary line from the "B" S/G Steam line to the PRT were reopened, equalizing pressure to the PRT.
3 ~ The Pressurizer vent valve to the PRT was opened.
4, The Pressuri'zer PORV was opened to equalize pressure at the top of the Pressurizer and allow it to drain when Pressurizer pressure equalled S/G pressure.
5 ~ The reactor head vent was aligned to the PRT to assure that no void existed in the reactor head. PRT liquid level increased 18 indicating fluid flow from the reactor head area; this demonstrated that there had been no void in the head ~
Reinitiation of draindown was achieved without use of RCDT pumps because the existing nitrogen pressure was sufficient to cause flow through MOV-1813A to the CVCS Holdup Tanks Steam generator secondary side level decreased to below the low level indicator tap which is 14" above the tube sheet, indicating that the rupture location was at or just above the top of the secondary side of the tube sheet of the generator.
Primary system draindown continued in this manner until secured at approximately 20" primary loop level (20" above the it was bottom of the primary system pipe) ~ Loop level then fluctuated to as low as 9-10 inches because the tubes in the "A" S/G had not fully drained'The voiding of water from steam generator tubes is a normally occurring phenomenon during system .draindown.
.The inverted U-tube configuration requires admittance of air to cause both hot and cold legs to drain.) During the midnight shift on January 31 February 1, one final level fluctuation occurred in the primary loop, indicating that voiding of the primary side of the non-faulted "A" steam generator had been 3~3 2
accomplished'rimary loop level then stabilized at 18". was Total calculated water inventory transferred to the holdup tanks 72,435 gallons of which 36,275 gallons was from draining the "B" generator secondary side.
The remaining nitrogen blanket covering the primary system was vented out the reactor head vent to the eductor through HEPA and charcoal filters and out through the containment vent.
3~3 3
4.0 OPERATOR RESPONSE 4.1 Procedures The Ginna Emergency Procedures, including E-l.l, "Immediate Actions..." and E-1.4, "Steam Generator Tube Rupture," are based on the generic Westinghouse Owners Group Guidelines,'evision 1,- October 1979, and revision 2, June 1980. These procedures, together with timely and competent Control Room personnel action, were used to effectively mitigate the incident, with no unacceptable results. Certain modifications to the emergency procedure E-l.4 are listed in Section 8.1.1. These modifications primarily concern plant specific operational changes, or clarifications in the use of the procedures. Other minor changes, primarily editorial in nature, have also been made.
The following procedures were used in responding to the incident:
E.-l.l, "Immediate Actions and Diagnostics for Spurious SI, LOCA, Loss of Secondary Coolant and Steam Generator Tube Rupture" E-l.4, "Steam Generator Tube Rupture" 0-2 ', "Normal Shutdown to Hot Shutdown" 0-2 ', "Plant Shutdown from Hot to Cold Shutdown" 0-100, "Draining the RCS Following a S/G Tube Rupture"
4.2 Evaluation The operators used the procedures specified in Item 4.1. Other control room personnel were consulted by the operators in the use of the E-1.4 procedure.
E-l.l was used for immediate action verification.
E-1.4 was used for accident mitigation and recovery.
0-2.1 and 0-2.2 were used by operators to accomplish normal plant shutdowns and cooldown.
0-100 was written to accomplish "B" S/G and RCS drain down ~
This procedure was approved by the Plant Operations Review Committee (PORC) prior to use. Other procedures had previously been reviewed and approved by PORC.
The significant operator actions are discussed below.
4.2.1 Reactor Coolant Pump Trip Reactor coolant pump trip was performed at 9:29 AM, less than one minute after Safety Injection (SI) pump operation was verified and RCS pressure was < 1715 psig, in accordance with E-1.4.
Pumps were tripped based on a trip pressure of 1715 psig as opposed to 1350 psig as suggested in the Westinghouse Owners Group Procedure Guidelines, because of lack of 'instrumentation which is qualified below 1715 psig. However, use of the lower value would not have resulted in any change to the transient, since RCS pressure dropped below 1350 psig within a minute of dropping below 1715 psig.
4.2.2 Verification of Natural Circulation Natural circulation was verified for plant cooling throughout the initial phase of the transient. Confirmation was gained by observing:
Loop "A" bT less than full power A.T.
2 ~ Core exit thermocouples subcooled and constant. or decreasing in temperature.
3 ~
"A" S/G level in the narrow range, as soon as the level recovered from the reactor trip.
4 Auxiliary feed flow to "A" S/G.
4 '-1
4' ' Safety Injection and Containment Isolation Reset Safety Injection (SI) reset and Containment Isolation (CI) reset were accomplished per E-1.4 when the safety injection pumps suction was transferred from the Boric Acid Storage Tanks to the Refueling Water Storage Tank. Reset was required because instrument air was needed in containment to accomplish the reactor coolant system (RCS) depressurization with Power Operated Relief Valves (PORVs), following the RCS cooldown to 490oF. (Had instrument air not been available, the low temperature overpressure protection system nitrogen supply was available.)
4 '.4 Restart of Charging Pumps The restart of the charging pumps was accomplished per E-l.4 after SI reset, after the RCS cooldown to 490 F, just prior to the depressurization of the RCS in order to provide additional ma'ke-up capability and in anticipation of starting the reactor coolant pump (provide seal injection flow). This step is based on the Westinghouse Owners Group guidelines for plants such as Ginna.
4.2.5 Isolation of "B" S/G Power Operated Relief Valve Manual isolation of the "B" steam generator power operated relief valve (PORV) was ordered at about 9:51 a.m. when isolating "B" S/G after identifying "B" S/G as the faulted loop. The safety valves, set at a higher pressure, were still available for steam system overpressure protection. The Ginna procedure calls for the PORV controller to be put into the manual closed position.
However, this was interpreted as a requirement to close the block valve. Thus the PORV block valve was closed. The isolation of the PORV resulted in a safety valve opening instead of the PORV; however, this had no effect on the progress of the recovery.
The procedure intended that the PORV be placed in the manual closed position which will result in a set pressure of 1060 psig instead of 1050 psig.
4.2.6 Operation of Pressurizer Power Operated Relief Valve Three options for reducing primary system pressure are provided in E-l.4: pressurizer spray, auxiliary spray and the pressurizer PORVs. The pressurizer spray was unavailable because the Reactor Coolant Pumps had been tripped'uxiliary spray was undesirable because letdown isolation prevented the water from being warmed to the proper temperature. A primary PORV was thus utilized.
The PORV was opened for only brief periods of time, instead of one extdnded relief, in order to depressurize in a more controlled fashion and to limit the extent of depressurization.
4-2-2
4' ' Safety Injection Termination Safety Injection termination was accomplished at 10:37 a.m. after the E-l.4 procedural guidance was met (20% pressurizer level and a 200 psig increase in primary system pressure) and after other primary and secondary system parameters were verified for assurance that adequate RCS inventory and core cooling was available even with a possible steam bubble in the reactor vessel head. Adequate inventory was determined by the person in charge who reviewed temperatures and pressures in the loops, steam generators and reactor vessel. SI was not terminated until about 25 minutes after the procedural criteria were met, because of the possibility of steam bubble in the vessel head and uncertainty as to its size. It should be noted that the thermocouples conditions which are located in the vessel head region indicated subcooled at the time of termination, however, the possibility of minor voiding above the elevation of the thermocouples existed. Even though the criteria for termination were met, the operators wanted to have every assurance that core cooling would be maintained if SI were terminated. Thus, additional indications of subcooling and natural circulation, such as level indication in the pressurizer and "A" S/G, were identified prior to SI termination. Although some releases to the atmosphere resulted during this evaluation period, all personnel concerned with the incident recovery realized that maintenance of adequate core cooling was the overriding concern relative to overall safety.
(It was subsequently confirmed that Westinghouse Owners Group analysis which supports the emergency response guidelines predicts in Section 8 ',
the formation of voids in the vessel head region. As described procedure revisions will clarify the fact that sfety injection may be terminated when certain criteria are met, regardless of the existence of a void in the head. The procedural guidance will ensure adequate core cooling at all times by means of subcooling and safety injection reinitiation criteria.)
4.2.8 Isolation of Condenser The air ejector provides a means of evacuating the main turbine condenser air and noncondensable gases and maintaining it at a vacuums The air ejector consists of an arrangement of nozzles and diffusers. High pressure steam entering the nozzle increases in velocity, and gas from the condenser is entrained in this high velocity steam jet. The mixture of air and steam enters the diffuser and the inner and after condensers where the mixture is cooled by condensate flow. Any air and noncondensables are then directed out the ventilation stack.
At. approximately 1040, the operating condensate pump was action was taken to prevent further contamination of the secured'his full flow condensate demineralizer system and of the condensate storage tanks, the latter via the reject line from the hotwell ~
4.2-3
(Other means to preclude contamination are also available, e.g.
manual isolation of these systems without stopping the condensate pumps.) The securing of the condensate pumps resulted in loss of the air ejector due to an interlock between"A"the systems.
Subsequently, decay heat removal was via the steam generator power operated relief valve. It should be noted that the "A" steam line pressure at the time of isolation was 280 psig and was approaching the minimum design value of 200 psig.
4.2.9 Safety Injection Re-established Safety Injection was re-established at 1107 prior to restarting the "A" reactor coolant pump (RCP) for added assurance of RCS inventory and core cooling, and in anticipation of the collapse of the Reactor Vessel upper head steam void, It was reactor anticipated that the collapse of the if steam one existed.
bubble could cause coolant inventory to shrink. Thus, use of SI would ensure that the core remained covered throughout the pump restart.
4.2.10 Rector Coolant Pump Restart The "A" RCP was restarted at 1122, after the E-l.4 emergency procedure criteria were met. The decision was made to start, the RCP, even though the pressurizer was suspected to be water solid, by pressurizer level indication of 100'he reactor coolant pump was restarted very deliberately, after checking all relevant parameters necessary for RCP operation, such as seal injection flow, lube oil pump operation, gl seal differential pressure and flow, oil level, labyrinth seal differential pressure, component cooling water flow, and the NPSH curve for the reactor coolant pump.
4.2.11 Pressurizer Level Control with Safety Injection Pump From approximately 1010 until approximately 1152, pressurizer level indication was off-scale high indicating a filled pressurizer (see Figure B-4). At 1152, pressurizer level returned on scale and began to decrease. Due to the rate of level. decrease and in order to maintain level near mid-scale, one safety injection pump was operated, for brief periods of time, three times between 1210 and 1240. Based on pressurizer level data, one pump was operated briefly at the following times: 1213, 1219, and 1227 safety injection pump was throttled to roughly 25% to 508 'he of normal flow during this time period.
4.2 '2 Reactor Coolant Pump Trip (January 26)
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The "A" RCP was tripped on Tuesday, January 26 because the number one seal leakoff was less than 0.2 gpm, the minimum value which assures adequate RCP seal cooling. RCS temperature was <200oF and RHR was in service.
4 '-4
4.3 Conclusions The Ginna procedures for mitigation of the tube rupture accident, and for subsequent recovery and cold shutdown, provided the necessary information to perform the required actions. Certain clarifications of the procedures, primarily in the use of the safety injection termination criteria and reactor coolant pump restart criteria, have been added as notes to Sections 3.15 and 3.18 of E-1.4.
4 '3-1
0 0
5~0 EQUIPMENT PERFORMANCE 5.1 Steam Generator Tube Failure Anal sis A report on the steam generator inspection, evaluation, and repair program will be submitted separately.
0 p
5 ' Pressurizer Power 0 crated Relief Valves 5.2.1 System Description The original system for control'of the pressurizer Power Operated Relief Valves (PORVs) was placed in service in 1969 'uring 1978, a low temperature overpressure protection system was in-stalled. In 1980, new, seismically qualified PORVs were installed.
As part of this work the original PORV position indication limit switches and solenoid valves SV-8620 ASB were replaced'he new valves and switches were seismically and environmentally qualified to IEEE-323, 344, and 382.
5.2.1.1 Valve Two PORVs, PCV 430 and 431C, are provided in parallel on the top of the pressurizer to protect the Reactor Coolant System (RCS) against overpressure during the normal operating conditions.
System configuration is shown in Figure 5.2-1. The relief valves protect the RCS against pressure surges which are beyond the pressure limiting capacity of the pressurizer spray. These valves are set to open at 2335 psig and to operate to relieve RCS pressure below the setting of the pressurizer code safety valves which are set at 2485 psig. The PORVs have remotely operated block valves to provide a positive shutoff capability should a relief valve become inoperable. The electrical power for both the relief valves and the block valves can be supplied from an emergency power source to ensure the ability to seal the possible RCS leakage path.
The relief valves are also used during low temperature "water solid" conditions. The RCS low temperature overpressure protection system is activated whenever the RCS cold leg temperature is below 330oF but is not depressurized and vented'nder this mode, the relief valves are set to open at 435 psig.
The relief valves are 3" diameter air operated globe valves (Copes-Vulcan Model D-100-160) designed to meet ASME Section III, Class 1 requirements. These relief valves. are "normally closed" and are designed to fail closed upon loss of power or instrument air (spring to close; air to open) ~ The operating mode is open or closed (not modulating).
5.2.1.2 Piping The relief valve piping extends from the nozzle on the pressurizer to the Pressurizer Relief Tank (PRT) whose rupture disc is set at 100 psig. Two relief valves are installed in parallel.
A motor operated block valve is provided upstream of each relief valve. The relief valve piping originates at the 4" diameter nozzle on the pressurizer and reduces to 3" prior to the PORV block valves'rom the pressurizer nozzle to a flange on the downstream side of the PORVs the piping is Schedule 160, A-376 5 '-1
0 type 316 stainless steel. From the flange to an 8" header located outside of the pressurizer compartment the 3" piping is Schedule 40, A-106 Gr.B carbon steel. The 8", Schedule 40, A-106 Gr.B pipe then terminates at the PRT.
The piping from ments'~ the pressurizer nozzle to the relief valve outlet is designed in accordance with ASME Section III, Class 1 require-The design limits for this piping are 680o F and 2580 psig. The remaining relief piping from the outlet of the relief valves, including the header, is designed to meet ANSI B31.1 requirements with a design pressure and temperature of 600 psig and 650 F, respectively.
The relief valve piping is analyzed for dead weight, earthquake, thermal, and dynamic (thrust) loadings. The associated pipe supports are designed to withstand the above loadings.
5.2.1.3 Instrumentation and Control Under the normal operating conditions, the relief valves open whenever the RCS pressure exceeds the set pressure of 2335 psig.
The pressure controller energizes the solenoid valve, SV-8620A or B in the instrument air line and admits the air to the relief valve operator that opens the relief valve to relieve the RCS pressure. Once the RCS pressure decreases to the set pressure, the pressure controller de-energizes the instrument air solenoid valve, thereby venting the air from the operator and permitting a spring to close the relief valve.
Two sets of contacts from two pressure transmitters are provided in series in the logic circuiting for each relief valve. PT-429 and 430 provide contacts to PCV-430 while PT-449 and 431 serve PCV-431C. Because of the two out of two logic, the pressure controller energizes the solenoid valve only when both transmitters sense the RCS pressure over the set pressure. That is, sensing of RCS pressure above set point by only one transmitter does not open the relief valve.
A manual override is provided in parallel with the pressure transmitters to afford flexibility to open the relief valve regardless of the RCS pressure. This is accomplished by a three position (closed-auto-open) switch in the control room for each relief valve. When this switch is in "Auto" position, the pressure transmitters actuate the relief valve, as described in the first two paragraphs above, in the event RCS pressure exceeds the set point. Turning the switch from "Auto" to "Open" position opens the relief valve. Similarly, turning the switch to the "closed" position closes the valve.
Indicating lights for the relief valve position taken from valve stem limit switches are provided on the Main Control Boards 5 '-2
0 During low temperature conditions, the relief valves function as part of the RCS low temperature overpressure protection system which is activated manually from the control room. In this mode, the relief valves open whenever the RCS pressure exceeds 435 psig. The overpressure protection system is de-activated whenever the RCS temperature is greater than 330o F. An alarm is provided to alert the operator during plant heatup to disable the low temperature over-pressure protection system prior to inadvertent actuation of the relief valves. An alarm is also provided to alert the operator during plant cooldown to enable the system at the appropriate point.
5.2.2 Operational Sequence 5.2.2.1 Time History During the transient, one of the pressurizer PORVs, PCV-430, was used to reduce primary system pressure. The valve position vs. time is shown on Figure 5.2-2. The PORV was opened at 1007:30 and remained fully open for approximately three (3) seconds.
The PORV was opened a second time at 1007:49 and was fully open for approximately six (6) seconds. A third opening cycle began at 1008:44 and the valve was fully open for almost seven (7) seconds'he valve was opened a fourth time at 1009:10 and was fully open for less than five (5) seconds. An attempt was then made to close the valve and the valve left the open position.
Approximately two (2) seconds after beginning to close, the valve returned to the open position and remained there. When it was determined that the PORV had not closed, the Block Valve (MOV-516) closure was initiated with the Block Valve reaching a closed position approximately 40 seconds later at approximately 1010.
At approximately 1905 on January 25th the D.C. control fuses for the PORV solenoid valves were removed. This ensured that the solenoids were, without question, de-energized. The PORV did not change po'sition. The fuses were then re-installed.
On January 28th the PORV went closed by itself.
5 ' ' ' Significant Parameters Immediately prior to the first usage of the PORV (1007) the Reactor Coolant Loop (RCL) pressure was 1270.6 psig with a pres-surizer level of 9.45. During the first two PORV usage cycles the RCL pressure decreased and the pressurizer level increased until at'008 the pressure was 1064 psig and the level was 25%.
During the third and fourth valve cycles the RCL pressure continued to decrease, reaching a minimum value of 830 psig at 1010, after which it began rising. The pressurizer level during these cycles increased rapidly to greater than 1008 by 1010 'ollowing the third valve closure the pressurizer water temperature was 517oF and the steam temperature was 610oF. Based on pressurizer levels 5 '-3
e l
during the period of PORV operation the first two and probably the third valve cycle resulted in the valve inlet flow being primarily steamy In the fourth cycle and perhaps the third, the inlet fluid consisted of either steam with a transition to water or was entirely water.
5.2.3 Inspection and Repair 5.2.3.1 Valve After the plant reached cold shutdown, a visual inspection was done on the valve/operator assembly to attempt to determine the cause of the failure to close. Nothing unusual was noted.
The valve was then tested using an air manual loading signal to the PORV. The valve was manually stroked, starting to open with 62 psi of air and being fully open at 85 psi. The valve worked smoothly and the switches operated as required'educing the air pressure, the valve started to close at 60 psi and was fully closed at 40 psi. The valve was cycled manually. a number sticking of times with the same results, and no binding or was noted. The valve was then reconnected to the system and cycled from the Control Room. The valve and switches worked properly with no noted defects. The valve was cycled a number of times with no problems before it was disassembled for internal inspection.
With the valve disassembled and the operator separated from the valve body, an air regulator was connected to the operator.
The valve operator opened and closed with the same pressure reading that was obtained when the valve was assembled (62 psi to 85 psi to open and 60 psi to 40 psi to close). An inspection of the valve plunger and cage did not show any sign of sticking, galling or wear marks of any kinds An inspection of the valve actuator revealed the presence of several small pieces of teflon tape in the actuator air cavity. Nothing else unusual was noted on the actuator. The conclusion of the inspection is that the valve did not stick open or malfunction due to any internal defects or valve operator failure.
5.2.3.2 Piping The piping and pipe supports from the pressurizer to the PORVs and, from the PORVs to the downstream side of the 8" diameter header, were visually inspected'o problems were noted with the piping, and only minor items were noted on the supports.
None of the support discrepancies were attributable to the system operation and all supports were judged to be fully functional.
5 '.3.3 Instrumentation and Controls
~
The D.C. control fuses for PCV-430 were removed and re-installed to ensure the valve was not electrically held open. The valve did not close, indicating the problem was mechanical not electrical'he control board selector switch was checked and no problems 5 '-4
were found'hen the valve was stroked using a manual loading signal, the valve, solenoid valve, and limit was switches worked properly with no defects. Computer printout reviewed and found to be corrects The limit switch inputs to the plant computer were found to be reliable and correct.
The solenoid valve was carefully disassembled in the I&C shop and inspected for foreign material and wear. The solenoid valve internals were found to be clean with no signs of wear. inThe 5.2.4.
solenoid valve was reassembled and tested as described 5.2.4 Solenoid Valve 5.2.4.1 Solenoid Valve Description 5.2.4.1.1 Summary The air operator of each PORV is connected to a 3-way solenoid valve manufactured by Automatic Switch Company, ASCO model NP8316A74E, Form F (Ginna valve numbers SV-8620 A&B). This solenoid valve supplies air to the PORV actuator to open the PORV and exhausts air from the PORV actuator to close the PORV.
The solenoid valve is a pilot-operated valve which utilizes sensed internal pressure differential across the various connecting ports to close or open the required flow paths. For a normally closed solenoid valve such as this, with the solenoid de-energized, the supply pressure port is closed and the flow path is established between the PORV actuator and the exhaust port ~ With the solenoid valve energized, the exhaust port is blocked off and a flow path is established between the supply pressure port and the PORV actuator. The pneumatic installation schematic utilized in the PORV is such that during use of the low temperature over-pressure protection system, nitrogen flows to the PORV actuator through a direct-acting, 3-way solenoid valve (SV-8619 A&B) ~
The nitrogen exhaust, like the air exhaust, is vented through solenoid valves SV-8620 A&B. In the low temperature overpressure protection system installation the exhaust port of SV-8620 A&B was intentionally restricted external to the solenoid valve, to provide slow closure of the PORV. This was done to extend the valve cycle time during a low temperature overpressure tran-sient. This was necessary in order to assure availability of nitrogen from the accumulators for the specified duration of this transients While this restriction reduced the closure time as required for the low temperature overpressure protection system, it has now been determined that to it can result in failure to their direct-acting of the PORV close as described below. Due design, valves SV-8619 A&B are not subject to these same problems.
5.2.4.1.2 Solenoid Valve Operation The ASCO solenoid valve is a three way, diaphragm type, pilot controlled, normally closed valve. An assembly drawing of the valve is shown as Figure 5.2-3. The valve body has three openings 5 '-5
for attachment to the piping system. These openings are referred to as the "pressure", "exhaust", and "cylinder" ports. For the Ginna application, the pressure port is connected to the instrument air supply, the exhaust port vents to atmosphere, and the cylinder port leads to the PORV actuator through an intermediate normally open valve.
When the valve solenoid is energized, as shown in Figure 5.2-4, the solenoid core rises uncovering a small pilot port connecting the pressure and cylinder sides of the valve. This connection equalizes the pressure on both sides of the pressure side diaphragm causing it to return to its "open" position, allowing full flow between the pressure and cylinder ports. When the solenoid core rises so does the disc assembly, which covers a small pilot port leading to the exhaust port. This ensures that the exhaust side diaphragm has a pressure differential across it, which forces the diaphragm to move to a "closed" position. This precludes any flow out the exhaust port.
When the solenoid is de-energized, as shown in Figure 5.2-5, the solenoid core drops down closing the pilot port connecting the pressure and cylinder sides of the valve. At the same time the disc assembly moves down and uncovers a pilot port connecting the exhaust and cylinder ports. This causes the pressures of the exhaust port and the area between the cylinder side diaphragm and the'valve bonnet to begin to equalize. When the pressure on the "back" side of the diaphragm decreases such that sufficient pressure differential exists across the diaphragm, the diaphragm moves to the "open" positions Coincident with this, when greater than 10 psi differential exists between the pressure and cylinder port pressures, the pressure side diaphragm moves to the "closed" position. This results in the supply pressure being isolated and the cylinder side pressure being vented to atmosphere.
In the PORV solenoid valve installation, the exhaust port of the solenoid valve was restricted. This had no effect on the PORV's ability to open since no flow took place through the exhaust port when the solenoid valve was in the energized or "opening" mode When the solenoid valve was in the de-energized or "closing" mode the exhaust port was used to slow closure of the PORV by restricting the flow out of the valve actuator (through the cylinder port) ~ The solenoid was in this de-energized mode when the PORV failed to close Based on ASCO installation and maintenance instructions, restriction of the exhaust alone is sufficient to cause faulty valve operations The manufacturer's information states that the pressure and exhaust lines must be full area, without restriction, to insure proper operation of the valve. It is also stated that any type of restriction device in either of these lines may cause valve malfunction.
5 '-6
When the exhaust port of this type solenoid valve is restricted, the solenoid valve is subject to the interaction of several phenomenal If the pressure side diaphragm opens when the valve is de-energized, thus venting out the exhaust port, very little flow out the exhaust is achieved due to the small flow area.
In order to maintain this flow the pressure side diaphragm is only required to remain open approximately 6 to 7% of its full travels This position is very unstable in that the valve achieves sufficient pressure differential to reclose the diaphragm the position is approximately 6S of travel, or less. If the if diaphragm position is approximately 7% or more open, insufficient differential is established and the diaphragm will remain open.
Restriction of the vent port in combination with other effects such as foreign material, temperature, or pressure surges could further increase the likelihood of valve failure.
The exhaust port restriction was such that the actual vent area was less than 0.01 sq.in. With this size opening, the restriction requires only a very small piece of foreign material to completely block the vent path ~ Due to the method of operation of the solenoid valve diaphragms, a vent blockage would only be required to be momentary to cause a position shift of the diaphragms.
During the discharge of reactor coolant through the PORV, significant.
heating of the discharge piping and thus the enclosed area at the top of the pressurizer, took place. It has been shown ana-lytically that due to expansion of the valve body, an increase in temperature of a few degrees is sufficient to cause a 1%
movement of the solenoid valve diaphragm when the diaphragm is in a nearly closed position. This phenomena is sufficient to transform the solenoid valve from being marginally operable at a 6S open position to being inoperable at a 7S open position.
This action would be capable of maintaining the pressure size diaphragm in the open position should a cessation of vent flow or other transient cause the diaphragm to open.
The dynamics of the air system operation during a closing sequence was investigated. It was determined that if the PORV started to close and the vent port of the solenoid valve was rapidly blocked, the PORV actuator would continue to move toward the closed position before rebounding toward the open position and settling out at an intermediate positions This results in a pressure surge which can equal or exceed the air supply pressure to the solenoid valve. When this happens the pressure side diaphragm would re-open.
5.2-7
5.2.4.2 Solenoid Valve Inspection The ASCO solenoid valve is qualified to IEEE requirements for in-containment application per Automatic Switch Company procedures.
Following the incident, the solenoid valve was electrically cycled and it functioned within specification requirements.
It was subsequently disassembled for further inspection. Visual examination showed no damage on the valve internals. The solenoid valve was judged to be in proper working condition.
5.2.4.3 Solenoid Valve Cycle Testing To confirm the solenoid valve performance under cyclic operations, cycle tests were performed on the solenoid with internal pressure under various conditions. The first set of tests was to investigate whether capping the exhaust port of the valve could result in the supply pressure feeding into the actuator port in a normally de-energized mode. This was found not to occur. The second set of tests was to investigate the effect of a restricted exhaust port in the venting of the actuator in the de-energized mode.
The test showed that, as the exhaust port becomes increasingly restricted, the back pressure could build up significantly, to the extent that the minimum required differential pressure necessary to internally connect the actuator port to the exhaust port may not be available. In a third set of tests the solenoid exhaust port was restricted, the solenoid de-energized and allowed to begin venting. Then the exhaust port was further restricted.
This caused the pressure side diaphragm to re-open and all three solenoid valve ports were then interconnected at approximately supply pressure.
5.2.4.4 Conclusion The PORV depends on the solenoid valve to open and to close.
The investigation shows that proper function of the solenoid is essential for the PORV to perform its engineered function when challenged. The arrangement at the time of the incident, in which the vent port was restricted to achieve slow closure of the PORV, is suspect and can lead to the PORV failing to close. The presence of foreign material or the effects of temper-ature or pressure surges probably combined with the restricted vent port to cause the failures The testing showed the solenoid, and thus the PORV, did function properly as designed when the restriction was removed from the vent port of the solenoid.
Therefore, the restriction has been removed from the vent port and other means are being utilized to control the closure time to meet the low temperature overpressure protection requirements'.2.5 Modifications In order to remove the restriction from the solenoid valve, and still provide for slow PORV closure, a check valve has been installed in the line to the PORV actuator for each PORV. The disk in this swing check has had holes drilled in it which allow 5 '-8
the PORV actuator to vent at a controlled rate. The new valves were installed in the line between valves SV-8619ASB and the PORVs and the restriction was completely removed from the exhaust ports of valves SV-8620A&B.
In addition to the check valve modification, strainers are being installed in the air line ahead of solenoid valves SV-8620AEB.
During the installation of the new PORV air system check valves, the PORVs were cycled using the air system. This was required to verify the size of the holes in the check valve disks in order to get closure times approximately equal to 3 seconds.
Following completion of the installation, Ginna Station procedure PT-32.2, "Checkout of the RCS Overpressure Protection System" was used to verify valve/system performance. This testing included verifying that the system will open the PORV in less than 3 seconds and that the valve starts to open in less than 0.6 seconds.
The total cycle time (opening plus closing time) is also verified to be greater than 4 seconds. During the performance of the testing approximately 22 to 24 cycles of the PORVs were required thus providing repeated verification of the PORVs'bility to open and close as required.
5 '-9
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5.3 Pressurizer PORV Block Valve 5.3.1 Description A normally open pressurizer PORV block valve is installed upstream from each of the PORVs. These valves are remotely 'operated from the control room to provide a positive shutoff capability should a PORV become inoperable. Position indication lights for the motor operated block valves are provided in the Main Control Board. The electric power for the block valves is capable of being supplied from an emergency power source.
The design response time of the block valve (to go from open to close position and vice-versa) is 40 seconds. The pressurizer PORV block valves are 3" diameter, 1500 lb. rating, motor operated (Limitorque SMB-000-5 motor operator) gate valves manufactured by Velan Engineering.
5.3.2 EPRI Program Results (Block Valves)
At the request of utilities with pressurized water reactors (PWR's), the Electric Power Research Institute (EPRI) implemented a PWR Valve Test Program responsive to the Safety and Relief Valve Test recommendations contained in NUREG-0578, Section 2.1.2 and applicable clarifications provided in NUREG 0737, Item II.D.l.A. The objective of the EPRI PWR Safety and Relief Valve Test Program is to perform full scale operability tests on a set of primary system relief and safety valves representative of those utilized in or planned for use 'in PWRs The test conditions
~
were selected to envelope those conditions postulated to occur in PWRs. All of the relief valve testing and safety valve testing was completed in December, 1981.
During the Relief Valve testing performed at the Marshall Steam Station, testing of Block Valve models representative of some Block Valve models in PWR plants was performed. The Block Valve testing was performed by EPRI for utility information but was not part of the EPRI PWR Safety and Relief Valve Test Program performed to respond to NUREG's 0578 and 0737.
The EPRI Relief Valve testing at the Marshall Steam Station included testing of a Velan Block Valve model B10-3054B-13MS, drawing 88425/B. The Velan valve was a 3'nch nominal pipe size, 1500 lb. class valve which had a Limitorque SMB-00-15 model motor operator. The Ginna Block Valves are the same Velan valve model with a Limitorque SMB-000-5 model motor operator.
For the Marshall Steam Station testing, the Velan valve was cycled open and closed twenty-one (21) times during evaluation tests performed on nominal inlet conditions of saturated steam at approximately 2460 psia on opening and 2160 psia on closing.
In addition to the evaluation test cycles, the valve was cycled under similar conditions during supplementary testing. The 5 '-1
0 valve fully opened on demand and fully closed on demand for each evaluation and supplementary test cycle. The Ginna Station block valve was called upon to close once against a steam/water discharge at 830 to 1000 psig. The valve went fully closed on demand.
5.3.3 Inspection The PORV block valve (MOV-516) was visually inspected following its closure against flow from the open PORV. No irregularities were noted during the inspection which included the valve, the motor operator and instrumentation and controls. No internal inspection was performed on the valve/operator assembly nor was it deemed necessary since the valve functioned'roperly'
'-2
5 ' B Main Steam S stem 5~4~1 Description The following desription applies specifically to the "B" main steam system. The functional design of the "A" main steam system is. identical. The main steam system is shown schematically in Figure 5.4-2.
5.4.1.1 Steam Generator (Figure 5.4-1)
The steam generator is a vertical, U-tube, Westinghouse Series 44 model containing Inconel tubes.
Moisture separating equipment is located in the steam generator above the tube bundle to limit the moisture content of the steam to one fourth of one percent or less under all design load con-ditions.
The steam generator is designed for 2485 psig at 650 F on the primary side and 1085 psig at 600oF on the secondary side.
The steam generator produces 3.13 x 106 lb/hr of saturated steam at 755 psig (513.8oF) during 100 percent. plant loads The primary chamber. (including the tubesheet) and the secondary chamber are built to the 1965 edition of the ASME Boiler and Pressure Vessel Code "Nuclear VesselsSection III, Class A Vessels".
5.4.1.2 Piping (Figure 5.4-2)
From the B steam generator, a 30 inch OD, 1 ~ 25 inch nominal wall ASTM A155-65 Grade C55, Class 1 electric fusion welded pipe conveys the main steam through containment penetration 402 and subsequently into the intermediate building (IB). In the IB, the 30 inch line is joined with the steam line from the A steam generator into a single 30 inch header. From the header, a single 36 inch OD line conveys the steam through the turbine building to the high pressure turbine stop valves.
The B steam line piping from penetration 402 to the main steam isolation valve and check valve contains the following major branch connections:
- a. 1-6" steam feed to the auxiliary feedwater pump turbine (crossconnected with the A steam line),
- b. 1-6" line to the main steam power operated relief valve (valve II no. 3410) which discharges to atmosphere,
- c. 4-6" connections for the ASME Code safety valves, which discharge to the atmosphere,
- d. 1-1" steam feed line to the safety valve discharge temperature compensated supports.
5 '-1
- e. 1-3" bypass around the main steam isolation valve.
From the header, in the Intermediate Building, a single 36 inch OD line to the high pressure turbine contains branch connections for steam dump to the condenser, heating steam to the moisture separator reheaters, turbine sealing steam, steam to the condenser air ejectors, 1
and turbine flange heating.
The main steam piping from the steam generator to and including the header was designed in accordance with the ASA Code for Pressure Piping (B31 1-1955) and ASA B31 Case N-7 for 1085 psig F
at 600oF.
5.4.1.3 Valves The following valves are in the B steam line except for the condenser dump valves:
a ~ Power Operated Relief Valve (PORV), valve no. 3410 The power operated relief valve functions to relieve minor pressure transients in the steam generator to avoid lifting of the code safety valves and to provide a means of cooldown of the reactor coolant system when the condenser steam dump is not available.
The relief valve is a pneumatically actuated control valve with a capacity- of approximately 10 percent of the B steam generator normal flow. The pneumatic actuator is supplied with air from the instrument air system and by a controlled pressure nitrogen bottle backup system in the event. of a loss of instrument air. The relief valve fails closed on loss of air. A manually operated block valve (valve no. 3506) is provided for isolation of the PORV.
b ~ Safety Valves (SV), valve nos. 3508, 3510, 3512, 3514 Four ASME Code safety valves are provided on the B steam linc'ach inlet, 10 valve is a Crosby style HA-65 with a 6 inch inch outlet, and a size R orifice. One of the four valves has a set pressure of 1085 psig. The other three are set at 1140 psig. The four safety valves have a total combined capacity of 3 '9 x 10 lb/hr, which exceeds the total full power steam flow of the B steam generator of 3 '3 x 10 lb/hr.
C ~ Main Steam Isolation Valve (MSIV), valve no. 3516 The isolation or stop valve is provided to isolate the steam generator. The valve is a special design swing check valve manufactured by the Atwood & Morrill Company. The valve disc is held open against the normal direction of steam flow by a pneumatic cylinder. In response to a steam line isolation signal, the valve disc is automatically 5 '-2
released to close with the steam flow assisting closure.
- d. Check Valve, valve no. 3518 A check valve is provided in the B steam line to prevent backflow from the A steam generator to the B steam generator.
The valve is a swing check type with external counterweights and was manufactured by the Atwood 8 Morrill Company.
- e. Condenser Steam Dump Valves, valve nos. 3349, 3350, 3351, 3352'353'354'355'356 Eight condenser steam dump valves are provided for normal plant cooldown and to compensate for transient power mismatches between the steam generator and the main turbine. The eight valves have a total combined capacity of approximately 35 percent to 40 percent of the main steam flow.
The condenser dump valves are used for cooldown provided that vacuum is maintained in the condenser and one circulating water pump is in service. The condenser dump valve operation during normal plant cooldown is limited by the vacuum capability of the condenser steam jet air ejectors. These air ejectors are supplied with main steam and maintain design performance at steam pressures above 200 psig. Plant cooldown at steam pressures below 200 psig is accomplished using the steam generator PORV until primary side conditions permit the residual heat removal system operation.
5.4.1.4 Instrumentation and Control a., Instrumentation The steam system and steam generator are provided with instrumentation to monitor steam flow, pressure, and steam generator level.
b ~ Steam generator pressure control Steam generator pressure control is provided by the condenser steam dump (turbine bypass) valves, power operated relief (atmospheric steam dump) valve, and the code safety valves.
The condenser steam dump valves have three modes of control:
(1) manual positioning,(2) steam pressure, (3) reactor coolant T-ave. The manual positioning or steam pressure control modes are used for plant startup and cooldown.
The steam pressure control mode is also used for removal of heat during hot shutdown operation.
The reactor coolant T-ave and T-ref control mode is selected during normal plant power operations In this control mode the condenser dump valves are actuated by a partial loss of turbine load. The valves are modulated by an error 5 '-3
signal between T-ave and T-ref, where T-ref is the programmed set point for T-ave as a function of turbine load (first stage pressure). If an error signal exists and is great enough, a trip signal is generated which leads to reactor trip and rapidly and fully opens the steam dump valves.
The power operated relief valve has two modes of control, (1) automatic opening at, a preset, variable steam header pressure or (2) manual. During normal plant power operation the power operated relief valve is in the automatic control mode with a pressure selected below the set pressure of the code safety valves'rior to the January 25 incident, the power operated relief valve was in the automatic control mode with a set pressure of 1050 psig. The power operated relief valve is used for plant cooldown when the condenser steam dump valves are not available.
The four code safety valves are provided to prevent over-pressurization of the steam generator as required by the ASME Code.
C ~ Steam generator level control Steam generator level is controlled by a three-element feedwater controller which maintains a programmed water level as a function of load on the secondary side of the steam generator. The feedwater controller continuously compares actual feedwater flow with steam flow compensated by steam pressure with a -water level set point to regulate the main feedwater valve opening. Feedwater is pumped .
to the steam generators by two cons'tant speed electric motor driven feedwater pumps.
A reactor trip signal provides an override signal to the feedwater control system. Upon receiving the override signal, all feedwater valves fully open to insure the full supply of feedwater following a reactor trip and turbine trip. Another override signal closes the feedwater valves when the reactor coolant average temperature is below a preset temperature value or when the respective steam generator level rises above a preset value. Manual override of the feedwater control system is also provided.
5.4.2 Overfill Sequence of Events
- 5. 4. 2. 1 Time History Table 5.4-1 presents a chronology of steam generator overfill events. 'he table includes the steam generator pressure and level, and a reference to the primary side condition.
The sequence of events has been reviewed relative to Figure 5.4-3 pages 1 and 2 ~
5 '-4
Prior to 0925 the plant was operating at 100% power at steady state. At approximately 0928 the reactor tripped on low pressurizer pressure followed by automatic actuation of safety injection.
Both main feedwater pumps tripped and both motor driven auxiliary feedwater pumps started upon safety injection. At this time the "B" S/G level was approximately 11$ of the narrow range level. Both reactor coolant pumps were manually tripped at approximately 0929. The turbine driven auxiliary feedwater pump automatically started at 0929, and at 0932 the "B" motor driven auxiliary feedwater pump was manually tripped. The B steam generator main steam isolation valve was closed at 0940 and the turbine driven and "A" motor driven auxiliary feedwater pumps were manually tripped by 0948. At 0954 the B steam generator PORV was manually isolated by closing the block valve. The "B" S/G narrow range level indicator went off scale high at approximately 0955 indicating that the moisture separating equipment was beginning to fill with water. To control primary system pressure, the pressurizer power operated relief valve was cycled several times; the last time the valve was cycled it stuck open and primary system pressure dropped to its lowest value (830 psig) during the transient. The block valve was then closed and continued safety injection resulted in increased primary system pressure. Since the "B" steam generator power operated relief valve was isolated, it did not open at 1050 psig steam generator pressure. The "B" steam generator pressure continued to increase causing one safety valve to lift at approximately 1080 psig for the first time. Primary system pressure remained at approximately 1370 psig for several minutes and the steam generator safety valve lifted a second time at 1060 psig S/G pressure and a third time at 1055 psig S/G pressure. After the safety valve lifted for the third time the safety injection pumps were secured and primary system pressure quickly dropped.
S/G pressure followed primary system pressure and the safety valve lifted for the fourth time at 1035 psig The safety valve lifted a fifth time at 1030 psig. It should be recognized that
~
each time the safety valve lifted, it lifted at a slightly lower prcssure'his is discussed under the valve section of Inspection and Repair (5.4.3.3). At some undetermined time, both the steam generator and the main steam pipe completely filled with water.
5.4.2.2 Significant Parameters From the sequence of events, limits on the consequences of the steam generator overfill can be determined'he following sig-nificant conclusions can be made from the sequence of events.
a ~ The B main steam isolation valve was closed at approximately 0940 when the steam generator level was at 51% of the narrow range and remained closed during the remainder of the incident.
The fact that this valve and the turbine stop valves were closed at this time eliminates concern about moisture carryover to the high pressure turbine. The closed isolation valve also limits the extent of the main steam piping and support review due to the overfill condition.
5 F 4-5
b ~ The B steam supply valve to the turbine driven auxiliary feedwater pump was closed at approximately 0932 when the B steam generator level was at 31$ of the narrow range and remained closed during the remainder of the incident.
Since this valve was closed prior to the steam generator overfilling, water induction into the turbine driven auxiliary feedwater pump turbine is not a concern.
C ~ The block valve on the steam generator power operated relief valve (PORV) was closed at approximately 0954 when the steam generator level was at approximately 100% of the narrow range and remained closed during the remainder of the incident. Although the block valve was closed at the 100% narrow range level, the PORV was not subjected to liquid flow since the block valve was closed prior to the upper section (moisture separator section) of the steam generator being filled with water.
5 '.3 Inspection and Repair As a result of the tube rupture incident of January 25, the "B" steam generator and main steam line were both filled with water as< described in the overfill sequence of events in section 5 '.2 ~ Subsequent to the incident, inspections and repairs on components in the B main steam system were performed'he following system components were inspected and repaired as required.
5.4.3.1 Steam Generator A visual examination was performed on the upper steam generator internals. The inspection included the swirl vane assembly of the primary moisture separators, deck plates, and demisters of the secondary moisture separator to determine if waterhammer had occurred. No indications of waterhammer were found.
5.4.3.2 Piping a ~ Pipe A visual inspection was made inside and outside of containment of the "B" main steam line from the steam generator to the headers The purpose of this inspection was to identify any evidence of unusual pipe deflections and to determine if there was any support damage.
General observation of the pipe inside containment, outside containment and to and including the header did not indicate any unusual line motion. There was no evidence of crushed insulation, or cracked paint as would be expected if there had been a waterhammer or acceleration of accumulated water An Inservice Inspection Program of selected welds of the Main Steam Piping has been underway since 1974. The welds 5 '-6
examined on a regular basis are shown on Figures 5.4-4 and 5.4-5. Manual ultrasonic, liquid penetrant, magnetic particle and visual techniques are used in the performance of this examinations As a result of this incident, pipe welds at "design break locations" were radiographed and evaluated in accordance with the acceptance criteria of USAS B31.1.0-1967 and the data base already in existance from previous examinations.
No indications of defects were found. The pipe welds shown on Figures 5.4-4 and 5.4-5 which were radiographed are:
SMS 1001A MS 1001C SMS 1001P1 SMS 1001P MS 1001J MS 1001D
- b. Pipe Supports During the incident on January 25, 1982, the main steam line spring hangers outside con'tainment were pinned at approximately 1430. The temperature at that time was approxi-mately 400oF and the pressure was approximately 350 psig.
From this condition the line was cooled. It and flushed at a later date with the pins in place.
was drained A visual inspection was made of main steam supports.
Support locations are shown on Figures 5.4-6, 5.4-7, and 5.4-8. No indications of irregularities due to the overfill condition were found. Individual support inspection results are shown on Figure 5.4-9.
5.4.3.3 Valves and Other Components a ~ Valves The steam generator PORV, safety valves, and main steam isolation valve were reviewed to determine if these valves were subjected to outside of normal conditions. The review evaluated the valves with respect to two phase flow (see sections 5.4.2.2.a and 5.4.2.2.c). Only one safety valve was subjected to adverse conditions. All valves were in-spected.
The safety valve set at 1085 psi lifted five (5) different times during the transient. As previously noted, these lifts started at 1080 psi and each subsequent lift lift was ps'tin theleast at a slightly lower pressure with the last water one lift passed main steam line.
two phase at 1030 flow because of 5.4-7
There are two reasons for the decreasing set point of the safety valves:
l) Valves heat up as a function of blowing and the set.
pressure gradually drops off as the spring heats up.
- 2) When a safety valve passes two-phase flow, there is cycling or vibration because of the water in the mixture.
This cycling causes local yielding of the seating surfaces and consequently a slight reduction of area.
This yielding was noted by the Crosby serviceman and was repaired before the valve was placed back in service.
The inspection showed that the remaining valves were in good condition. All safety valves were cleaned and surfaces were lapped as part of normal valve main-tenance. The set pressure will be adjusted during startup.
Other Components Both the high pressure turbine and turbine driver of the auxiliary feedwater pump were reviewed to determine if these components were subjected to outside of normal condi-tions. The review evaluated these components operation with respect to the possibility of excessive moisture carryover (see section 5.4.2.2.a and 5.4.2.2.b). It was determined that both turbines had been isolated from the B steam system prior to moisture carryover. The high pressure turbine was disassembled and inspected as part of the normal scheduled maintenance.
5.4-8
TABLE 5.4-1 B STEAM GENERATOR OVERFILL CHRONOLOGY All events occurred on January 25, 1982.
Secondary Side B Steam Generator Primary Side Time Event Pressure Level Condition 0925 S/G "B" level deviation 880 psig Pressurizer pressure low alarm < 2185 psig 0928 Safety injection pumps 880 psig 118 NR Reactor trip on low auto start, A and B pressurizer pressure, motor driven aux. FW auto safety injection pump start, main feed-water isolation 0929 Turbine driven aux.
FW pump start 950 psig ill NR Reactor coolant pumps manual trip 0932 "B" motor driven aux. 880 psig 31% NR FW pump manual stop, isolate "B" steam supply to turbine driven aux. feedwater pump 940 "B" main steam isolation 790 psig 51% NR RCL system pressure valve closed at 1138.7 psig 0946 "A" steam supply to 760 psig 68% NR turbine driven pump aux'eedwater isolated 0948 "A" motor driven aux. 790 psig 77% NR FW pump manual stop 0954 "B" S/G PORV isolated 860 psig >100% NR 0957 Safety injection reset 990 psig >1008 NR 1010 >100% NR Minimum RCL pressure 830 psig 1017 "A" motor driven aux. 1053 psig >1008 NR RCS pressure at 1350 FW pQmp manual start psig 1018 "B" S/G safety valve 1080 psig >1008 NR RCS pressure at 1370 discharge psig 27 "B" S/G safety valve 1060 psig >1008 NR Pressurizer relief discharge tank high level alarm
~
TABLE 5.4-1 (Continued)
Secondary Side B Steam Generator Primary Side Time Event Pressure Level Condition 1029 .
"A" Motor driven aux. 1000 psig >100% NR FW Pump Manual Stop 1037 Safety injection 1040 psig >1008 NR Primary system pumps secured pressure reduced from 1370 psig to 930 psig 1038 "B" S/G safety valve 1055 psig >1008 NR discharge 1059 "A" motor driven aux. 930 psig >100% NR RCL system pressure FW pump manual start 966 psig 1107 Manual start and 940 psig >100% NR throttle one safety injection pump 1119 Safety valve discharge 1035 psig >100% NR 1122 >100% NR "A" RC pump started Safety injection pump >100% NR secured 1137 "B" S/G safety valve 1030 psig >100% NR discharge 1213 Manual start, then stop, one safety injection pump 1219 Manual start, then stop, one safety injection pump 1227 Manual start, then stop, one safety injection pump 1701 "A" motor driven aux. > 100% NR FW pump manually stopped 1840 "B" S/G level re- <1008 NR established NR = narrow range level
~ ~
STEAM OUTLET TO TURBINE GENERATOR DEMISTERS SECONDARY MOISTURE SEPARATOR SECONDARY MANWAY ORFICE RINGS UPPER SHELL SWIRL VANE PRIMARY MOISTURE SEPARATOR FEEDWATER RING FEEOWATER NLET ANTIVIBRATION BARS TUBE BUNDLE LOWER SHELL WRAPPER TUBE SUPPORT PIATES SECONDARY HANDHOLE BLOWOOWN LINE TUBE SHEET
~ '~ A PRIMARY MANWAY TUBE IANE BLOCK PRIMARY COOlANT OUTLET PRIMARY COOLANT INLET QZ SERIES 44 STEAM GENERATOR NOT TO SCAI.E 9189 FIGURE 5.4-1
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MAIN STEAM SUPPORT INSPECTION February 9, 1981 TYPE RESULTS MS-6 CONSTANT LOAD HANGER NO RECORDABLE INDICATIONS MS-7 HYDRAULIC RESTRAINT NO RECORDABLE INDXCATIONS MS-8 HYDRAULIC RESTRAINT NO RECORDABLE INDICATIONS MS-9 CONSTANT LOAD HANGER NO RECORDABLE INDICATIONS MS-10 VARIABLE SPRING HANGER NO RECORDABLE INDICATIONS OUTSIDE CV RESULTS MS-11 RIGID HANGER NO RECORDABLE INDICATIONS MS-12 RIGID HANGER NO RECORDABLE INDICATIONS MS-159 HYDRAULIC RESTRAINT NO RECORDABLE INDICATIONS MS-13 VARIABLE SPRING HANGER NO RECORDABLE INDICATIONS MS-160 HYDRAULIC RESTRAINT NO RECORDABLE INDICATIONS MS-14 VARIABLE SPRING HANGER NO RECORDABLE INDICATIONS MS-27 GUIDE NO RECORDABLE INDICATIONS MS-15 VARIABLE SPRXNG HANGER NO RECORDABLE INDICATIONS MS-28 GUIDE NO RECORDABLE INDICATIONS MS-146 HYDRAULIC RESTRAINT NO RECORDABLE INDICATIONS MS-148 HYDRAULIC RESTRAINT NO RECORDABLE INDICATIONS MS-16 VARIABLE SPRING HANGER NO RECORDABLE INDICATIONS MS-17 VARIABLE SPRING HANGER NO RECORDABLE INDICATIONS MS-147 HYDRAULIC RESTRAINT NO RECORDABLE INDICATXONS MS-31 GUIDE NO RECORDABLE INDICATIONS MS-30 GUIDE BOLT BENT*
MS-29 ANCHOR NO RECORDABLE INDICATIONS NOTES:
- This guide has six (6) bolts that are loose to allow the pipe to expand axially; one (1) of these bolts was bent from what appeared to be an original installation problem. This bolt was replaced.
FIGURE 5.4-9
5.5 Letdown Isolation During normal plant operation, reactor coolant letdown flow is drawn from Loop "B" cold leg upstream of the reactor coolant pump suction line through LCV-427 (see Figure 5.5-1) ~ This valve closes automatically when pressurizer level drops to 10.6%.
LCV-427 is located in containment inside the missile barrier and fails open upon loss of control power or instrument air.
The letdown flow then passes through the shell side of the regen-erative heat exchanger where its temperature is reduced by the charging stream flowing through the tube side. The three letdown orifices downstream of the regenerative heat exchanger limit the flow of the letdown stream during normal operation and reduce the pressure to a value compatible with the downstream piping design. 'etdown flow is controlled by remote manual operation of valves AOV-200A, AOV-2008, and AOV-202. These valves will automatically close when LCV-427 closes to prevent the of a steam bubble in the shell side of the regenerative formation heat exchanger. When one or more orifice valves are open, the letdown flow passes out of containment through containment isolation valve AOV-371 to the nonregenerative heat exchanger in the CVCS system.
A 600 psig relief valve (RV203) located downstream of the letdown orifice valves provides overpressure protection of the downstream piping'he relief valve discharges to the pressurizer tank (PRT).
relief If a containment isolation signal is generated during normal letdown operations, AOV-371 is automatically closed while LCV-427 and one or more orifice valves remain open, allowing pressure to build to the relief valve setpoint ~ This occurred during the transient resulting in relief to the pressurizer relief tank. To prevent this from r'eoccurring, a modification has been implemented so that a containment isolation signal is input to LCV-427. When LCV-427 receives a closure signal, the orifice valves AOV-200A, 200B, and 202 will also receive a closure signal, providing redundant isolation of the letdown stream from the relief valve.
5 ~ 5-1
ROCHESTER GAS AND ELECTRIC CORPORATION 42 ~ 33 ENG'EPT'TATION' l ~ fJ Cl DATE: OF I (3D I 6Q E JOB: MADE BY'I l(Q zo PpT CVC 5 aeo A Ko&
LSTOowQ oA.xV<CC 5 L,~liowM l lsdG WR~ 4oaP 6 P,CQ Cll48.Cl HC CQC5 discs~- Hx 5 IOQ l ~S I fOg uO't'ai M Co<TA<t4hhgmT Cowl'TA<W WC~T Figure 5.5-1
5.6 Effluent Monitorin S stem 5.6.1 Main Steam Radiation Monitors The main steam line monitoring system is designed to detect and quantify releases of radioactive material from the secondary system via the steam generator PORVs and safety valves. The system consists of a collimated energy-compensated Geiger-Mueller detector on each steam line that can be read locally or in the Control Room. These radiation detectors are designated on the Control Room monitor console as monitors R-31 and R-32 for the "A" and "B" steam lines, respectively. The system also monitors the PORV and safety valve positions for each steam line. Ualve position indication is recorded in the Control Room. A high activity alarm causes the system recorders to start and to maintain a time history of header activity and valve position. Releases can then be quantified by taking the product of the valve flow rate, the header activity, and the time during which the valves are open.
During the incident, a high setting of the alarm setpoint prevented the system from initiating an automatic continuous recording.
Although continuous data were not recorded, an Instrumentation and Control technician reported to the Control Room and manually interrogated the system at the console. Stored ten>>minute average radiation readings were obtained for both steam lines, for the period 0920-0950. The technician was not able to secure additional data before being called away from the Control Room shortly after 0950. Later attempts to retrieve the data were not successful due to a malfunction of the monitor at approximately 1308 on January 25 'he monitor malfunction is believed to have been due to a small smudge of dirt or residue which caused electrical leakage on a printed circuit board. No other signs of foreign substance were observed elsewhere in the system, indicating that it probably was not deposited during the incident.
The position indication for the safety valves did not provide a record of safety valve position during the post-event period.
A follow-up investigation showed that this had been due to inadequate adjustment. of new actuator rods installed on the valves. It was also determined that the steam generator PORU position indication was inoperable due to open sliding links on terminal blocks in the relay room. This condition did not affect the incident evaluation since the "B" steam generator PORV did not open.
Adjustments to both the monitor alarm setpoint and valve position indication system will be performed prior to startup. The alarm set points will be established at the lowest practicable detection level for the monitor, above normal background fluctuations.
5 '-1
5.6.2 Air Ejector and Gland Seal Exhaust Monitor (R-15)
The design and response of the R-15 monitor is detailed in Section 7.2.1. The R-15 alarm was one of the first indications of primary-to-secondary leakage during the steam generator tube rupture event, and continued to function properly thoughout the post-event periods 5.6.3 SPING Air Ejector and Gland Seal Exhaust Monitor (R-15A)
The SPING monitor (R-15A) is designed to detect and quantify an extended range of radioactivity releases from the secondary system via the air ejector and gland seal off-gas. A high activity alarm causes the system to provide a continuous readout and maintain a time history of releases. In addition, hourly averages of the monitor readings are automatically printed out daily regardless of alarm status. 'Section 7.2.1 provides a detailed description of the monitor design and response during the tube rupture event.
Hourly-averaged data from the SPING unit were used in conjunction with the R-15 monitor readings to quantify off-gas releases resulting from the tube rupture. Better time resolution in the SPING readings could have been achieved had a lower alarm setpoint been established for the monitor's middle range. This would have yielded data at 10-minute intervals. The alarm setpoints for SPING low, middle and high ranges will be reviewed and adjusted prior to startup to assure the continuity of 10-minute readouts over all monitor ranges.
5.6.4 Plant Ventilation Effluent Monitors Plant effluent monitors R-13, R-14 and R-10B are designed to monitor radioactive particulates, noble gases and radioiodine, respectively, in ventilation air being discharged from the Auxiliary Building. The response of these units is described in Section 7.2.3. The effluent monitors functioned properly throughout the tube rupture incident and provided important information regarding the timing and relative magnitudes of atmospheric releases due to the safety valve liftings.
5 '-2
5.7 Sum A Level Indicator All floor drains z.n containment drain to containment sump "A" which is located at the low point in containment, below the reactor vessel. The sump has two level indicators. Early in the incident (1400 hours on January 25) one indicator registered 9.5 ft while the other registered 5 ' ft At that time, all
~
actions were based on the higher reading. Although no water was removed from the sump, the readings at 0950 on January 26 were 7.5 ft and 5 ' ft, respectively. A comparison was then made between the inputs and outputs of the Sump A level indication SPEC 200 racks to determine the source of the discrepancy.
The problem was traced to one of the vertical scale indicators on the control board which was responding sluggishly due to static charge buildup on the cover. When discharged by a technician, the two indicators read 5.3 ft and 5.5 ft, respectively, which is within tolerance for the 30 ft instrument span. A static charge occasionally builds up on the clear plastic cover of an indicator, inducing an opposite charge on the indicator pointer and interfering with normal motion. This rather unusual occurrence can be avoided by periodically applying an antistatic spray to the indicator covers. Periodic application to indicator covers will be performed.
5 '-1
5.8 Safet In 'ection Pum 1C Following the safety injection signal at 0928:19.6, all safeguards equipment was activated't was noted that, although both safeguards trains were energized, the 1C safety injection pump was sequenced into bus 16 instead of bus 14, as had been expected'his difference in loading had no impact on the course of the incident or on the response to the incident. It is discussed here since evaluated following the incident.
it was The emergency safety features actuation system (ESFAS) at Ginna Station consists of control relays, electro-pneumatic timers, and a series of electrical and mechanical interlocks on each train. In general, Class IE loads are sequenced to their respective buses at five second intervals. The only exception is the 1C Safety Injection pump, which may be fed from either bus 14 (train A) or bus 16 (train B). To prevent closure of both circuit breakers, which would allow buses 14 and 16 to be paralleled, a series of interlocks are used. At present, these interlocks are configured as discussed in the Ginna Station FSAR, page 8.2-12a.
The timing relay in the train A sequencing circuit for the bus 14 circuit breaker and the timing relay in the train B sequencing circuit for the bus 16 circuit breaker are electrically interlocked so that only one can be energized. Therefore relay will time out and close its associated breaker.onlyIfone one relay energizes first and its instantaneous contact fails to open, the other relay will also energize, but in doing so, its instan-taneous contact will de-energize the first relay. Therefore only one relay times out and one breaker closes. The time settings of the two timing relays are different so that even in the event that both .timing relay interlocks failed to open (two failures),
one circuit breaker will receive a close signal first and block the other circuit breaker from closing'his scheme results in the random loading of the lC SI pump onto either bus 14 or 16. The design meets all criteria and guidelines applicable to a "swing pump" configurations In particular it assures that at no time are A and B trains paralleled.
The existing configuration has been fully reviewed for conformance with the FSAR Design Bases and for potential adverse effects on safety recorded system performance.-
A modification to establish a fixed loading sequence is currently under review, however, this modification will not be installed during the current outage.
5 '-1
6.0 ANALYSIS 6' Com arison of Plant Res onse with Previous Anal sis FSAR Section 14.2.4 qualitatively assesses the plant response to a single steam generator tube rupture and quantitatively assesses offsite doses. This section addresses plant response.
Offsite doses from the incident are discussed in Section 7.0.
The FSAR states that a rapidly falling pressure and level in the pressurizer will initiate safety injection (plant circuitry now requires only low pressurizer pressure to initiate safety injection) thereby tripping the plant. With no loss of offsite power, the air ejector will alarm. Plant trip will automatically shut off flow through the turbine and will bypass steam to the condenser'he design basis analysis assumes that the entire radioactivity contained in the primary system is transferred to the secondary side and that the affected steam generator is not isolated during a 4 1/2 hour cooldown periods It is noted that with steam dump to the condenser, the safety valves will not lift, but safety valves will dump to condenser. It lift if there is no steam is estimated that the initial primary to secondary leak rate through a double ended tube break is approximately 80.5 lbs/sec (which corresponds to approximately 843 gpm).
The actual transient was similar to that discussed in the FSAR.
The initial plant transient developed slower than the FSAR assumption in that overtemperature T turbine runback of 5S and manual load reduction to 70% power were accomplished between the time of initial control room indications at 0925 on January 25 and the occurrence of reactor trip at 0928:12. Safety injection occurred shortly thereafter. The "B" main steam isolation valve was closed at 0940. Steam dump to condenser was available until the condenser was secured at 1040.
As a result of B steam generator PORU isolation and continued safety injection, there were several releases through the "B" main steam safety valve and the primary side pressure was not reduced below the "B" steam generator pressure until about 1230.
"B" main steam safety valve lifting occurred despite steam dump to the condenser. While this did not result in exceeding the bases for the dose analysis, which is that all primary activity is transferred to the secondary side, it did result in the transient extending over a longer period of time than the nominal conditions evaluated in the FSAR.
6 '-1
6.2 Steam Void Formation The head region of the reactor, above the upper internals, contains approximately 300 cubic feet of free space which is normally filled with water. The rest of the reactor vessel, including the upper and lower plenums, core, downcomer and bypass regions, contain approximately 2180 cubic feet of free space, also normally filled with water. During normal power operation, the head region of the reactor operates at a temperature of approximately 595oF. Little bypass flow is provided to the upper head and, consequently, it operates slightly below Thot With the RCPs
~
tripped, convection between the fluid in the upper head and the upper plenum is limited. Hence, during cooldown on natural circluation, the upper head fluid temperature will cool down slowly and lag Thot. Depressurization of the RCS during natural circulation may saturate fluid in the upper head and initiate steam void growth. Figure 6.2-1 shows data for RCS pressure, head thermocouple temperatures, pressurizer level, and pressurizer surge line temperature for times between 0925 and 1025 on January 25, 1982. The calculated saturation pressures corresponding to the head thermocouple temperature and to the core exit temperature are also shown on the figure. The time period of the figure includes those times when void formation in the RCS may have occurred'xamination of the data presented on Figure 6 '-1 indicates that steam voids may have occurred at three times, approximately 0928, 0940 and 1010 as discussed below.
RCS pressure was intentionally lowered by opening the pressurizer PORV several times beginning at 1007 to reduce RCS flow through the tube rupture. When the PORV failed to close, RCS pressure was reduced to a minimum of approximately 830 psig. The saturation pressure in the head was over 1000 psig at the time A rapid rise in pressurizer level at 1009 and a sudden decrease in the head thermocouple temperature a short time later are indications of void formation in the head. As the PORV block valve was closed and the safety injection pumps reprgssurized the system, the head thermocouples cooled to below 530 F several minutes later. Cooling of the thermocouples probably resulted from cooler water returning to the head. Prior to the time of the PORV opening, core exit thermocouple temperatures indicated a saturation pressure of the bulk fluid circulating through the RCS substantially below the minimum pressure resulting from the PORV opening. No RCS radioactivity increases were noted which might be indicative of fuel failure. Therefore, it concluded that the core remained covered and adequately cooled is during the PORV opening.
At the request of RGSE, Westinghouse performed a series of calcula-tions to estimate the extent of voiding in the upper head which occurred during the PORV opening. The results of simple calcula-tions based upon an upper head energy balance, are presented in the following paragraph which provide gross estimates of the maximum volume of the upper head voids 6 '-1
Since the head region is effectively insulated, energy is removed from this region only by water which is displaced from the head as the vapor bubble expands'onsequently, the extent of voiding can be estimated from an energy balance between conditions in the upper head immediately prior to the PORV opening and saturation conditions at the minimum RCS pressure during depressurization.
Thermodynamic equilibrium has been assumed, although for rapid depressurizations, non-equilibrium phenomena may result in slightly more extensive head voiding'stimates of the extent of voiding in the Ginna vessel head are provided in Figure 6 without metal heat energy transfer during depressurization.
'-2 with and For the case with metal heat transfer, thermal equilibrium is conservatively assumed between the vessel head and head water.
It is expected that this provides an upper bound on the extent of voiding. The above assumptions lead to the conclusion that the head region ( 300ft3) was nearly completely voided's an alternative method of evaluating the steam volume in the head region which developed during the depressurization of the RCS, an attempt was made to analyze the rate of increase in pressurizer water volume during the void formation. Because of uncertainties in the time resolution of the pressurizer level indications, this method did not provide meaningful results.
However, net water input to the RCS (safety injection flow plus charging flow minus break flow) plus voiding of the reactor head could account for the observed change in pressurizer level when the level indication is corxected for the water density of the incoming cooler water. PRT level readings during the, PORV opening confirm that little or no water was released from the pressurizer.
Steam voiding may have also occurred in the head region early in the transient as the result of the rapid RCS depressurization and tripping of the reactor coolant pumps (RCPs) ~ Tripping the RCPs reduced coolant circulation to the head and slowed head cooling. A sparcity of head thermocouple data for the it first twenty minutes of the transient makes difficult to draw specific conclusions about void formation. However, RCS pressure at 0940 was below the saturation pressure corresponding to the head thermocouple temperature at 0948. RCS core exit temperatures were below the head temperatures at all times following reactor trip so the head fluid temperature at 0940 was probably not significantly less than the head thermocouple temperature at 0948 approximately one minute of reactor trip, RCS pressure
'ithin was below 1300 psig and the pressurizer level was at or near zero. Reactor head saturation pressure during normal power operation is greater than 1400 psig. These conditions, absent specific head cooling data, indicate a potential for steam void formation. Specific conclusions about void formation during this period cannot be reached without extrapolating the data further than is justified'
'-2
Throughout the tube rupture incident no indications of inadequate core cooling were observed. Reactor coolant system pressure was maintained substantially above the saturation pressure cor-responding to the bulk fluid temperature during the accident as shown on Figure 6 '-1 Void formation in the head region, during the period(s) that
~
it may have occurred, resulted in no detrimental effects upon core cooling and produced no increases in radioactivity concentration within the reactor coolant'
~ 2-'3
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6.3 Calculation of Leak Rate The primary to secondary leak rate has been independently calculated by several outside sources using pressurizer level change and system pressure change prior to reactor trip. The maximum leak rate calculated depends upon the assumptions used in the calcula-tions. Since pressurizer level and .pressure are affected by charging, turbine runback, steam dumping to the condenser and core power, all of which were changing prior to reactor trip, calculating the primary to secondary leakage is not a straightforward calculation. The leak flow rates calculated by RG&E consultants range from greater than 532 gpm to around 620 gpm.
The 532 gpm value was calculated based on the pressurizer level behavior prior to reactor trip. The 620 gpm value was calculated based on the rate of depressurization before reactor trip and sensitivity studies done for another 2 loop Westinghouse plant.
The Ginna FSAR gives a value of 80 ' lbs/sec ( 843 gpm) for a double-ended tube break. Current analysis for Westinghouse two loop plants with model 44 steam generators yields a value of 1065 gpm for a double-ended tube break.
Another method used to estimate the leak flow was to model the portion of the transient prior to reactor trip with the RETRAN computer program. The objective was to obtain a reasonable reproduction of the primary system pressure prior to reactor trip. Figures 6.3-1 and 6.3-2 illustrate pressurizer pressure, core power, and T-ave taken during the January 25 incident prior to trip. The RETRAN model was forced to reproduce core power and T-ave prior to trip as illustrated on Figure 6 '-3 ~ A leak flow was then determined which would reproduce a pressure response similar to that observed in the Ginna data. Figure 6.3-4 illustrates a comparison for pressurizer pressure calculated by RETRAN and Ginna data. Figure 6.3-5 illustrates the leak rate required to produce the RETRAN pressure response. The leak is assumed as a small constant leak area until t = -70 seconds (where
= 0 is the time of reactor trip). At this time the leak area t
is increased and remains at the larger area for the remainder of the transient. The small leak rate calculated by RETRAN is approximately 346 gpm ~ The leak rate changes to a maximum of approximately 601 gpm when the area is increased and then decreases throughout the remainder of the transient as primary system pressure approaches steam generator pressure. Thus, the maximum primary to secondary break flow is estimated to have been 601 gpm. Additional analyses are underway to confirm this estimate.
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6.4 Thermal Transient on Reactor Coolant S stem Westinghouse has performed an evaluation of the January 25, 1982 transient for the following regions:
- 1. Reactor vessel beltline
- 2. Reactor vessel inlet nozzle
- 3. Safety Injection nozzle For the beltline a detailed analysis was made assuming two extremes in fluid mixing between fluid in the cold leg and the safety injection fluid, i.e , perfect mixing and no mixing. For the
~
inlet nozzle, the evaluation was based on existing analyses performed on other plants again assuming two extremes in mixing.
It is judged that detailed analyses will confirm the conclusions drawn. The safety injection nozzle was evaluated by referring to a previous analysis that is applicable to this transient. The analyses followed the general methods outlined in WCAP 8510.'(1)
The results of the evaluation demonstrate that the January 25 transient did not impair the integrity of the regions evaluated; that is, no crack initiation or calculated large critical flaw sizes'he evaluations are summarized below.
6.4.1 Description of Transients Two sets of transients, corresponding to the perfect mixing and no mixing assumptions, were analyzed'oth used the same RCS pressure history and the same flow rate history. A full flow of 180,000 gpm was assumed with the reactor coolant pumps running and 7% of the total flow or 12,600 gpm was assumed with the reactor coolant pumps tripped. For the perfect mixing case, the measured cold leg temperature transient was used and for thy no mixing case, the temperature was ramped from 550 F to 60 F after the pumps were tripped'he actual case is expected to be between these two bounding cases'nitially, Safety Injection (SI) flow is taken from the Boric Acid Storage Tanks (BAST).
These tanks have a capacity of approximately 6000 gallons of 155 to 160 F borated water. When the level in these tanks reaches the low level setpoint, SI is automatically switched to the Refueling Water Storage Tank (RWST). The temperature of the RWST is estimated to be 60 to 70 F; therefore, 60 F was con-servatively used in the analysis'.4.2 Material Properties and Irradiation Effects Irradiation damage for the beltline was established by considering the USNRC Regulatory Guide 1.99 trend curve in conjunction with surveillance data obtained from 3 capsules. The trend curve used is illustrated in Figure 6.4-1. The dashed-line trend
.curve used in the analysis matched the Reg. Guide 1.99 curve for .23 wtR copper up to a shift value of 170oF after which
- 6. 4-1
it became presented horizontal in accordance with the surveillance data in Table 6.4-1.
The reactor vessel inlet nozzles were made of SA 508 C2 forgings and full Charpy curves were obtained for each of the nozzle forgings. Since drop weight test results were not obtained on these materials, the initial RTNDT was assumed to be 60oF.
This is expected to be very conservative because the material has very good toughness properties as evidenced by charpy curves (about 75 ft-lb at 10oF).
6.4.3 Results 6.4.3 ' Beltline The two cases (perfect mixing, and imperfect mixing) under con-sideration were subjected to different analysis assumptions.
The perfect mixing transient was analyzed at 9 EFPY (effective full power years) using the Regulatory Guide 1.99. No flaw initiation was shown to occur at 9 EFPY for this case. Con-servatively, the principle of warm prestressing was not applied.
The plant was at approximatly 9 EFPY at the time of the incidents Similarly, the imperfect mixing transient was also analyzed at 9 EFPY using the previously described modified USNRC Regulatory Guide 1.99 trend curve ~ No flaw initiation was found for this case. The emphasis in the extremely conservative imperfect mixing analysis was to remove any additional conservatisms that would be present. Therefore, to approximate reality as well as possible, the modified Regulatory Guide 1.99 trend curve and the principle of warm prestressing were employed.
It is therefore concluded that no flaw would have been initiated in the vessel belting region due to the transient that the plant experienced. Examination of Figure 6.4-1 shows that this conclusion would apply to end of life conditions'.4.3
' Inlet Nozzle As with the beltline region, both perfect mixing and imperfect mixing assumptions were applied, resulting in two different analyses. Unlike the beltline region, however, the exact transient was not used in the analysis because of time limitations in preparation of this report. 1nstead, use was made of previous analysea and conservative engineering judgments.
For the perfect mixing case, a previous analysis of a large steam-line break (LSB) transient was used to conservatively bound the January 25 incident. The analysis was carried out on a nozzle of essentially identical geometry, and leads to the conclusion that the critical flaw depth in the nozzle corner region due to the January 25 incident was greater than 1.4 inches.
6 '-2
For the imperfect mixing case, a different approach'was used.
The thermal analysis from a large loss of coolant accident analysis of a nozzle of identical geometry was used to estimate the toughness profile, since the injection water was 70 F in that case.
loadings and applied stress intensity factors were calculated The'ozzle from a detailed three dimensional analysis of another nozzle subjected to a large steamline break transient.
The result of the evaluation indicates that the critical flaw depth relative to propagation through the section thickness is greater than 1 9" A flaw size of greater than 0.75" depth
~ ~
would be required for crack extension to take place along the surface of the nozzle corner. The inservice inspection of this area in the past has shown the nozzle corners to be free of unacceptable ultrasonic indications. Therefore, no crack extension would have occurred during this transient.
a It is judged that detailed analysis on the nozzle will confirm this.
6.4.3.3 Safety Injection Nozzle The safety injection nozzle is fabricated of stainless steel, and" therefore fracture is not of concerns An analysis was carried out on this nozzle under full safety injection flow conditions in a previous report UNCAP 83212] and the nozzle was shown to be satisfactory'his previous analysis is applicable to the January 25 incident, and shows the nozzle integrity was not.
impaired ~
"Method for Fracture Mechanic Analysis of Nuclear Reactor Vessel Under Severe Thermal Transient" July, 1976.
2"A Summary Analysis of the Loss of the Loss of Offsite Power at the Robert E. Ginna Generating Station October 21, 1973, dated April 1974.
6.4-3
TABLE 6.4-1
SUMMARY
OF SURVEILLANCE CAPSULE RESULT R- E. GINNA Material Cu 30 ft-lb Temperature Shift After Fluence of (wts) 5.32 x 1018 n(cm2* 7.6 x 1018 n/cm2** 1.75 x 1019 n cm2*** Weld SA1036 0.23 140oF 165oF 150oF Forging 125P66VA1 0.05 25oF 25oF 35oF Forging 1255255WAl 0 '7 25oF ooF 00F
- Analysis of Capsule V from the Rochester Gas and Electric R. E. Ginna Unit No. 1 Reactor Vessel Radiation Surveillance Program", T. R. Mager et.al- Westinghouse Nuclear Energy Systems report FP-RA-l, April 1973.
** Analysis of Capsule R from the Rochester Gas and Electric R E. Ginna Unit No- 1 Reactor Vessel Radiation Surveillance Program", S. E. Yanichko et.al Westinghouse Nuclear Energy Systems
~
report WCAP 8421, Nov. 1974.
*** Analysis of Capsule T, to be published by S. E. Yanichko, April 1982.
A ~ f40,+ 1000 I/o Cu O.OB) + 6000 (% P . 8) ifI1019) 1/2
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t I, 2X101> 6 S 10'8 2 4 6 S 10'9 FLUENC E, num~ lE>>eeV) Figure 6.4-1 Irradiation Damage Curve Used for Beltline Fracture Analysis Compared with Regulatory Guide 1.99 $ 1). (Note surveillance results which are numbered)
6.5 H dro en Transfer Following the incident on January 25, 1982, samples of the faulted loop steam generator vapor space and the pressurizer vapor space indicated significant hydrogen concentrations. Samples indicated vapor space hydrogen concentrations of 1105 and 1578 cc of hydrogen per Kg of vapor in the "B" steam generator and the pressurizer respectively on January 29, 1982. As a result, analyses were initiated to determine whether these levels were to be expected given the pre-accident plant conditions and the characteristics of the incident. Prior to the incident, the reactor coolant hydrogen level was at 45-48 cc/Kg of coolant. Analyses were completed based upon this pre-accident level and considered the following parameters:
- 1) Blowdown of reactor coolant to the steam generator secondary side and to the pressurizer relief tank.
- 2) Dilution of the hydrogen in the reactor coolant by charging and safety injection flow.
- 3) Dilution of the reactor coolant blowdown by steam generator secondary coolant.
- 4) Atmospheric relief from "B" steam generator as well as initial steam flow to the condenser')
"B" steam generator water level variations.
The analysis did not consider the solubility of hydrogen in water as a function of temperature and pressure. Rather, varying fractions of hydrogen in the reactor coolant were assumed released to the vapor phase during and following the transients The results of these analyses indicate that the levels of hydrogen found in the pressurizer and "B" steam generator vapor space were well within the range that could be expected to occur with no additional hydrogen formation or introduction from other sources. The hydrogen concentrations in the "B" steam generator could result from release of hydrogen from the reactor coolant through the tube rupture. This conclusion is based on the specific Ginna incident characteristics and the pre-accident hydrogen levels in the coolant. It is also noted that there were no sources of oxygen to produce a mixture required for hydrogen deflagration. The lack of oxygen was confirmed during to the waste gas system via the pressurizer relief tank transfer which was directly monitored for oxygen. 6 '-1
6.6 Fuel Performance 6.6.1 Mechanical Design Considerations The chronology of events that occurred when the steam generator tube ruptured on January 25, 1982 has been reviewed with respect to possible effects on the fuel.. The data indicated that during the reactor trip, there was a rapid pressure drop (of 700 to 800 psi) in eight seconds or less. Later, between 1007 and 1010, about a 500 psi pressure drop occurred over two minutes. Radiochemistry levels remained essentially constant during the sequence, and the thermocouple readings at the top of the core were always below the saturation temperature. Exxon Nuclear Company (ENC), the fuel manufacturer, evaluated three potential areas of concern from these transients:
- 1) mechanical behavior of the cladding,
- 2) metallurgical behavior of the cladding, and
- 3) mechanical response of the fuel assembly.
Based on burst test information of irradiated Qconee and H. B. Robinson tubes (reference: "Evaluating Strength and Ductility of Irradiated Zircaloy, Experimental Data/Final Report," NURFG/CR-1729 BMI-2066, Vol. 1), the pressure decrease will generate a worst case pressure difference across the cladding of no more than 1200 psi, and most likely less than 500 psi. These pressures are not large enough to cause mechanical deformation'lso, the rate of pressurization is not important at these pressures. Because of the temperatures shown by the thermocouples and because of the low stresses generated, the metallurgy of the tubing would be unaffected. ENC postulated that the rapid pressure drop during the reactor trip could have resulted in a large pressure differential between the lower and upper parts of the core because of the more rapid decrease in pressure in the hot leg versus the cold leg. Kith this assumption, the potential exists that the resulting forces could cause the fuel assembly to move upward. However, the resulting movement would be slight and the loads on the fuel assembly well within those allowed during normal concludes that there were be no significant mechanical effects handling'NC on the fuel assembly. 6 ' ' Core Transient Considerations During the first few minutes of the incident, (approximately 9<28 a.m.), the reactor was still at approximately 708 of rated thermal power and the reactor coolant system pressure was falling. ~ System pressure dropped rapidly from about 1900 psig to about 1250 psig. This drop in pressure initiated high pressure safety injection and reactor trip. 6 '-1
To evaluate whether adequate margin to DNB existed during this time, a DNB calculation was performed by ENC for the following conditions: Core power 70% Core pressure 1200 psia Core inlet temperature 560oF Assembly radial peaking 1.5 These conditions reflect a conservative assumption that system pressure fell to its low value (hot leg saturation) before any reactor trip shutdown had occurred. Fop the above conditions, the calculated DNBR using the N-3 correlation was 2.63 'his result indicates a large margin to DNB, and thus no loss in clad integrity from an overtemperature condition. Subsequent to reactor trip, the reactor coolant pumps were manually tripped and cooling was by natural circulation. The various events and operational modes that occurred after coolant pump trip have not been analyzed by ENC, but natural circulation cooling of the core is an accepted mode of operation and will prevent excess cladding temperatures once a reactor has been tripped. 6 6-2
6' Steam Generator Overfill 6.7.1 Structural Analysis 6.7.1.1 Steam Generator Supports The original steam generator support calculations were reviewed to determine if the flooded steam generator caused the supports to exceed their original design loads. The original Gilbert Associates, Inc. (GAI) steam generator support calculations consider the steam generator being flooded as one possible loading case. For this condition, the total flooded weight of the steam generator including piping and miscel-laneous loads is given as 963.0 kips. This load would be shared by the four (4) steam generator lower support columns (approximately 240.7 kips per column)- The controlling loading case for the design of the lower support columns is a reactor coolant pipe rupture. For this condition, the maximum single column design load is 1433 kips. All four columns were fabricated to satisfy the controlling design load case. Therefore, the steam generator supports remain acceptable. 6.7.1.2 Piping The main steam piping from the steam generator to and including the header was originally designed for 1085 psig at 600oF in accordance with the ASA Code for Pressure Piping (B31.1-1955) and ASA B31 Case N-7. The B main steam line was analyzed in two sections. The first section of the analysis was inside containment -from the "B" steam generator to containment penetration 402. The second section of the analysis was outside containment from containment penetrations 402 and 401 to the main steam header; and then to the high pressure turbine stop valves. The piping/support system was evaluated with a three dimensional static model which included the effects of supports, valves and equipment. The static analysis employed the displacement method, stiffness matrix formulation and assumed that all components and piping behave in a linear elastic manners Three analyses were performed to evaluate the steam generator overfill and cooldown conditions. The deadweight analysis reflected a water 'solid condition from the B Steam Generator to main steam isolation valve 3516 in combination with a pressure of 1085 psig. The thermal analysis evaluated the thermal effects associated with a temperature of 555oF and the system filled with water. The cooldown analysis evaluated the portion of the piping outside containment with several of the variable spring cans pinned at 400 F; and subsequent cooldown to 70 F. Tables 6.7-1 and 6.7-2 summarize the maximum piping stresses for all three analysis conditions. Stress results reported 6 '-1
0 were obtained using ANSI B31 1 Power Piping Code, Summer 1973
~
Addenda, equations lland 13. This analysis was done to the applicable portions of the Ginna Seismic Upgrade Program Design Criteria transmitted to the NRC in a ll/4/80 letter from J.E. Maier to D.M.Crutchfield All piping stresses, both inside
~
and outside containment for all loading conditions, are below the allowable'.7.1.3 Pipe Supports After the overfill incident,'he B main steam piping was analyzed for the overfill conditions as described in Section 6.7.1 2. ~ The resultant loads on pipe supports were then evaluated. Pipe support loads from the piping analyses were used to calculate stresses in support components. These stresses were compared to the allowable values for the support component materials. These analyses showed that the deadweight loads associated with the steam generator overfill caused only one active support to be stressed over code allowable values. It was MS-12, a rod type hanger, located on a section of piping outside containment. The calculated deadweight load on this support was 29,370 lbs., compared with an allowable load of 15,000 lbs. on the pipe clamp; and 11,630 lbs. on the rod and turnbuckle. Since the allowable loads have a minimum factor of safety of 3.0 based on material yield strength, this support was not stressed over yield during the transients Subsequent visual inspection of the support components showed no evidence of damage The analyses showed that two (2) pipe guides were overloaded due to deadweight. loads'hey were MS-27 and MS-28 located on a section of piping outside containment. The analyses showed that the additional pipe deflection due to the weight of water caused the pipe to bear on the lower horizontal members of these supports; and stress them over allowable. Visual inspection of these members showed no evidence of deflection or damage. The analyses showed that one (1) spring hanger was overloaded due to the effects of the cooldown following its being pinned. This was MS-17 located on the section of piping outside containment. The deadweight plus thermal load on this support during the cooldown loading case was 37,524 lb' compared with a minimum allowable load for the support assembly of 15,000 lbs. Since the allowable loads have a minimum factor of safety of 3 0 based ~ on material yield strength, this support was not stressed over yield during the transients Subsequent visual inspection of the support components showed no evidence of damage. Finally, the analyses showed that the main steam header anchor bolts were stressed over allowable values. The bolts were stressed to 7,325 psi in shear and 41,335 psi in tension for the thermal analysis case. These stresses are a result of thermal loads 6-7-2
from the main steam piping both upstream and downstream of the anchor. The stresses are in excess of the allowable values for shear plus tensile loading. In addition, the stresses are above the minimum yield strength for the material. Therefore, these bolts will be replaced prior to plant startup. 6 '.1.4 Nozzle Loadings The B steam generator main steam nozzle loads are summarized in Table 6.7-3. Main steam isolation valve stresses due to nozzle loads are tabulated in Table 6.7-4. Allowable load and stress limits are stated in the criteria for the RGSE Seismic Upgrade Program (see letter to Mr. D. M. Crutchfield, of the NRC from J. E. Maier of RGE dated November 4, 1980). All loads and stresses are below the allowable limits. 6.7.1.5 Containment Penetration (No.402) A review was made of the original Gilbert Associates, Inc. (GAI) main steam pipe containment vessel penetration calculations to determine if the overfill load conditions experienced, exceed the original design loads for the penetration'he results of the review are summarized in Table 6.7-5. The original GAI main steam penetration calculations consider the penetration as being subjected to non-simultaneous loads resulting from a rupture of the main steam pipe. An analysis of the overfill condition was performed by Westing-house. This analysis treated the penetration as an anchor point for the main steam pipe. The results of this analysis predicted the most severe combined (from inside and outside the containment vessel) simultaneous loads applied to the penetration during the overfill condition. It is evident from the relatively small magnitude of overfill loads in comparison to the original design loads that the penetration was not severely stressed during the overfill condition. 6.7.2 Waterhammer Potential An evaluation of the thermal and hydraulic conditions in the B steam generator subsequent to the tube leak was made to aid in determining whether any conditions existed which could lead the potential for waterhammer or rapid local depressurization. 6 ' ',.1 \ Description The following is a description of the conditions required for .waterhammer to occurs Figure 6.7-1 shows modes of steam volume collapse. The numbers represent the conditions necessary for occurrence of the waterhammer 6 '-3
phenomenon. For example, depressurization by condensation requires two conditions: Condition 1 ~ A confined volume of steam; the confinement boundaries may be solid or liquid. Condition 2. A means of allowing subcooled water access to the confined steam. If the depressurization can act to accelerate the subcooled water flow rate, increase the turbulent mixing or in any way enhance the heat transfer of the subcooled water with the steam volume, then the depressurization may become quite rapid., The depressurization duration will correspond to the time required for the subcooled flow and" any other available flow volumes to fill the steam volume. At the moment the last volume of steam disappears there will be a positive pressure pulse associated with the deceleration of flow into the steam volume. If the deceleration rate is only the minimal one associated with the flow of the subcooled water then the positive pressure pulse may not even be observable. There are two circumstances however when the positive pressure pulse may reach high pressure. These circumstances are referred to as "slugging and snapping." Slugging or snapping could lead to waterhammer damage other's In addition to conditions l and 2 noted above, slugging requires: Condition 3. The presence of a volume of liquid with the low pressure steam volume on one side and; Condition 4. A "plenum region" on the The plenum region must be able to maintain a pressure level higher than that in the condensing steam volume so that a pressure difference can develop across the fluid volume noted in 3 above, thus allowing acceleration of a "slug" into the condensing steam volume. For the "plenum" region to act as described in condition 4 above it must either be open to a large high pressure gas volume or must be composed of saturated water which can flash to maintain near saturation pressure levels. if It may be noted that the slug is subcooled, its motion into the condensing steam volume may greatly enhance turbulent mixing at the steam volume-slug interface therefore increasing the condensation rate. The "snapping" mechanism involves somewhat different conditions: Condition 5. The presence of slow moving or stationary subcooled water separated from a higher pressure steam volume 6 '-4
by some type of vented obstruction. The steam will flow through the vent into the liquid, displacing some volume ~ While the steam bubble is still small, the steam flow rate through the vent may be larger than the condensation rate over the available steam-subcooled water interface The bubble would therefore grow until some critical area is reached when the condensation rate equals the steam mass flow rate into the bubble and the steam volume will start to collapse and, Condition 6. A "Plenum region" condition corresponding to Condition 4 above is met, i.e., there must be free access of a make up liquid or gas to the volume behind the collapsing bubble. If these conditions are obtainable, the motion of the interface enhances the condensation rate and results in a rapid collapse of the steam volume toward the initial steam source. 6 '.2.2 Evaluation Westinghouse has evaluated the data available for the RCS and S/G systems behavior during the first two hours following the tube leak to determine have been met. Three if the conditions described above could locations in the B main steam system were identified in which the potential for waterhammer could exist. These locations were:
- a. at the ruptured tube, be at the main steam outlet of the steam generator,
- c. at the main steam elbows nearest to the steam generator.
The following is a discussion which addresses the waterhammer potential at each locations a ~ Ruptured tube location if It appears that, the primary side temperature is sufficiently higher than that of the secondary side hot leg (where the tube leak occurred) the possibility of primary water flashing and then collapsing by condensation on the secondary side of the steam generator might be a concern. Such condensation, however, is usually considered to develop pressure pulses corresponding to "noise" pressure levels; that is, pressure levels which are not normally considered to cause adverse system effects. The fact that such conditions would only be possible over the few minutes between the tube break and the effect of safety injection (which reduces the primary temperature) lessens the concern. Another fact which mitigates the concern is that unless the excess thermal energy in the flashing primary water is sufficient to cause complete evaporation of the leak flow, the secondary side hot leg 6 '-5
would only see small vapor bubbles rather than a large volume. Complete evaporation of the leakage would require an excess primary temperature well above the saturation temperature in the steam generator. This condition did not exist; therefore, waterhammer did not occur. Main steam outlet Once safety injection was initiated, the measured "B" loop cold leg temperature started dropping and it may be assumed that the secondary side bulk fluid temperature in the steam generator also dropped to some degree of subcooling with respect to the pressure of the steam trapped between the S/G liquid level and the closed steam line isolation valve. Until the liquid level reached the steam outlet at the top of the S/G, 3 discussed it is apparent that conditions 1, 2, and above were met, however, either the subcooling was insufficient or the S/G liquid surface was too quiescent to allow depressurization due to condensation. Normally the liquid at a steam-liquid interface is very close to the saturation temperature of the steam and some type of turbulent mixing or spraying is required to initiate a pressure reduction due to condensation. Based on the pressure data, such a long term pressure reduction did not occur. However, when the S/G liquid level reached the main steam line, the type of flow disturbance which might be expected to start the depressurization can occur. Slugging phenomena time scales in a S/G are on the order of 100 msec so that it is possible an event could have occurred and not registered on the discontinuous pressure readouts available of the incidents What would prevent slugging at this time is the lack of condition 4 listed above; i.e., there is no high pressure plenum available in the lower regions of the S/G to replace the volume swept out by a hypothetical slug as the slug moves out into the steam linc'hus there was no slug motion toward the isolation valve. Main steam elbow Since there is approximately 1000 cubic feet of steam line between the isolation valve and S/G, it was possible that, once the overflow of liquid into the line starts, a fluid seal slug might occur at one of the elbows near the S/G so that steam between the slug and isolation valve could act as a pressure reservoir to propel the slug back toward the S/G. Development of such a slug seal would normally require steam line to be about half full of liquid which could occur in the elbows nearest the S/G only if the feedflow dyrlamic head was capable of maintaining a head of 1/2 D, approximately 15 inches. This would have required a liquid velocity of about 9 ft/sec. While such a velocity might easily be obtained with a high pressure plenum in the S/G and depressurization in the steam line, without the former 6 '-6
j the only velocity available is the S/G filling rate of about 6 inches/min which becomes 0.25 ft/sec in the steamline, a velocity which can sustain less than 0.1 inch elevation head. It has been concluded that the steam line was only filled by the slow filling of the safety injection, pressurizer depletion and auxiliary feedflow after the S/G was filled. Therefore, during the steam generator tube leak incident, waterhammer could not have occurred'
'.3 Effect of Boric Acid Ingress The effect of the ingress of reactor coolant into the steam generator through a failed tube has been. evaluated as to its corrosivity on the materials of construction of the B steam generator secondary side as well as the components in the B steam line up to and including the main steam isolation valve.
Components downstream of the main steam isolation valve were not affected due to early closure of the valve (see Section 5.4 ' ' ') ~ A list of secondary side materials was gathered from: 1) valve list, 2) materials specifications for the steam generator, and
- 3) steam systems design manual,. These materials are listed in Table 6.7-6.
The Inconel 600, Stellite 6 and Stellite 21 are normally exposed to boric acid solutions in the reactor coolant and would behave similarly in the post-leakage exposure. This is due to the preclusion of oxygen from the steam generator during the cooldown. Thus, only carbon steel required evluation of its corrosion resistance in the boric acid solution. During the tube leak and overfill incident, water samples were taken from the B steam generator. At 1230 on January 25, 1982 the boron concentration in the B steam generator was 1083 ppm. A peak boron concentration of 1747 ppm in the B steam generator was reached on January 29, 1982. By February 4, 1982, the B steam system and steam generator was flushed several times and the boron concentration in the steam generator was reduced to 2 ppmo Table 6.7-7 shows the corrosion rates for carbon steel at various temperatures in a 2500 ppm boron as boric acid. From the table it can be concluded that for the short time period the steam system contained a significant boron concentration (below the peak concentration of 1747 ppm), negligible corrosion occurred' The effect of boric acid on stressed carbon steel has been studied by Westinghouse with no cracking observed for any of the carbon steel specimens. In addition, the ingress of reactor coolant into the steam generator would not introduce any chloride into the steam systems. Therefore, no cracking nor significant corrosion 6 '-7
of carbon steel would occur due to the boric acid in the steam systems. The steam generator and steam lines were flushed with demin-eralized water prior to any lengthy exposure to air and prior to any heatup after exposure to air. This was done to eliminate the potential for the concentration of aerated boric acid in crevices which might result in higher corrosion rates. 6.7.4 Thermal and Hydraulic Effects on the Steam Generator An evaluation of the thermal and hydraulic conditions in the B steam generator subsequent to the tube leak was made to determine whether any conditions existed which could have affected the structural integrity of the steam generator internals. 6 '.4.1 Data Review A review of the data has been made to estimate the thermal and hydraulic conditions in Steam Generator "B" in the immediate post-leakage period. Figure 6.7-2 is a plot of the liquid level, temperature and pressure in the steam generator. Tem erature The thermal environment within the steam generator is shown on Figure 6.7-2. It is postulated that any low temperature water that may have entered the steam generator would tend to remain low in the tube bundle. The auxiliary feedwater from the indoor condensate storage tank that entered the steam generator would also be directed down from the feed ring by the is expected that the hotter water at saturated conditions J-tubes't was adjacent to the steam volume as the liquid level rose; thus it is believed unlikely that any significant amount of cold water was available to cause rapid depressurization or water hammer. (Refer to Section 6.7.2) Pressure Figure 6.7-2 illustrates the pressure in the steam generator in the post,-leakage period. For a brief period (10:10) the pressure in the steam generator was higher than the RCS pressure indicating reverse flow through the tube leak. Secondary pressure also remained above primary pressure after 1230. Li uid Level During the initial pre-trip period when the differential pressure between RCS and the steam generator was high, the flow from the leaking tube tended to compensate for the steam generator water shrinks The water shrink is expected since the normal frothing decreases due to decrease in steam production after reactor trip. As shown in Figure 6.7-2, the steam generator level decreased from approximately 608 to 6-7-8
about 11% during the first few minutes of the incident. The liquid level in the steam generator then rose from 11$ to the top of the steam generator at a very slow rate, 6 in/min. This rate of liquid rise would not create flow impingement forces of any significant magnitude on any steam generator internals. The flow rate of water through the dryers was low and no significant loads were imposed on these components. The dryers were subsequently inspected and no damage was observed (see Section 5.4.3). 6.7.4.2 Areas of Additional Review From the review of the thermal and hydraulic data above, three areas were identified for investigation. These areas were:
- a. potential for water hammer, be thermal and pressure differentials across the tubesheet and channel head, and
- c. effect of external pressure on the tubes.
The potential for water hammer was addressed in Section 6.7.2 above. The structural effects of the thermal and pressure diffe-rentials across the tubesheet and channel head are addressed in Section 6.7.4.3 and the effect of external pressure on the tubes is addressed in Section 6.7.4.4 6.7.4-3 Effects of Thermal and Pressure Differentials Across the Tubesheet and Channel Head From review of Figure 6.7-2, the maximum abnormal temperature and pressure differential across the tubesheet occurred at approx-imately 1009. The abnormal condition being the secondary temperature and pressure exceeding that of the primary. At 1009 the primary temperature was 260 F while the secondary was at 540 F for a differential of 280 F. Also at 1009 the primary pressure reached its lowest pressure during the incident of 830 psig while the secondary pressure was 990 psig for a differential of 160 psig ~ The effects, therefore, on the tubesheet and channel head which need to be considered are the secondary-to-primary P of 160 psi and the secondary-to-primary T of 280 F. This temperature difference is judged to be very conservative as it assumes the temperature above the tubesheet is about 540 F, a temperature corresponding to the saturation pressure inside the steam generator. More probably, the temperature above the tubesheet is less than .400 F due to the cooler water flowing through the leak during the primary to secondary leak phase. Any hot water from the 6 '-9
top of the generator near the steam interface that may have reached the tubesheet during the secondary to primary reverse flow phase have mixed with the cooler water thus, resulting in considerable temperature attenuation. The thermal transient is slow enough so that only the maximum steady-state 5T requires an evaluation. The most highly stressed region from the above conditions is the secondary face of the tubesheet. Since this is a steady-state thermal condition, the thermal stress is given by: z(i- ~) which, for SA-508 Cl 2 at. 550 F, yields gpss ps i To this must be added the stress due to the secondary-to-primary L P. The pea]c ligament stress due to the 160 psi is scaled to be less than: Q 254 p~i T The combined stress caused by the hT and hP is thus LLS ) 0 oops 'L As this is less than the minimum yield for the tubesheet material, deformations from this event were elastic and no detrimental consequence to the tubesheet is believed to have occurred. It, is also worthy to note that based on a 3Sm code allowable value, the margin is 1.78 (80,100/45,000) ~ If this margin were converted into hT and hP values, the corresponding values would be 285 psi vs. 160 psi and 499o F vs. 280oF. The conservative 280oF 5T will induce discontinuity stresses at this junction from the restraint to radial expansion of the shell provided by the tubesheet. A conservative analysis assuming zero rotation at this junction resulted in a maximum stress intensity of 87,900 psi. This is a secondary stress developed by the constraint, of adjacent material and is thus self-limiting." Local yielding and minor distortions can satisfy the conditions which cause the stress to occur and any significant detrimental consequence from one application of the stress is believed remote. Also, since this is a one-time event, fatigue is insignificant. 6.7.4.4 Effect of External Pressure on the Tubes From Figure 6.7-2 at approximately 1009, just before the lowest primary "B" loop cold leg temperature was reached, the RCS pressure 6 '-10
dipped lower that steam generator B secondary pressure. This secondary-to-primary ~P exerted an external pressure on the tubes'he differential magnitude being 160 psi, this pressure reversal would not collapse any tube in the bundle since the tubes are subjected to much higher pressure without detrimental effects during hydrostatic test of the secondary side of the steam generator. During hydrostatic testing the tubes would be subjected to an external pressure of 1085 psig with the primary side being at atmospheric prcssure'
~ 7-11
TABLE 6 '-1 STRESSES AT MAXIMUM STRESSED NODES INSIDE CONTAINMENT NODE 6 EO 11 STRESS EQ 13 STRESS 740 7590. 19055. 2000 7308. 8567. 570 7257. 8559 730 7220. '6572. 511 7027. 6792. 520 6979. 6498. 530 6978. 4165. 750 6956. 8963. 631 6728. 14118. 615 6621. 14006. 610 6642. 13952 600 6577. '2768. Allowable Stress 13700. 20550 All stresses in PSI
'OADING COMBINATIONS B31.1-11: Design Pressure + Deadweight Loads < SH B31 ~ 1-13: Maximum Thermal Loads < SA 6 ~ 7-12
TABLE 6 '-2 STRESSES AT MAXIMUM STRESSED NODES OUTSIDE CONTAINMENT NODE EQ11 STRESS EQ13 STRESS 5010 7950. 0 ~ 2150 7783. 735. 450 7758. 3199. 460 7636. 3215. 1105 6973. 5215. 1000 6051. 4008. 3000 7132. 3776 353 6251. '512
'llowable Sh=13700. Sa-20550.
All stresses in PSI LOADING COMBINATIONS B31.1-11: Design Pressure + Deadweight Loads < SH B31.1-13: Maximum Thermal Loads < SA 6 '-13
TABLE 6 '-3
SUMMARY
OF B MAIN STEAM LINE OVERFILL CONDITION STEAM GENERATOR NOZZLE LOADS ANALYSIS CONDITION Fx Fy Fz Mx My Mz Kips Kips Kips in-kips in-kips in-kips Deadweight -15 ' ~ 3 3 -55.3 159.8 1516.1 Thermal -18 ' 6 ' -27 ' -2856.2 -907.6 1368.6 Deadweight + Thermal -33.9 7.1 -27.7 -2911.5 -747.8 2884.7 Allowable Loads +120. +60. +60. +3050. +5500. +5500. 6.7-14
P TABLE 6 '-4
SUMMARY
OF B MAIN STEAM LINE OVERFILL CONDITION MAIN STEAM ISOLATION VALVE STRESSES DUE TO NOZZLE LOADS ANALYSIS CONDITIONS Max Torsion Psi 'ending Psi Psi Deadweight + thermal 13633. 2438. 1179. Allowable stresses 19425 12950. 12950 '
'-15
TABLE 6 '-5
SUMMARY
OF MAIN STEAM LINE B OVERFILL CONDITION CONTAINMENT PENETRATION NO. 402 LOADS ANALYSIS AXIAL SHEAR BENDING TORSIONAL CONDITION FORCE FORCE MOMENT MOMENT Kips Kips Kips in-kips Overfill 30 ' 4.21 5, 384 2, 720 Design 767.0 767.0 75, 600 68,000 NOTE: The overfill condition loads tabulated above are simultaneous loads, the design loads are non-simulaneous. 6 '-16
TABLE 6.7-6 WORK SHf ET *4
~ ~
tCSSlttONOUSC fOS55 b295 E COHPOSITON OF HATERIALS IN RGE STEAH GENERATOR,'ND SS Cl TED VALVING 5 PIPING Carbon Steel PERCENT OF ELEHENT PRESENT HATER IAL Ni Cr Ho Cu Co Fe Pb A-105-GRII 0.35 0)) 0.05 0.05 0.35 Rem. A-106-GAB 0.30 l. 06 0. 048 0.058 .1(min Rem. A-216-WCB 0.30 1.00 0.05 0.06 .60 0. 5;. 0.4.. 0.25. 0.5... Rem. O.'4 to 1006 to .50t) 0.91tP A-217-GRC5 0.20 0.7 0.05 o.a6 .6a O 5 0.1 ~ ~ Rem., A-283-GRC 0.06 0.05 0.2 A-285-GRC 0.30 0.8 0.04 0.2~t) .Rem A-302-GRB 0.20 1.151t 0.035 0.04 .150t) O.t56t A-307-GR58T 0.04 a. 05 A-5a8-GR2A 0.27 0'50th o.o25 0.025 .1) )) 0 50t. 0.$ 57t 0.05 Rem. A-516-GR70 0.28 0.035 0.04 .II53to . Rem. 1 ~5 t .1) )o 0.45' A-533-GRA2 0 035 0.0 Inconel 6008 163 1.0 0.015 0.5 72(min) 14.to. 1 0.5 6. to. 1 ellit Stellite 6 '.3 3 32 0. 3to6 Rem, Stellite 21 .25 0.6 0.6 3 27 Rem.
~ o +to
TABLE 6 '-7 Corrosion Rates for Carbon Steel at Various Temperatures in 2500 PPM Boron as Boric Acid* Temp op Deaerated Mg/dm -da mil/ r With M dm 1 PPM
-da 'il/ r Oxygen With M
7 PPM
/dm -day Oxygen mil r 70 0~7 0 '3 10 ' 1.9 100 0' 0 '4 5.5 1~0 38 ' 7 '
140 0' 0.06 82 ' 15 ' 500 3 ' 0 '4
- Per Westinghouse Testing 6 ~ 7-18
MODES OF STEAM VOLUME COLLAPSE 1,2 De ressurization Slugging 4 5,6 Snapping Depressuri zation Only
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6' Pressurizer Power' crated Relief Valve 6.8.1 Structural Analysis 6.8.1.1 Piping The system analyzed includes the relief line between the four-inch pressurizer nozzle and anchors PRH-1 and PRH-2 located outside of the pressurizer shield wall, including the 3/4 inch vent and thermal element connection. This analysis was done to the applicable portions of the Design Criteria for EWR 2512, Seismic Upgrade, transmitted to the NRC in a ll/4/80 letter from J.E. Maier to D.M. Crutchfield. A drawing of the piping analysis model is attached as Fig. 6.8-1. This piping system was analyzed for the transients necessary to adequately envelope the scenario. Specifically, this includes: (a) the initial valve discharge transient, (b) the pressurizer water fill transient, and (c) the water solid discharge transient. A time history analysis was performed on the defined piping/support sys'em incorporating a three-dimensional dynamic model which includes the effects of supports, valves and equipment. The dynamic structural solution is obtained using a modified predictor-corrector-integration technique and normal mode theory and assumes that all components and piping behave in a linear elastic manner. The peak pressure in the pressurizer relief piping system near the relief valve potentially could have been significantly higher than the design values for a very short time. This can occur when the water from the pressurizer reaches the valve. According to ANSI B31.1, the piping system is acceptable for occasional short operating periods at higher than design pressure, stress in the wall not exceed the if the calculated pipe does maximum allowable stress value in Appendix A, for the coincident temperature, by more than 20% during one percent of any 24 hour operating period. The pressurizer relief piping system has been shown to meet this stress criteria and is in compliance with the RG&E Seismic Upgrade Program under the various transients during and after the incidents. A listing of the highest stressed nodes as a result of all thermal hydraulic thrust transient loadings is provided in Table 6.8-1 ~ 6.8.1.2 Pipe Supports The pipe supports, including hydraulic snubbers, sway struts, and rxgid supports on the pressurizer relief piping from the pressurizer to the 8" diameter header located outside of the pressurizer compartment are designed in accordance with the requirements of ASME Section III, subsection NF- The pipe supports were originally designed to withstand the deadweight, thermal expansion, earthquake (SSE) and dynamic (due to the system operation) loadings acting simultaneously. These supports were evaluated and found to be adequate to withstand the thrust 6.8-1
loads imposed during the incident, the original dead weight thermal expansion, and SSE loads all acting simultaneously. The loads were combined by the "square root of sum of squares" methods 6.8.1.3 Nozzle Loadings The nozzle loads for all the valves in the piping system have been shown to meet the applicable limits stated in the referenced Design Criteria'he maximum nozzle loads for the pressurizer PORVs as a result of all relevant thermal hydraulic transients (see Section 6.8.1.2) are tabulated in Table 6.8-2. The nozzle loads for the 4" relief line pressurizer nozzle have been shown to be acceptable and are tabulated in Table 6.8-3. 6.8.2 Qualification 6.8.2.1 EPRI Program Results (PORVs) At the request of utilities with Pressurized Water Reactors (PWRs), the Electric Power Research Institute (EPRI) implemented a PWR Valve Test Program responsive to the Safety and Relief Valve Test recommendations contained in NUREG-0578, Section 2.1.2 and applicable clarifications provided in NUREG-0737, Item II.D.l.A. The objective of the EPRI PWR Safety and Relief Valve Test Program is to perform full scale operability tests on a set of primary system relief and safety valves representative of those utilized in or planned for use in PWRs. The test'onditions were selected to envelope those conditions postulated to occur in PWRs. All of the relief valve'testing and safety valve testing was completed in December, 1981. The EPRI Relief Valve Testing included tests of a Copes-Vulcan Relief Valve which is representative of the Copes-Vulcan Power Operated Relief Valve (PORV) used in Ginna. The EPRI test valve and Ginna Copes-Vulcan PORV model are 3 inch nominal pipe size globe valves with a 316 stainless steel with stellited plug and a 17-4 PH cage. The valve operator is model D-100-160. EPRI tests on the Copes-Vulcan valve were performed at the Marshall Steam Station during Phase III of the Wyle Test Program. For the Marshall Steam Station testing, the Copes-Vulcan valve was cycled open and closed eleven (ll) times during evaluation tests at nominal inlet conditions performed with saturated steam at approximately 2460 psia on opening and 2160 psia on closing'n addition to the evaluation test cycles, the valve was cycled under similar conditions during supplementary testing. The valve fully opened on demand and fully closed on demand for each evaluation test cycle and supplementary test cycle. For the Wyle testing, the Copes-Vulcan valve was cycled nine (9) times under the following test conditions: 6 '-2
a full pressure (approx. 2700 psia) saturated steam test six full pressure (approx. 2500 psia 2700 psia) and reduced pressure (approx. 675 psia) water tests at both saturation and sub-cooled conditions. a full pressure (approx. 2500 psia) saturated steam-to-saturated water transition test. a reduced pressure (aprox. 1530 psia) nitrogen-to-water test. The Copes-Vulcan valve fully opened on demand and fully closed on demand in each test Following test completion, the valve was disassembled and inspected by the Copes-Vulcan representative. No damage was observed that would affect future valve performance. 6.8.2.2 Comparison with Transient The tests done as part of the EPRI Relief Valve Testing resulted in a total of twenty (20) test cycles. The testing was done at pressures ranging from 2700 psia to 675 psia and included steam, water, and steam to water transition tests'uring the tube rupture incident, the Ginna PORV was subjected to four (4) cycles. The pressure during the transient ranged from 1285 psia to 830 psia. Fluid conditions included steam, water, and probably a steam to water transient. The Ginna transient conditions were enveloped by the EPRI test program. The EPRI results were the successful opening and closing of the valve during all tests and no damage to the valve was observed following the testing. At Ginna the valve successfully opened and closed three (3) times and was inhibited from doing so a fourth time due to the failure of the air supply solenoid valve to vent the valve operator. At Ginna, as in the EPRI testing, no damage was observed on the valve following its use. The results of the Ginna transient are thus in agreement with the results of the EPRI testing in that the valve itself was fully capable of performing its intended function with no resulting degradation. 6 ~ 8-3
TABLE 6.8-1 Maximum Stressed Nodes Due to Thrust Loadin Pressure (PSZ) Node 4 Stress* B31.1-11 B31.1-13 B31-1-12 (Max. Thrust) 2040 3209 3763 4479 16987 222 364 667 2014 16155 150 3505 4796 5649 15976 212 364 584 1237 12869 1100 3505 4405 7839 12710 2015 3209 4407 3056 12328 206 364 729 1314 12254 2010 3505 4429 3062 12250 O4 364 711 1487 11791 1105 3209 4384 7823 11788 120 3505 3824 6222 11561 Allowable 16600 24900 19920 .* Based on design pressure Loadin Combinations B31-l-ll: Design Pressure + Deadweight Loads < Sh B31.1-12: Design Pressure + Deadweight
+ Thrust Loads < 1.2 Sh B31.1-13: Maximum thermal loads < Sa 6 ~ 8-4
TABLE 6 '-2 Maximum Nozzle Stresses for Pressurizer Power 0 crated Relief Valve (PSI) PCV-431 PCV-430 Allowable Maximum Principal Stress 15000 12292 15,500 Maximum Shear Stress 4791 3873 104 333 Maximum Bending Stress 8467, 7131 10, 333 Maximum Torsional Stress 3354 1324 10,333 TABLE 6 '-3 Maximum Nozzle Loads for 4" Relief Line Pressurizer Nozzle (K3P3) (IN-KIPS) FZ MZ Deadweight 0.95 0 '7 0 '2 0-5 . 0' 2 ' Maximum Thermal 0 '5 0.20 0 '3 23.1 18.5 23.2 Maximum Thrust 2.47 2.52 10.68 20.7 45.9 7 ' Allowable 10.00 12-00 12.00 70.0 117.0 117.0 6 '-5
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6.9 Plant Water 1nventor The plant water inventory has been assessed to assure that within instrument accuracies no unexplained water transfers took place during the transient. Water input to the primary system was balanced against losses from the system and against makeup needed for shrinkage during system cooldown ~ Losses from the primary system went to the pressurizer relief tank (PRT), containment sump A, and B steam generator. Shrinkage of water in the reactor coolant system and steam generators was also evaluated as a loss against system input. 6.9.1 Reactor Coolant System Inventory Inputs to the primary system were from the two boric acid tanks and from the refueling water storage tank (RWST). The boric acid tanks contributed approximately 4300 gallons assuming the two 3600 gallon tanks were reduced in level from approximately 70% level to the 10% level where automatic switchover to the RWST takes place. (The high level alarm setpoint is 75't ) ~ Operator readings of the RWST control board indicator for RWST level before and after the transient were 94%, and 82% respec-tively. Each percent change in level corresponds to 3,425 gallons (reference 6.9.1). The 12 percent change in RWST level corresponds to approximately 41,000 gallons. Total input to the primary system from the RWST and boric acid tanks was approximately 45,300 gallons or 378,000 ibm. The chemical and volume control system (CVCS) tank levels at the beginning and end of the transient were approximately the same indicating no net CVCS inputs A second method for determining the input to the RCS is to integrate the flow of the pumps adding mass to the system (safety injection and charging)- For convenience of calculation, the period of interest (0922 to 1235) has been broken down into shorter time periods as given below. Charging input was calculated using flow values (Computer ID numbers F0128 and F0134) integrated over four periods: Time Volume, al Mass, ibm 0922-1004 0 0 1004-1045 1970 16,000 1045-1110 1750 15,000 1110-1235 3000 25.000
~~
Total Charging Input 56,000 Safety injection input was calculated using pump performance data (Reference 6.9.2 and Figure 6.9-1) and the indicated RCS pressure, and the resulting flows were integrated over the periods of safety injection. The resulting input to the RCS was: 6.9-1
Time Volume, al Mass, ibm 0930-1037 33,940 283,000 1107-1135 3,300 27,000 1200-1235 2i200 19,000 Total SI Input 329,000 From 0930-1037 the SI pumps were operating at full flow. However, from 1107-1135 one pump was operating throttled back to approximately 30% of full flow. This 30% flow rate is an estimate based upon operator experience with manually throttling a valve. The throttling was performed to control pressure and the flow rate could vary by 508 of the assumed flow rate. This variance is also estimated by the operator based upon his experience with the system. From 1200-1235 one pump was started and stopped three times to raise the pressurizer level. To calculate the resulting flow assumed that the change in pressurizer level was due completely it was to the SI flow. There were three changes to the level, totaling a 49% change which corresponds to 19,000 ibm. The integrated flows from the SI and charging pumps total 385,000 ibm (56,000 ibm + 329,000 ibm) ~ This compares well with he 378,000 ibm input calculated using tank inventories. The change in RCS inventory has been evaluated for the period from 0922 to 1235 to determine how much of the mass added to the RCS was transferred to other systems. The conditions of the RCS (temperature and pressurizer level) were determined at several times before, during and after the event. Using a total RCS volume of 6054 ft and pressurizer volume of 800 ft3 (drawing 33013-1225), the total mass of water in the RCS at these times can be calculated as indicated below. The intermediate times of 1045 and 1110 are evaluated so that mass transfers during these time intervals may be calculated'ime RCS Tem oF PRZR Level 8 RCS Mass ibm e 0922 72oF (T-ave) for loops 47 255,000 650oF for pressurizer 1045 440oF (Exit T/C) 100 314,000 1110 450oF (Exit T/C) 100 312,000 1235 370oF (Exit T/C) 75 321,000 Change in Inventory 0922 1235 66,000 Note that only the change in RCS mass during the time intervals is important'herefore, the core exit thermocouple temperature is an acceptable measure of changes in RCS temperature because of the low decay heat 75 minutes after trip and the small dif-ferential temperatures around the loop. The inventories calculated 6.9-2
at 1045 and 1110 have assumed full RCS and may be in error if steam voids existed in the a system at this time. Paths through which RCS inventory was lost were the pressurizer PORV and relief valves on the letdown and reactor coolant pump seal return lines'll these paths direct flow to the pressurizer relief tan'k (PRT). Mass lost through'hese paths raised the PRT level, burst the rupture disc, and spilled to the containment sump. Additional water vapor released from PRT into containment was probably condensed in the containment fan cooler units and subsequently drained to the sump. The level of the 6,000 gallon PRT was raised from 69% to a final reading near 90%. The change in tank level corresponds to approximately 1,300 gallons. During the event containment sump A was evaluated to contain between 2,000 and 11,000 gallons because of different instrument readings. After the incident approximately 1,320 gallons were pumped out. Thus, the total mass loss to the PRT and sump was 2,620 gallons or 22,000 ibm. The change in reactor coolant system inventory between 0922 and 1235 of 66,000 ibm and the system loss to the PRT of 22,000 ibm leave 297,000 ibm (385, 000 input 66,000-22,000) which must have been transferred from the RCS to the B steam generator through the ruptured tube. The mass lost through the tube rupture can be calculated using the inventory values above for each time period as follows: (all amounts as ibm) Time 0922-1045 1045-1110 1110-1235 Beginning RCS Inv 255i000 314,000 312,000 Additions SZ 283,000 0 46, 000 Charging 16,000 15, 000 25, 000 Subtotal 554,000 329,000 383,000 Loss Flow to PRT 22 000 Ending RCS Inv 314i000 312,000 321,000 Subtotal 336, 000 312, 000 321,000 PO Ruptured Tube Flow 218,000 17,000 62,000 6.9.2 B Steam Generator A water inventory balance can also be calculated for the B steam generator. Sources include the main feedwater system, the B 6 '-3
Auxiliary Feedwater Pump (B AFWP), the Turbine Driven Auxiliary Feedwater Pump (TDAFWP), and flow from the RCS. Losses include main steam flow, steam dump to the condenser prior to closing the B Main Steam Isolation Valve (B MSIV) and losses through the steam line safety valve. Main Feedwater flow was terminated by pump trip at 0928:22. Main steam flow was terminated by turbine stop valve closure at 0928:13. Feedwater flow at normal conditions (6.26 x 106 lb/hr) would have exceeded the main steam flow by approximately 16,000 ibm for these nine seconds. However, the feedwater control system would have reduced feedwater flow to the steam generator because of the tube rupture flow in an attempt to maintain steam generator level. Integrated tube break flow up to 0928 (see Section 6.3) is approximately 2,000 gallons or 12,000 ibm. Thus, a net input of 4,000 lb for the combined main steam and feedwater systems is assumed. The steam dump valves which transferred mass from the B steam generator to the condenser were open approximately 16 valve-minutes prior to closure of the B MSIV, or during the time 0927 to 0939. The duration of the openings were obtained from the computer alarm printouts which have times recorded only to the nearest minute The total opening times may be in error by 50% because of repeated cycling of the valves. Each valve is rated at 302,000 lbs/hr at a steam pressure of 695 psig. During the period of 0927-0930 when all eight valves were open for some time, both steam generators had steam pressures of approximately 940 psig ~ The mass lost from the B steam generator would then be: 302 ibm x 16 HR x 940 x HR 60 695 1/2 ~ 47, 000 ibm The B AFWP and the TDAFWP both supplied water to the B steam generator during the first 3 minutes of the event. At approximately 200 gpm for each pump, the total mass supplied is 10,000 ibm. Steam flow from the B steam generator to the TDAFWP for the 3 minute period was negligible and is neglected. Another loss that must be considered is flow through the steam generator safety valve. It has been estimated (see Section 7.2) that the safety valve was open for a total of 2 minutes; 45 seconds total relief time are assumed to have occurred at 1018, 1027 and 1037 and 75 seconds total relief time are assumed for the 1119 and 1137 openings'elief times for the first four valve openings have been assumed to be 15 seconds each (60 seconds total) for calculational purposes consistent with Section 7.2. Based upon a rated capacity of 1 37 x 104 ibm/minute,
~
these relief times result in mass releases of approximately 10,000 ibm and 17,000 ibm respectively for the 0922 to 1045 and 1110 to 1235 periods. Using the mass transfers identified above, changes in the water inventory of the B steam generator for the time periods indicated would be as follows: (all amounts as ibm) 6 ~ 9-4
Time 0922-1045 1045-1110 1110-1235 Total (0922-1235) Additions From RCS 218,000 179 000 62,000 297,000 AFWP's 10,000 10,000 Main Feed- 4,000 4,000 water Losses Steam Dump (47,000) (47,000) Safety (10,000) (17 000) (27,000) Valve Net Addition 175,000 17,000 45,000 2374000 As a result of the tube rupture, the B steam generator and B main steam line were filled with water (see Section 5.4). The design condition for the steam generator (FSAR Chapter 10) in its original configuration is a steam space of approximately 2900 fthm. Modifications to the steam generators in 1975 removed the downcomer resistance plate. Itresult, is expected that this increased the recirculation ratio and, as a raised the average fluid temperature around the tube bundle and increased the steam void volume in the generators. A steam space volume of 2900 ft will be assumed may be increased upon for the completion steam generator of analyses although which take this volume into account the effects of the increased recirculation ratio. The volume of the steam pipe from the steam generator to the MSIV is 1,055 ft3 (drawing 33013-1225). The temperature of the water transferred from the RCS through the ruptured tube varied from approximately 550oF (TAVE at trip) to approximately 370 F (core exit TC at 1235). An average temperature of 500 F 020 ft /ibm) will be assumed. The ft3 space volume of 3,955 mass of water required to (2,900 plus 1,055) is 198,000 ibm. fill ( ~ the steam This space was initially occupied by saturated steam at approximately 800 psia (.57 ft3/ibm) or 7,000 ibm. Therefore, the mass required to be added to ibm. fill the steam generator and steam line is 191,000 difference between the mass calculated to have been added The to the':steam generator and the mass that is assumed to fill the steam generator and steam line is 46,000 ibm (237,000-191,000) or approximately 88 of the combined masses of the RCS (321,000 ibm), B steam generator (4,656 ft3 assumed at 500 F) and B main 'steam line (1,055 ft3 assumed at 500 F) ~ 6 '-5
6.9.3 Uncertainties All of the values used in this evaluation were generated on a best estimate basis. Estimates of the uncertainty in the calculated values for those parameters having the greatest effect upon system inventory are given below. Variable Estimated Uncertainty Basis for Estimate Calculated (ibm) of Uncertaint A. Reactor Coolant
~Sstem integrated flow to RCS from SI (283,000)(.07) ~ 20,000 error of + 1%, range in RCS pressure indication yields
+ 78 change in flow at 1300 psi for period from 0930-1037 14,000 operator estimate for "SI from 1107-1135 from Charging (56,000)(-20) ~ 11,000 charging pump speed
+ 20%
SRSS Total ~2 ,000 mass input from (300,000 gal)(1.4) RWST 4,200 gal RWST level indicator and boric acid 35 000 lb can be read to + tanks 1% of range. Total error for 2 readings,
~2% ~
final RCS (321,000)(.007) 2,200 10 F change in assumed inventory RCS average temperature yields 0.78 change in density at 1,000 psi, 370oF initial RCS (247 000)(0.003) 2oF change in TAVE inventory 1000 (see FSR pg. 14-2) at 2200 psi and ARCS inpentory, SRSS 2500 570oF yields -3% density change Total estimated uncer- 35,000 tainty in RCS inventory and additions and losses 6 '-6
B. Steam Generator Variable Estimated Uncertainty Basis for Estimate Calculated (ibm) of Uncertaint Steam generator 20g000 assumed as 10% of steam space design condition Net main feedwater 4,000 100% of calculated value input no detailed analysis of control system per formed Steam dump valve flow 23,000 Computer alarm printout gives open and close times only to nearest minute. Analysis of times for all cycles yields potential + 50% error Steam generator safety 30~000 Estimates of safety valve flow valve open times by operators and other people based upon what they heard could be in error by 100%. The valve may have been partially open without being heard. Eetimate8 uncertainty in ~3,000 steam generator inventory and additions and losses SRSS 6.9.4 Conclusions No significant unexplained water transfers took place during the tube rupture incident. Uncertainties in several of the parameters calculated to balance plant water inventories are large enough so that the difference between the calculated mass input to the B steam generator and the calculated steam generator capacity is not unaccountable. Uncertainty in the RCS inventory and additions to it is approximately 35,000 ibm. Uncertainty in the steam generator steam space and the additions and losses is approximately 43,000 ibm. These uncertainties envelope the difference of 46,000 ibm between the net input to the steam generator and the calculated steam generator capacity. 6 '-7
Reference 6.9.1 RG&E letter dated August 18, 1981 from John E. Maier to Dennis M. Crutchfield, USNRC. Reference 6.9.2 Safety Injection Flow for Various Reactor Vessel Pressure at Ginna Station, written for RGSE EWR 2292. 6 '-8
(gY'0 X IO TO THE INCHe I X IO 0<CHES
~E KCUFFEL a ESSEX'O. saocessa 46 0782
- 7. 0 RADIOLOGICAL ASSESSMENT 7.1 Reactor Coolant S stem and Steam Generator Radionuclide Inventories 7.1.1 Radionuclide Concentrations in RCS Table 7.1-1 presents a comparison of calculated primary coolant concentrations of selected radionuclides taken from the Ginna Final Safety Analysis Report (FSAR), and actual radionuclide concentrations measured in the primary coolant prior to the steam generator tube rupture event. The calculated FSAR concentrations were based on a thermal power rating of 1520 MWt and fuel con-taining 1 percent cladding defects. Comparison of the calculated and measured values shows the measured values to be generally lower than the calculated values by a factor of 10 or more, reflecting a high degree of fuel cladding integrity.
7.1.2 Radionuclide Concentrations in "B" Steam Generator Prior to the tube rupture, gamma isotopic concentrations in the "B" steam generator were less than 1 x 0 pCi/gram, and H concentration was approximately 3 x 10 $ pCi/gram. Radionuclide concentrations measured in the "B" steam generator immediately following the tube rupture event on January 25, 1982 are presented in Table 7.1-2. These concentrations are again referenced in Table 7.2-6 and are used as the basis for estimating the portion of atmospheric releases due to the "B" steam generator safety valve liftings. 7.1>>1
0 TABLE 7.1-1 COMPARISON OF FSAR AND ACTUAL PRIMARY COOLANT SYSTEM RADIONUCLIDE CONCENTRATIONS (uCi/g) Primary Coqlant Primary Coolant Noble Gases FSAR( Measured Activit 85Kr 2 '2 85mKr 2 '4 3.20 x 10-2 (b) 87Kr 1 ~ 18 6.23 x 10"2 (b) 88Kr 3 '8 7.60 x 10 (b) 133ge 2.40 x 102 7.44 x 10 1 (b) 135ge 7 '8 2,40 x 10-1 (b) 135mge 8.52 x 10-2 (b) 138ge 4.54 x 10 1 2.55 x 10-1 (b) 41Ar 9 '8 x 10 2 (b) Corrosion/Activation Primary Coqlant Primary Coolant Products FSAR(a> Measured Activit 51Cr 1~2 x 10 4 (c) 54Mn 3 ~ 64 x 104 1~7 x 10 6 (c) 58Co 1 09 x 102 3 ' x 10 4 (c) 59Fe 252x 104 2.0 x 10-6 60co 1 ~ 29 x 10 2 ' x 10 5 (c)
TABLE 7.1-1 (continued) Primary Coolant Primary Coolant Fission Products FSAR(a) Measured Activit BBRb 3 '4 3.9 x 10 2 (b) 95Zr 7.5 x 10"6 (c) 99Mo 4.65 2 ' x 10 3 (c) 131I 1 ~ 90 9 ~ 38 x 10 3 (c) 132Te 2.59 x 1Q 2.2 x 10 5 (c) 132I 8.35 x 10 1 1.91 x 10 1 (b) 133I 2 '5 9.43 x 1Q-2 (b) 134I 4.95 x 10"1 3.26 x 10 2 (b) 134Cs 3 '1 x 10-1 5 ' x 10 4 (c) 135Z 1~9 1.52 x 10 1 (b) 136cs 3.11 x 10 1~5 x 10 4 (c) 137Cs 1~7 9.8 x 10 4 (c) s 6.13 x 10 4.33 x 10 1 (b) 140Ba 8' x 10 4 1~3 x 10 5 (c) Primary Coolant Primary Coolant Tritium FSAR(d) Measured Activit 3H 2 ' 1 ~ 24 Notes Ginna FSAR Table 9.25 (assuming 1% clad defects) b ~ Average activities of samples collected 1/6, 1/13, 1/20/82; analysis by RG&E C ~ Sample collected 1/21/82; analysis by Science Applications, InC .. 'd ~ Ginna FSAR Table 11.1-5b (assuming four changes per year of primary coolant)
TABLE F 1-2 RADIOIONUCLIDE CONCENTRATIONS MEASURED IN "B" STEAM GENERATOR SAMPLE 1/25/82 Concentration (uCi/g) in S/G "B" Nuclide at 1230 hrs(a) 131I 2' + 0.5 X 10 3 (b) 132I 3.85 + .13 X 10-2 133I 2 '1 + F 08 X 10<<2 134Z 2.19 + e64 X 10 135I 2 '3 + 14 X 10-2
~
54Mn 1~7 + 0' X 10 58Co 1.98 + 0.15 X 10 60co 5 ' +11X10 99Mo 7~3 + 1~2 X 10 4 140Ba 2 ' + .1 X 10-2 134CCs 2~2 + 0.1 X 10-4 137Cs 4' + 1 ~ 2 X 10 4 3H 3 ' + .04 X 10-1 (b) Note
- a. Analysis by RG&E, except as noted
- b. Analysis by Science Applications, Ines
0 7.2 Radiolo ical Releases Radionuclides were released from three points:
- 1. the condenser air ejector, which is combined with the gland seal exhaust,
- 2. the turbine driven auxiliary feedwater pump exhaust, and
- 3. a safety valve on the steam line from the "B" steam generator.
Two types of releases occurred: a; noble radioactive gases, and
- b. radioiodines, radioactive particulate material and tritium.
7.2.1 Noble Radioactive Gases Released from the Condenser Air Ejector and Gland Seal Exhaust Non-condensable gases are removed from the condenser by a steam jet air ejector. The estimated flow rate of this off-gas is 5 cfm. These non<<condensable gases are combined with approximately 600 cfm of air from the gland seal condenser, and exhausted through an 8-inch diameter steel pipe on the roof of the Turbine Building. For the purposes of this analysis the combined off-gas and gland seal exhaust is referred to as "off-gas," and the flow rate is assumed to be 600 cfm. There are two devices which measure radionuclide concentrations in the off-gas: the R-15 monitor, and the SPING R-15A monitor. The R-15 monitor is a sodium iodide detector attached to the outside surface of the 8-inch off-gas pipe (Victoreen Instrument Co. Model No. 843-03). The response of this monitor is to gross gamma radiation and is recorded on a strip chart and fed to a computer. Figure 7.2-1 shows the response of monitor R-15 for the period 0920 to 1400 on 1/25/82. This figure shows that at about 0925 the count rate increased rapidly from its normal reading of 640 cpm. At 0926, the computer, which scans the monitor output, reported an output of 5.18 volts, which corresponds to 1,500,000 cpm; the strip chart recorder went off scale for 105 seconds, beginning at 0926. At about 0928, the strip chart recorder came back on scale and decreased rapidly until about 0937, when at about it increased again until it reached a second maximum 0945. The strip chart, recorder showed a decrease until about 1130, when a slow increase began and continued until about 1220, when it started a slow decline toward the original background count rate. Figure 7.2-2 shows the response of the R-15 monitor during. the period from 0900 on 1/25/82 to 0900 on 1/26/82. The increased reading of monitor R-15 between 0937 and 0945 is believed to correspond to the opening of the condenser steam dump valves. The increased reading between 1130 and 1220 is believed to be a result of increased detector background due to contami-nation released from the safety valve and deposited on the Turbine Building exterior. 7~2 1
Noble radioactive gas concentrations in the off-gas were computed from the calibration curve for monitor R-15 supplied by the manufacturer (Figure 7.2-4), and the mixture of noble radioactive gases measured in the primary coolant (Table 7.2-1). Table 7.2-1 gives the mix of fission gas radionuclides before the incident, for various'imes after the incident, and the calibration factors for monitor R-15 for each radionuclide in the mixture. Table 7.2-2 gives the resulting half-hour average concentrations from the R-15 monitor for the period 0900 to 1300 on 1/25/82-The second monitor for the off-gas, the SPING monitor, designated as R-15A (Eberline Instrument Company, Model SPING-4), draws a sample of gas continuously from the 8-inch pipe about a foot downstream of the R-15 monitor. The SPING monitor has three sensitivity ranges, each of which uses a separate sensor. R~an e Sensor ~R low beta scintillation 10 to 0.05 middle compensated GM tube 2.8 x 10 to 10 high compensated GM tube 0.03 to 10 The stated concentration for the low range is based on Kr-85 beta particles, and for the two higher ranges on an average gamma energy of 0.5 MeV. At 0926 on 1/25/82, the SPING low-range gas monitor gave a high alarm, and is suspected to have been off scale. However, the middle range monitor provided hourly average concentrations, which are given in Table 7.2-2 for the period from 0900 to 1300 on 1/25/82. As indicated in Table 7.2-2, the SPING monitor average concentration for the interval 0900 to 1000 has been used to estimate the concentration during the 105-second interval when the R-15 monitor was off scale. The estimate so obtained for this interval, and the direct readings of monitor R-15 for the remainder of the period 0900 to 1300 have been used to estimate the release of noble radioactive gases from the air ejector and gland seal exhaust, i.e. 26 Ci. Note in Table 7.2-2 that the average concentrations given by the SPING monitor are substantially higher than those given by the R-15 monitor during the period from 1000 to 1200. It seems likely that the reason for this is that the SPING monitor was contaminated by the high concentration (0.39 uCi/cc) during the 105-second interval. During the period from 1200 to 1300, the concentrations indicated by the two monitors were comparable, suggesting that the contamination of the SPING monitor was a short-lived material, probably Rb-88 and Cs<<138. It should be pointed 'out, however, that at least a portion of the response of both monitors may have been to external radiation from the radio-nuclides deposited on top of the Containment Building and the Turbine Building. The steam jet air ejector was taken out of 702 2
service at 1040. This should have reduced the release rate of the off-gas considerably. The total release of noble radioactive gases from the condenser air ejector and gland seal exhaust is estimated to have been 26 Ci (see Table 7.2-2). This estimate is probably high by about 2 Ci because the estimated releases during the last three hours were largely the result of elevated background radiation levels in the area of the detectors which resulted from the liftings of the safety valve. Table 7.2-3 gives the release rates for individual isotopes in the periods between 0926 and 1300. 7.2.2 Noble Gases Released from Turbine Driven Auxiliary Feedwater Pump During the steam generator tube rupture transient, a small quantity of: noble gas is estimated to'have'. been, released'o the atmosphere from the turbine driven auxiliary. feedwater pump steam exhaust. Both steam supply valves to the pump were automatically opened at 0929, which would have exhausted noble gases to atmosphere until the steam supply valve from the "B" steam generator was manually closed at 0932. The 0.03 Ci release shown in Table 7.2-4, was estimated by dividing the portion of the "B" steam supply line flow to the pump (approximately 11,900 lbs. hour), the total steam flow from the "B" steam generatorper(3.13 x 10bg lbs./ hour). This ratio was then multiplied by the total noble gas release from the "B" steam generator from 0929 to 0932, as deter-mined by the R-15 off-gas monitor response for that time period (Figure77.2-1) and a corresponding monitor calibration factor of 2 x 10 cpm/pCi/cc (Table 7.2-1). 7.2.3 Noble Radioactive Gases Released from the Safety Valve Pressure and temperature data for the primary system and the "B" steam generator indicate that at least one safety valve on the main steam line from the "B" steam generator may have lifted on five occasions at approximately the following times: 1018, 1027, 1037, 1119 and 1137 on January 25, 1982. While it is not known exactly how long the valves were open, there is evidence that the first four lifts were short (a few seconds), and that, the last was relatively long. This evidence consists of:
- 1. operator interviews,
- 2. plant data,
- 3. the. likelihood that the steam generator and the steam line weze solid later in the transient (i.e. full of water), and
- 4. the fact that the reactor coolant pump was in service during the last release.
Inspection after the incident showed that only one of four "B" steam line safety valves had lifted. 7 ~ 2~3
The estimated number and the relative magnitudes of the releases are supported by the indications of the three monitors for the ventilation air discharged from the Auxiliary Building. The intake for supply air to the Auxiliary Building is located on the roof of the Auxiliary Building at a point which was, most of the time, downwind from the safety valve releases. Therefore, the Auxiliary Building effluent monitors are believed to reflect the time and duration of the safety valve releases. The Auxiliary Building radioactive particulate, noble gas and radioiodine monitors are designated as R-13, R-14 and R-10B, respectively. A sample stream is drawn isokinetically from the main exhaust vent through the particulate and noble gas monitors, and a separate stream is similarly drawn through the radioiodine monitor. The particulate monitor, R-13, consists of a moving filter and scintillation detector. The R-14 gas monitor is a Geiger-Mueller detector. The R-10B radioiodine monitor uses a fixed iodine cartridge and scintillation detector. Monitor R-10B gives a count rate proportional to the number of 0.364 MeV I-131 gamma rays (with background subtracted) emitted from the cartridge. Figure 7.2-3 shows the outputs of the Auxiliary Building effluent monitors. The estimated times of safety valve lifts are shown in the figure. The gas monitor (R-14) appears to have responded most rapidly after each after the lift lift. The greatest increase occurred at 1137; the smallest occurred after the lift at 1027. The response of the particulate monitor (R-13) occurred a short time after that of the gas monitor. It should be noted that all Auxiliary Bulding exhaust air is passed through HEPA filters before it is monitored. Therefore, the particulate monitor was most likely responding to the parti-culate daughters of the fission gases, which were produced after the gases had passed through the HEPA filters, e.g., Rb-88 and Cs-138. The I-131 monitor (R-10B), also, responded to each suspected valve lift. Some, but not all, of the exhaust air is filtered through charcoal before it reaches the effluent sampling point. The presence of. radioiodine is indicated: by an increase in'he slope of the count rate vs. time curve. This monitor, like the gas and particulate monitors, showed the largest response after the safety valve lift at 1137. The particulate and I-131 effluent monitors alarmed after exceeding their respective setpoints between 1143-1149 on 1/25/82. The noble gas monitor reading did not reach its alarm setting. The magnitude of the noble gas GM detector response, per unit of activity concentration, is very much less than the scintillation detectors belonging to the particulate and radioiodine monitors. ~ Therefore, it is not unexpected that short-lived fission gases would cause the gas monitor's GM detector response to remain below its alarm setpoint, while the particulate daughters of these gases produce a much higher (particulate monitor) response. 7.2-4
p I The greater sensitivity of the iodine monitor's scintillation detector would also result in a higher response relative to the gas detector for a given activity concentration. The fact that the Auxiliary Building vent monitors responded after the five suspected liftings and that there were no other indications is considered adequate support that there were five liftings, of which the last was the longest. It has been con-cluded from various plant instrument indications that the total duration of valve liftings was about two minutes. For the purposes of this analysis lifts it is assumed that the 1018, 1027, 1037 and 1119 combined lasted for 60 seconds, and the total duration of the 1137 lift was 60 seconds. Data evaluations indicate the occurrence of a liquid phase release during at least one, and probably the last safety valve lift. Because of this and the fact that snow samples indicated a nuclide mix that was representative of reactor coolant, that there was little if it is assumed any partitioning of radionuclides and particulates when the safety valve lifted. There are a total of 8 safety valves which can be used to relieve "A" and "B" main steam line pressure. The combined rating for release through the 8 valves is 6,580,000 lbs/hr. It is assumed that one valve releases a maximum of 823,000 lbs/hr (1/8 the combined maximum). It is further assumed that this release rate applies to water as well as steam. This assumption gives thg release rate of water when the safety valve was open as ' 10 grams per second. 7The total release for 2 minutes thus would have been 1.2 x 10 grams (- 3300 gallons). Subsequent field examination by a representative from the steam line safety valve manufacturer has provided additional supporting information on the safety valve releases. First, it was observed during the field inspection that the safety valve never reached a full lift position. For this condition the valve manufacturer estimated a steam flow rate of approximately 500,000 lb/hr (at 1085 psig), as opposed to the 823,000 Ib/hr flow rate assumed above. Assuming the last valve lift consisted of saturated water instead of steam, the manufacturer also estimated that the flow rate (at 1085 psig) was between 1000 to 4000 gallons per minute. The flow rate through the valve would begin at a maximum value and continue to decrease with decreasing steam generator pressure lift it until the valve closed. If is assumed that the last valve at 1137 was a liquid phase release, and the flow rate over the 60<<second lift period averaged approximately 2000 gpm, the estimated release would be 2000 gallons. The release contribution due to the first four (steam phase) lifts is estimated to be about 8300 lb over a 60-second period, equivalent to about 1360 gallons of saturated water under the same temperature and pressure conditions. The resulting total of approximately 3300-3400 gallons obtained by this alternative estimate would indicate that a volume release estimate on the order of 3300 gallons (1.2 x 10 grams) is a reasonable basis for quantifying radionuclide releases. 7.2-5
Prior to the shutdown at 0928 the gas concentration in the coolant was 1.59pCi/g (see Table 7.2-1). For a total primary coolant mass of 255,000 lb. (1.16 x 10 g), the total quantity of the measured fission gases available was approximately 190 curies. As shown above, approximately 26 curies were released in the off-gas. From the time 0928 until 1018, when the first safety valve lift occurred, approximately 50 curies were lost through decay. Therefore, when the valve lifted approximately 114 Ci were available in the primary coolant and the "B" steam generator water. It is estimated that approximately 380,000 lb. of make-up water were added to the RCS during the incident, 297,000 lb. of which were added to the secondary side of the steam generator (see Section 6.9). If it is assumed that there was no water lost, the maximum total water mass that may have been present in the "B" steam generator and steam lines at 1018 assuming all the break flow occurred prior to this time was 388,000 lb. If the RCS contains 255,000 lb., 60% of the total gas (-68 Ci) was present in the "B" steam generator at 1018. The concentration of gas in the "B" steam generator was thus calculated to be 0.39pCi/g. A total lift duration of 60 seconds for the first four safety valve lifts would have released approximately 2.4 curies of noble gases. During the 60-second release assumed at 1137, approximately 59 curies are estimated to have been in the "B" steam generator system, of which 2 curies are estimated to have been released. Table 7.2-4 shows the estimated noble gas releases to the environ-ment during the valve lifting. The total noble gas release including the off-gas, turbine driven auxiliary feedwater pump exhaust and safety valve lifts is estimated to have been 30 Ci. 7.2.4 - Radioiodines and Particulates Released in Off-Gas Because partitioning occurs in the steam generator, the main condenser and the gland seal condenser, releases of particulate nuclides and radioiodines in the off-gas were compared to those from safety valve liftings. Measurements at another PWR* with primary-to-secondary system leakage, showed that for a steam generator ~~~I concentration of 3.3 x 10 pCi/g, the total release rate in Qe off-gas (5 cfm) and gland seal exhaust (320 cfm) was 1.6 x 10 pCi/sec. The concentration of ~~~I in the "B" steam generator measured at 1230 on Janury 25, 1982 was 2 x 10 pCi/g. If the same ratio is assumed to apply for Ginna, the release4rate in the off-gas during the accident would have been 9.7 x 10 pCi/ sec. Over the period when the air ejector was operating, up to 1040 on 1/25/82, a total of 4.4pCi would have been released. This quantity is a small fraction of the releases estimated for the safety valve lifts discussed in the following section. Smears were taken on the inside of the 8-inch off-gas exhaust line. No contamination was found ((100 dpm/100 cm ). During the period of release, condensate from the off-gas sample line was collected an) analyzed. The gross beta-gamma activity was less than 8 x 10 pCi/ml, and a gamma scan of a 100-ml aliquot of the 7.2-6
condensate showed no detectable radioiodine activity. These observations support the conclusion that radioiodine releases in the off-gas were negligible. 7.2.5 Radioiodine, Particulate and Tritium Releases from Safety Valve Release of radioiodine, particulates and tritium were calculated by multiplying the assumed liquid releases for the 5 valve lifts by the concentrations measured in the "B" steam generator at 1230 on January 25, 1982. Releases for radioiodines, other than 'I were decay-corrected to approximately 1119. Table 7.2-5 summarizes the results. For general comparison purposes, the inventories of radionuclides can be compared before and after the steam generator tube rupture event. This comparison was made for ~~~I and ~H and shown in Table 7.2-6. The calculated inventories of I and ~H before and following the tube rupture are in reasonable agreement with account taken of measurement, volumetric and rounding errors. It would be extremely fortuitous to have had significant spiking of
~~'I and still show the close agreement in Table 7.2-6. Previous experience with the current fuel loading showed that no spiking of ~~~I occurred after either shutdown or startup.
t *Sources of Radioiodine at Pressurized Water Reactors, C.A. Pelletier et. al, EPRI NP-939, Nov. 1978. 7~2 7
TABLE 7.2-1 NOBLE GAS NUCLIDES IN THE PRIMARY COOLANT BEFORE THE INCIDENT AND AT VARIOUS TIMES AFTER Gamma Half Energy Relative Concentration (8) Nuclide Life (MeV) Constant(>) t=o 3 0-5hr 1 hr 2 hr 3 hr 4 hr 6 hr 41Ar 1.8 hr 1.28 3.14 x 107 5.8 6.0 5' 4-0 2.9 2' 1.0 85mKr 4.4 hr 0.26 2.78 x 107 2.0 1.9 2.3 2 ' 1~9 1 ~ 7 1 ~ 3 87Kr 76 min 0.86 3.61 x 107 3.9 3.7 3.1 1.9 1.2 0' 0.3 88Kr 2.8 hr 2 ' 3.30 x 107 4.8 5.2 5.0 4.3 3.6 2.8 1~9 133Xe 5.27 d 0.045 7 '2 x 105 46.8 57.7 65.3 68.9 71.5 74.4 78.5 135Xe 9.14 hr 0 '5 x 10 15.1 17.8 18.9 19.1 18.8 18.2 17 ' 135mXe 15.6 min 0.43 4.08 x 107 5.2 1.7 0.5 138Xe 17.5 min 1.18 4.24 x 107 16.0 5.9 1~9 Total -concentration (uCi/cc) 1.59 1.29 . 1 ~ 18 1.08 1-02 0.98 0.92 Average energy (MeV) 0.49 0.36 0 '0 0.24 0.20 0.17 0.13 Calibration constant R-15 (x 107 cpm/uCi/cc) 2.22 1.85 1.65 1.45 1.35 1.24 1.08 (1) Based upon nuclide concentrations from plant chemistry log, which are averages of samples taken on 1/18, 1/20, 1'/22 and 1/25. (2) Expressed in cpm/uCi/cc computed from Figure 7-2-4 and the decay schemes of each nuclide'3) Time noted as T=O corresponds to 0926 on 1/25/82.
TABLE 7.2-2 AVERAGE CONCENTRATION OF FISSION GASES IN THE AIR EJECTOR AND GLAND SEAL EXHAUST January 25, 1982 SPING R-15 Activity Monitor Monitoq Period Released, Interval uci/cc uci/cc<a) minutes Ci 0900 0926 26 0926 0927 0 '4 1 0. 68 0927 - 0929 0.024 X=O 39 13 ' 0929 0930 0.026 1 0.44 0930 1000 0 '20 30 10 ' 1000 - 1030 0.0057 0.00049 30 0.25(b) 1030 - 1100 0.00023 30 0.12(b) 1100 - 1130 0.0022 0.00020 30 0.10(b) 1130 1200 0.00048 30 0-25(b) 1200 1230 0.00082 0 F 0011 30 0.56(>> 1230 1300 0.0013 30 0.66(b) TOTAL 26. Ci Notes: All concentrations given above are from the R-15 monitor, except for the interval 0927-0929, which were read from the strip chart record, Figure 7.2-1. The concentration for the interval 0927-0929, when the R-15 monitor was off scale, was obtained by finding the concentration, x, during this interval that gave the average concentration for the R-15 monitor readings over the period 0900 to 1000 equal to that indicated by the SPING monitor during the same period. That is:
'a
~ 26(0) + 1(-04) + 2(x) + (.026) + 30(.02) 60 Monitor reading due at least in part to elevated radiation background levels in the area of the detectors.
-TABLE 7 '-3 ESTIMATED NOBLE GAS RELEASES IN THE AIR EJECTOR AND GLAND SEAL EXHAUST 0926 - 1300 Time Avera e Release Rate (uCi/sec)
Period 41Ar 85mKr 87Kr 88Kr >33xe >35Xe 135mge 38ge 0926-0930 3400 1200 2300 2900 28, 000 9000 3100 9500 0930-1000 340 110 220 290 300 940 200 650 1000-1030 7' 2.9 4.8 F 1 86 26 1~5 5.5 1030-1100 3.5 1~5 2.0 3 ' 42 12 0' 1 ~ 2 1100>>1130 2.7 1~3 1-4 2 ' 38 11 0.1 0.5 1130-1200 . 5.6 3 ' 2~7 6' 97 27 negligible negligible 1200-1230 6.4 4.8 12 220 59 negligible negligible 1230-1300 7~0 4~4 13 270 70 negligible negligible Total Release Each Isotope(Ci) 1~5 0.53 0.98 1~3 13 4.2 3.4 Total (Ci) 26
TABLE 7 '-4 ESTIMATED NOBLE GAS RELEASES FROM TURBINE DRIVEN AUXILIARY FEEDWATER PUMP EXHAUSTS SAFETY VALVE LIFTS AND OFF-GAS 1/25/82 Estimated Noble Gas Time Release (Ci) 0929 0932 0. 03 (a) 1018, 1027, 2.4 (b) 1037 and 1119 1137 (b) 0926-1300 26 (c) TOTAL 30 Ci Notes: a ~ Turbine driven auxiliary feedwater pump steam exhausts
- b. "B" steam line safety valve lifting.
- c. Air ejector and gland seal off-gas.
TABLE 7.2-5 RADIOIODINE AND PARTICULATE RELEASES FROM SAFETY VALVE LIFTS 1/25/82 Radionuclide Releasesa Concentration (uCi/g) in S/G "B" Nuclide at 1230 hrs Total Curies 131Z 2 ' + ~ 5 X 10 0.027 132I 3 '5 + .13 X 10-2 0.680 133I 2 '1 + F 08 X 10-2 0.290 134Z 2.19 + .64 X 10 0.077 135Z 2.53 + .14 X 10 2 0 '40 54Mn .1 7 + 0.2 X 10
~ 0.021 58co 1.98 + 0.15 X 10 0.024 60co 5 ' + 1 ~ 1 X 10 4 0.007 99Mo 7' + 1 ~ 2 X 10 4 0.009 140Ba 2' + ~ 1 X 10 0 '90 134Cs 2 ' + ~ 1 X 10 4 0.003 1 37Cs 4' + 1 ~ 2 X 10 4 0.005 3H 3 ' + ~ 04 X 10 1 4 '7 Note: assuming a total water release volume of 3,300 gallons (1 2 x 10 grams) due to 5 safety valve
~ lifts over a total period of two minutes.
TABLE 7.2-. 6 COMPARLSON OF THF. INVENTORIES OF I AND H BEFORE A'ND FOLLOWING THE S/G TUBE RUPTURE EVENT 1/21 82 1230 on 1/25/82 Primary Coolant li B II S/G Primary Coolant tt B II S/G Nuclide (1.16 x 108 ) (b) (4.13 x 107 ) (1.46 x 108 ) (c) (1,76 x 108 ) (a)(d) 131Z 1.11 Ci 0.70 Ci 0.39 Ci TOTAL 1.11 Ci 1-09 Ci 3H 144 Ci 0.001 77 Ci 66 Ci TOTAL 144 Ci 143 Ci (a) includes 297,000 lb of makeup water to the steam generator and 91,000 lb of water and steam normally in the steam generator. The steam generator and steamline were full of water at this time. (b) based upon analysis of primary coolant 1/21/82; analysis by Science Applications, Inc. (c) based upon analysis of primary coolant 1/31/82; decay-corrected to 1/25/82; analysis by Science Applications, Inc. (d) based upon "B" S/G sample (1230 1/25/82); analysis by Science Applications, Inc.
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7.3 Meteorolo ical Data Meteorological data for the Ginna site are available from the primary onsite weather tower, located west, of the main plant buildings. The primary tower is equipped with redundant wind speed and wind direction sensors at the 33-ft and 150-ft levels, and redundant temperature sensors at the 33-ft I 150-ft and 250-ft l evels. There is a single wind speed and direction unit at the 250-foot level. Dew point and rainfall measuring equipment is also provided. One set of wind direction, wind speed and temper-ature values measured at each of the three tower elevations are displayed by 'the plant computer in the Control Room and Technical Support Center and via a computer link to the offsite Emergency Operations Facility. The Control Room also has a continuous chart recording of the 33-foot level wind speed and direction along with a digital display of ambient tower level temperatures at all three elevations. Other sensor chart records for the primary tower are available in the Weather Building (west of Project Building). A windspeed and direction unit is mounted at the 33-foot level. on the back-up tower at Substation 13A. The 13A tower sensors are recorded by strip chart at the tower location (approximately 0.5 miles due south of the primary tower). During the period of 0900 - 1300 on January 25, 1982, the wind direction was generally centered from 310 - 320't approximately 10-15 mph. The range of wind direction fluctuation was about The atmospheric stability, as determined by 50'-290'--340'). temperature difference between the 33 and 250 foot levels was neutral during that time period (hT (250 - 33 ft) approximatel e y -1.0 to -1.5 F). A wound shaft to the westerly direction occurred at approximately 1500 hrs in the afternoon, but occurred subsequent to releases associated with the steam generator tube rupture. Using wound speed,'cloud cover, and time of day to estimate stabilit yields the same neutral stability categorization as determined by temperature difference.* The neutral stability centerline plume dispersion coefficients (X U/Q mph-sec/m ) in Table 1 of Ginna Station Procedure SC-1.13 were used to estimate concentrations and dose rates at downwind locations. The average ground level temperature between 0926 and 1200 was 12'F. Snow was falling throughout the period at a rate of 1/4 inch per hour.
- Slade, Meteorology and Atomic Energy 1968, U.S. Atomic energy Commission, Office of Informational Services,.page 101.
7.3-1
The Emergency Survey Center (ESC), in the basement of the Training Center was manned at 1000 on January 25, 1982 and a survey of the ESC showed that the general area inside the building was <0.1 mR/hr and on the outside north the general area outside and north of the building was 0.1 mR/hr. Readings from the radiation monitor mounted on the east side of the ESC approximately 19 feet off the ground are plotted in Figure 7.4-1. The two on-site teams (Blue and Yellow} and the Green offsite team were manned and standing by at 1020, and the Red offsite team was manned at 1023. Both remaining teams (Orange and White) were manned and standing by at 1051. Between 1031 and 1044 the Blue, Yellow, Red and Green teams departed on their primary survey routes as directed by the Technical Support Center. The Orange team departed at 1105 and the White (spare) team was standing by in the ESC. At 1044 the site evacuation alarm was sounded and all non-essential personnel left the plant and reported to the top level of the Training Center. Field instruments for radiation measurement included the RM-14 count rate meter (Eberline Instrument Co., Model RM-14 with HP-190 end window GM probe}, and the Xetex Auto Digimaster (Xetex Model 305). Initial Survey Results were as follows: ONSITE BLUE:* The Blue team surveyed the area east and south of the plant. Results of the initial survey indicated that most, of the release was to the east and south of the plant between the ESC and the Manor House Bridge area. The maximum reading south of Deer Creek was 1.6 mR/hr at 1101 in the area of Environmental Sampler 44. Maximum readings of 3 mR/hr (Xetex), and 10,000 cpm (RM-14) were obtained concurrently at 1158 as the team passed under the steam cloud on the southeast side of the protected area fence. Once inside the fence, the readings in the area west of the main buildings were 100 - 300 cpm (gross) and east of the guardhouse up to 1,600 cpm (gross) and 0.7 mR/hr at edge of steam cloud, which was blown down the the ground at 1215. ~Under field conditions,
'd'"g' g' b' it may
- 0 bep (II "') '"
assumed that Eberline RM-14/HP-190 b~k'""5 to instrument variability, handling, and meter interpretation
'"d'"g'ue by the individual. Using the RM-14 and HP-190 been determined that 2200 cpm = 1 mR/hr, probe, it has with the probe held 3 feet above ground level.
7.4-1
ONSITE YELLOW:+ The Yellow team surveyed the area north and west of the ESC, and survey results indicated that very little of the activity released went into this area. All the readings taken were 20 gross cpm with the exception of one taken outside of plant Door 24 (1.0 mR/hr with the Xetex). Both onsite teams met at the south cor'ner of the Service Building at 1210 and at this point the Yellow team discovered that their RM-14 survey instrument was erratic. After obtaining a new RM-14 they entered the Service Buildling via plant Door 24 (escorting the NRC) at 1350 and a reading of 350 gross cpm was reported. A reading of 300 gross cpm was reported in the guard house as they exited from the site. OFFSITE TEAMS:* An area extending approximately 1.5 miles west to 4 miles east and 4 - 5 miles south of the plant was surveyed during the time period of 1045 - 1300. These results indicated that to the west-southwest the general area was 40 - 50 gross cpm. However, the area starting at the plant entrance and Lake Road and extending east to the intersection of Lake Road and Knickerbocker Road to approximately 1.5 miles south indicated several average readings of 50 - 80 gross cpm. A high reading of 2,800 gross cpm (approxi-mately 1.2 mR/hr) at 1106 was obtained at the intersection of Lake Road and the entrance road to the ESC, the highest reading recorded by the offsite teams. This same location was resurveyed at 1219 and a reading of 30 - 60 gross cpm was obtained. The other areas to the southwest had readings of 40 50 cpm and those to the east were 20 gross cpm. At approximately 1225 - 1240 both the Green and Orange teams were instructed to repeat their primary surveys. These results indi-cated that all areas had decreased to 20 - 50 gross cpm. Two spikes of 200 500 gross cpm, lasting a few seconds, were reported (Xetex reading was 0.0 mR/hr) at the intersection of Lake Road and Furnace Road at 1219; however, the count, rate meter returned to 20 gross cpm and remained there. The Red team was dispatched at 1225 to conduct their Second Stage survey to the south and east of the plant. Their results indicated that all areas south of Route 104 were 20 gross cpm and the area along Route 104 from Knickerbocker Road to Fisher Road were 40 - 50 gross cpm; however, at, 1700 these areas had decreased to 20 gross cpm.
*Under field conditions, it may be assumed that RM-14 readings ranging between 20-50 cpm (gross) are back round readings, due to instrument variability, handling an meter t P interpretation by the individual. Using the RM-14 and HP-190 probe, it has been determined that 2200 cpm = 1 mR/hr with the probe held 3 feet above ground level.
7.4>>2
0 During the above surveys, TLDs were placed at preset locations and air samples taken as directed. (See also Sections 7.5 and
- 7. 6)
Follow-up onsite and offsite surveys were al'so conducted after the initial series of environmental surveys was completed. Table 7.4-1 describes the dates, times and objectives of the post-accident surveys performed by monitoring teams. Table 7.4-1 is followed by corresponding survey maps (Figures 7.4-2 through 7.4-17) which provide details of each survey. Two survey teams were also made available from the Emergency Operations Facility. One EOF survey team was directed to take offsite radiation readings east and south of the Ginna plant from 1400-1600 on January 26. The other EOF team performed detailed offsite and onsite radiation surveys on January 29 and 30, respectively, using a Reuter Stokes RS-111 pressurized ion chamber. The latter team also collected additional snow samples south and east of the plant, and retrieved environmental thermoluminescent dosimeters.
TABLE 7.4-1
SUMMARY
OF ENVIRONMENTAL SURVEYS PERFORMED BY RGSE MONITORING TEAMS FOLLOWING GINNA TUBE RUPTURE EVENT Team Date Time Desi nation Ob'ectives ONSITE I/25/02 1044-1424 Yellow Radiation and air sample readings; change filters at fixed air monitors 1045-1352 Blue Radiation and air sample readings; change filters at fixed air monitors 1400-1530 Bl ue Radiation readings at 3 ft and 1 inch above snow 2130-2330 Blue Radiation readings at 3 ft and 1 inch; snow samples 1/26/82 0155-0330 Yellow Radiat,ion readings at 3 ft and snow samples 1 inch; 0905-1100 Blue Radiation readings at 3 ft and 1 inch; snow samples 1725-1805 White Radiation readings at 3 ft and 1 inch 1/27/82 0910-1005 Blue Radiation readings at 3 ft and 1 inch 1/3A/82 1000 EOF-1 Detailed onsite survey using Reuter Stokes RS-ill pressurized ion chamber OFFSITE 1/25/82 1030-1730 Green Radiation and air sample Orange readings, placement of Red TLDs, within 10-mile radius 2100 Green Radiation readings at 3 ft and' inch; snow samples, southeast and east of Ginna
TABLF. 7.4-1 (continued) Team Date T1Hl6 Desi nation Ob 'ectives 2330 Green Radiation readings at 3 ft and 1 inch; snow samples, along plant driveway, Lake Road and field south of ESC 1/26/82 0117-0310 Red Radiation readings at 3 ft and 1 inch; snow samples; east and south of Ginna (Lake/Fisher/ Tr imbl e/Bailey/Knicker-bocker Roads) 0127 Orange Radiation readings at 3 ft and 1 inch along Lake Road from Wilson farm to Deer Creek 0910 Green Radiation readings at 3 ft and 1 inch; snow samples, southeast of Ginna ( Furnace/Tr imble/ Fi sher/Putnam/Lake Roads) 1400-1600 EOF-1 Radiation readings at 3 ft and 1 inch, east and south of Ginna 1/29/82 0930 EOF-1 Detailed offsite radiation survey using Reuter Stokes RS-ill pressurized ion chamber; snow samples, south and east of plant
8 7 FIGURE 7.4-1 RESPONSE OF AREA RADIATION MONITOR OUTSIDE OF EMERGENGY SURVEY CENTER
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~
SURVEY MAP 10 ECEE BLUE 4 YELIANt TEAHS
~
TIME; ~ Ntatata toots t SUGGESTEO ROUTE.<<
~ C1tt Nouat 1Jawaatt 100 c stoa*at 0 lnR/
01352 r NNN IQQ cpa NEN41, NoMEE 60 cpa 0 eu40 1 No Or :0 1150
. No rt,Nett MQ IO4ine Cartrfdge
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s 100 cpa 8 1123 RKG. N c rrr ell58 Rca4fngs ca Envfr.ganple Part. Filter 1 BXQ g4 60 cpa t~ Back 8 4oor fnsfdet
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/hr.
.iP'1103 SURYEY HAS HaDE WITH THE PQLL0t INC INSTRUNENTS ~
I I, RH 14 Nf th HP-190 Probe (open NfndENE) 2 XEttea
FIGURE 7.4-4 ONSITE SURVEY A NO SCALK T/ DATE: ~~SQ TIME: TEAM MEMBERS L AN C 4 N T A 4 I 0 BLUE SUGGESTED
~1 TOWCR
+hh'CATNCR b 0 S CRT C
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~ NS W
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..... W" AUTO-DIGI HASTHI 4
DCCN CRCCN All readings are in gross~c unless noted otberwi se. T readiTvcs are in Air Sg Bottcss readings 41'e Ground Level. ply ~~~ CIrrA TIN CRT" ur LTKAAro Ihlt+K C ~
FIGURE 7.4-5 ONSITE SURVEY MA NO CCAEC I/~e/ii je.iTso DATE TIME E LAKE ON 1 A AID TEAM MEMBERS BLUE I EL
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FIGURE 7.4-6 ONSITE SURVEY MAP NO SCALE DATE: ~/26/g2 TIME: oss'5- o33o TEAM MEMBERS LANE ONTANIO YELLOW SUGGESTED ROUTE --.
---r Ilr SCNEE NOVAE t 4 A 0 W A S 'I E STONAOE N
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PIGORE 7.4-7 N ITE SURVEY MA NO SCALE 0<TO~</- <l TIME oa < - a<> TEAM MEMBERS LAN f ON S AN I0 BLUE
/LIE< PO<t 'TiLI- I<S av SUGGESTED ROUTE ~
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FIGURE 7.4-8 NSITE SURVEY M NO SCALC OATS~/ia TA TIME ~ITAS dr TEAM MEMBERS LANS ONE AIIIO CCIACggEN HP-iso SUGGESTED ROUTE ~ ~~ ~ ~ ~~ ~ ~
'"" "p SCNCC Er
<<OUSE NADWASTC STONAOC IIANON NOVAE
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@CAMO Al 7OO QCTCS Q l 50u aIIOCT VDr7NIw c'i T WIL'<~
FIGuRE 7.4-9 ONSITE SURVE Y MA NO SCALE DATE ~AT/IA TIME't/O Iool KE ONE ANIO TEAM MEMBERS r,I L A BLUE NEATHEII TOTEEN "-
"""ro SUGGESTEO ROUTE---
SCAEE HOUSE NADTEASTE STOAAOE -va 0O
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FIGURE 7.4-10 ONSITE SURVEY MAP uu ECAll DATE:~~30 u TIME: l Au 4 ou IAAIO EoF-1 suRvEY TEAN REUTER STOKES HODEL RS-ill ALL READINCS IN OH/HR. OCATVCO TO%CO ~o~ SUGGESTED ROUTE:--"- -""-."4 6 NOTE THIS SURVEY HAS M)E HITH THE INSTRUHENT MOVEE l ~ Cl THE TAILCATE OF TRUCK - APPROX. 3 Feet Off Groua4. 12.~ AAOWAATg ua u4 oo u B.o 10.0 6.o
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~~E 14.0 24 0, 25 0 r 3.0 8.0 20~0
, 15.0 B.o 45.0 7.0 8.0 10.0 33.5.
FIGURE 7. 4-11 GREEN e ORANGE & RED S>>>>. )Fey OFFSZTE SORVEYS
~ va. Sv<@
GZNNA PLANT ct>> 1030-1730 1/25/82 Qei ee tee<<(tet>>
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FIGURE 7.4-12 GREEN TEAM OFF-SITE SURVEY DATE: ~may/82 e moo BY: NOIE: ALL READINGS IN GROSS C1% UNLESS OlliERWISE NOTED. READINGS ABOVE LINE ARE 6 1" READINGS BEQN LINE ARE 8 3'~yap
~ 4"a SlMlC 6>> SJIWJ io Skilli7 NC w
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FIGURE 7.4-13 EMERGE'NCY MOHlTORIH G TEA]A Suave~ MA p
~~ 5~ Tea MEyecRs:
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FIGURE 7.4-14 0/l 7 03/~ Rr(r~~ acr figpy 5OC f e
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] -7o cPM INSTRUMENT: 2':-14 with HP-190 NOTE: ALL READINGS IN HtOSS CPM UNLESS OTHERWISE NOTED.
C I+41)t ~ ~lbe Svevn aaae
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FIGURE 7.4-16
-'E.Ee'Q TeAH suRv~ (opto-iioo) i-'i~'-di: '.'-: .
5DRVE'f LDCAT'lo M DATA (g j pg~H 20 l 0 I g y g -g gb RO 'g p p~~)gpss
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l I INSTRVMENT: RM-14 w 'P-1/0 Probe "..:, "- ~:"...'.- .'.- .: ~
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. ALL RSQ)INGS IN GROSS CPM UNLESS mrZmrrSZ"
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g.d CO CO s.o BRICK c:.'.can ROAD 7.0 g.5 g,o 4.o ,TRZH7'- RD. FOLLUVJP SURVEY F,'EvTRf.'-SQ~ES VITH uR-%KB > RS-111 40 29 gANUARv 1o82 COo3O ALL READlViGS EN uR/Hr. g,d Survey was made with instrument on tailgate KENYON ROAD ~s:S of truck (approx. 3') from ground. EOF-1 SURVEY TE~ O CC C.s 8 FIGURE 7.4-17 c,o RC ZE 1O4
".ONTARIO CETHER ONTARIO
7.5 Sam lin Air, Snow, Mater 7.5.1 Air Samples 7.5.1.1 Air Samples Collected Offsite by Survey Teams Airborne radioiodine was detected in silver zeolite (AgX) cart-ridges used by field survey teams to obtain short grab samples of air at predetermined offsite locations around the station. Radioiodine was detected only in the AgX cartridges; none was found on the particulate filters. Concentrations that were above background, shown in Table 7.5-1, were measured at Intersections ¹1 and ¹19 (corresponding to the intersections of Lake Rd. and Knickerbocker Rd., and Fisher Rd. and Putnam Rd., respectively). These measurements show the influence of the vesterly component of the winds. The Ginna plant is situated approximately both locations. As noted in Section 7.3, the wind direction 290'rom ranged from -2900 to 3400 The data from Intersection ¹1 suggest that the I air concen-tration remained above background levels for several hours after the release. The second sample was collected approximately 2.5 hours after the last release from the "B" steam generator safety valve. The straight line travel time (for u = 6.7 m/s) from the point of release to Intersection ¹1 would be less than 5 minutes. The observed concentrations may be due to volatilization of radioiodine that was deposited in snow on building roofs near the release point. Transport of volatile or blowing radioactive material from plant structures may have been later assisted by the considerable amount of clean steam being relieved from the "A" steam generator. Detectable concentrations vere measured at fixed onsite monitoring stations from January 25 to 29, 1982,-. presumably due to a similar evolution of deposited activity from snow or by drifting. 7.5.1.2 Environmental Air Concentrations at Fixed Air Monitoring Locations Airborne radioiodine was measured at three of Ginna Station's onsite routine air monitoring locations, air monitors ¹2, 3 and
- 4. (Locations are shown on Figure 7.6-2.) The location with the highest observed concentrations was ¹4, near the Emergency Survey Center. The measured iodine concentrations are shown in Table 7.5-2. As can be seen, the average airborne concentrations between 1125 and 1510 were approximately 50 times higher than those between 0925 and 1125 on January 25. This observation generally supports the belief that the principal radioiodine release occurred when the safety valve lifted at 1119 and 1137.
The same particulate filter was in place throughout the period. The filter concentrations may be due to the collection of airborne moisture (snow) containing radioiodine, as the filter was observed to be damp when changed. The concentrations of> Co and Mn 11 collec)ed on the filter were 1.2 x 10 pCi/cm and 2.9 x 10 pCi/cm , respectively, both lower than the concentration of '~'I. 7.5-1
Three grab samples were collected on January 25 near Air Monitor
¹4. No gaseous radioiodines were detected in a sample collected inside the Emergency Surveylfenter between 1110 and 1145. The detection limit was 4 x 10 pCi/cm . Only ' was detected in a second sample collected upstairs in the Emergency Survey Center between 121$ 0and 124$ . The particulate filter concentration was i
pCi/cm3, the concentration seen by the AgX cartridge 8 2 x 10 was 5 x 10 10 pCi/cm . A grab sample collected on the lawn east of thy ESC between 1110 and 1200 gontaineg concentrations of 4.1 x 10, 4.9 x 10, and 6.5 x 10 pCi/cm of I, and I, respectively. The 10 I concentration seen by the AgX i cartridge was 8 2 x 10 pCi/cm . The cartridge was not counted until January 27, so the ' and ' activities would have decayed prior to counting. The ratio of the particulate filter to cartridge activity in this sample is 8. The lower ratio for A~XI may reflect the migration of ' from the particulate filter into the cartridge during the longer sampling period. Airborne radioiodine was also measured in the AgX sample from Air Monitor ¹4 for the period January 25-29. These concentrations, more than two orders of magnitude lower than those observed on January 25, may be due to blowing snow or volatilization of radioiodine from melted snow. Air temperatures were near 40'F on January 28. The average concentrations of ~~'I and I meyyured at Air 13 Monitor ¹3 during January 25-29 were 3.1 x 10 and 7.4 x 10 pCi/cm respectively. These concentrations are roughly 20% of those measured at location ¹4. Co was also observed during the samy4period yt location ¹3; the average concentration was 9.6 x 10 yCi/cm . No airborne radioiodine was detected in samples collected between January 29 and February 5. The average air concep$ rations at Air monitor g2 between January 25 and 29 were 9.8 x 10 and 2.1 x 10 pCi/cm for '~'I and I, respectively. The concentrations at location ¹2 were approximately 2/3 of those at location ¹4. No radioiodines were detected in the subsequent sample (removed on February 5). 7.5.2 Measurements of Radionuclides in Samples of Snow During the period when radionuclide releases occurred, the ambient temperature was 12'F and snow was falling. The average snowfall was estimated to be 1/4 inch per hour. More than one hundred samples of snow and melted snow were collected and ana3:yzed by gamma spectrometry (refer to Figure 7.5-1 for intersection locations). The sample results have been separated into three categories: (a) samples collected within the station security fence, (b) samples collected outside the security fence, but on RGB'roperty, and (c) samples collected at offsite locations. The measured concentrations within each category were generally comparable, although some data exhibit variability spanning two or more orders of magnitude. The onsite concentra-tions were generally a factor of -40 or more lower than 7.5-2
the peak value which was found inside the security fence. The offsite concentrations were another factor of -40 lower, or ' 1/1600 the peak values inside the fence. The results for snow samples collected within the security are shown in Table 7.5-3. The highest concentration of ~~~Ifence was measured in a sample from the Turbine Building roof. The '~'I concentrations in three other samples are comparable; three of the four samples were collected near the steam line safety valve exhaust line. Radionuclide concentrations in these samples are comparable to those found in liquid from the "B" Steam Generator. This finding suggests that some of the discharged steam and water condensed rapidly and was deposited locally on the roofs of buildings and on the ground near the release point. Table 7.5-4 contains the results of measurements of snow samples collected onsite at locations outside the security fence on January 25 and 26. These data show that a significant fraction of the plume was transported toward the )raining highest concentrations of '~'I (-2 x 10 to -2 xCenter. The 10 pCi/g) were found at locations near the facility. Lower concentrations were found east of the fence in the vicinity of the unoccupied Manor House, indicating that a portion of the discharge was carried in that direction by the variable wind. Table 7.5-5 summarizes the results for radioiodines and particulates in samples collected at offsite locations. The vast majority of samples did not contain detectable concentrations of radioiodines. The locations where detectable activity was found are consistent with the general pattern shown by the air sampling data and the onsite snow samples. The radioiodines were carried along the average wind direction to the southeast and also along a path to the ESE of the station toward Intersections Cl and 019. A review of the snow sample collection methods and analytical results suggests that the snow data should be interpreted judiciously. Interviews with personnel who performed the sampling and analyses have indicated that there was sufficient variability in snow collection depth, surface area, snow/ice density and counting geometry to significantly influence the results. A review of sample handling methods also suggests that the possibility of sample cross-contamination cannot be ruled out. 7.5.3 Drinking Water Samples Grab samples of tap water were collected onsite and composite samples. have been obtained from the Ontario Water District. These samples were analyzed by gamma spectrometry and results are shown in Table 7.5-6 for four representative radionuclides. No activity above background was detected. 7.5-3
TABLE 7 '-1 RADIOIODINE CONCENTRATIONS IN AIR SAMPLES COLLECTED OFFSITE BY THE SURVEY TEAMS, 1-25-82 Sam ling Period Average Concentration Location Start End (uci/cm3 of 133I) Intersection 41 1105 1115 9.5 + 2.5 x 10 11 1343 1413 8.2 + 1.8 x 10-11 Intersection 419 1233 1243 9.3 + 2.1 x 10 11 Refer to Figure 7 '-1 for location identifications
TABLE 7 '-2 RADIOIODINE CONCENTRATIONS MEASURED AT. AIR MONITOR 44 Time Period Sample Averaqea Air Concentration (uCi/cm ) Durin Period Start End ~Tpe 131I 132I 133Z 135I 1-25-82 1-25-82 AgX NDb 7 ' x 10-11 7.4 x 10-11 1.1 x 10 IO 0925c 1125 1-25-82 1-25-82 3.4 x 10 10 DCd 3.8 x 10 9 5.3 x 10 9 1125 1510 1-25-82 1-25-82 Part. 3.8 x 10-11 2.8 x 10-10 2.4 x 10 6.3 x 10-10 0925c 1510 Filter 1-25-82 1-29-82 AgX 1.4 x 10-12 ND 3~3 x 1012 ND 1500 0800 1-29-82 2-5-82 AgX <3.0 x 10 14 ND 1 3 x 10-13 ND 0800 0748 a ~ Average concentration sho~n assumes a constant, concentration during the sampling period. Not detected; the 364-kev peak was not seen in the gamma spectrum. Sampler operating prior to event; concentration computed assuming the starting time shown. Delayed count; the sample was counted 42 bours after collection, therefore any I present would have decayed prior to counting.
Table 7.5-3 tfeasured Concentrations (pCi/g) of Radionuclides in Samples of Snow and HeIted Snov Collected Within the Ginna Station Security Fence Radionuclide Concentration ( Ci/ ) Date Location 1311 1331 1351 134Cs 137Cs 55CO soco ~~Hn ssIIo 1408a 1-26-82 1100 Trans. Yard, Betveen Shield 6 6.6x10 1.6x10 1.8xlO 1.4x10 2.2x10 1.3x10 I.lx10 2.4x10 4.1x10 2.6x10 Door 22 1-27-82 1100 Snov Pile by East Pond 8.2KIO 7.5xlo I.lx10 1.4x10 1.2xlO 1.0xlo 3 Ox10 3 4x10 1100 Gas Storage Bldg. Roof, Ice 2.7xlO 2.8xlO 2.1x10 3.0xlO 9.3x10 I.lx10 1.5xlQ 2.Qx10 2.4x10 1100 Gate West of Transformer 2. Ix10 2.6x10 3.3x10 5.9x10 3.0xlO 3.4x10 5.3x10 8.7xlO 1.2x10 1-28-82 0300 Containment Dome 4.9xlQ 2.7xlO I.lxlO 1.5xlO 3.2x10 2.4x10 I.lx10 3.1xlO 0300 Turbine Bldg. Roof, Ice 5. IxlO 3.8xlO 4.4x10 I.IKIQ 7.6xlQ 1.6KIO 1.9x10 1.5x10 I-3Q-82 1500 Water Leating Into Aux. Bldg. 2.&x10 2.9x10 3.7x10 1.6xlo 3.9KIO 1600 Aux. Bldg. Roof, Snov 4.lx10 1.4xlO 5.6x10 2.0x10 1.3xlO 1615 E. Storm Sever by AVT, Water 1.4x10 1.8x10 2.4x10 1.7x10 2.QxlQ 7.2xlO 4.5xlO 1630 Aux. Bldg. Roof, 'Mater 1.3x10 1.9x10 1.5x10 2.5x10 1.4x10 1.6x10 8.0x10 4.6x10 1-31-82 0100 Inter. Bldg. Roof Drain Water 4.&x10 5.5xlO 7.2xlO 6.9xlO 9.5xlO 5.6xlO 1.4xlO 3.0x10 2-1"82 1815 Storm Sewer Water in Drive 6.6x10 ND 4.7xlO 6.9xlO 9.&x10 9.4x10 4.1x10 5.8x10
- a. Concentrations are all corrected for decay from 0930 1-25-82 to the=time of analysis.
- b. ND indicates the nuclide vas not detected. Detection limits at the time of analysis vere about 2x10 pCi/g.
Table 7.5-4 Measured Concentrations (pCi/8) of Radionuclides in Snow Samples Collected Onsite, Outside the Ginna Station Security Fence a Radionuclide Concentration ( Ci ) Date Time Location 1311 1331 1351 13%ps 137gs ssC so o s<Mn s Mo 1aoBa 1-25-82 1210 Outside Training Center 3. lx10 3.8x10 6.4x10 1.5x10 2.3x10 4.3xlO ND 6.4xlO 1.4x10 1509 Taille Yard 1.2xlo 1.0x10 1.8xlo 3.9xlO ND ND 5.8x10 ND 2200 Intersection Training Ctr Drive & 1.2xlo 2.2x10 6.4x10 3.4x10 ND ND ND 2.5x10 Manor House Drive 2200 Manor House, Near Pool 7.2x10 7.1x10 4.7x10 ND ND 9.9x10 1.5x10 2200 Plant Drive, N. of Deer Creek ND ND ND ND ND ND 2245 Field West of Taille Farm 2.0x10 2.3x10 3.5x10 2.2x10 ND 3.0xlO ND ND 6.3x10 ND 2315 Intersection Plant Drive and ND ND ND Training Ctr. Walkway 2320 Training Center Road ND 8.0x10 1.7x10 6.4x10 1.5x10 6.3x10 ND ND 1.1xlO ND 2335 Field, SW of Training Ctr. ND ND ND 1-26-82 0120 Field S. of Training Center 1.7xlO 7.5x10 4.1x10 3.8x10 4.0x10 3.2xlo ND 4.6xlO 2.2x10 1000 S. Side of Manor House S.gx10 l.lxlO 1.4x10 2.5x10 4.4x10 ND 6.4xlO ND 1000 Perimeter Fence, SE Corner ND 1000 Training Ctr. Drive & Manor House 5.8x10 6.6x10 1.2x10 1.6xlo 3.lxlO 1.0x10 2.2xlo 6.4x10 1045 Snow on Truck, Training Ctr. Lot 2.6x10 3.0x10 5.4x10 7.3x10 7.7xlO 4.4xlO O.gx10 3.3x10 1050 Snow on Truck, Training Ctr. Lot 2.5xlO 2.7x10 4.3x10 6.4x10 9.3xlO 4.3xlO 9.6xlO 3.0x10 1100 Training Center Parking Lot 4.8xlo 6.0x10 7.4xlo l.lxlO 1.9x10 l.lxlO 2.3%10 6.6xlo 1130 Field Between Plant Drive & I.lxlO l.lxlO 2.lxlO 1.5xl0 2.9xlO 5.0x10 7.0x10 l.lxlO Training Center Parking Lot
- a. Concentrations are all corrected for decay between 0930 1-25-82 and the time of analysis.
- b. -7 ND indicates the nuclide was not detected. Detection limits at the time of analysis were about 2x10 pCi/g.
- c. Only 1596 KeV Lanthanum-140 peak detected; Barium-140 calculated assuming equilibrium with Lanthanum-140.
e Table 7.5-5 Measured Radionuclide Concentrations (pCi/8) in Snow Samples Collected at Offsite Locations Radionuclide Concentration Ci t Time Location (C) 131I 133I 13SI ssCO ssMo 25-82 1430 Intersection 848'1 ND ND ND ND ND 1443 Intersection 5.5xl0 2.0x10 3.8%10 3.3xlO 5.4x10 1449 Intersectioa d8 ND ND'D 1457 Intersection 020 NDb 1500 Intersection Lake & Fisher ND 1505 Intersection //19 ND 1505 Intersection Lake & plant ND Entr. 1507 Iatersection 87 ND ND ND ND 1510 Iatersection /I6 ND ND ND ND ND 1515 Loomis Yard 4.8xlO 6.3x10 2.4x10 5.5xlO l.lx10 1518 Entrance to West Side of ND ND ND ND Substation gl3A 1545 Intersection P2 ND ND 1600 Intersection P10 ND ND 1610 Intersection 09 ND ND 1627 Intersection 8)2 ND ND ND ND 1630 Intersection 827 3.3xlO 2.5xlo 3.lx10 4.1xlO 1640 W. of Intersection i/24 ND ND ND 1642 Intersection f28 ND ND 1648 Iatersection 850 ND ND 1649 Intersection 831 ND ND 1653 Intersection 830 ND ND 1654 Iatersection 023 ND ND 1657 Intersection 829 ND ND ND 1707 Intersection 822 ND ND ND 1717 Intersection 821 ND 4.5xl0 ND 1718 Intersection 813 ND ND ND ND 2143 Intersection df6 3.9xlo 2.8x10 1.9xlo ND 2150 Intersection 81 ND ND ND 2157 Between Intersections dl & 82 ND ND ND ND 2209 Intersection 82 2.7x10 ND 5.0x10 ND 2226 Intersection 83 3.8x10 2.2xlO ND 2230 Fence N. of Inter. 83 7.2xlO ND 1.3x10 ND 2305 Inter. Knickerbocker & 6.6x10 7.0xlO l. lx10 5.5x10 l.lxlO Bailey 2310 Loomis House 2.1xlO 6-82 1000 Intepsection 819 2.2x10 2.3xlO 3.9xlO 9.5xlo 1.3xlO 1555 Inte'rsection 83 ND . ND ND Concentrations are all corrected for decay between 0930 1-25-82 and the time of analysis. ND indicates the nuclide was not detected. Detection limits at the time of analysis were about 2x10 7 pCi/8. Figure 7.5-1 for intersection locations, Also detected 6.2x10, 9.4x10 and 2.4xlO pCi/8 of Cs, Cs and Ba, respectively. Also detected 3.3x10, 5.8xlO and 1 ~ 2x10 pCi/8 of 13aCs, 131Cs and Ba, respectively.
TABLE 7.5-6 Measured Concentrations of Radionuclides in Water Samples Water Concentration (uCi ml) Location Date 131I 58Co 140Ba 137Cs Onsite 1-30-82 <2 x 10 8 1 x 10-8 <2x 108 <1 x 108 Tap Water 1-31-82 <6 x 10"8 3 x 10-8 <3 x 10-8 <3 x 10-8 Ontario Water Works Grab 1-30-82 <3 x 10 <1 x 10 <2 x 108 1 x 10-8 Composite 1-22/1-26-82 <3 x 10 8 <1 x 10 <2 x 10-8 <1 x 10 Composite 1-26-82 <2 x 10 8 <1 x 10-8 x 1Q-8 1Q 8 Composite 1-30/2-1-82 3 x 10-8 1x108 1 x 10-8 <1 x 10 8 Composite 2-2-82 <4 x 10-8 <2 x 10-8 <3 x 10-8 <2x10 Composite 2-3-82 <2 x 10 8 <6 x 10 9 <1 x 10-8 <7x109
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23 TRuMMOHOS 22 F'" v Rn Ro FAR WORTH Ro 46 33 50 47 d 2 SM(TN Rg l FIGURE 7.5-1 NUMBERED INTERSECTIONS 2 O CORRESPONDING TO AIR AND SNOPl OFFSITE 25 SAMPLING LOCATIONS Pl Oc l 2 O I X O 0 tr) O 32 O
7.6 TLD Measurements Thermoluminescent dosimeters (TLDs) are located at 32 offsite locations (Figure 7.6-1) including 11 located along the site boundary (Figure 7.6-2). Additionally, TLDs were placed at 9 other locations by the offsite survey teams on January 25, 1982 immediately following the incident (Locations A-I, Figure 7.6-1). The USNRC had TLDs located at 27 offsite locations (Figure 7.6-3), and the State of New York had two TLD locations on site (Figure 7.6-2). Ten RG&E offsite TLDs, 31-40, are located on a five mile radius from the plant and 10 are located on a 10 mile radius from the plant (locations 8-12 and 25-29). Table 7.6-1 shows the location, the measured uncorrected TLD dose and the expected TLD dose for the RG&E TLDs. The expected dose is prorated from the third quarter of 1981 which was the last, time the same set of TLDs was in the field. Table 7.6-3 provides the same information regarding NRC TLDs. The NRC expected TLD doses were calculated using data from the fourth quarter of 1981 and prorating'or the shorter exposure period. The error given in both tables is the one-sigma statistical error only. The expected dose, representative of normal background, for the TLDs placed at, field locations A through I was calculated to be 3.5mR. This is the sum of the residual background for freshly annealed TLD (2.6 mR), 4 days of normal environmental exposure (0.6 mR), and 19 days of storage in a lead box assuming a factor of 10 for shielding from natural background (0.3 mR). In both the RG&E and NRC offsite TLD data, no dose was measured which was statistically different from the normal background. This is expected since the maximum whole body dose at the site boundary from noble gases was estimated to be 0.07 mrem (see section 7.7). This low level of incremental dose could not be determined by the TLDs due to the magnitude and variatibn of the natural radiation background. Table 7.6-6 shows the results of measurements obtained from the two sets of onsite TLDs belonging to the State of New York. Both sets had been placed in the field on January 4, 1982. The TLD set placed west of the plant was collected at, approximately 1600 on 1/25/82. The set of TLDs that had been placed on a lighting pole southeast of the plant (approximately 30 meters east of RG&E TLD location 44) was collected at about 1800 on 1/25/82. noted during numerous onsite radiation surveys following the It was event that considerable surface deposition had occurred in proximity to the State TLD set near location 44 (see Section 7.4), which probably contributed significantly to the exposure measured. 7.6-1
The only apparent indication of a measurable incremental TLD dose from the RG&E onsite TLDs (Table 7.6-4) was found at Location No. 4 situated approximately 300 meters downwind of the release point and 50 meters southeast of the Emergency Survey Center. This location corresponds to the approximate centerline of the release plume as determined by meteorological and survey measurements., Measurements of direct radiation levels from snow deposition in proximity to Location No. 4, indicated that ground deposition alone may have accounted for most, if not all of the dose received by that TLD between January 25 and January 29 (see Table 7.6-5). This conclusion is consistent with the predicted plume centerline gamma dose rates at approximately the No. 4 location as discussed in Section 7.7.4. 7.6-2
TABLE 7.6-1 RG&E OFFSITE TLDs Period of Exposure 12/29/81 - 1/29/82 Location (see Figure 7.6-1) Measured Dose Ex ected Dose mR 8 5.6 2 2.4 6.3 2 1.0 9 7.0 2 1.3 6.3 2 0.5 10 6.9 2 0.3 7.4 2 1.7 11 5.8 2 0.1 no data 12 4.9 2 1.3 6.3 2 1.1 25, 5.0 2 0.2 4.2 2 0.2 26 4.8 2 0.4 3.5 i 0.4 27 missing 28 5.7 2 1.3 5.5 2 0.4 29 6.1 2 0.7 8.1 2 3.3 30 5.5 2 0.6 3.5 2 0.5 31 6.0 2 1.6 no data pa 7.9 2 2.4 no data 33 6.9 2 0.3 5.2 t 0.4 34 missing 35 missing 36 4.6 2 0.6 4.9 2 0.4 37 5.8 2 0.9 5.1 2 0.9 38 5.1 2 0.2 4.8 2 0.6 39 6.3 2 0.1 6.3 2 0.2 40 5.2 2 0.5 5.1 2 0.5 Period of Exposure 1/25/82 - 1/29/82 (annealed 1/6/82 and stored in lead box) A 3.4 2 0.1 approx. ~ 3.5 B 3.1 t 0.4 C 3.7 2 0.5 D 3.3 2 0.1 E 3.4 2 0.1 F 3.6 2 0.1 3.5 2 0.2 3.5 2 0.3 3.5 2 0.9
TABLE 7.6-2 RG&E SITE BOUNDARY TLDs Period of Exposure 12/29/81 - 1/29/82 Location (see Figure 7.6-2) Measured Dose mR Ex ected Dose mR 14 2.5 2 0.6 4.7 2 0.5 15 t 3.4 0.3 6.0 2 0.4 16 5.5 2 0.7 no data 17 6.6 2 0.1 6.5 2 0.4 18 7.5 2 2.4 6.9 i 0.6 19 6.1 2 2.4 6.3 2 2.0 20 missing 8.3 i 0.3 21 7.0 2 0.5 6.7 2 0.7 22 7.6 2 1.3 7.5 2 1.0 23 5.2 2 0.8 6.4 2 0.3 8.3 2 1.1 8.7 i 3.3
TABLE 7-6-3 USNRC TLDs Period of Exposure: Ol/04/82 01/27/82 DISTANCE MEASURED EXPECTED LOCATION (MILES) DOSE (mR) DOSE (mR) 1~7 6 ' 1~2 6 ' + 0.6 1 ~ 1 6~1 1~0 6' + 0.6 1~7 6' 1 ~0 6 ' + 0.3 1~5 7 ' 0' 6.7 + 1.5 1.4 7' 0' 6 ' + 0' 1~6 6 ' 0' 6' + 0' 0' 7' 2 ' NO DATA 0.6 7' 0~6 7 ' + 1 6~ 10 1 ~ 5 6 ' 0' 7.0 + 0.6 4 ' 6 ' 0.6 7'1 + 0 ' 12 3~8 6' 0.4 6' + F 9 13 4 ' 6 ' 2' 6 ' + 0' 14 3' 7' 1 ~8 6 ' + 0 ' 15 3' llew 7 ' 1 ~ 1 6.1 + 0.3 16 3' 6~7 0.2 7' + 0' 17 3 ' 6' 0' 6 ' + 0' 18 4' ,7 ~ 6 0' 6' + 0' 19 4' 7~2 1 ~ 1 7.0 + 0.6 20 6 ~ 2' 6~2 2 ' 5' + 0' 21 ' 7 ' 2' 6' + 0' 22 12 ' 6' 1.9 6 ' + 0' 1 7~5 1~8 6 ' + 0-7 24 13 ' 7 ' 1.4 6' + 0 4 26 16 ' 7 ' 1~2 6' + 0' 27 14 ' 7' 1~5 6 ' + 0' 28 6 ' 7 ' 1~6 6 ' + 0' 29 0' 7' 2 ' 6 ' + 0' (a) See Figure 7.6-3
TABLE 7.6-4 RG&E ONSITE TLDs Period of Exposure 12/29/81 - 1/29/82 Location (see Figure 7.6-2) Measured Dose mR Ex ected Dose mR 2 5.8 2 0.4 5.9 2 0.1 3 5.7 2 0.2 6.1 2 0.3 4 21.7 i 2.7 6.4 2 0.9 5 8.5 2 1.2 8.5 2 2.1 6 5.5 2 0.4 5.6 R 0.1 7 5.9 2 0.8 6.4 2 0.5 13 4.8 2 2.3 6.2 2 0.5
TABLE 7.6-5 ESTIMATED DIRECT RADIATION COMPONENT DUE TO BACKGROUND AND DEPOSITION AT TLD LOCATION NO- 4 Period Estimated Avera e mrem r Total mrem 12/29/81-0930 hr, 0.006 1/25/82 1200-2359 hr, 0.6(') 1/25/82 0000-1159 hr, 0 4(1) 1/26/82 1200-2359 hr, 0 14(1) 1.6 1/26/82 0000-1000 hr, 0.02 1.2 1/27/82-1/29/82 Sub Total 18 mrem Plus average TLD residual reading 2.6 mrem Total 20.6 mrem Notes:
- 1. Determined by Eberline RM-14 survey meter with HP-190 end window GM probe, measured 3 feet above ground.
- 2. Determined by Reuter Stokes Pressurized Ion Chamber, RS-111, measured approximately 3 feet above ground.
TABLE 7.6-6 NEW YORK STATE ONSITE TLDs Period of Exposure 1/4/82 1/25/82 Measured Dose (mR)'(b) WEST SET (collected 1600 1/25/82) 1 3 2 3
'9
'5 3 - 4 '
4 BAD Average Reported 3.91 + 10% SOUTHEAST SET (collected 1800 (a) 1/25/82) 1 8 2 - 9
'8
'4 3 9 4
'4 9 '1 Average Reported 9.39 + 108 Note refer to Figure 7.6-2 for locations as reported by New York State in a communication to the RG&E Emergency Operations Facility, from E. Carter (NYS Health Dept.), 1/26/82.
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0 FIGURE 7.6-3 LOCATIONS OF NRC THERMOLUMINESCENT DOSIMETERS
'PERIOD OF EXPOSURE 01/04/82 - 01/27/82 1~ 19 QHT*RIE QH THE LAKE+
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X O Ih BosTok RD, BlttCK C HlpRCH Ro~ 12 CEELEY O BaggE EAT( veooARD Ro. EJ O Ro. Wit.t ITS 18 Ro. O Ro. W Y. I \J Z BElt G R D. 0o 'Y KEHvoe R LJ O O tA RTC. i 4 Y C$ X EHGERR PADDY LAHE HALET Ro. Rn'auMMOl DE Fig v RD. O LOCATION MEASURED DOSE (mR) Ck le Z 6.8 + 1.2 2 6.1 + l.o P I Z 3 6.6 + l.o O 7.4 + o.8 5 7.2 + o.8 6 6.7 + o.5 7 7.8 + 2.5 8 7.5 + o.6 O lo 6.8 + o.6 tA 12 6.3 + O.4 aJ 13 6.5 + 2.3 I 14 7.o + 1.8 e 15 16 17 7.2 + 1.1 6.7 + o.2 6.9 + o.8 18 7.6 +'o.6 19 7.2 + 1.1 29 7.8 + 2.8
7.7 Estimated Offsite Doses The estimated offsite doses resulting from the steam generator tube failure are discussed in the following sections. The estimates are based on the radionuclide release estimates given in Section 7.2 and on the observed concentrations of radionuclides in the environment. Dose pathways evaluated include inhalation, external exposure and ingestion. The nearest point of public exposure in the downwind area, a 50 degree sector in the center of the southeast quadrant, is approximately 600 m from the release points; the distance to Lake Road is somewhat greater. The atmospherig dispersion factor for a distance of 600 m downwind is 2.7 x 10 sec/m for the mean wind speed of 6.7 m/sec (refer to Section 7.3). The nearest public drinking water intake (Ontario Water District) is located approximately 1.1i miles east: of the< Ginna'lant. 7.7.1 Plume Exposure Pathways 7.7.1.1 Inhalation of Radioiodines Inhalation of airborne radioiodines is a potential exposure pathway for persons in the path of the plumes that resulted from the several short releases that occurred at approximately 0926, 1018, 1027, 1037, 1119 and 1137. The total releases of radio-iodines were 27, 680, 290, 77, and 340 mCi for I, I, I,
~I and I. respectively.
An upper bound for the possible thyroid dose was computed using the following assumptions: (a) the exposed individual was an adult at. the center of the pl~e yt 600m breathing at theradio- rate for light exercise (3.47 x 10 m /sec), (b) all of the iodines released remained airborne, and (c) the dose conversion factors for radioiodines given~ in Regulatory Guide 1.109 are applicable. Using these assumptions, the maximum potential thyroid dose to any individual is estimated to be 2 mrem.known This estimate is conservative for two reasons. First, it is that a significant fraction of the radioiodine release was deposited near the release point. Second, because the wind direction was quite variable, it is unlikely that the plume centerline would have coincided with the location of an individual throughout the period of potential exposure. Inhalation of airborne radioiodines by teenagers and children were alamo considered. The average breathing rates and dose conversion factors given in Regulatory Guide 1.109 were used to make dose estimates for these groups. The computed doses to teenagers and children located 600 m from the release point were less than that given above for the adult. 7~7 1
The radioiodine concentration measured at, Intersection Ol (see Section 7.5.1.1) can be used to estimate the thyroid dose that could have been received by an adult working outdoors at the Ontario Water District treatment facility, near Intersectioy101. If the> I concentration is assumed to have averaged 9x10 pCi/cm for hours, ' 1100-1700, the projected thyroid dose is 0.25 mrem from 6 I and about 0.5 mrem if the other (undetected) radioiodine isotopes were present in proportion to the quantities released. 7.7.1.2 External Exposure to Noble Gas The principal contribution to this external exposure is the approximately 26 Ci of noble gases released primarily from the air ejector and gland seal off-gas. An upper bound for the external exposure from the plume was computed in a manner similar to that used above to estimate the maximum thyroid exposure. The exposed individual was again assumed to be on the plume centerline at 600 m throughout the period. The dose conversion factors from Regulatory Guide 1.109 were used to estimate the dose. Those factors assume that the peak concentration is uniformly distributed throughout a semi-infinite cloud and therefore overestimate the exposure from a finite plume. Decay of radioactive noble gases during the 1.5 minute transport period was ignored. The maximum whole body dose from the plume was estimated to be 0.07 mrem. The maximum beta skin dose was estimated to be 0.04 mrem. The maximum whole body and beta skin dose rates were estimated to be 0.6 and 0.3 mrem/hour respectively, and persisted for a period of about four minutes. Approximately 60% of the whole body and skin doses from noble gases would have been received during that time. 7.7.1.3 Inhalation of Particulate Radionuclides and Tritium The maximum dose from radioactive particulates and tritium was estimated using the same assumptions employed in the radioiodine inhalation calculations. As noted previously, it is known that deposition near the release point substantially reduced the airborne radionuclide concentrations. The effective whole body dose was estimated using dose conversion factors from Regulatory Guide 1.109 and the weighting factors in ICRP Publication 26. (It was conservatively assumed that doses to the smal intestine and upper large intestine were equal to those computed for the lower large intestine). The maximum effective whole body dose from particulate nuclides and tritium was estimated to be 0.1 mrem for an individual continuously in the plume 600 meters downwind. The maximum lung dose was calculated to be 0.5 mrem for an j.ndividual at the same downwind location. 7.7.1.4 Summary of Maximum Doses from Plume The doses computed in previous sections can be used to estimate the maximum effective whole body dose that could have been received by an individual exposed to airborne radionuclides. The estimated maximum effective whole body dose at 600 m from the release points is 0.2 mrem. 7~7 2
- 7. 7.2 Maximum 40-Mile Population Dose The maximum 40-mile population dose was estimated for the releases that occurred following the steam generator tube rupture. A set of simplifying conservative assumptions'as'sed'o. bound'he population dose. As in the previous calculations, it was assumed that no depletion of the plume occurred and decay of short-lived nuclides in transit was ignored. The total populations of three downwind 22.5 degree sectors given in Ginna Station Procedure No.
SC-1 were assumed to be located on the plume centerline throughout the exposure period. Using these assumptions, the maximum effective whole body dose to the affected group (148,000 persons) is esti-mated to be 0.2 'person-rem. The estimated maximum dose is com-parable to that delivered to the same group by natural background radiation in a period of about 10 minutes. 7.7.3 Potential Ingestion Pathways Ingestion of potentially contaminated water and fish is a possible exposure pathway foll'owing snow melt and runoff. If the ground were frozen when the melting occurred, much of the radioactivity deposited in the snow could enter Lake Ontario. An estimate on the potential doses to those drinking water from the nearest drinking water intake (Ontario Water District 1.1 East of Ginna) was computed by making the following assumptions:
- a. All the released radionuclides were deposited on the snow in the 50-degree sector within 600 m of the station. This is a conservative assumption because a substantial portion (>50%)
of the most highly contaminated snow within the plant security fence was plowed up and is presently stored in an enclosed onsite storage bunker.
- b. A sudden major thaw melts all the snow and the contaminated water all enters the lake via Deer Creek and o'ther local drainage routes.
- c. Dilution in lake water between the runoff points and the nearest water supply reduces the initial concentration to 1/20 of the original value.
- d. Water consumption rates and dose conversion factors for the local population are the same as those in Regulatory Guide 1.109.
- e. The exposure occurs during a 10-day period during and after the. runof f.
Because, at the time the evaluation was performed, meteorological forecasts provided assurance that the assumed major thaw would not occur prior to February 10, that date was selected for cal-7~7 3
culation of the maximum radioactivity in the runoff. Table 7.7-1 contains the amounts of released radionuclides that would remain on February 10, 1982. Also shown in Table 7.7-1 is the estimated maximum concentration in runoff water and corresponding maximum permissible water concentrations (10CFR20, Appendix B) for unrestricted areas. The volume of drainage water was estigatyd using only part of the Deer Creek drainage basin, 2.3 x 10 m within 800m2of the site, and a measured available water volume of 30 liters/m . The minimal drainage basin size,was used conser-vatively in lieu of a detailed evaluation of flooding following the hypothesized snow melt. Under the assumed conditions and no additional snowgll occurs,'he. radioactivity would: be con-if tained in 6.9 x 10 ml (18 million gallons) of runoff water. The daily intake of the Ontario Water District is about 2 million gallons/day at this time of year. The initial concentrations expected under normal conditions would be many times lower than those shown in Table 7.7-1 because:
- a. a large fraction of the deposited radioactivity in snow was plowed up and is being held for radioactive decay;
- b. precipitation prior to melting would cause dilution;
- c. 'he drainage area is greater than that assumed; and,
- d. seepage of runoff into the soil during the spring thaw would reduce the activity reaching the lake.
The individual dose commitment that would be received by adults and children under the assumed conditions is estimated to be 0.06 mrem for the 10-day period. The maximum population dose from drinking water is estimated to be 1.3 person-rem during the =same period. Although grounds~ fish consumption is another hypothetical ingestion pathway, the potential dose to an individual is considered negligible. No commercial fishing is done in the region around Rochester, and little if any recreational fishing occurs during winter months. In addition, fish samples collected subsequent to the incident have indicated no radioactivity above natural back-7.7.4 Comparison of Predicted and Measured Dose Rates Near the ESC The noble gas gamma dose rate predicted for the plume centerline at 300m downwind from the gland seal exhaust line can be compared with'he. readings of'he) monitor attached'o'he outside of the building housing the ESC. The maximum gamma dose rate was pre-dicted to be -1.3 mrem/hr following the 0926-0930 release. The average dose rate for the next half-hour (0930-1000) was predicted to be -O.ll mrem/hr. After 1000, the predicted dose rates were all less than 3.3 pR/hr. The exposure rates measured by the monitor reached approximately 0.2 mR/hr soon after the tube rupture. The maximum observed value was about 1/6 of the predicted value. This is not surprising because (a) the calculated value assumes a semi-infinite cloud, (b) the building provides partial shielding of the detector, and (c) the monitor location may not have been on the centerline of the released activity. 7.7-4
The exposure rate measured between 0930 and 1000 was comparable to the predicted value. However, the plot (Figure 7.4-1) shows that the exposure rate is declining with a half-life of -30 minutes during the period, suggesting that the monitor was responding principally to short-lived noble gas daughters (e.g., Cs) during that period. The dose rates measured at later times resulted mainly from deposition of activity in snow near the ESC. 7.7.5 Comparison of Measured and Predicted Activities Near the ESC The airborne radioiodine concentrations measured at Air Monitor 44 can be compared with predicted values. The predicted time-integrated concentrations of radioiodine on and near the plume centerline, assumed to be the direction of the mean wind (310-320'), are shown in Table 7.7-2. Also shown are the observed time-integrated concentrations for Air Monitor 54. The observed concentrations are 4-6 times those predicted for the plume centerline and 6-10 times those predicted at the off-centerline location. The predicted concentrations are for a ground level release under Class D stability conditions with u = 6.7 m/sec and consider initial diffusion in the building wake. Aerodynamic downwash of the steam plume was observed during the morning; the plume was observed to touch the ground near the security fence. It is believed that uncertainties in the dispersion parameters are the most likely cause for the differences shown in the table. 7.7.6 Summary of Estimated Doses Table 7.7<<3 provides a summary of estimated offsite doses resulting from the Ginna tube rupture incident. The calculated doses are considered best, estimates. Uncertainties associated with release estimates, meteorology and other analytical models could result in lower or higher dose values than those shown in Table 7.7-3. Scaling the Table 7.7-3 estimates upward by a factor of 3-4 would provide a conservative upper bound. This results in doses that are still less than 10 percent of the yearly natural background radiation received by all residents in the Rochester, N.Y. area. 7.7-5
TABLE 7. 7;1 MAXIMUM AMOUNTS OF RADIOACTIVITY IN RUNOFF FROM SNOW MELT AND ESTIMATED MAXIMUM CONCENTRATIONS Maximum Permissible Concentration, Activity (Ci) Estimated 10 CFR 20, App ~ B Activity Remaining at Maximum Runoff Table II, col. (uci ml) 2 Radionuclide Released (Ci) 1130, 2-10-82 Concentration (uCi/ml) 131Z 0.027 0.007 9.7 x 10 8 3x107 132I 0.680 10-6 < 2 x 10-11 8 x 10-6 133I 0 '90 10 6 < 2 x 10-11 1 X 10-6 134I 0.077 10 6 < 2 x 10-11 2x105 135Z 0.340 10-6 < 2 x 10-11 4 x 10 6 54Mn 0.021 0.020 2 ' x 10 1 x 104 58Co 0.024 0.021 3.0 x 10 7 9x105 60Co 0.007 0.007 1.0 x 10 7 3x105 99Mo 0.009 0.0002 2 ' x 10 4 x 10 5 134Cs 0.003 0-003 4.1 x 10-8 9 x 10 5 137Cs 0.005 0-005 7.7 x 10-8 2 x 10 140Ba 0.290 0.120 1.7 x 10 6 2 x 10 3H 4.67 4.67 6.7 x 10 3x103
TABLE 7 '-2 PREDICTED AND MEASURED AIR CONCENTRATIONS NEAR THE EMERGENCY SURVEY CENTER Time-Integrated Concentration (uCi-Sec/m3) Predicted Predicted, Off- Measured Release Centerline Centerline at Air Radionuclide (Ci) (300 m) (300 m, 9=7 5o)a
~ Monitor 04 131I 0 '24 1 ~ 3 0 '4 5.4 133I 0.29 16 10 102 135Z 0 '4 18 12 85 aApproximate location of Air Monitor 44 ~
TABLE 7.7-3
SUMMARY
OF ESTIMATED OFFSITE DOSES RESULTING FROM GINNA STEAM GENERATOR TUBE RUPTURE INCIDENT 1/25/82 Maximum Estimated Dose Pathwa Offsite Dose (mrem) PLUME 0' (lung) Inhalation 2 (thyroid) 0~1 (effective whole body) Direct Exposure 0.07 (whole body gamma) from Noble Gas Plume 0.04 (skin beta) INGESTION Drinking water 0.06 (effective whole body) Population Dose from Plume 0.2 person-rem Population Dose from 1.3 person-rem Ingestion Note: Refer to Section 7.7 for assumptions used as bases for these dose estimates. These calculated doses are considered best estimates. Associated uncertainties could result i.n lower or higher values. Scaling dose estimates upward by a factor of 3-4 would establish a conservative upper bound estimate of doses. Upper bound values are still less than 10 percent of yearly natural background radiation levels in the Rochester, New York region.
7.8 Additional Radiolo ical Information 7.8.1 Comparison of Releases Due to Tube Rupture Event With Ginna Technical Specifications Ginna Technical Specification Section 3.9.2 establishes limits for controlled releases of airborne radioactive material to unrestricted areas. The Ginna incident, by its very nature, did not constitute a controlled release and the Technical Specification therefore is not applicable. However, the following release comparisons are presented for purposes of perspective. Specifically, subsection 3.9.2.1 limits the maximum release with rates of gross activity, except airborne iodines and particulates half-lives greater than eight days in accordance with the following equation: i (MPC
< 2.0 x 10 5 (m 3
/sec) where Qi is the release rate (Ci/sec) of any radionuclide i, and (MPC) is the maximum permissible concentration in air as specified in Column 1, Table II of 105CFR3Part 20, Appendix B (pCi/cmof ).
The coefficient of 2.0 x 10 (m /sec) reflects the degree long-term average atmospheric dilution determined for the site boundary. The release rate limit. specified under subsection 3.9.2.1 is treated as an instantaneous release rate limit, allowing no credit for time-averaging. The highest release rate of gross activity in the form of noble gases occurred between 0926-0930 on January 25, as shown in Table 7.2-3. Taking the sum of Qi(Ci/sec) divided gy pe MPCi for each radionuclide, the sum of (Qi/MPCi) = 5.4 x 10 m /sec, which is larger than Technical Specification 3.9.2.1 by a factor of 2.7. Proposed Radiological Effluent (Appendix I) Technical Specifi-cations for Ginna have incorporated provisions for time-averaging noble gas releases over 24 hours. Allowance for time-averaging over a minimum of ll minutes would have resulted in a value lower than contained in this Technical Specification during the January 25 noble gas release. The release rates of airborne radioactive iodine and particulates with half-lives longer than eight days are limited under subsection 3.9.2.2 of Ginna Technical Specifications as follows: i MPC
< 2.9 x 10 (m /sec) where the terms are the same as above. The atmospheric dilution coefficient has been reduced by a factor of 700 (to account for the air-grass-cow-milk iodine pathway) and, under subsection 3.9.2.2, time-averaging over 24 hours is permitted.
7.8-1
Estimated releases of ~~~I and particulates radionuclides following the tube rupture event. are presented in Table 7.2-6. Taking the 24-hour-averaged releyse3rates for each radionuclide, the sum of (Qi/NPCi) = 9.82 z 10 m /sec, which is larger than Technical Specification 3.9.2.2 by a factor of 34. The release rate limit reduction factor of 700 is inappropriate .when applied to QylJanuary 25 releases because a) to apply only to it is intended I, and b) is intended to account for possible milk pathway effects during the grazing season. 7.8-2
7.9 Recommendations The following short term actions have been deemed appropriate to characterize and monitor the radiological impacts of the tube rupture event:
- 1. Perform detailed radiochemical analyses of reactor coolant and "B" steam generator samples. These samples were shipped to Science Applications Inc. (SAI) on February 2, 1982 for gamma isotopic, tritium, transuranic, and strontium determinations.
Preliminary results have been received and are under current review by RG&E. Gamma isotopic results are in reasonable, agreement with values presented in Tables 7.1-1 and 7.1-2. Additional gamma emitters identified in the 1/25/82 "B" S/G sample include:3 Cr, Fe, Sr, Zr, Ru, Te, and Cs (all are 6 x 10 pCi/g or less).. All "B" S/G transuranics: measured on 1/25/82 were found to be in low concentrations (5 x 10 pCi/g or less). Strontium-90 concentration in the "B" S/G was determined to be 1 x 10 pCi/g. Although these additional analytical results have not been incorporated in the preceeding radiological estimates, their contribution to the overall estimated doses is believed to be small.
- 2. Increased sampling frequency of surface, ground water and fish according to the following schedule:
Sample Collection Water TZpe Fre enc A~nal sis Ontario Water, Gross beta, District Intake Composite 3 times/wk Gamma isotopic Ginna Circ. Gross beta, Water Discharge Composite 3 times/wk Gamma isotopic Grab or Gross beta, Deer Creek Composite 3 times/wk Gamma isotopic Gross beta, Tap Water Weekly Gamma isotopic Gross beta, Well Water Weekly Gamma isotopic Gross beta, Pish, edible Monthly Gamma zsotopzc This schedule will be followed until May 2, 1982, at which time sampling type and frequency will be re-evaluated according to monitoring results. 7.9-1
- 3. Continue Ginna environmental monitoring program as currently conducted, with the inclusion of onsite soil samples in proximity of Deer Creek, Training Center and onsite vegetable garden and quarterly direct radiation survey with micro-R-meter or equivalent, method.
- 4. Processing and/or controlled release of collected contaminated snow now stored in Radwaste Building bunker, based upon sampling and normal plant, discharge procedures.
- 7. 9-2
8' RECOMMENDATIONS 8.1 Procedures 8.1.1 Short Term Procedure Changes Only a small number of significant short term procedural changes to procedure E-l.4, "Steam Generator Tube Rupture", were considered necessary. These are listed below. Other minor changes, primarily of an editorial nature, were also made. In addition, Emergency Procedures E-l.l, "Immediate Action and Diagnostics for Spurious Actuation of SI, LOCA, Loss of Secondary Coolant, and Steam Generator Tube Rupture"; E-1.2, "Loss of Reactor Coolant"; and E-l.3 "Loss of Secondary Coolant" will also be reviewed and revised as necessary based on changes being made in E-lan
\
Add CAUTION in STEP 3.0 "CAUTION: The Technical Specification limit cooldown of 100oF per hour should not be exceeded." STEP 3.9.3 Change to read, "put atmospheric steam dump con-troller in the manual closed position". This change will clarify that the controller is to be put into manual, but that the valve itself need not be manually closed. Add STEP 3 ~ 11 ~ 1 "Reset SI if the BAST swap over has occurred." This will ensure that the SI pumps are drawing from the RWST when SI is resets SI reset is required to regain use of instrument air, and to perform other manual actions. Add to STEP 3.15.3 After "and an indicated water level of 20% has returned to the pressurizer" add the following "and the RCS THOT is 30 F subcooled per the the core exit thermocouples, or, as a backup, the saturation meter in the unaffected loop. Add NOTE After STEP 3.15.3 "Termination of SI with suspected voids in the upper RV head is allowed when natural circulation is verified'Refer to 0-8)" This note serves to eliminate hesitancy in terminating SI when the SI termination criteria are met and natural circulation is assured. 8 '-1
Add STEP 3 '6 ' "Operate the fans." CRDM and reactor compartment cooling This will help cool the reactor vessel head region, and minimize reactor vessel head-to-RCS bT. Add to CAUTION After STEP 3 '7 F 1 "If <30 until F 50 F subcooling, reinitiate SIP operation subcooling is established. Monitor 50 F subcooling subsequently." Add NOTE after STEP F 18 "NOTE: The RCP may be started with a full pressur-izer, if the core exit thermocouple temperature is > 330oF." This note serves to eliminate hesitancy to start an RCP with a water-solid pressurizer. Although this change has been made in the procedure, the RCP restart conditions are currently under review by Westinghouse. A@a STEP 3.19.1 "Isolate reject to contain the possibly contaminated hotwell, until activity sample allows water usage. CAUTION: Do not overfill the condenser". This step lessens the contamination of the condensate system in the turbine building, thus lessening the contamination of the feedwater for the good SG, as well as the turbine building in general. Add STEP 3.20.3 "Block SI before the faulted S/G drops below 550 psig." This will prevent SI re-initiation due to low SG pressure. Add STEP 3 '4 ' "Degassify and clean-up the as quickly as possible." RCS as soon as and. 8 '-2
Since reactor coolant system pressure is dropping, number 1 seal flow or dp will become too low to operate the RCPs. Operation of the RCPs makes cleanup easier. Add to STEP 3.25 "...permit, as soon as possible and cooldown to < 200oF." By cooling down the RCS using the reactor coolant pumps, such action will serve to minimize the potential for creating steam bubble in the a RCS ~ Add 3 '7 ' "Depressurize the non-faulted S/G by opening the atmospheric steam dump valve." Such action'erves to reduce the possibility of forming a bubble in the steam generator U-tube region. 8.1.2 Long-Term Procedure Changes and Areas of Recommended Study The following are recommendations to consider for long-term procedure changes. Attempt to eliminate RCP trip criteria from steam generator tube rupture criteria or provide additional options to maintain RCPs in operation. Add a section to the procedure to address operation with the faulted steam generator full of water. Provide additional detailed guidance relative to operator action in the event of real or suspected void formation in the reactor vessel upper head. Provide additional guidance relative to operator actions to be taken in the event of a water solid pressurizer, especially with regard to reactor coolant pump restart. Provide additional guidance relative to long term cooldown using only natural circulation. 8 '-3
This section summarizes recommendations regarding equipment addition or modification resulting from the incident. The recom-mendations fall into two categories, short term and long term Short ~ term modifications will be completed prior to plant startup from the current outage. Long term recommendations include those which are not required for safe operation and which require further investigation prior to determining beneficial and feasible. if the change is 8.2.1 Short Term The following equipment-related recommendations will be implemented prior to startup. Modifications to the pressurizer PORV control systems have been completed. The existing restrictions have been removed from the vent port of solenoid valve SV-8620A and a new check valve has been added between the solenoid valve and PCV 430. The dish in the check valve has been drilled to provide the PORV vent path orifice. Filters have been added in the air supply. The same modification has been performed in the vent path for PCV 431C. See Section 5.2.5 for details. A containment isolation signal has been provided to letdown stream valves LCV427, AOV200A, AOV200B, and AOV202 ~ See Section 5' for details'he alarm setpoints for the main steam radiation monitors and the air ejector radiation monitor will be adjusted to a lower levels In addition, the steam line high range radiation monitor will be repaired. See Section 5.6 for details. The position indication for the main steam power operated relief valves and the main steam safety valves will be repaired. See Section 5.6 for details. During calibration of RCS subcooling meter, it was discovered that the monitor indicates 1/2 of the actual margin when below 500 F and indicates the actual margin above 500 F. Interim procedures were in place at the time of the incident which ensured that the operators obtained the actual subcooling margin from the meter indication. This has been corrected so the monitor indicates the actual subcooling margins 8.2.2 Ipng Term The following equipment-related recommendations are among those being considered for implementation but are not required for plant restart. 8~ 2-1
The logic for the 1C safety injection pump will be modified. See Section 5.8 for details. To permit reactor coolant pump trip at lower reactor coolant system pressure, a qualified wide-range pressure transmitter with indication on the front of the main control board desirable. This modification was already in progress prior to this incident and it is expected that this modification will be completed prior to startup. Control room recorders for main steam line pressure are desirable'
'-2
APPENDIX A Chronology Ginna Steam Generator Tube Failure Incident,
Appendix A Chronology Ginna Steam Generator Tube Failure Incident Date T1m8 Event Descri tion 1/25/82 0922 100% steady state no previous indication of steam generator tube leak Reactor Coolant Loop (RCL) System Pressure (transmitter P420) 2197.1 psig (Normal reading) T 572.4 F PMsurizer pressure 2235 psig 1/25/82 0925 All four pressurizer pressure channels on low alarm. Average of four channels was 2169 psig. Alarm setpoint 2185 psig Almost simultaneous control board alarms include:
- 1) Charging pump speed
- 2) S/G Level Deviation (B S/G)
- 3) "B" Steam Generator steam-flow/feedflow mismatch R-15 (Air Ejector) - First Indication of Primary to Secondary Leak
- 5) Pressurizer Ievel Deviation
- 6) Pressurizer Pressure Deviation 1/25/82 Pressurizer Water Temperature 645.7'F (Normal) 1/25/82 0926:23 - RCL system pressure low alarm 2057.9 psig Computer Alarm setpoint 2064.1 psig calculated limit 1/25/82 0926:27.7 - Overtemperature bT Turbine Runback of approximately 5% due to decreasing pressure.
1/25/82'926 1/25/82 *0926:30 - Commenced Manual Load Reduction 1/25/82 *0926:45 - R-15 (Air Ejector) Off-scale-high.
*0927 - R-16 (Containment Fan Coolers Service Water Discharge) Hi Alarm (Alarm apparently due to increased background in Intermediate Building)
Date Time Event Descri tion 1/25/82 *0927 - Steam Dump armed (due to 10% step decrease in first stage pressure). All eight (8) Condenser Steam Dump Valves automatically open.'
-T f deviation approximately 1/25/82 0927:14.0 TAVE at 577.4 F 1/25/82 *0927:30 Manually started 3rd charging pump 1/25/82 0927:31 - RCL system pressure 2043.2 psig 1/25/82 *0927:45 - Four of the eight condenser steam dump valves automatically closed. T, -T deviation approximatRP 1P ~
1/25/82 0927:47 - RCL system pressure 1956.2 psig 1/25/82 *0928 R-15 (Air Ejector) comes back on scale. 1/25/82 0928:11.9 Pressurizer Level low Alarm 8.1% Alarm setpoint 10.5% Automatic Letdown Isolation (10.6%) Automatic Pressurizer Heaters OFF 1/25/82 0928:12.00 Automatic Reactor Trip on low pressurizer pressure. Nuclear power at time of trip approxi-mately 70%. 1/25/8-2 0928:12.07 Reactor trip breakers open 1/25/82 0928:13.1 - Turbine stop valves closed 1/25/82 0928:19 RCL system pressure 1759.5 psig 1/25/82 0928:19.6 Automatic Safety Injection on low pressurizer pressure (< 1723 psig) Automatic Containment Isolation on S.I. 1/25/82 *0928:22 Both main feedwater pumps auto-matically tripped Automatic Feedwater Isolation with Safety Injection 1/25/82 0928:24 "A" S/G level < 17% narrow range 1/25/82 0928:27 - RCL system pressure 1431.7 psig ~ 1/25/82 0928:27.6 - "B" S/G level < 17% narrow range A-2
Date Time Event Descri tion 1/25/82 0928:35 - RCL system pressure 1266 psig 2/25/82 ~0928:49 - "A" Motor Driven auxiliary feed-water pump automatically started on Safety Injection sequence 1/25/82 +0928:51 << "B" Motor Driven auxiliary feed-water pump started on SI sequence 1/25/82 0929:02.5 - Main Electric Generator Trip, Station fed from offsite power.. 1/25/82 0929:09.6 Both Reactor Coolant Pumps manually tripped. Natural Circulation established. 1/25/82 *0929:15 -'oth steam supply valves to turbine driven auxiliary feed-water pump automatically open. 1/25/82 *0929:15 - Pressurizer level near 0 1/25/82 *0930 - Two more condenser steam dump valves automatically close 1/25/82 *0930:30 - All condenser steam dump valves automatically closed. 1/25/82 *0932 Manually stopped "B" Motor driven auxiliary feedwater pump Manually Closed Steam Supply valve from B S/G to Turbine Driven Auxiliary Feedwater Pump. 1/25/82 0933 - NRC Operations Center informed via ENS 1/25/82 *0935 Manning of Technical Support Center commenced. Plant Assessment Manager in the Technical Support Center 1/25/82 0935:44 NRC Senior Resident Inspector arrived in Control Room 1/25/82 4'0937 - Source Range Detectors Re-instated automatically 1/25/82 *0938 NRC Region I in phone communica-tions with the site. 1/25/82 *0938-39 - Two condenser steam dump valves cycling. Operator initiating a manual cooldown. A-3
Date Time Event Descri tion 1/25/82 0939:55 Average Core Exit Thermocouple was 521.1'F system pressure
'CL 1138.7 psig This represents the approximate lowest RCL pressure during the initial transient 1/25/82 0940 "B" Main Steam Isolation Valve closed.
Alert Declared. 1/25/82 0941 Operator throttled auxiliary feedwater flow to the "A" S/G. Narrow Range level approximately 70%. 1/25/82 0943 - Two condenser steam dump valves cycling. 1/25/82 0943 Pressurizer surge line low tem-perature 542.3'F. Alarm setpoint 545'F. This indicates a possible inflow into the surge line. 1/25/82 0946 Manually closed the Steam supply valve from the "A" S/G to the Turbine Driven Auxiliary Feedwater Pump. 1/25/82 0946 - "B" S/G Narrow Range Level 68%. 1/25/82 0946 - New'ork State, Monroe County and Nayne County notified by Plant Superintendent. 1/25/82 0948 - Two condenser steam dump valves cycling 1/25/82 0948 - Stopped the "A" Motor Driven Auxiliary Feedwater Pump 1/25/82 0948 "B" S/G Narrow Range Level 78% 1/25/82 *0948:50 Third condenser steam dump valve cycling 1/25/82 0949 - One condenser steam dump valve closes. 1/25/82: 0950 - R-19 (S/G Blowdown) Alarms.
Date Time Event Descri tion 1/25/82 0950:48 - Auxiliary operator enters Inter-mediate Building to manually isolate "B" S/G Power Operated relief valve. 1/25/82 0953 - Two condenser steam dump valves close. All valves now closed. 1/25/82 0953:42 - Auxiliary operator leaves Inter-mediate Building. "B" S/G PORV isolated. 1/25/82 0955 - "B" S/G Narrow Range Level Off Scale High 1/25/82 0955 - NRC Region I Incident Response Center Activated. 1/25/82 *0957 - Safety Injection Reset. Con-tainment Isolation Reset. (To re-establish instrument air to containment) 1/25/82 0958 - Two condenser steam dump valves cycling 1/25/82 0958 - Onsite Technical Support Center fully manned and operational. ,1/25/82 *0959 Instrument Air restored to Containment 1/25/82 1000 - "A" S/G Pressure 498 psig 1/25/82 1000 - A and C condensate pumps secured. 1/25/82 1001 - R-19 (Blowdown) Off Scale High 1/25/82 1003 - Two condenser steam dump valves closed (All valves now closed) 1/25/82 1004 - Charging pumps manually restarted to subsequently restart a reactor coolant pump. 1/25/82 1006 Pressurizer level approximately 5% and increasing. A-5
Date Time Event Descri tion 1/25/82 1007 RCL System Pressure 1270.6 psig Pressurizer level approximately "A" loop cold leg temperture 474.4 F 1/25/82 1007:30 Pressurizer Power Operated Relief Valve (PORV) placed under manual control and opened to reduce primary pressure and hence reduce leak rate: 1/25/82 1007:30.5 - PORV full open 1/25/82 1007:33.8 - PORV starts to close 1/25/82 1007:35.5 - PORU fully closed 1/25/82 1007:49.3 - PORV starts to open 1/25/82 1007:49.8 - PORV full open 1/25/82 1007:55.7 - PORU starts to close 1/25/82 1007:57.3 - PORV full closed 1/25/82 *1008 Letdown isolation automatically reset, when pressurizer level increases to greater than 10.6%. Letdown stop valve (LCV 427) and one orifice isolation valve go open. 1/25/82 1008:25 - Average of core exit thermocouples 483.9'F. 1/25/82 1008:44. PORU starts to open 1008:44.4 - PORV full open 1008:51.2 - PORV starts to close 1008:52.7 - PORV full closed 1/25/82 1009 - Pressurizer Relief Tank High Pressure 12 psig 1/25/82 1009:10.1 - PORV starts to open 1009:10.5 - PORV full open 1009:15.3 - PORV starts to close 1009:17.4 - PORV reopens, stays open A-6
Date Time Event Descri tion 1/25/82 1009:38.8 - Pressurizer Level 87%
*1010 - Pressurizer Level > 100%
e 1/25/82 1010 - Pressurizer Relief Tank liquid temperature 134'F. Computer Alarm setpoint 115'F. 1/25/82 *1010 Minimum RCL system pressure approximately 830 psig Thermocouple in reactor vessel head indicates 525.4'F Pressurizer liquid temperature approximately 505'F 1/25/82 *1010 Based upon RCL system pressure data, estimate that. the block valve was being closed. Upon block valve closure, Safety Injection repressurizes the reactor coolant system to approxi-mately 1350 psig over the next 5 minutes. 1/25/82 1017 - Operator starts the >>A>> Auxiliary Feedwater Pump. >>A>> S/G narrow range level 43%. 1/25/82 1017 >>B>> S/G pressure 1053 psig. Computer Alarm setpoint 1050 psig. 1/25/82 1017 >>B>> S/G power operated relief valve opens indicating pressure greater than 1060 psig (however, no relief because valve isolated) 1/25/82 1019 >>B>> S/G pressure 1027 psig and decreasing indicating first safety valve lifted. (First safety valve setting is 1085 psig) 1/25/82 1020 >>B>> S/G pressure 1056 psig 1/25/82 1026 - Pressurizer Relief Tank high level 81.2%. Computer Alarm setpoint 80%. 1/25/82 1028 - >>B>> S/G Pressure decreased to approximately 1000 psig indi-cating safety valve lifted. 1/25/82 1028 >>B>> S/G Power operated relief valve closes indicating pressure less than 1060 psig. (Isolated at 0950) A-7
Date Time Event Descri tion 1/25/82 1029 - "A" Motor driven auxiliary feedwater pump secured to main-tain S/G level. 1/25/82 1031 Pressurizer Relief Tank pressure 50.5 psig. 1/25/82 *1037 Indication that "B" S/G safety valve lifted. SI pumps secured to reseat "B" S/G safety valve. Primary system pressure reduced from approximately 1370 psig to approximately 930 psig. 1/25/82 *1039-1041 - Several Steam Line Safety Valve Thermally Compensated Support Temperature System Alarms symptomatic of the safety valve lifting. 1/25/82 1040 "B" Condensate Pump secured to prevent cross contamination of Condensate Storage Tanks and Condensate Demineralizer System. Air ejector secured. 1/25/82 1040 "A" S/G power operated relief valve (PORV) manually throttled open'. 1/25/82 1042 - NRC headquarters activated 1/25/82 1042 Time of minimum RCL system pressure after securing Safety Injection pumps. RCL system pressure 931.9 psig Average Core Exit thermocouple 443 2oF 1/25/82 1044 - Site Emergency declared. 1/25/82 1045 - Condenser vacuum 23.77 in. Hg. (confirming that air ejector is secured). 1/25/82 1045 Pressurizer Relief tank level 90%. 1/25/82 1051 Pressurizer Relief Tank Pressure-
-.5 psig indicating rupture disc blown.
Charging pumps ~ 1/25/82 1052 RCL system pressure 966.6 psig A-8
Date Time Event Descri tion 1/25/82 1057 - Pressurizer relief tank level 79 . 7% 1/25/82 1059 - "A" Motor driven auxiliary feedwater pump started to maintain S/G level. 1/25/82 *1107 - Restart one safety injection pump 1/25/82 1119 - RCL system pressure decreases approximately 35 psig in 30 seconds indicating "B" S/G safety valve lift. 1/25/82 *1120 - Plant process computer system failed 1/25/82 *1122 - Restart "A" Reactor Coolant Pump 1/25/82 1125 - Offsite Emergency Operations Facility operational 1/25/82 *1135 Safety Injection Pump throttled and secured. 1/25/82 *1135 - Plant process computer system restarted. 1/25/82 1135 - "A" S/G power operated relief valve wide open 1/25/82 1136 - Pressurizer relief tank level 90.7/ 1/25/82 *1137 - Indication of safety valve on the "B" S/G. lift 1/25/82 1141 - "A" S/G power operated relief valve throttled. 1/25/82 1143-1149 R-13 (Plant vent particulate), R-10B (Plant vent Iodine) alarmed high. May be due to increased background radiation or due to ventilation recir-culation following safety valve lifting at 1137. 1/25/82 1152 Pressurizer level channels coming back on scale. Indicates normal steam space forming in the pressurizer. A-9
Date Time Event Descri tion 1/25/82 1202 - Normal letdown restored 1/25/82 1203 Pressurizer level ( 87%. SI pump briefly restarted to maintain pressurizer level 1/25/82 1208 - Pressurizer level 73.7% 1/25/82 *1213 - Restart and then stop one SI pump to control pressurizer level. 1/25/82 *1219 - Restart and then stop one SI pump to control pressurizer level. 1/25/82 *1227 - Restart and then stop one SI pump to control pressurizer level. 1/25/82 1230 "B" steam generator pressure greater than Reactor Coolant System pressure 1/25/82 *1234 - Operator re-establishes RCP seal water return. 1/25/82 1251 - "A" S/G PORV wide open 1/25/82 1303 "A" S/G PORV throttled 1/25/82 1313 - ~~A~i S/G PORV wide open 1/25/82 1316 - "A" Main Steam Isolation Valve closed. 1/25/82 1607 - Manually stopped B and C service water pumps. 1/25/82 1615 - NRC Region I Incident Response Team on site 1/25/82 1701 - Stopped "A" Auxiliary Feedwater Pump. 1/25/82 *1840 Reestablished level in the "B" S/G. Plant cooling down via forced circulation and dumping steam from "A" S/G to the atmosphere.
"B" S/G secondary side pressure being maintained about 20 psi above primary.
B S/G being fed by Auxiliary Feedwater and bled via the ruptured tube to the Reactor Coolant System. A-10
Date Time Event Descri tion 1/25/82 1904 Cycled'ressurizer'ower operated relief valve several times in an attempt to close the valve. The valve did not go closed. 1/25/82 1917 - Downgraded event from Site Emergency to Alert. 1/26/82 *0600 - Overpressure Protection system in service 1/26/82 0650 - Started Residual Heat Removal Pump 1/26/82 *0658 Started RHR cooling 1/26/82 1045 - Downgraded event from Alert to recovery status 1/26/82 1215 Completed burping the Volume Control Tank for hydrogen removal from the Reactor Coolant System Commenced RCS cooldown 1/26/82 1853 Cold shutdown achieved Notes:
- 1) Data and times have been obtained from plant process computer, control board charts and plant security computer. Times for some activities, indicated by an asterisk (*), have been obtained based on logs and operator interviews and are approximate.
- 2) Alarm setpoints and trip setpoints can be 21% from actual to allow for instrument drift.
APPENDIX B Plots of Data
0 APPENDIX B LIST OF FIGURES Figure B-1 Pressure vs. Time S/G A, S/G B, Pressurizer, (0926-0931): Reactor Coolant Loop (Wide Range) Figure B-2 Pressure vs. Time S/G A, S/G B, Reactor Coolant (0900-1400): Loop Figure B-3 Level vs. Time Pressurizer (0926-0931): S/G A, Narrow and Wide Ranges S/G B, Narrow and Wide Ranges Figure B-4 Level vs. Time Pressurizer, (0900-1400): S/G A, Narrow and Wide Ranges S/G B, Narrow and Wide Ranges Figure B-5 Pressure vs. Time (1/25 at 0900 1/26 at 2400): S/G B, Reactor Coolant Loop Level vs'ime (1/25 at 0900 1/26 at 2400): S/G B, Narrow and Wide Ranges Figure B-6 Pressurizer Temperature vs. Time (0900-1400): Water, Steam, Surge Line Figure B-7 Pressurizer Relief Tank vs. Time (0900-1400): Temperature, Pressure, Level Figure B-8 Cold Leg Temperature vs- Time (0900-1400): A Cold Leg, B Cold Leg Figure B-9 Loop A Temperature vs. Time (0926-0931): THPT'CPLD, ET, TCOLD (Wide Range), TSAT (Based on RCL Pressure) Figure B-10 Loop B Temperature vs. Time (0926-0931): THPT, TCOLD, QT, TCPLD (Wide Range), TSAT (Based on 'RCL Pressure) Figure B-ll Temperature vs. Time (1/25 at 0900 1/26 at 2400): A Cold Leg B Cold Leg Avg. of 5 Incore Thermocouples Figure B-12 Thermocouple Temperature vs. Time (0900-1400): Vessel Head Thermocouples, GOl, G04, and I10; Avg. Vessel Head Thermocouple; Core Exit Thermocouples FOS and G07. TSAT (Based on RCL Pressure)
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