ML19337B586
| ML19337B586 | |
| Person / Time | |
|---|---|
| Site: | Three Mile Island  |
| Issue date: | 10/03/1980 |
| From: | METROPOLITAN EDISON CO. |
| To: | |
| Shared Package | |
| ML19337B584 | List: |
| References | |
| NUDOCS 8010070338 | |
| Download: ML19337B586 (150) | |
Text
I REPORT IN RESPONSE TO NRC STAFF RECOMMENDED REQUIREMENTS FOR RESTART OF TIIREE MILE ISLAND NUCLEAR STATION UNIT 1 AMENDMENT 21 INSTRUCTIONS 4
Those sheets of the TMI-I Restart Report listed in the left-hand column are to be deleted and, where appropriate, replaced with the revised sheets listed in the column on the right.
REMOVE -
INSERT TABLE OF CONTENTS TABLE OF CONTENTS
Pages i through viii SECTION 1 SECTION 1 Pages 1-1 through 1-2 Pages 1-1 through 1-2 SECTION 2 SECTION 2 Pages 2.1-8 through 2.1-16 Pages 2.1-8 through 2.1-16a Pages 2.1-29 through 2.1-29b Pages 2.1-29 through 2.1-29b Pages 2.1-31 through 2.1-37 Pages 2.1-31 through 2.1-37 Table 2.1-1 Table 2.1-1 Tabic 2.1-2 (2 Pages) Table 2.1-2 (2 Pages)
Table 2.1-3 Table 2.1-3 Fi g ure 2.1-6 Figure 2.1-6 Figure 2.1-7 Figure 2.1-7 Figure 2.1-11 Figure 2.1-11 SECTION 6 SECTION 6 Pages 6-1 through 6-17 Pages 6-1 through 6-17 SECTION 7 SECTION 7 Page 7-9 Pages 7-9 and 7-9a G b SECTION-8 SECTION 8 Pages 8-1 through 8-2 Pages 8-1 through 8-2 Page 8 Page 8-15 g S l
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Amendment 21 Instructions Page No. 2 REMOVE INSERT SECTION 9 SECTION 9
Pages i through v SECTION 11 SECTION 11 Pages 11-1 through 11-25 Pages 11-1 through 11-26 Dr.a.ft Tech. Spec. Section 11.2.2 Draft Tech. Spec. Section 11.2.2 (7 Pages) (9 Pages)
Draft Tech. Spec. Section 11.2.3 Draft Tech. Spec. Section 11.2.3 (3 Pages) (6 Pages)
Draft Tech. Spec. Section 11.2.5 Draft Tech. Spec. Section 11.2.5 (3 Pages) (4 Pages)
Draft Tech. Spec. Section 11.2.6 Draft Tech. Spec. Section 11.2.6 (3 Pages) (5 Pages)
Draft Tech. Spec. Section 11.2.7 Draft Tech. Spec. Section 11.2.7 (11 Pages) ,
(15 Pages)
Draft Tech. Spec. Section 11.2.9 Draft Tech. Spec. Section 11.2.9 (3 Pages) (3 Pages)
SUPPLEMENT 1, PART 2 SUPPLEMENT 1, PART 2 Question 16 Qu( : tion 16 Question 52 + Attachments Question 52 + Attachments (8 Pages)
Question 95 + Attachments Question 95 + Attachments (13 Pages) (22 Pages)
SUPPLEMENT 1, PART 3 SUPPLEMENT 1, PART 3 Question 11 - Page 2 Question 11 - Page 2
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{ TABLE OF CONTENTS Page
1.0 INTRODUCTION
AND REPORT ORGANIZATION 1-1 i
l 1.1 Introduction 1-1 l
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- 1. 2 Report Organization 1-1 1.3. Abbreviations 1-2 l
1.4 Definitions 1-2 l
2.0 PLANT MODIFICATIONS ,
2.1-1
! 2.1 General 2.1-1 j 2.1.1 Short-Term Modifications 2.1-1 2.1.1.1 Reactor Trip on Loss of Feedwater/ 2.1-1 l
l l 2.1.1.2 Position Indication for PORV and Safety 2.1-3 l Valves 2.1.1.3 - Emergency Power Supply Requirements 2.1-6 for Pressurizer lleaters, PORV, Block Valve, and Pressurizer Level Indication 2.1.1.4 Post LOCA Ilydrogen Recombiner System 2.1-8 2.1.1.5 Containment Isolation Modifications 2.1-11 2.1.1.6 Instrumentation to Detect Inadequate 2.1-17 Core Cooling 2.1.1.7 Auxiliary Feedwater Modifications 2.1-20 2.1.1.8 Leak Reduction Program For Systems 2.1-29a Outside Containment 2.1.2 Long-Term Modifications 2.1-30 l 2.1.2.1 Post Accident Monitoring 2.1-30 2.1.2.2 RCS Venting 2.1-31 2.1.2.3 Plant _ Shielding Review 2.1-38
% 2.1-39 2.1.2.4~ Post Accident Sampling Capability 2.1.2.5 Reactor Coolant Pump Trip on llPI 2.1-41 i Am. 21 9 *-
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l TABLE OF CONTENTS - Continued Page I
2.1.2.6 Auxiliary Feedwater System 2.1-41 2.1.2.7 Increased Range of Radiation Monitors 2.1-43
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3.0 PROCEDURAL MODIFICATIONS 3-1 3.1 General 3-1 3.1.1 Emergency Procedures 3-2 3.1.2 Administrative Procedures 3-2 l 3.1.3 Surveillance / Preventative Maintenance / Corrective 3-3 Maintenance Procedure 3.1.4 Operating Procedures 3-3 4.0 EMERGENCY PLAN 4-1 l 5.0 THREE MILE ISLAND NUCLEAR STATION ORGANIZATION 5.1-1 f
5.1 General 1 5.2 Station Organization 5.2-1 5.2.1 Vice President - TMI-1 2-2 5.2.2 Manager TMI-1 2-6 l
5.2.3 Supervisor of Operations 2-8 5.2.4 Training Coordinator 2-9 5.2.5 Supervisor - Radwaste, Nuclear 2-11 5.2.6 Shift Supervisor 2-14 5.2.7 Shift Foreman 2-18 5.2.8 Control Room Operator 2-22 5.2.9 Auxiliary Operator 2-22 5.2.10 Superintendent of Maintenance 2-23 h
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TABLE OF CONTENTS - Continued l
Page 5.2.11 Supervisor - Corrective Maintenance 5.2-24 5.2.12 Supervisor - Preventive Maintenance 2-26 5.2.13 Maintenance Foreman 2-27 5.2.14 Lead thintenance Foreman 2-28 5.2.15 tianager Plant Engineering 2-28 5.2.16 Lead Nuclear Engineer 2-31 5.2.17 Lead Electrical Engineer 2-33 5.2.18 Lead Instrument and Control Engineer 2-35 5.2.19 Lead Mechanical Engineer 2-38 5.2.20 Supervisor Chemistry 2-40 5.2.21 Technical Analyst - Fire Protection 2-42 5.2.22 Shif t Technical Advisor 2-45 5.2.23 Manager Administration and Services 2-53 5.2.24 Manager Radiological Controls 3-55 5.2.25 Radiological Controls Manager 2-60 5.2.26 Supervisor Radiological Controls Technicians 2-61 l
5.2.27 Radiological Controls Foreman 2-63 5.2.28 Radiological Controls Technicians 2-65 5.2.29 Supervisor Radiological Engineering 2-66 5.2.30 Radiological Engineers 2-68 iii Am. 21-I I
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TABLE OF CONTENTS - Continued Page 5.3 Station Support organization 533-1 5.3.1 Technical Functions Group 3-2 5.3.2 Nuclear Assurance Program and Procedural Control 3-4 5.3.3 Administration 3-26 5.3.4 Radiological & Environmental Controls Dept. 3-28 5.3.5 Maintenanc.c & Construction Division 3-29 5.3.6 Communications Division 3-30 5.4 Safety Reviews and Operational Advise 5.4-1 5.4.1 Safety Review Program 5.4.1 6.0 OPERATOR ACCELERATED RETRAINING PROGRAM (OARP) 6-1 6.1 Introduction 6-1 6.2 Program Objectives 6-1 6.3 Topical Outline 6-2 6.4 Program Rationale 6-5 6.5 Instructional Procedure 6-6 6.6 Evaluation Procedure 6-9 6.7 Program Format 6-11 7.0 RADWASTE MANAGEMENT 7-1 7.1 General 7-1 7.2 Separation and Isolation of the Units 7-1 7.2.1 Radioactive waste transfer piping 7-1 7.2.2 Fuel llandling Building Environmental Barrier 7-3 7.2.3 Liquid Radwastes and Miscellaneous Waste Evaporator 7-3 7.2.4 Solid Waste Disposal 7-4 iv Am. 21 i
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TABLE OF CONTENTS - Continued Page 7.2.5 Sanitary Facility Drains 7-5 7.2.6 Radiation Protection and Decontamination Areas 7-5 7.2.7 Nuclear Sampling and Radiochemistry Laboratory 7-5 7.2.8 Industrial Waste Treatment Facilities 7-6 7.3 Supplemental Topics 7-6 7.3.1 Radwaste Capability 7-6 l
a 7.3.1.1 Liquid Radwaste Processing 7-6 7.3.1.2 Waste Cas System 7-9 7.3.1.3 Solid Waste System 7-11a 7.3.2 Plant Shielding 7-12 1
7.3.2.1 General 7-12 2
7.3.2.2 Design Review 7-12 7.3.2.3 Near Term Modifications 7-12 :
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J f 7.3.2.4 Long Term Modifications 7-12 7.3.3 Auxiliary Building Ventilation System 7-12 7.3.3.1 General 7-12 1
7.3.3.2 Testing Requirements 7-13 4 7.3.3.3 Impicmentation Schedule 7-14 7.3.4 Nucicar Sampling 7-14 7.3.5 Nucicat Sampling Capabilities 7-14 7.3.5.1 Post-Accident Sampling . 14 j 7.3.5.2 Sample Drains 7-15 7.3.5.3 Improved in-Plant Radio-iodine Monitoring Instrumentation 7-15 7.4 Af fect of TMI-2 Recovery on TMI-1 Operation 7-15 4
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TABLE OF CONTENTS - Continued (3 Page 8.0 SAFETY ANALYSIS 8-1 8.1 Introduction 8-1 8.2 Areas of Investigation 8-1 8.2.1 Modificat ions Resulting from the 8-1 August 9, 1979 Order 8.2.2 Modification as Result of Order of May, 8-2 1978 8.2.3 Modific~ation Originating from within Met-Ed 8-2 8.2.4 I&E Bulletin 79-05C 8-2 8.3 Effect of Changes oa Safety Analysis
- 8-2 8.3.1 Rod Withdrawal from Startup 8-3 8.3.2 Rod Withdrawal at Power 8-3 8.3.3 Moderator Dilution Accident 8-4
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8.3.4 Cold Water Addition 8-5 8.3.5 Loss of Coolant Flow 8-5 8.3.6 Dropped Control Rod 8-6 8.3.7 Loss of Electric Power 8-7 8.3.8 Station Blackout (Loss of AC) 8-7 8.3.9 Steam Line Failure 8-8 8.3.10 Steam Generator Tube Failure 8-10 8.3.11 Fuel Handling Accident 8-11 8.3.12 Rod Eject ion Accident 8-11 8.3.13 Feedwater Line Break Accident 8-12 8.3.14 Waste Gas Decay Tank Rupture 8-13 8.3.15 Small Break Loss of Coolant Accidents (LOCA) 8-13 (yjg 8.3.16 Large Break Loss of Coolant Accidents (LOCS) 8-17 We 8.4 Summary and Conclusions 8-18 vi Am. 21
TABLE OF CONTENTS - Continued Page 9.0 DRAWINGS 9-1 10.0 CROSS REFERENCE TO ORDER RECOMMENDATIONS 10-1 i 10.1 Introduction 10-1 1
10.2 Short-Term Recommendations and Met-Ed Responses 10-1
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10.3 Specific Responses to Recommendations 10-4 10.3.1 Response to IEB 79-05A, Item 2 10-4 l
10.3.2 Performance Testing for PWR Relief and Safety Valves 10-5 10.3.3 Onsite Technical Support Center 10-6 1
10.3.4 Onsite Operational Support Center 10-9 l
10.4 Transient Analysis and Procedures for Management of J Small Breaks 10-10 1
j 11.0 TECllNICAL SPECIFICATIONS 11-1 4
11.1 Introduction 11-1 l 11.2 Draft Technical Specification 11-1 11.2.1 Reactor Trip on Loss of Feedwater or l Tuchine Trip 11-1 l' 11.2.2 Position Indication of PORV and Safety Valves, Setpoints 11-2 2
11.2.3 Emergency Power Supply Requirements -
Pressurizer Heaters 11-5 i 11.2.4 Post-LOCA Ilydrogen Recombiner System 11-7 11.2.5 Containment Isolation Modifications 11-8 11.2.6 Instrumentation to Detect Inadequate Core Cooling 11-11 11.2.7 Emergency Feedwater System Modifications 11-13 11.2.8 ' Post Accident Monitoring 11-16 i
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TABLE OF CONTENTS - Continued Page 11.2.9 Reacte- Coolant Pump Trip on Coincident ESFAS ind Coolant Voiding 11-18 11.2.10 TMI-1/TMI-2 Separation 11-20 11.2.11 Low Reactor Coolant System Pressure Channel for llPI/LPI Initiation 11-21 11.2.12 Raising the Low Reactor Coolunt System Pressure Trip Setpoint 11-22 11.2.13 Post-Accident Pressure Temperature Limits 11-23 viii Am. 21
1.0 T KrRODUCTION AND REPORT ORGANT7.ATION
1.1 INTRODUCTION
Metropolitan Edison Company (Met-Ed) applied for a license to construct and operate Three Mile Island Nuclear Station Unit 1 (TMI-1) on May 1, 1967 (TMI-1 is jointly owned by Met-Ed, Jersey Central Power and Light (JCP&L), and Pennsylvania Electric Company (Penelec) but operated by Met-Ed. Met-Ed , JCP&L and Penelce are wholly owned subsidiaries of General Public Utilities (GPU).) Following issue of the Atomic Energy Commissions ( AEC)
Safety Evaluation Report (February 5,1968 as supplemented April 26, 1968) and hearings before the Atomic Safety and Licensing Board ( ASLB) the AEC issued a permit to construct TMI-l (CPPR-40) on May 18, 1968.
On March 2, 1970, Met-Ed filed the Final Safety Analysis Report (FSAR) and Operating License Application for TMI-1. The applica-tion was for operation at a core power level of 2535 megawatts thermal (FMt) based on Babcock & Wilcox (B&W) analyses performed for a core power level of 2568 MWt. Based on its SER issued June 11, 1973, the AEC issued Operating License DPR-50 on April 19, 1974.
TMI-l achieved ini tial criticality on June 5,1974 and was declared " Commercial" on September 2, 1975. Since commercial operation TMI-l has been refuelled five times. The unit was ready to begin operation on the fif th core on March 28, 1979 when the TMI-2 accident occurred. Until conditions at TMI-2 were fully understood Fbt-Ed decided to keep TMI-l shutdown. On April 16, 1979, Met-Ed committed to providing the NRC with significant advance notice prior to startur o f TMI-1.
On June 28, 1979, Met-Ed info rmed the NRC that TMI-1 would not b'e started up until certain plant modifications were completed. The NRC issued an Order on July 2, 1979 that TMI-1 remain shutdown until af ter a public hearing and further commission order. The Commission issued a further Order and Notice of Hearing on August 9, 1979 which included a list of requirements which the Director !
of NRR had recommended as a condition for restart of TMI. This report addresses these recommended requirements, except that the j requirements for a demonstration of financial resources and of l financial qualifications will be separately addressed. 1 1.2 REPORT ORGANIZATION 1 This report is composed of eleven (11) sections which, combined, cover the August 9, 1979 Order requirements. All requirements of a related nature are discussed in a single section. For example all requirements related to plant hardware modifications are presented in Section 2 and referenced by other Sections as appropriate. Section 10 provides a discussion of how a require-ment is met or where in the report the discussion can be found.
, Supplement I responds to NRC questions raised during the review of this report and Supplement 2 contains the TMI-1 Restart QA Plan.
1-1 AM-21
1.3 ABBREVIATIONS Abbreviations or Acronyms are frequently used throughout this re po rt . The ones more commonly used are defined below:
ACRS Advisory Committee on Reactor Safeguards AFW See EFW B&W Babcock & Wilcox 3 CRDM Control Rod Drive Mechanism DH Decay Heat EFW Emergency Feedwater ECCS Emergency Core Cooling System ES Engineered Safeguards FSAR Final Safety Analysis Report HPI High Pressure Injection ICS Integrated Control System LOCA '
Loss of Coolant Accident LPI Low Pressure Injection
, MU Makeup NPSH Net Positive Suction Head NRC Nuclear Regulatory Commission NSSS Nuclear Steam Supply System 1
PORV Power Operated Relief Valve PRZR (PZR) Pressurizer psig pounds per square inch gauge QA Quality Assurance RB Reactor Building RCDT Reactor Coolant Drain Tank RCP Reactor Coolant Pump RCS Reactor Coolant System SFAS (ESFAS) Safety Features Actuation System TMI Three Mile Island 1.4 DEFINITIONS Safety Grade - Safety grade within the context of this report means that a system or component has (unless otherwise stated) the following features: redundancy, testability, reliable onsite power source, and capability to withstand appropriate adverse environments (including seismic). 1 Safety Related (Nuclear) - Safety related means that the system or component is useful in protecting nuclear safety. Nuclear safety related items may be safety grade or non-safety grade. In general only those items which are nuclear safety related and form the primary line of defense (in a defense in depth approach to safety) are safety grade.
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2.1.1.4 POST LOCA HYDROGEN RECOMBINER SYSTEM 2.1.1.4.1 System Description The purpose of this modification is to provide a system which shall serve as a means of controlling combustible gas concentra-tions in containment following a loss of coolant accident (LOCA).
After a LOCA, the containment atmosphere of a PWR is a homo-geneous mixture of steam, air, solid and gaseous fission products, hydrogen and water droplets containing boron, sodium-hydroxide and/or sodium thiosulfate. During and f ollowing a LOCA, the hydrogen concentration in the containment results from radiolytic decomposition of water, zirconium-water reaction and aluminum reacting with the spray solution.
If excessive hydrogen is generated it may combine with oxygen in the containment atmosphere. The capability to mix tre combus-tible atmosphere and prevent high concentrations of combustible gases in local areas is provided by the reactor building ventila-tion system. The hydrogen recombiner system must be capable of reducing the combustible gas concentrations within the contain-ment to below 4.0 volume percent.
The recombiner shall be capable of removing containment air mixed with hydrogen, recombine the hydrogen and exhaust the processed air back into the containment. This system is not required during normal plant operation.
2.1.1.4.2 Design Basis The recombiner system shall meet the design and quality assurance requirements for an engineered safety feature in terms of redun-dancy for active components, electrical power and instrumentation.
The design basis for the system shall be a loss-of-coolant accident (LOCA) with hydrogen generation rates calculated in accordance .
with NRC Regulatory Guide No. 1.7.
The hydrogen recombiner to be utilized f or the system shall be the Rockwell International, Atomics International Div. recombiner unit purchased for TMI Unit No. 2.
One hydrogen recombiner will be installed prior to restart. The second (redundant) recombiner need not be installed, however, the piping system, electrical power supplies and structural provisions shall be installed and available. The second hydrogen recombiners shall be installed af ter an accident within half the time period available before they need to be operational. The redundant re-combiner will be available at the site, stored in a seismic Class 1 structure.
The system will be designed to meet the criteria of NRC Regula-tory Guide 1.7, the acceptance criteria of SRP 6.2.5, NUREC 0578 (July 1979), 10CFR50 Appendix A-General Design Criteria for containment design and integrity and 10CFR100 Reactor Site ,
Criteria for limits of offsite releases. !
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2.1.1.4.3 Systco Derign The zy: ten d::ign providta en instellcd hydrogrn recombin:r cr.d a location with installed piping for a future redundant hydrogen rec ombiner . The recombiners will be located in the Intermediate Building at floor elevation 305 ft., in the Leak Rate Test equip-ment area, and their control consoles will be below at elevation 295 f t. as shown in Fig. 2.1-6. This system will utilize the existing " Containment Vessel Leak Rate test" penetrations (nos.
415 and 416) as shown disgramatically in Fig. 2.1-7.
Since only active component failure needs to be considered, common containment penetrations will be utilized for the redun-dant recombiners. All active components will be redundant and will be provided with independent power supplies.
All system components forming the containment boundary will meet the containment isolation criteria and will be designed to Safety Class 2 per ANSI B-31.7. All system supports will be design-ed for the DBE'as seismic class S-1. The recombiners will be powered from Class IE power sources. The inside containment isolation valves will be solenoid, de power, operated valves, controlled from the control room.
The recombiner cooling air will be discharged directly to the outside environment. An evaluation will be performed to demon-strate that potential releases of intermediate building air used for recombiner cooling will not result in off site releases in excess of 10CFR100.
2.1.1.4.4 System Operation The cystem is designed to maintain the hydrogen concentration inside containment below the 4.0 percent by volume, lower flam- l mability limit of hydrogen. .
Based on the hydrogen generation rate calculated in accordance with NRC Reg. Guide 1.7, the hydrogen recombiner should start processing the containment gases when the hydrogen concentration l reaches 3 percent by volume of the total containment.
l l The recombiner is placed into operation by opening the contain-ment isolation valves af ter having sampled the containment I i atmosphere and then turning on the recombiner from its remote- i local panel. Local monitoring of the control panel is required j until the reaction chamber reaches the required temperature for a .
I self sustaining reaction between hydrogen and oxygen. Once the system is in a recombination mode, only periodic inspection at the control panel is required. A single remote recombiner alarm is provided in the main control room to advise the operator of an operating problem with the recombiner When the hydrogen concentration has dt ,; e to an acceptable level, the system is shutdown and the cot..ainment isolation valves are closed.
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2.1.1.4.5 Szfsty Evaluation-The hydrogen recombiner system is designed as a nuclear safety class 2, sesimic class S-1 system with class 1E power supply.
Containment integrity is normally maintained by double valve isolation (with a valve inside and another outside containment).
4 While the recombiner is being utilized f or post-LCCA hydrogen control, containment integrity at the penetration is maintained by a single, manually operated, locked closed valve located
! outside of containment and the redundant isolation is provided by a spectacle flange also located outoide containment. l In order to insure the ability to draw and return containment atmosphere, considering single active failure of the power operated inside containment isolation valve, two such valves are
! provided per penetration with each of a redundant pair of valves
- powered f rom alternate de power supplies. Redundant outside manual containment isolation valves are also being provided for ,
each containment penetration. _These isolation valves are designed i
to fail closed on loss of power in order to maintain containment integrity.
All other active components have redundancy by virtue of the redundant recombiner skid and control panel. Each panel may be powered by either the " Red" or " Green" Engineered Safeguards Syatem power supply.
Off site releases due to leakage and discharge to the atmosphere vsth the recombiner cooling air will be evaluated to demonstrate 1 these releases to be below the 10CFR100 limits.
I 2.1.1.4.6 Inservice Testing Requirements 1 No inservice testing is required for the llydrogen Recombiner System. Ilowever, normal inspection, testing and maintenance will be performed in accordance with standard plant operating proced-ures and Technical Specification requirements.
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2.1.1.5 Contzinm:nt Isolatien Modificctions 2.1.1.5.1 System Description The functional requirements of the additional containment isola-tion signals are the following:
- 1. Provide diverse containment isolation signal from the appli-cable reactor trip, high radiation, 1600 psig RCS pressure (SFAS), or pipeline break signal. These signals will assure that radioactive material is net inadvertently transferred out of the reactor building even if a 4 psig isolation signal is not reached.
f 2. All lines open to the containment atmosphere or connected directly to the RCS (either normally or intermittently which
' can result in transfer of radioactivity outside containment),
which are neither part of the Emergency Core Cooling Systems nor support for RCP operation, should be isolated on reactor trip.
- 3. In order to maintain non-ECCE support services for RCP opera-tion, the following service lines should be classified as Seismic Category I and closed on the following signals, provided that the piping is protected from pipe whip and/or jet impingement (see Fig. 2.1-5), Deletion of 4 psig RB Isolation Signal Logic):,
- a. Reactor coolant pump seal return valves MU-V25&26, should be isolated on 30 psig reactor building pressure signal or by the operator through remote manual operation on high radiation alarm.
- b. Nuclear Services Closed Cooling (NSCC) water and Interm,e-diate Closed Cooling (ICC) water entering and exiting the containment shall be isolated on a 30 psig reactor building pressure signal and by a pipeline break iso-lation signal coincident with a safety injection (HPI) signal.
- c. Normal R.B. Cooling Unit coils should be isolated on 4 psig reactor building pressure signal or by a 1600 psig R.C. pressure signal both of which shall automatically initiate the Emergency R.B. Cooling Water System.
In order to utilize specific systems which have been auto-matica11y isolated, an isolation signal override capability l
is required. The isolation signal override shall be either on a common basis for more than one penetration or on an individual penetration basis dependent on the isolation signal source and the penetration which is to be opened.
The override will be to the isolation signal which will not automatically reopen the isolation valves. Operator action to reopen selected containment isolation valves will be required after the signal override has been accomplished.
See Tabic 2.3-1 for a listing of penetrations and the required isolation override requirements.
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The rediction nonitoring shall be accomplich2d at tha locc-tions indicatsd on Tabla 2.1-3 A common liigh Radiation alarm shall be provided in the control room for those radiation monitors that provide a high radiation alarm or closure signal.
4 Specific requirements for each containment isolation valve are tabulated in attached Table 2.1-2. This tabic identifies the isolation signal for each valve and pipe upgrading requirements for each piping system.
- 5. The existing 4 psig reactor building isolation signal may be deleted for a system if the following criteria can be met:
1 (1) The system is or is made to be a closed piping system inside the reactor building as defined by 10CFR.50 Appendix A, Criterion 57 This requires that the peiping be designed to seismic category S-I and that it not be subject to, or is protected from, or can withstand pipe whip, jet impingement and missile forces.
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j (2) The piping system is a closed loop inside of the reactor building which presently is, or is to be upgraded to seismic category S-I; and, whose containment isolation valves will be closed either by a 30 psig reactor l
building pressure signal or by a line break detection signal.
Refer to Fig. No. I " Deletion of 4 psig Reactor Building Insolation Signal Logic."
- 6. Containment isolation signal override capability will be provided in accordance with attached Table 2.1-1 which lists' the following types of overrides:
- a. Individual Isclation Signal Override - This override shall be capable of overriding only the specific isolation signal to the appropriate valves associated with only the penetration which it is desired to reopen. This t ype 'of override is noted by an "1" on Table 2.1-1. The initiat-ing isolation condition may still exist when utilizing this override.
- b. Common Isolation Signal Override - This override shall be a common override capable of bypassing only the specific isolation signal to all of the appropriate valves asso-l ciated with the various penetrations which may be dcsired i to reopen by the operator. 'Sa common isolation signal override shall also provide the override for the individual isolation signal override. This t ype of override is noted by a "C" on Table 2.1-1 The initiating isolation condition may still exist when utilizing this override.
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- c. Individual Isoletion Signal Byptee - This byptss ehn11 be capsble of bypassing only tha specific isolation eignsi to the appropriate valves associated with only the penetra-tion which it le desired to be maintained open although an isolation signal is initiated. This type of bypass is noted by an "IB" on Table 2.1-1. The initiating isolation signal may exist when utilizing this bypass.
- d. Automatic Isolation Signal Override - The isolation signal for this type of override shall automatically be cleared although the initiating isolation condition may still exist. This will allcw the operator to simply push the valve switches to "open" position in order to re open the valves. This feature is used only for the RC system letdown isolation valvers and shall function af ter they have been closed by a reactor trip signal only. This t ype of override is noted by an "A" on Table 2.1-1.
- e. No Override or Bypass Capability - This override shall not permit operator to re-open the valve, from the control room, unless the initiating condition is removed. If the isolation valves have been re-opened and the initiating con-dition re occurs then the valves shall again be isolated.
This function is designed as "NO" in Table 2.1-1.
The containment isolation overrides shall be on an individual signal source basis such that overriding the j
isolation signal due to one source will still allow the valves to be isolated by a second isolation source if it l
! is activated.
l The containment isolation overrides shall by pass the l isolation signal but shall not automatically re open the containment Isolation valve (s). '
2.1.1.5.2 Design Bases 1 The diverse containment isolation system shall meet the requirements of IEEE No. 279.
- 2. Redundancy of existing sensors, measuring channels, logic, and actuation devices shall be maintained and not be degraded by the modifications. ,
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- 3. Electrical independence and physical separation shall be in accordance with TMI-1 plant criteria as described in the FSAR.
4 Switches, independent of the automatic instrumentation, shall be provided for manual control of all containment isolation valves modified.
l 5. Manual testing facilities shall be provided for on-line testing to prove operability and to demonstrate reliability.
Plant operation should not be adversely af fected by the use of the on line testing capability.
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- 6. Switches, relays indictora and other similar devices shall be of equal or batter quality than equipm:nt used in the original iMI-l safety grade systems.
- 7. Status (open/ closed) indication for all containment isolation valves shall be provided in the main control room and shall not be affected by the modifications, i
- 8. The radiation monitors used for containment isolation actuation shall se classified as non-safety grade.
. 9. All cable added by this modification shall be qualified to the applicable requirements of IEEE-383.
- 10. Electrical power for safety grade actuation logic portions of the system shall be derived from class lE uninterruptiable sources.
11 Line bread isolation shall be provided for those systems identified in attached Table No. 1.
12 The line break isolation for the intermediate coling water and nuclear services cooling systems shall be designed to meet the
, following requirements:
- a. Provide leak detection and isolation protection for Reactor Building pressure conditions which are below 30 psig such that if there were a leak in the piping system inside of the R.B. during an accident, then that leak would be into rather than out of the R.B.
- b. Detect and alarm (in the control room) system leakage i rates which if undetected would reduce the surge tank volume from high to low level within one hour or ,
less.
- c. Close the containment isolation valves when the level in the surge tank reaches the low-low level only if a saf ety injection (HPI) signal had been initiated.
2.1.1.5.3 Design Evaluations and Systems Operation In order to cover a broader spectrum of events for which contain-ment isolation is desirable, the reactor trip signal is used as a diverse containment isolation signal. Since a reactor trip signal occurs on low R.C. prqssure (1900 psig) it is anticipatory of SFAS and occurs prior to SFAS initiation. Therefore the NRC directive would be fulfilled in a conservative way by the reactor trip signal rather than the SFAS signal. l l
The use of the RPS system would provide isolation for the follow-ing events:
- a. Rod withdrawal accidents
- b. Loss of coolant flow 2.1-14 Am. 21
- d. Small steam line break accident outside containment (isola-tion of containment lines is still desirable)
- e. Ejected rod accident
- f. Boron dilution accident
- g. Cold water addition -
- h. Iodine spikes or crud burst af ter trip
- i. Loss of of fsite power or station blackout The 1600 psig R.C. pressure SFAS signal would not isolate contain-ment for items a, b, c, f, g, h and i. Isolation on 1600 psig R.C.
pressure SFAS for items d and e would not cover a f ull spectrum of events.
As discussed above, lines which will be isolated on reactor trip are:
- a. reactor bui1 ding sump
- b. RCDT gas vents and liquid discharge
- c. RCS sample lines l d. containment purge lines
- c. RCS letdown
- f. demineralized water
- g. OTSG sample lines (due to primary to secondary leaks) l Closure of these paths by a signal that is not dependent on building pressure assures that there will be no uncontrolled radioactivity release f rom containment for design basis events.
With the exception of the letdown and the demineralized water valves, the above lines are normally isolated. If these lines receive an isolation signal af ter a reactor trip the plant condition is not degraded. The letdown lines is normally open, -
and it is now immediately closed by operator action af ter reactor tripper existing operating procedures.
Special design provisions will be taken with letdown line isola-tion. If neither 4 psig R.C. pressure nor high radiation l
exists, the operator will be able to reopen the valve on demand.
! If either of these signals does exist, however, the operator can only reopen the letdown valve by overriding or bypassing the closure signal to the valve.
The demineralized water line is normally open to provide purging of the reactor coolant pump number 3 seal. The purging prevents boron building in the seal. Loss of this function is not a concern. Westinghouse, the pump manufacturer, has stated that loss of seal purging has been determined not to affect the seal; 1
2.1-15 Am. 21
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- ' L. -. - . - . ^'h__
in fact, at the owners discretion, some pumps are being operated without the purge water connected.
Individual high radiation signals will be used to prevent re-leases outside containment for the:
- 1. Reactor building sump drain 2 Reactor coolant system letdown line
- 3. Reactor coolant drain tank vent 4 Reactor building purge (monitor already exists)
- 5. Reactor coolant sample lines 6 OTSG sample lines
- 7. Reactor coolant pump seal return (alarm only) 8 Intermediate closed cooling water (alarm only) 4 Intermediate closed cooling water will be alarmed on high radia-tion in order to prevent inadvertent releases due to letdown cooler leakage 'into the ICCW system. Isolation of the ICCW system will not jeopardize operation of the reactor coolant pumps since normally functioning seal water injection provides adequate cooling for the seals. Plant operating procedures will be revised in order to address reinitiation of ICCW cooling of the seals.
Individual raidation isolation have been chosen in lieu of a general radiation isolation signal for the following reasons.
First, reactor trip isolation will be anticipatory of a high i radiation condition. Second, individual isolation is more sensitive to isolating the source of activity. For example, a general radiation signal based on dome activity would not detect a source of activity being added to the RCDT.
Once containment isolation is completed, certain lines may have .
to be reopened in order to support post trip or post accident operation. Table 2.1-1 provides a list of override capability for each of the lines receiving either: reactor trip, high radiation, 4 psig or 30 psig R.B. pressure, 1600 psig R.C.
pressure (HPI) or line break isolation signals. Overriding the isolation signal shall not open the containment isolation valves, deliberate operator action shall be required to reopen selected individual valves.
Plant procedures will govern the conditions under which any of these overrides are utilized. In general, the prerequisite for i override is a determination that neither an accident conditions nor l
a radiation hazard exists. If either of these conditions exist, then specificsas to if or when the isolatin can be bypassed will be developed on a case by case basis.
Individual reactor trip override capability has not been supplied for all lines er. cept RCS letdown. When a stable post trip condition 2.1-16 Am. 21 e =4mes-w % .
e
l 2.1.1.8 Leak Reduction Program for Systems Outside Containment A leakage reduction program is being developed consistent with the requirements of NUREG-0578. Babcock & Wilcox (B&W) has been contracted to provide assistance in developing the overall program.
Metropolitan Edison Company will knplement the leakage reduction program in three distinct phases. In Phase 1, the scope, plan and development will be accomplished. This will include:
- 1. Determination of which systems need to be included in the program and which systems may be excluded.
- 2. Determination of where the leakage should be
! measured on' each system.
- 3. Determination of the best method to measure lea kage.
- 4. Determination of the system and plant conditions during the leakage measurement.
l
- 5. Development of a testing procedure for each system.
- 6. Development of a method to collect and present l
the data such that meaningful recommendations
! can be made.
- 7. Develop a schedule and frequency for data -
collection to improve the consistency of sample results.
In Phase 2, the actual leakage measurement tests will be performed for those systems identified. And in Phase 3, the data collected during the tests will be evaluated and the necessary corrective actions performed. The results of these Phase 2 tests will be reported to the NRC within 60 days of completion of Phase 3.
t Af ter the program's initial implementation, Metropolitan Edison Company will initiate a Preventive Maintenance Program '
which will perform periodic leak tests of the systems defined in the initial program.
l 2.1-29a Am. 21 J
is achieved, the operator can override the containment isolation signal at the system level in order to reestablish control of these s ystems .
2.1.1.5.4 References
- 1. Letter from Boyce Grier, of US NRC, to all owners of B&W
~
reactors dated April 5, 1979, IE Bulletins79-05A, 79-05B,79-05C.
2 10CFR50, Appendix A, General Desiga Criteria 55, 56, and 57.
- 3. B&W Company, Nuclear Power Generation Division, dated 5/22/79,
" Recommendations for Short-Term Changes to Containment Isolation Systems as a result of the Three Mile Island Unit 2 Accide nt . "
4 B&W Company, Nuclear Power Generation Division, dated 5/22/79,
" Recommendations for Long-Term Changes to be Considered to Containment Isolation Systems."
- 5. U.S. Nuclear Regulatory Commission. Standard Review Plan Section 6.2.4, Containment Isolation System, U.S. Nuclear Regulatory Commission.
- 6. U.S. Nuclear Regulatory Commission. TMI Lessons Learned Task Force Status Report and Short Term Recommendations. NUREG-0378, July 1979.
1 i 2.1.1.5.5 Safety Evaluation I
The selective addition of the containment isolation signals on high radiation, reactor trip and 30 psig R.B. pressure does '
not compromise plant safety for the following reasons:
- l. The system is designed as safety grade and single f ailure proof (except for high radiation isolation). Thus, the system will perform its saf ety function when required.
The probability of containment isolatfon occurring on demand is increased.
- 2. Spurious initiation of an isolation signal will not introduce new accidents into the plant design. Spurious initiation of any of the above signals would not isolate any components that would also be ~ isolated by a spurious initiation of the existing 4 psig building pressure signal.
Finally, the design meets the intent of all NRC directives to Met-Ed regarding containment isolationnamely the addition of isolation of high radiation, and low RCS pressure. The design j meets the requirements of Standard Review Plan 6.2.4 to the extent practicable.
2.1- 16a Am. 21 V T
Those systems which could contain highly radioactive fluids during a serious transient or accident have been listed in Table 2.1-4 as being within the scope of the NUREG-0578 f
Leakage Reduction Program. Table 2.1-4 also includes a summary description of the test method for each system.
j In some cases, wholly new procedures are required, while in other cases minor revisions to existing surveillance procedures will suffice. With the exception of the Reactor Building 7 -tegrated Leak Rate Test, all Leakage Reduction Program l .
Surveillance tests will be performed on a refueling interval frequency.
-Table 2.1-5 lists those systems presently excluded from this program and the reasons for their exclusion. These systems will be part of Peak Control Program and tested on a refueling interval frequency once in service.
~
Phases #2 and 3 of this program will be completed prior to TMI-l Restart. The results of the Phase #2 tests will be reported to the NRC within 60 days of completion of Phase 3.
Since testing is required at normal operating conditions, most tests will be performed during plant start-up and some others, such as the Sampling System, will be done during hot shutdown.
The leak reduction program will be based on ALARA considera-tions.
In addition to the above, review and inspection of release paths, as identified in IE Circular 79-21 and exemplified by the North Anna Unit 1 incident, were conducted. No modifica-tions to existing systems and/or equipment were deemed to be necessary as a result of this review. There were, however, '
1 some minor maintenance items identified, such as the need for installation of additional pipe caps or blanks on the down-stream side of some system vent, drain or test isolation valves.
These corrective measures will be completed prior to restart j 1
of TMI Unit 1.
2.1.1.9 Automatic Closure of the Pressurizer PORV Block Valve This Section has been deleted.
2.1-29b AM. 21
Regulatory Guide 1.97 Rsv. 2 (Dac.1979) will be followed for the design of high range effluent monitors. Vital bus power shall be employed for each system's modular assembly with the normal power supplying the monitor pumps with diesel gener-ations as back ups. Further descriptions of increased range capabilities are provided in Section 2.1.2.
High Range Ef fluent Radio Iodine & Particulate Sampling Analysis -
The existing sampling system will be expanded and will include the addition of silver zuolite cartridges. The system design and operation will both decrease the activity on the cartridges so they can be handled and will decrease the xenon to iodine ratio. Counting of the cartridges will be by use of Na1 crystal connected to a single or dual channel analyzer with appropriate window and discrimination settings for th 364 Kev gamma of I-131, or by use of a GELI/MCA system. The expanded portion of the sampling system would be placed in service follow-ing an accident and will be located in an applicable area exhibit-ing low background. The system will be on site and operable by 1 January, 1981.
Prior to incorporation of the expanded sampling system, procedures l will be developed for the use of silver zeolite cartridges and normal particulated filters for sampling with a NaI detector and a single or dual channel analyzer for iodine and gross particulate release rate determination. Specific details to insure exposures i are maintained as low as reasonably achievable will be incorporated into the procedures.
These procedures will be available for NRC review prior to restart.
I 2.1.2.2 RCS Venting ;
i 2.1.2.2.1 System Description Power operated vente will be provided for the reactor coolant system in order to ensure that natural circulation and adequate core cooling can be maintained following an accident. The vents ,
will be from the top of the pressurizer, the top of both hot legs l using existing connections on the reactor coolant piping and from the Reactor Vessel Head. The discharge from the reactor vessel and I hot leg vents will be directed to the containment atmosphere. The I system is shown schematically in Figure 2.1.-11.
The hot leg vents will tie into existing hot leg vent piping in-side the secondary shield wall. As part of this modification, re-mote operation of the vent valves in the existing vent line from the pressurizer to the reactor coolant drain tank will be provided and tl'c system will retain the existing venting capability. Con-trol and position indication for the power operated vent valves will be provided in the control room.
2.1-31 Am. 21
Panding the availability of the required safety grada equipm:nt to eccomplich this nodification, implementation can be completed by l March 1981. .
Instrumentation will be used for determining when hot leg venting is i
required and for determining when the venting is complete. The de-tails of this instrumentation will be provided later.
- 2.1.2.2.2 Design Basis Small break loss of coolant accidents (LOCA's) can lead to RCS depres-surization in which steam and/or non-condensible gases may accumulate in the reactor vessel head, the upper portion of the hot legs and in the pressurizer. Following repressurization of the RCS by high pres-sure injection (HPI), the steam bubbles collapse and remotely con-trolled vents on' the upper hot legs and pressurizer can be used to vent non-condensible gases to promote water solid natut al. circulation for core cooling.
The function of the reactor coolant venting system is to permit vent-ing, from a remote location, of gases trapped at high points in the re-actor coolant system when post-accident radiation and contamination levele will not permit access to systems inside the containment.
The hydrogen generation design basis for the system will be loss of coolant accident (LOCA) with hydrogen generation rates calculated in accordance with NRC Regulatory Guide 1.7.
The system will be capable of venting a volume of non-condensible gas equivalent to one-half of the reactor coolant system volume in one hour *. The system in performing its design function will not degrade nor defeat any features of the existing reactor coolant system. The remote operated vent valves will be solenoid operated (except for the normal " degas" valve from the pressurizer to the RCDT which is motor opera ted) . The power supplies and any instrumentation for the v,ent valve operators will be Class lE and from on-site power sources.
For new vent piping the pipe size selected and/or suitable restrictions will be such as to preclude challenges to the high pressure injection function of the Fbke-Up and Purification system. The vent lines will be sized so that an inadvertent opening of a pair of vent valves in a single vent line will not result in out-flow greater than the make-up capacity of a Make-up Pump. On this basis a LOCA analysis will not be required.
2.1.2.2.3 System Design The venting system will be designed to assure reactor coolant system integrity and the capability to vent the RCS to the containment follow-ing an accident.
- No te : This vent rate does not apply to the pressurizer since the pressurizer is being vented to the RCDT and a rapid vent rate poses the risk of blowing the RCDT ruptured disc and subsequent hydrogen burns / explosions. The vent f rom the pressurizer will be operated as a slow "degasing" vent.
2.1-32 Am. 21
I.
Tha key elem:nts of systen design are as follows:
l
-a) - Piping will be designed in accordance with ANSI (USAS) B31.7 l
" Code for Pressure Piping - Nuclear Power Piping."
Piping from the reactor coolant system hot legs, the reactor vessel head and the pressurizer to the power operated vent l . valves will be class N-1. Piping downstream of the vent valves will be class N-2. All vent valves will be class N-1.
l b) The solenoid vent valves, their operators, and the vent piping will be seismically designed and analyzed in accordance with
! the requirements of Seismic Class I.
c) New vent piping and valving will be designed and sized such {
that the failure to completely close off any one of the vent paths will'not cause a loss of reactor coolant at a rate in excess of the normal capability of the makeup system at full RCS design pressure.
d) The effluent flow from the reactor vessel and hot leg vent points will be routed directly. to the containment atmosphere.
The region into which the discharge is diverted will be selected j to enhance mixing and dilution so as to minimize the potential l
for regiorr, within the reactor building reaching flammable hydrogen gas concentrations. The design will take advantage of ev'. sting ventilation and heat removal systems for mixing and dilution. Discharges will be routed and directed so that the effluent will not adversely affect any structures, systems or components important to safety, e) Vent piping and valving will be designed to the same conditions as the reactor coolant system. Pipe and valve materials will be compatible with all anticipated fluids. These include '
water, saturated steam, steam water mixture, superheated steam, fission product gases, helium, nitrogen, boric acid solution and hydrogen.
l f) Spark f ree solenoid operated valves will be employed for vent-l ing. The valve operators will be qualified for normal and post-accident reactor building conditions, g) The system will be capable of venting a volume of non-l condensible gas equivalent to one-half of the reactor coolant system volume in one hour.
-h) The hydrogen generation design basis for the system will be a loss of coolant accident (LOCA) with hydrogen generation i
j rates calculated in accordance with NRC Regulatory Guide ~ l 7.
l i) The system will retain local manual vent capability to the i Reactor Coolant Drain Tank (for normal system operation venting.)
2.1-33 Am. 21
j) The reacts ,operatsd vant valvas will be solenoid operated (except for' the normal pressurizer . " degas" valve' which is motor operated). The solenoid valves will be energized to j open and fail closed on loss of power.
1
- k) . There will be two remote actuated valves in series in each vent line to provide redundancy so that a single active i failure of a valve to close will not degrade the RCS integrity.
k Each valve will have its own control switch and position-d indicating lights.
j
- 1) All valves for any one hot leg vent nozzle will be powered
- . from a safety grade supply independent of that which powers the valves for any other hot leg vent nozzle so that any single power supply failure cannot cause a failure to vent at least one hot leg.
m) Each venting point will be individually operable, independent <
. of any other vent point.
I n) Control of vent valves will be remote manual from the control room. Direct indication of actual valve positions will be provided in the control room.
o) Both vent valves at a vent point will be powered by the same power source, but controlled by independent swi tche s . An alarm in the main control room will indicate when the valves l
are energized.
. p) The piping and valving for the venting system will be routed, oriented and protected to preclude loss of system pressure re-i taining integrity f rom pipe whip, jet impringement and missiles j caused by small 00CA's and steam / feed ruptures.
q) Pipe routing, orientation and evaluation will assure that all remotely operable valves are located well above the maximum
' anticipated level of water in the containment following an l
j accident. Each solenoid operated vent will be designed to remain functional after all design basis events except large l
LOCA's, evacuation of the Main Control Room, and loss of actuation power.
l r) Existing nozzles in the RC System will be used for the venting
- system. No new nozzles will be added to achieve the venting l capability.
i 2.1.2.2.4 System Operation 2
- f This system will be used following a loss of coolant accident
, that generates volumes of non-condensable gas in suf ficient volume to jeopardize water solid natural circulation. The system is oper-ated manually f rom the main control room. Two spring loaded (to close) key-locked operating - switches must be manually held in the open position, simultaneously, in -order to establish a vent path to the containment atmosphere from any one hot leg vent point.
When the key-locked operating switches are released or when power i
i 2.1-34 Am. 21 9
e m *
- - uiL s-y - e ----
to the vent valva operators is cut off, the valves closo. Spec-ific operating procedures will prevent the operator from opening more than one vent path at a time. Inadvertant opening of a vent path will result in a loss of coolant rate which will be within the normal make-up capability of a Make-up Pump.
2.1.2.2.5 Design Evaluation The RCS high point venting modification will utilize, in part, existing high point vent piping in the RCS. Existing high point vents are used on a routine basis to vent the RCS during normal preoperational filling procedures. This modification
. will make possible the remote venting of gases, from high points in the RCS, to the contain2ent atmosphere following an accident.
, 2.1.2.2.6- Safety Evaluation The RCS remote operated system will be designed as a seismic category S-I system with safety grade power supply. Pipe class-ification will be N-1 up to the second isolation and N-2 down-stream of the second isolation valve.
RCS Integrity will be maintained by two (2) valves mounted in series in each vent line.
Based on hydrogen generation rates calculated in accordance with Regulatory Guide 1.7, no further analysis of hydrogen release to the containment atmosphere as result of operating this system is required, since TMI-l is being modified to install a hudrogen recombiner system capable _of handling hydrogen volumes in accordance with Regulatory Guide 1.7.
2.1-35 Am. 21 f -
+ m.-e e - , -y- -.1
Tha power supply to the respective vant valves will coma from dif ferent sources so as to provide a degree of redundancy of power to the dif ferent hot leg vent valves. l In order to prevent possible loss of coolant accidents, that could result from inadvertent valve actuation, the power supply to the vent valves will be nurmally de-energized. Also, adminis-trative controls, including key locked operating switches in the main control room, will be provided to preclude inadvertent operation.
Since the only portions of the system to penetrate the containment will be electric and instrumentation systems, there is no potential
-for a direct release to the outside environment as a result of the operation of this system.
2.1.2.2.7 Startup Testing and Inservice Testing / Inspection Requirements Besides the normal inservice inspection requirements imposed on design by ASME B&PV~ Code Sect. XI for system design and inspection, the following surveillance will be conducted on the solenoid actuated vent valves:
The vent valves will be exercised during each refueling outage in accordance with existing TMI-l requirements for reactor cooling system venting.
Also, provisions will be made for testing all portions of the venting system during the TMI-l restart startup and test program.
Testing will consist of the following:
a) Flow indication to show that flow is present. Such testing will likely be done during initial fill, b) Confirmation of vent shutoff capability will be established during pre-service hydrostatic testing.
During plant operation flow indications which have been previously tested will be monitored to assure that gross inadvertent venting is not occurring during normal reactor operation.
2.1.2.2.8 Instrumentation The remote actuation station for the solenoid vent valves (located in the main control room) will be controlled by means of key-oper-l ated switches. The switches will be two position, spring return to 'the "CLOSE" position. The actuation station will be equipped with the following for each solenoid valve:
a) Key-locked Operating switch i
b) Position indicating lights (open-red / closed green) i 2.1-36 Am. 21
,1-Valve position shall be derived from stem operated limit switches or comparable means.
Annunciation (visual and audio), for unintentional vent valve operation will be provided in the main control room.
Control of valves for any one vent point will be independent of the control for valves for any other vent point.
Instrumentation will be used to allow the operator to determine 1 when venting is required. Also, instrumentation-will be provided to indicate the presence of flow in the vent lines.
~
i i
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i s
4 2.1-37 Am. 21
~ . - - ~_. - ..
THREE MILE ISLAND UNIT NO.1 ,
TABLE 2.1-1 List of Isolation Signal Override Capability Isolation Signal Penetration Reactor High 4 psig 30 psig 1600 psig Line No. Trip Radiation Building Building (L.AS) Break Containment Air Sample 108 N/A N/A C N/A C N/A R.B. Sump 353 C IB C N/A N/A N/A RCDT 330,331 C IB C N/A N/A N/A RCS Sample 328 C IB C N/A N/A N/A R.B. Purge 336,423 C K K N/A N/A N/A RCS Makeup 323 N/A N/A C N/A C N/A RCS Letdown 309 (MU-V2A/B) N/A IB C N/A C N/A (MU-V3) A NTA C N/A N/A N/A Demin Water 307 C N/A C N/A N/A N/A OTSG Sample 213, 214 C IB C N/A N/A N/A NSCCW 346, 347 N/A N/A N/A NO N/A NO ICCW 302, 333, N/A N/A N/A NO N/A NO 334 R.B. Air Coolers 421, 422 N/A N/A C N/A C N/A R.C. Pump Seal Return 329 N/A N/A NA NO N/A N/A Core Flood TK 348,348 C N/A C N/A N/A N/A Legend C = Common Signal Override; initiating isolation condition may still exist.
I = Individual isolation signal override capability; procedures governing override to be developed.
4 IB = Individual isolation signal bypass capability A = Automatic isolation signal override.
K = Common signal override with key interlock permissive. l NO = No override or bypass capability; initiating condition must clear to allow reopening of valve.
N/A = Not applicable.
Note: For combinations of initiating signals tbat are allowable, refer to Table 2.1-2.
i Am.M21
P;gt 1 of 2 THRFE MILE ISIMD L3IT NO. 1
- TABLE 2.1-2 LIST OF CCPrTAINMENT ISOLATICN VALVt.S REOUTRIP:C MODIFICATICNS Valve Line Method Normal Post Actual TalVe PJne t ra tion Valve Valve Sire, of Valve Accident Position Position Actuation Signal Source No. Se rvic e System Tag No. Type In. Actuation Position Existing Mod 1 5 d Indication Existice Modified Notes 108 Contatruent Air RM CM-VI Ball 1 Ai r Open Closed Closed Yes 1,10 1.22 6.10 Sample CM-V2 Ball 1 Air Open Closed Closed Tes 01-V 3 Ball 1 Ai r Open Closed Closed Yes CM-V4 Ball 1 Air Open Closed Closed Yes 213 Steam Cenerator CA CA-V4A Clobe 3/8 EMO Closed Cl osed Closed Yes 1,10 1,4,5,6,10 No 84W recommendation Sampl e CA-V5A Clobe 3/8 Ai r Closed Closed Closed Yes 214 Steam Generator CA CA-V45 Clobe 3/8 EMO Closed Closed Closed Yes 1,10 1,4,5,6,10 Sample CA-V5B Clobe 3/8 Air Closed Closed Closed Yes 302 In te rmedia te IC IC-v2 Cate 6 EMO Ope n Closed Open/ Closed Yes 1,L10 J,7,8,9,10 Cooling IC-V3 Cate 6 Air Open Closed Open/ Closed Yes Water Outlet Line 307 Demin. Water to CA CA-V189 Cate 2 Ai r Open Closed Closed Yes 1,10 1.5.10 Reactor Building FU-V2A Clobe 2-1/2 EMO Open Open/ Closed Closed Yes 1,10 1,2,4,6,10 309 Letdown Line to MU Purification MU-V2B Clobe 2-1/2 EMO Open Open/ Closed Closed Yes 1,10 1,2,4,6,10 Demineralizers MU-V 3 Cate 2-1/2 Air Open Open/ Closed Closed Yes 1,10 1,5,6,10 323 P'. Makeup MU MU-V18 Cate 2-1/2 Ai r Open Closed Closed Yes 1,10 1,2,10 328 Pressurizer and CA CA-VI Clobe 3/8 EMO Closed Closed Closed Yes 1,10 1,4,5,6,10 Reactor Coolant CA-V2 Cate 3/8 Air Closed Closed Closed Yes Sample Lines CA-V3 Clobe 3/8 EMO Closed Closed Closed Yes CA-V13 Clobe 3/8 EMO Closed Closed Closed Yes 329 Reactor Coolant MU itU-V25 Clobe & EMO Opm Closed Open/ Closed Yes 1,7,10 3,7,8,10 Pump Seal Return MU-V26 Cate 4 Air Open Closed Open/ Closed Yes Reactor Coolant WDC WDG-V3 Clobe 2 EMO Open Closed closed Yes 1,10 1,4,5,10 330 Drain Tank WDC-V4 Cate 2 Air Open Closed Closed Yes Vent Reactor Coolant WDL WDL-V 303 Cate 4 EMO Closed Closed Closed Yes 1,10 I,4,5,10 3 31 Drain Tank Pump WDL-V304 Cate 4 Air Clesed Closed Closed Yes Di sc ha rge 333 In t e rmediat e IC IC-V4 Cate 6 Ai r Open Closed Open/ Closed Yes 1,32 10 3,7,8,9,10 Cooling Water Supply Line 334 In t e rmed ia t e IC IC-v6 Cate 3 Air Open Closed Open/ Closed Yes 1,L10 3,,7,L9,10 Cooling to CRDM Cooling Co!!s
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Pg. 2 Ef 2 THREE MILE ISIAND 1: NIT NO. I TALLE 2.1-2 (CGNT'D)
LIST OF CONTAI W ENT Is0LATION %ALVES REOCIRING MODITICATIONS Valve Line Method No rmal Post Actual Valve Valve Valve Sire, of Valve Ac c i<f e n t Position Position Actuation Signal Source Pene t ra tion No. Service System Tag No. Type in. Actuation Position Fufsti g Modified Indication Existing Modified Notes 3 36 Reactor Building AH AH-VIA Butter- 48 Air Closed Closed Closed Yes 3.10 1.4.5.10 Outlet Purge fly Li ne AH-VIB Butter- 48 EMO Closed Closed Closed Yes fly 346 Reactor Coolant NS NS-VIS Cate 8 EMO Open Closed Open/ Closed '. s 1.10 7.8,9,10 Pump letor Cooling Water Su ppl y Cate Open Closed Open/ Closed Yes 1.10 7.8.9.10 Pissp Motor 347 - Reactor Coolant NF NS-V4 8 EMO Rea'ctor Building RB-V7 Cate 8 Air Open Closed Open Yes 1.10 1.2.10; 422 RB Normal Air Coolers Return Line 423 Reactor Building AH Afi-VIC Butter- 48 EMO Closed Closed Closed Yes 1.4.10 1.4.5.10 Inlet Purge fly Li ne AH-VID Butter- 48 Air Closed Closed Closed Yes fly 348.349 Core Flood TK. CP CF-V2A&B Clebe ! EMO Closed closed Closed Yes M 1.5.10 Sample and N Fill -Vl9A&B Cate i Air Closed Closed Closed Ye*
2 Lines -V2CA&B Cate 1 Air Closed Closed Closed Yes Valve Actu ; ion Signal Source
- 1) 4 pale reactor building pressure isolation 7) Classify line to Seismic Category I
- 2) 1600 psig (SFAS) f oolation 8) 30 psig reactor building pressure isolation
- 3) Radiation alare, operator action required 9) Line break isolation signal
- 4) High radiation (non-safety) isolation 10) Remote manual control
- 5) Reactor trip isolation
- 6) Override capability on individual valves nn --
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LIST OF CONTAINMENT PENETRATIONS REQUIRING ISOLATION ON HI-RADIATION Isolation Radiation Penetration Valve Detector Type of No. Service System Tag No. Location Monitor 213 Steam Generator CA CA-V4A Locate the monitors outside the R.B. Area and Sample -V5A near the sampling line downstream of Camma 214 -V4B the containment isolation valve and Detectors
-V5B upstream of connection for Turb. (New)
Plant sampling 3 09 Letdown Line to MU HU-V2A Utilize existing Rad. Monitor RM/L-1 Inline Purification -V2B located outside R.B. (Existing)
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328 Pressurizer and CA CA-VI locate the monitor outside the R.B. Area Camma
.f Reactor Coolant -V2 between the isclation valve and the Detector 5h 1 Sample Lines -V3 sample cooler. (New)
-V13 ij l} 329 Reactor Coolant MU HU-V33L Locate the online radiation monitor Area Camma Pumps Seal -35B downstream of the containment isola- Detector
.l;; Return -33C tion valves outside of the R. B. for (New) f -33D Alarm Operator action is required to close valves.
]
330 Reactor Coolant WDG WDG-V3 Imcate the monitor on the outside of Area Camma Drain Tank the tank.R.B. St rap monitor onto vent Detector and Vent -V4 and drain lines are near each other (New) 331 Reactor Coolant WDL WDL-V303 Drain Tank Pump Discharge -V304 336 Reactor Building AH AH-VIA Utilize the existing purge outlet Inline Outlet and -V1B line Rad. Monitor RM/A-9 located (Existing) .
and Inlet Purge '- VIC outside of R.B.
423 Lines -VID 353 Reactor Building WDL WDL-V534 Locate an area radiation monitor Sump Area Sump Drain -V535 in the R.B. Sump mounted inside Monitor a seismically supported pipe. (New) 302 Intermediate Cooling IC IC-V2,3 Locate the radiation monitor on the Incline 333 Supply & Return -V 4,6 6" IC return line between valve (Existing) and IC-V3 and the 2" ptsap recirc. line 1
334
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6.0 OPERATOR ACCELERATED RETRAINING PROGRAM (OARP)
6.1 INTRODUCTION
In preparation for restarting THI-1, a retraining program for TMI-l Reactor Operators and Senior Reactor Operators was implemented. Several . training issues considered as prerequisites to resuming power operation at TMI-l have been identified and addressed in the Operator Accelerated Retraining Program, a subsequent evaluation process is required of all personnel who will be assigned as Reactor Operators and Senior Reactor Opera-tors at THI-l during the resumption of power operation.
The Operator Accelerated Retraining Program included over sixty (60) presentations and/or practice sessions involving over two-hundred hours of training. Included in the program were at least twenty (20) hours of training directly involved with analyzing and handling abnormal and emergency situations at the Babcock and Wilcox Nuclear Training Center Simulator.
The Operator Accelerated Retraining Program covered topics which could be grouped into four functional areas:
- TM1 Plant System Review
- THI Plant Operational Review
- Radioactive Materials Control
6.2 PROGRAM OBJECTIVES The Operator Accelerated Retraining Program was designed to accomplish several objectives relating to enhancing 'D11-1 Reactor Operator and Senior Reactor Operator performance. The achieve-ment of these objectives is in accordance with the performance standards specified in Section VI (Evaluation Procedure) and is a prerequisite to resuming operation of THI-1. Program lectures which support the objectives and references for the objectives are listed in Appendix A.
The Operator Accelerated Retraining Program objectives were as follows:
A. To improve operator performance during small break loss of coolant accidents.
B. To assure that the operator can recognize and respond to conditions of nadequate core cooling.
1 l
6-1 Am. 21 i
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es I
C. To improve operator performance during transients and acci-dents including events that cause or are worsened by inap-propriate operator action.
D. To ' assure that the operators have an in-depth understanding of the TM1-2 accident and lessons learned.
E. To assure that operators are knowledgeable of operating i procedures and actions required upon initiation of the engineering safeguards features including reactor coolant pump requirements.
F. To assure that operators understand the manometer ef fects of water levels in the reactor coolant system under dif ferent coolant system presure and temperature conditions.
G. To assure that operators are aware of the extreme seriousness and consequences of the simultaneous blocking of both auxiliary feedwater trains.
H. To assure that operators are aware of the prompt NRC notifi-cations required in the case of serious events and signifi-cant events.
I. To provide the operators with an in-depth understanding of the methods required to establish and maintain natural circulation.
I J. To assure that operators are knowledgeable of both short and long term plant systems modifications. -
K. To provide the operators with a review of the major plant j systems.
L. To provide specialized training on " Operations and Procedural Guidance Requirements".
M. To-assure operators are fully qualified through the admini-stration of the Company and NRC administered final written and oral examination.
N. To provide the operator with a review of major administrative, normal, abnormal, and entegency procedures.
O. To assure all licensed Unit 1 operators receive training on the B&W Simulator covering the THI-2 incident.
6.3 Topical Outline The Operator Accelerated Retraining Program included over sixty (60) presentations and/or practice sessions covering topics which could be grouped into four (4) functional areas:
i
- TMI Plant Systems Review
- TMI Plant Operational Review i
6-2 Am. 21 I I
- Radioactive Materials Control
- TM1 Plant Transient Analysis The program topics included coverage of essential information needed to understand Is11-1 plant design and operation. Detailed information on plant systems, operating procedures, and transient analysis were also included to provide an-overall understanding of safe nuclear plant operating practices.
A. TMI Plant Systems Review Topics which provided a specific plant systems information addressed the following areas:
- Features of Facility Design
- Instrumentation and Control
- Safety and Emergency Systems Presentations covering specific information on system func- j l
tions, capabilities, limitation, interrelationships and )
controls were involved.
The specific topics were:
- 2. Makeup and Purification System
- 3. Control Rod Drive System
- 4. Nuclear Instrumenta tion and In-Core Instrumentation
- 6. Decay Heat River System l 7. Conta inment Isolation System
! 8. High Pressure Injection System
- 9. Nuclear Services Closed Cooling System
- 10. Decay Heat Closed Cooling System
- 11. Core Flood System
- 12. Nuclear Service River Water System
- 13. Reactor Building Emergency Cooling System
- 14. Intermediate Closed Cooling System
- 15. Feedwater System 1 16. Condensate System i 17. Emergency Feedwater System
- 18. thin Steam System
- 19. Electrical Distribution System
- 20. Emergency Diesel
- 22. Ventilation
- 24. Emergency Safeguards Actuation System
- 25. Non-nuclear Instrumentation and Interlocks
- 20. Computer and Mod Comp
- 27. T!!I-1 Short Term Change Modifications
- 28. TMI-1 Long Term Change Modifications 6-3 Am. 21 W% stamp %~muw - -- , a a 2.%W'. ; ,,e = - - = - e +2C
B. TMI Plant Operational Raview Topics which provided information covering the plant general operating characteristics and specific procedural guidance addressed the following areas:
- Heat Transfer and Fluid. Dynamics
- Principles of Reactor Operation and Reactor Theory
- General and Specific Operating Characteristics
- Administrative Procedures, Conditions and Limitations
- Fuel Handling and Core Parameters Presentations on plant operation were designed to give detail-ed information on fundamental plant operation and specific procedural guidance. The specific topics were:
- 1. Heat Transfer and Fluid Dynamics
- 2. Reactor Theory
- 3. Use of Procedures
- 4. Operating Characteristics Review-including natural circulation
- 5. Solid Plant Operations
- 6. Operational Chemistry
- 7. Standard and Emergency Operating Procedures-(covered in nine sections)
(1) Administrative Procedures (2) Limitations and Precautions (3) Emergency Procedures (4) Emergency Feedwater Procedures (5) Reactor Coolant Pump Procedures (6) Electrical Power Emergency Procedures (7) Primary System Leak Emergency Procedures (8) Operating Procedures (9) Steam System Emergency Procedures
- 8. Technical Specifications - Limiting Conditions for Operations
- 9. Technical Specifications Review
- 10. Fuel Handling and Core Parameters
- 11. NRC Prompt Notification Enforcement Policy C. Radioactive Materials Control f
Topics which provided information covering radioactive ma-terials control addressed the following areas: ,
! 6-4 Am. 21 i
i ___ _
+
- Radiation Control and Safety
- Radioactive Material Handling, Disposal and Hazards
- TMI Emergency Plaa The specific topics were:
- 1. TMI Radiation Emergency Plan
- 2. Radiation Safety and Radioactive Materials Control
- 3. Radiation Monitoring
- 4. Liquid and Gaseous Releases D. TML Plant Transient Analysis Topics which provided information covering plant abnormal operating characteristics and plant transients addressed the
.following areas:
- THI-2 Transient
- Safety Analysis for TMI-l
- TMI Simulator Training The specific topics are:
- 1. THI-2 Transient
- 2. Small Break Loss of Coolant Accident Operator Guidance
- 3. Reactor Coolant System Elevations and Manometer Ef fect
- 4. Expected Instruments and Plant Response to Transients
- 5. TMI Control Room Session
- 6. Safety Analysis Workshop In addition to these topics, specifically besigned training sessions were conducted at the Babcock and Wilcox Simulator Traiaing Center. These training sessions involved discussion of plant transient information and simulator training on specific casualty situations.
The topics covered included:
- 1. Power Distribution and Rod Withdrawal Limits
]
- 2. Heat Transfer and Fluid Flow
! 3. Small Break Analysis 4 Safety Analysis
- 5. Unannounced Casualties (conducted on the simulator)
- 6. Special program on the B&W Simulator covering the TMI-2 accident I 6.4 PROGRAM RATIONALE The selection of topics which were included in the Operator Accelerat-ed Retraining Program was based on several factors. During the program formulation stage, the extensive training curriculum the TMI-l Reactor Operator and Senior Reactor Operator have already 6-5 Am. 21 e
- completed was balanced with the training needs related to the current TMI-l and D11-2 plant status. Specific sources utilized in identifying program topics included the following areas:
A. Standard references for operator training programs considered in determining course content include:
- 1. 10 CFR 55 - Operator's License
- 2. NUREG-0094 - NRC Operator Licensing Guide
- 3. T!!I-l FSAR
- 4. Ril-1 Operator Requalification Program The topics included in the Operator Accelerated Retraining Program provide for coverage of all the areas in the NRC operators written examination (10 CFR 55.21/22). In addition topics included in the program include lecture requirements
' in the T!!I'Requalification Program (10 CFR 55 Appendix A and T!il-1 FSAR Section 12).
B. Other Licensed Nuclear Operator Training References In making specific topic selections for the course content, )
other information sources for operator training were used. i I
These sources include:
- 1. NRC Bulletins 79-05,79-05A, 79-05B and 79-05C. l
- 2. Metropolitan Edison Company commitments on operator training (J. Herbein letter to hRC dated June 28, 1979).
- 3. NRC letter - Order and Notice of Hearing, August 9, 1979.
I
- 4. Interviews with TMI Operators.
- 5. T!!I-1 plant modifications (Short Term and Long Term).
- 6. D11-2 incident information and other relevant License Event Reports.
- 7. NUREG - 0578 nil-2 Lessons Learned l 6.5 INSTRUCTIONAL PROCEDURE The Operator Accelerated Retraining Program topics were presented using a variety of instructional techniques. Instructional techniques utilized for particular program topics were selected to build comprehension of nuclear plant fundamentals, develop the 6-6 Am. 21
ability to analyze and respond to plant operational situations, and ensure understanding of current TMI-l plant conditions and
- procedural guidance.
! In order to achieve the retraining program goals, the instruc-tional techniques utilized included:
- Classroom Lectures
- Classroom Discussions
- Classroom Working Sessions
- THI Control Room Training Sessions
- Nuclear Plant Simulator Practice Sessions (B&W Simulator Training Center)
A. Classroom Sessions In preparation for the classroom presentations conducted at TMI, an extensive program development process was
- completed. This preparation included the involvument of a primary and, as needed, a backup instructor for designated
! training sessions. Comprehensive lesson plans developed for the training sessions ensured a well directed approach for the presentations.
- 1. Topic Lesson Plan Preparation Lesson plans deve1oped for the training sessions were in ace ' with a st-adard format which
! includes a elements c comprehensive presenta-i tion and written guidance at carrying out a topic presentation.
1 Primary instructors assigned to prepare topic lesson plans have technical expertise in the specific areas covered by assigned topics. The primary instructor identified specific lesson plan objectives and developed the lesson plan material.
Backup instructors, as needed, were assigned to assist in preparing topic lesson plans.
The combined development efforts of the primary and backup instructors were reviewed by designated training department staf f members at various stages i to ensure a well directed, comprehensive topic presentation was adequately supported.
6-7 Am. 21
- 2. Topic Classroom Presentation Classroom sessions were conducted following the direction provided by the topic lesson plan and lesson plan development summary. The primary instructor (or a designated alternate) presented the topical information. The backup instructor, when appropriate, sat in on the presentation and ensured that the essential topic information was covered during the presentation. This included clarifying certain points and asking specific questions related to the topic lesson objectives and support material.
B. Control Room and Simulator Sessions The Conttol Room and Simulator Training sessions were designed to enable hands on application of guidance provided to TMI-1 operators. In preparation for these sessions, specific areas of coverage were designated to ensure essential items identified and/or demonstrated for the operators.
- 1. Control Room Sessions A review with the information/ instrumentation available in the TM1-1 Control Room was addressed in a specific session. This supplements the references made during other topic presentations which interfaced with Control Room features. A tour of the Control Room was conducted under the guidance of a lesson plan prepared by a primary instructor and was designed to build the association of operational concept and guidance with actual system controls.
- 2. Simulator Sessions I
The B&W Simulator Training was included in the program to provide actual practice for the TM1 operators in handling planc transient situations. ,
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i 6-8 Am. 21
The training practices used during the simulator train-ing sessions enabled the following:
- Detailed use of procedures (including follow-up actions)
- Plant casualties carried out until a stable condition is reached
- !!ultiple plant casualties simulated
- Watch section members handling casualties as a team, with specific job assignments made
- Casualty conditions analyzed with watchstander input, supervisor deciding course of action and supervisor directing recovery
- Watch section members evaluated as a team on specific casualty response 1
6.6 EVALUATION-PROCEDURE ,
i The Operator Accelerated Retraining Program was evaluated formally and informally in several manners. Continuous informal evalua-tion occurred during the training sessiosn as the instructor ,
and/or backup instructor gauged trainee understanding by asking !
questions and observing performance. l Formal evaluations of the training program, instructor delivery, trainee performance and trainee knowledge level were also conduct-ed and analyzed. In addition, performance standards were speci-fled for key evaluation processes.
A. Trainee Evaluation of the Program At the completion of each week of the training program, selected trainees were asked to evaluate and comment on the training sessions. This evaluation encompassed the instructors, training materials, presentation techniques, and classroom facilities. Results of these evaluations i were a means of measuring the trainees' reaction to the l training program. Problems which were identified by these l evaluations were considered and resolved by the TMI ;
Training Department staff. Necessary changes to the l program were factored into subsequent presentations. If a l deficiency was deemed to be severe and could not be otherwise compensated for, parts of the program were repeated with the appropriate modifications incorporated. i B. Presentation Evaluations Each seasion of the program was be monitored and evaluated. l 6-9 Am. 21
An Instructor Evaluation Form was completed for the session and a presentation grade computed. To ensure the overall quality of instruction for each session, the .
following minimum standards were established.
- 1. Individual Presentation Standard Presentation Grade > 2.5 (on a 4.0 scale)
- The Presentation Grade is the average grade of all the individually graded entries on the Instructor Evaluation Form.
- 2. Topic Presentation Standard Topic Crade > 3.0 (on a 4.0 scale) l The Topic Grade is the average grade of all the indi-vidual presentation grades for the topic.
Presentations which do not meet the minimum standards have been subjected to the following:
- 1. Weaknesses found in the presentation were discussed with the instructor.
l
- 2. Key concepts which were not adequately covered in the presentation were presented again to the trainees in a subsequent training session.
- 3. Trainee performance on quiz questions on the concepts covered in the presentation were evaluated. If the class average performance of 70% was found, the j
entire training session was repeated for the af fected i trainees.
C. Knowledge Evaluations by Quiz Each lesson plan for the program was developed with -
representative quiz questions identified. During each week of training, quizzes were administered and utilized for evaluation of trainee knowledge level. The quizzes l met or exceeded the following quiz standards: l
- 1. Quizzes were administered for each week of training.
- 2. Each quiz will consisted of at least ten questions.
- 3. At least 75% of the individual lesson plans presented during the week had representative questions included in one or more of the quizzes.
l
- 4. A variety of question types were used, but essay questions predominated.
l 6-10 Am. 21 1
A Quizzes were scored and a grade for each quiz determined.
j To ensure satisfactory level of understanding of the weekly program naterial, the following minimum standard was es-tablished for each trainee's performance:
- 1. Individual Quiz Standard Individual Quiz Grade > 80%
I - For trainees who did not meet this standard, the following
, action was taken:
- 1. The trainee reviewed the program material by re-viewing the topic lesson plan and/or handouts.
I
- 2. Another quiz or oral examination using different ques-tions was administered and graded with the same 4 standards in effect.
{ D. Knowledge Evaluation by Oral and Written Comprehensive i Examination
- 1. At the completion of the program, an Auditor Group
. conducted a written and oral evaluation of the l licensed trainees. The evaluation was equivalent to i an NRC administered licensing examination. It
! included an expanded examination section covering the j Operator Accelerated Retraining Program objectives.
! Each successful trainee was required to pass the audit examination established examination standard.
i
- 2. Licensed Unit 1 personnel will finally be required to i take an NRC administered oral and written license examination.
! 6.7 PROGRAM FORMAT The Operator Accelerated Retraining Program was developed with over sixty individual lessons involving classroom presentations,
- THI Control Room walkthrough and simulator training sessions.
! The entire program was scheduled for completion in seven modules, with a module consisting of 4 to 5 days (8 hr/ day) of training.
6-11 Am. 21 i
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Structuring the program into modules enabled the scheduling of the presentations to occur during the six week cycle TMI training shift, or as a full time program. The content of each module was a selected grouping of individual lesson plans which covered material which was related to similar subjects. The modules are identified in Appendix B and are representative of the program scheduling.
A. Simulator Training Module The initial program training module involved four and one-half days of training at the Babcock and Wilcox Nuclear Training Center. The module content included classroom training sessions and Control Room operational sessions. The indivi-dual topics were:
- 1. Power ~ Distribution and Rod Withdrawal Limits (4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />)
- 2. IIcat Transfer and Fluid Flow (4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />)
- 3. Small Break Analysis (4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />)
- 4. Safety Analysis (4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />)
- 5. TMI-2 Accident Analysis (4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />)
- 6. Unannounced Casualties (16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br />)
The plant casualties included:
- a. Natural Circulation Cooldown
- c. Station Blackout (with diesels)
- d. Loss of Coolant Accident
- e. Steam Generator Overfeed
- f. Steam Generator Tube Leak
- g. Steam Leak in the Reactor Building The simulator training module provided an overview of guid-ance for operators which has resulted from analysis of the THI-2 incident and involvement in simulated plant abnormal and emergency conditions. This initial program module supplemented previous operator training and provided a reference point for subsequent program modules dealing with detailed plant systems, operator guidance and nuclear plant
. fundamentala.
6-12 Am. 21 l
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B. TMI Module One The first module of the program conducted at TMI involved four days of classroom training focused on nuclear plant fundamentals intergrated with specific plant operational characteristics. The individual topics were:
- 1. Heat Transfer and Fluid Dynamics (16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br />)
- 2. Reactor Theory (16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br />)
The content of module one provided an in-depth coverage of the fundamental aspects of nuclear reactor control and nuclear reactor heat removal. These topics review principles were necessary for understanding the purpose and function of nuclear plant systems, operational procedures and required operator actions for safe operation of THI-1.
l C. TMI Module Two The second module of the program conducted at TMI involved three and one-half days of classroom training covering specific THI-1 plant information on selected plant transients, plant systems and the Radiation Emergency Plan. The indivi-dual topics are:
- 1. TM1-2 Transient (4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />)
- 2. Reactor Coolant System (5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />)
- 3. Make-up and Purification System (4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />)
- 4. In-Core Instrumentation (1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />)
- 5. Control Rod Drive System (4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />)
- 6. Nuclear Instrumentation (2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />)
, 7. Integrated Control System (4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />) i l
- 8. Radiation Emergency Plan (4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />) i The content of module two provided detailed coverage of the THI-2 Transient which occurred March 28, 1979. This put into perspective the plant systems and procedural training sessions included in subsequent program lessons. Detailed plant-system coverage began in module two with sessions on key primary plant systems.
1 1
6-13 Am. 21 I l
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D. T!!I flodule Three The third module of the program conducted at T!il involved four and one-half days of classroom training covering cpe-cific T!!I-l plant systems and operational procedures. The individual topics were:
- 1. Decay lleat Removal System (1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />)
- 2. Decay llent closed Cooling System (1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />)
- 3. Core Flood System (1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />)
- 4. Containment Isolation (1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />)
- 5. liigh Pressure Injection (1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />)
- 6. Use of Procedures (2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />)
- 7. Nuclear Service Closed Cooling System (1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />)
- 8. Nuclear Services River Water System (1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />)
- 9. Reactor Building Emergency Cooling System (1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />)
- 10. Intermediate Closed Cooling System (1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />)
- 11. Feedwater System (1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />)
- 12. Condensate System (1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />)
- 13. Procedure Review-Reactor Coolant Pump Procedure (2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />)
- 14. Procedure Review-Emergency Feedwater Procedure (2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />)
- 15. Main Eteam System (1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />)
- 16. Electrical Distribution (3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />)
- 17. Emergency Diesel (2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />)
- 18. Procedure Review-Electrical Power Emergency Procedure (2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />)
- 19. Engineered Safeguards Actuation System (4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />)
- 20. Procedure Review-0TSG Tube Rupture, Loss of RC PAZ/ Coolant, High Radiation and Activity Levels
- 21. Procedure Review-Plant STitTUP/ Shutdown, Approach to Criticality, RC Fill / Vent, RC Draining and N2 Blanketing, and unanticipated criticality J 6-14 Am. 21
- 22. Procadure R: view-Prescurizsd Sys. Faillre, Loss of Decay Heat Removal, Steam Supply Rupture and Loss of Instrument Air
- 23. Procedure Review-Station Blackout, Load Resection, Natural Circulation and Low System Voltage.
The content of module three provided detailed coverage of selected TMI-1 primary and secondary plant systems. The systems covered in the program included systems essential to normal and emergency cooling of the reactor.
E. TMI Module Four The fourth module of the program conducted at THI involved four and one-half days of classroom training covering spe-cific TM1-1 plant systems, operational procedures and radio-active materials monitoring / control. The individual topics were:
- 1. Reactor Protection System (4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />)
- 2. Operating Characteristics Review including Natural Circulation (4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />)
- 3. Solid Plant Operations (2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />)
- 4. Procedure Review-Emergency Procedure (2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />)
- 5. Procedure Review-Operating Procedures (4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />)
- 6. Radiation Safety and Radioactive Materials Control (4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />)
- 7. Radiation Monitoring (included in Radiation Safety Lecture)
- 8. Liquid and Caseous Releases (2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />)
- 9. Operational Chemistry (2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />)
- 10. Procedure Rcview - Radiation Trip and Turbine Trip The content of module four provided detailed coverage of selected TML-1 systems and plant procedures. Specific attention was given to normal and abnormal plant operating and related procedural guidance. Radiation safety, radiation monitoring, and radioactive materials control was covered to review existing guidance and present modifications made at THI following the TMI-2 incident.
l l F. THI Module Five l- The fif th module of the program conducted at TMI involved five days of classroom training covering specific TMI-1 plant i 6-15 Am. 21 1
W. N> ? i O .
cyst:rs, optrational proc:dures, technical ep:cificatienz and plant op2roticnal charactsristica. Tha individual topics wera:
- 1. Ventilation (3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />)
- 3. Technical Specifications-Limiting Conditions for Opera- 1 tion (4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />)
- 4. Technical Specifications-Definitions and Safety Limits (2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />)
- 5. Procedure Review-Administrative Procedures and Limita-tions and Precautions (2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />)
- 6. Technical Specifications Review (4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />)
- 7. Non-Nuclear Instrumentation and Interlocks (4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />) s 8. Small Break Loss of Coolant Accident Operator Guidance i
(4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />)
- 9. Expected Instrument and Plant Response to Transients (4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />)
- 10. Reactor Coolant System Elevations and Manometer Effects (2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />)
- 11. Fuel Handling and Core Parameters (4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />)
- 12. Simulated Transients in Control Room (4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />)
- 13. NRC Prompt Reporting Requirements.
The content of module five provided detailed coverage of selected TMI-1 Systems and plant administrative procedures.
Specific attention was given to normal and abnormal plant operating characteristics and related procedural guidance, including plant technical specifications. The THI-l Control Room was used to develop further relationship between expected plant response to operational situations and actual control instrumentation locations and features.
G. TMI Module Six The sixth module of the program conducted at TMI involved five days of classroom training covering THI-1 plant modifi-cations and extensive coverage of safety analysis for THI-1.
The individual topics were:
- 1. Computer and Computer Modifications (Post 0ARP Program)
- 2. TMI-l Long Range Design Modifications (4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />)
- 3. Safety Analysis Workshop (32 hours3.703704e-4 days <br />0.00889 hours <br />5.291005e-5 weeks <br />1.2176e-5 months <br />) 4 6-16 Am. 21 w ;- _, .- _, _ . , . ; . y.
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l The content of module six provided an overview of specific changes being planned and accomplished at THI and provided an
- in-depth presentation of key safety analysis areas and their
.l _ implication to TMI-l plant operation. The safety analysis l training covered several areas of integrated TMI-1 plant response to normal and abnormal events and provided guidance
! in evaluating plant performance in real time. The fundamen-tal principles of plant operation and plant system informa-
! tion was combined with existing plant data to analyze several categories of potential abnormal operating conditions and categories of plant emergencies.
4
)
4 4
4 4
t 6-17 Am. 21 4
Further centributing to the availability and escurity of the liquid waste system is the fact that all of the above equipment is located within Seismic Class 1 structures that have been hardened to with-stand an aircraf t impact. Within these structures, all equipment that is anticipated to become a significant radiation source is housed within 2 to 3 foot thick shield walls for the protection of plant personnel from . radiation. The atmosphere of each of these shielded cubicles is maintained at a slightly lower pressure than that in surrounding areas to ensure that any radioactive gas leakage is away from plant personnel.
4 Based on the above indicated systems and equipment, the design basis waste liquid quantities generated annually and the design basis activity levels analysis indicates that the liquid effluent leaving
! the plant site is well within the limits specified by Appendix 1 with the exception of tritium. With 17,500 gpm of the cooling tower effluent allocated to Unit 1, the Unit 1 annual discharge volume for which dilution credit may be taken is 3.48 x 1010 liters. The annual quantities of mixed fission products (excluding
! tritium) and tritium discharged from Unit I are 49,000 uCi and 5.02 x 108 uCi respectively. These design basis numbers result in an annual average mixed fission product concentration in the plant ef fluent of 1.4 x 10-6 uCi/ liter (compared with the Appendix 1 limit of 2X10-5 uCi/ liter) which is about 1/14 the Appendix I limit; whereas the annual average concentration of tritium in the plant ef fluent of 1.45 x 10-2 uCi/ liter (compared with the Appendix 1 limit of 5 x 10-3 uCi/ liter) is about 3 times the Appendix 1 limit.
7.3.1.1.3 Epicor 1 Liquid Radwaste Treatment System 7.3.1.1.3.1 System Function and Design Objectives Existing plant equipment was not designed to process the quantity or radioactivity of the waste generated subsequent to the Three Mile Island Unit 2 incident. A temporary custom-built externally -
located liquid radwaste treatment system, designated Epicor-1, was installed to supplement the station's existing system. 1 The temporary system is designated to remove suspended and dis-solved radioactive contaminants from liquid waste. Treatment is achieved through filtration and demineralization.
Environmental protection is maintained by the use of features that provide leak and/or overflow protection.
The discharge of radioactive gases is minimized.
The system facilitates assembly and is flexible enough to con-form to plant requirements and layout.
7-9 Am. 21
7.3.1.1.3.2 Drscription of the System Figure 7.2 is a flow diagram for the system.
The Epicor-1 system consists of a demineralizer, prefilter and auxiliary hoses, pumps and tanks. The process vessels are de-signed f or disposal af ter they have been expended. The system takes its suction from either the Unit 1 Auxiliary Building Sump, Unit 1 Neutralizer tanks or the Unit 1 Fuel llandling Building Sump. Particulates are removed in a prefilter and dissolved contaminates are removed in the demineralizer. Water is re-turned to either of the Unit 1 Waste Evaporator Condensate Storage Tanks.
7.3.1.1.3.3 System Operation The prefilter and the demineralizer are operated by filling them with the liquid waste and removing the treated effluent via in-ternal laterals. The system is started up by actuating either CG-P-1A or B (feed pumps) to provide flow from any of the three Unit I sources to the prefilters. When the liquid level in the prefilter reaches the high level, level switch CG-P-2 (prefilter i decant pump) is manually started to begin filling the demineral-izer. Inlet and outlet flows are balanced to maintain a constant level in the prefilter. When the liquid level in the demineralizer reaches the high level, level switch CG-P-3 (demineralizer decant pump) is manually started. The demineralizer outlet flow is adjusted to maintain a constant level in the demineralizer. The ef fluent f rom CG-P-3 flows to one of the two ef fluent tanks labelled llAL 1 or 2. 1 The operation of the system is continued until:
- a. There is a leak of source water
- b. The effluent quality is poor
- c. The radiation level on the exterior of a process vessel ex-ceeds a predetermined value. (Based on shipping require-ments)
- d. The effluent tank is full, or
- c. There is a system malfunction. l l
Liquid stored in the effluent tanks may be reprocessed through l the demineralizer (to provide additional treatment) or routed ;
to the Unit 1 Waste Evaporator Condensate Storage Tanks in prep- (
aration for discharge to the environment.
Shutdown is initiated by stopping the feed pump and partially dewatering the process vessels. Reclaimed water from the Unit
! 1 Auxiliary Building is then used to flush the process hoses.
Flush water is then displaced by blowing air through the hoses.
7-9a Am. 21 M F WT
Proc 2sa vsesals are completely dewatare.d prior to baing removsd from garvica. This is done by operating either of the d: cant pumps (CG-P-2 or 3) until they loose suction.
In the event of a leak, high-high level alarm, or other system malfunction the main air supply to the pumps is terminated im-mediately causing all flow to stop.
Precautions have been taken to minimize the possibility of spilling radioactive liquid and to contain any spills if they occur. Primary emphasis has been given to creating and maintaining a leak-tight system. All fittings and hoses installed have pressure ratings that ,
exceed the maximum discharge pressure of the pumps used. All dis-charge hoses have a pressure rating of 600 psig or greater. All hoses and fittings are hydrostatically tested prior to use. Pump diaphragms are designed to rupture at pressures greater than 125 psig. The maximum available air pressure to drive the pumps is 100 psig (thus protecting diaphram integrity).
Any leaks that m'ay occur will be contained in a multi barrier contain-ment system. All hose connections are taped and wrapped with plastic to contain drips from fittings. Leaks within the Unit 1 Auxiliary Building would be contained in the floor drain and sump system. Small leaks external to the building would be contained in a plastic lined hose tray. A meries of block containment dikes around the process vessels would contain leakage in the vicinity of the process vessels.
Leaks from the process vessel would be contained in a circular steel l container in which the vessel is set prior to operation.
7.3.1.2 Waste Gas System 7.3.1.2.1 General The TMI-1 gaseous rad waste system is totally independent of the anal-ogous system in TM1-2. The sr tem has functioned satisfactorily to sup-port the unit's requirements since initial startup. The TM1-1 waste ,
gas system has had a leak tight history since modifications were made !
during the 1976 refueling outage. The system's leak rate and component I malfunctions frequency have been very low for the period subsequent to the 1976 refueling outage. in June 1979, a pressure drop test was con- i ducted on the TM1-1 Waste Gas System. No indication of leakage was noted during the test.
7.3.1.2.2 Gas Waste Systems and Equipment The TMI-1 gas waste systems are:
- 1. The liigh Level Waste Gas System: for the accumulation, storage and re-use or controlled disposal of high activity level gases evolved from primary coolant in various systems within the unit.
- 2. The Auxiliary and Fuel Handling Building Ventilation Systems:
for the continuous particulate and charcoal filtration, moni-toring and disposal of small quantities of radioactive gases released to the atmospheres of the auxiliary and fuel handling buildings.
7-9b Am. 21
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_ __ 1
l 8.0 SAFETY ANALYSIS
8.1 INTRODUCTION
Design changes af fecting the acceptance criteria for the THI-l FSAR safety analyses arise f rom several sources. First is the TMI-1 " Order and Notice of Hearing" (Ref erence 19) which contains NRC staf f recommendations that certain changes be made to the pla nt. This order encompasses recommendations made in NRC bulletins 79-05 A, B and C and the TMI-2 Lessons Learned Task Force NUREG-0578 (Ref erence 20). Most of the changes listed below are being made in response to this order. Prior to the TMI-2 accident, B&W 177 FA plants received orders requiring modifications to the high pressure injection system to accommo-date certain small break LOCA's. These changea are being evalu-ated as well. A third source of changes has originated f rom plant upgrades that Metropolitan Edison believes would improve plant perf ormance. Some of these modifications were being evaluated prior to the TMI-2 accident on March 28, 1979.
1 8.2 AREAS OF INVESTIGATION 1
The plant modifications which are being investigated are sum-marized below. They are grouped according to their origin.
8.2.1 Modifications Resulting from the August 9, 1979 Order
- 2. A complete loss of feedwater flow will initiate a reactor trip.
- 3. A turbine trip will initiate a reactor trip.
- 4. The emergency feedwater system will be modified before re-start to allow:
- a. safety grade automatic initiation of the steam and l motor driven, EFW pumps upon loss of all 4 reactor coolant pumps or a loss of both main f eedwater pumps.
- b. loading of EFW pumps on the diesel generators and dele-tion of the blackout start interlock.
- c. alternate manual control for the EFW control valve,s.
- d. negative feed to steam differential pressure.
- e. loss of both main FW-pumps.
8-1 Am. 21
- 5. A long-term modification will provide saf ety grade actuation of the EFW pumps on the low steam generator level. This is a long-term item since further engineering is required.
Plant safety therefore will be discussed with and without this feature.
8.2.2 Modification as Result of Order of May, 1978 The HPI injection lines have been cross connected to assure acceptable results from a break in a high pressure injection line. Cavitat-ing venturis have been added to provide the proper flow split in the event of an HPI line break, while still providing adequate flow for the core flood line break.
8.2.3 Modification Originating from within Met-Ed
- 1. Post accident instrument and valve operator availability will be improved by the addition of heat shrink tubing.
- 2. The switchover of the ECCS system suction supply from the borated water storage tank (BWST) will be accomplished automatically rather than by operator action.
This change will provide equal drawdown of the BWST and NaOH tanks for a large spectrum of single f ailures.
- 4. Letdown Flow will be automatically isolated af ter a reactor trip.
- 5. Cavitating venturis are being added to the emergency Feed-water system to prevent pump runout and to limit maximum flow to each OTSG.
8.2.4 I&E Bulletin 79-05C Met-Ed has committed to install an automatic reactor coolant pump trip to be initiated on a SFAS coincident with an indi-cation of saturation . conditions in the RCS. (See section 2.1.2.5) ;
d.3 EFFECT OF CHANGES ON SAFETY ANALYSIS Following are summaries of the accidents listed in Table 8-1. l Table 8-1 indicates where FSAR analyses took credit for non- f saf ety grado equipment, or where mitigation is dependent on a l specific operating / emergency procedure or design margin. These conclusions will continue to be revised to account for plant design changes.
The event description and mitigating equipment are for the plant i design before modification. The modifications discussed in the l previous sections were considered in the review of each accident. l If a modification af fected that analysis, then a note as to its l safety significance was made under the " conclusions" section.
8-2 Am. 21
Key assumptions for the small break LOCA analyses versus the TMI-1 plant design are given below:
BAW-10103 Generic TMI-l Reactor Power (MWL) 2772 2335 Reactor Trip (psig) 1900 1900 RC Pumps (LOOP) Coastdown Coastdown AFW Available** Yes-40 sec. Yes****
ESFAS HPI (psig) 1600 1600 Operator Action Yes-cross-connect none***
HP1 Distribution 70% to Core 70% to core within 10 min. from time zero***
HPI Flow (gpm) 450 at 600 psig 500 at 600 psig*****
- Amount assumed for generic analyses 550 gpm. The resonse to Supplement 1, Part 2 Question 4 demonstrates that 500 gpm is the minimum EFW required for THI-1. THI-1 is capable of delivering this minimum under the worst case single f ailure.
i Results of Ref erence 2 demonstrate that EFW is not required bef ore 20 minutes.
- Prior to startup TMI-l will install HPI injection leg cross
! connects and flow control devices to eliminate operator action to cross connect HPI and equalize flow in all four injection legs.
- For worst case LOCA in which of fsite power is lost, EFW is initiated by the loss of feedwater or by the loss of 4 reactor coolant pump signals.
- Also refer to the response to supplement 1, Part 3 Questions 1, 2 and 3.
In all cases, TMI-l plant specific information is as conservative or more conservative than the generic assumption.
Since the TMI-2 accident, greater focus has been placed on small break LOCA's and the capability of the ECCS to mitigate them.
Problems such as those discussed in Ref erence 21 (where the pressurizer stays full due to the loop seal arrangement despite loss of RCS inventory) have been addressed. These studies are documented in B&W's " Evaluation of Transient Behavior and Small Reactor Coolant System Breaks in the 177 Fuel Assembly Plant" May
- 7, 1979 (Reference 2). Breaks of 0.01, 0.02, and 0.07 ft.2 are analyzed utilizing varying assumptions on the availability and timing of AFW and HPI. These analyses use the same initial assumptions as used in BAW-10103 except that ESFAS is assumed to occur at 1350 psig. Therefore, they are also bounding assumptions for TMI-1 except for the distribution of HPI flow as discussed be lcw. The analysis in Ref erence 2 also established that EFW flow is not required less than 20 minutes before any steam line break accident. .
8-15 Am. 21
302 SERIES Mechanical Rev. # Description
- 302011 22 Main Steam 302012 01 MN Stm to Relief VLV Post Suppts 302031 00 Composite Start-Up ~
302032 02 Main Stm & Feed Wtr Instr 302041 10 H.P. Extraction Stm j 302042 05 L.P. Turbine Extraction Steam i 302051 22 Auxiliary Steam 302081 17 Feedwater 302101 17 Condensate 302111 11 Fdwtr Htr Drns 302112 11 Fdwtr Htr Vents. Rel & Misc Drns 302121 11 Feed Pump Turb Drains 302131 16 . Coser Air Removal j 302141 12 Turb Gland Steam & Drains 302161 14 Cycle Makeup Pretreatment Schem 302162 17 Cycle Makeup Demineralizers 302163 14 Cycle Makeup Demineralizers Sh 2 302171 07 Coste Chemical Feed
. 302172 17 Powdex Condensate Filter Units 302173 08 Cire Wtr Chlorination & Chem Feed 302174 05 C1g Wtr Chlorination Units 162
! 302175 01 Sampling & Chemical Feed-Aux Bir 302181 04 Turb Plt Smping 302182 06 Turb Plt Smping
- 302191 06 Chemical Cleaning (Turb Pint)
! 302201 16 Circulating Water i 302202 15 River Water Sys 302203 15 Screen Wash & Sluice System
- 302204 04 Condenser Cleaning 302221 16 Secdy Serv C1g-closed Cycle 302231 24 Flow Dia Fire Serv Wtr i 302271 17 Instr & Stn Serv Air !
302281 12 Fo & Fd PP Shaf t Seals & Leakoff 302283 01 Fuel Oil Unloading Sta to Stor Tks 302291 06 Turb Lube Oil 302301 05 Cen Gas & Vents j 302351 07 Emer Diesel Generator Serv 302352 12 Air Tunnel & Turb Rm Sump Pumps 302610 24 Nuc Serv Close Cycle Cing Wtr 302620 19 Intermediate Cooling 302630 11 Spent Fuel Clg Sys-Schematic 302640 23 Decay Heat Removal 302645 13 Decay Ht CC C1g Wtr 302650 18 Reac Coolant Sys 302660 17 Makeup & Purification 302661 19 Make-up & Purification 302669 18 Chemical Addition i Am. 21
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302 SERIES - (cont'd)
Mec hanical Rev. # Description 302670 11 Chemical Addition 302671 19 Sampling Liquid & Gas 302690 17 Liquid Wste Disposal 302691 16 Liquid Waste Disposal 302692 19 Liquid Waste Disposal 302693 20 Liquid Wst Disposal 302694 19 Flow Dia Waste Gas System 302695 02 Liquid Waste Evaporators 302705 08 Penetration Fluid Block 302706 09 Penetration Press Quadrants I - II 302707 10 Penetration Press Quadrants 3 & 4 302708 12 Pen Clg Flow Dia Reac Bldg 302711 12 Core Flooding 302719 24 Sump PP & Drainage Sys (Reac & Aux 302720 09 Nuc Plnt N2 & H2 Supply 302721 03 Hyd Purge Disch & Cntmt bbnitoring 302725 05 Cv Leak Rate Test 302728 00 Fuel Transf Canal Leak Detect 302831 25 Reactor, Aux & Fuel Hdig Bldgs 302842 25 Cont Bldg & Machine Shop 302843 13 Serv Bldg Flow Diag 302844 17 Turb Bldg & Out-Bldgs Air Flow Diag 302845 14 Industrial Cooler System 302846 08 Service Building 302847 06 Cont Bldg 302848 02 Charcoal Spray Sys Reac Bldg 1
l 11 Am. 21
201 SERIES Drawing # Rev # Sht# Drawing # Rev # Sht#
201171 3 l 201040 14 3
042 14 172 045 6 173 7 176 9 046 6 177 5 l 049 9 178 6 051 17 2 179 5 1 052 1C 182 3 052 22 1 183 4 053 17 2 184 3 053 22 1 185 1 055 7 188 9 059 11 3 2 189 13 059 16 190 4 059 17 1 191 5 060 12 192 8 061 17 193 3 062 15 1 194 0 062 17 2 195 0 063 15 196 0 064 10 2 197 0 064 14 1 198 3 065 11 2 200 0 065 13 1 201 4 066 12 1 12 2 205 5 066 206 4 067 11 068 12 207 5 2 208 5 069 17 18 1 209 7 069 13 210 2 070 14 211 9 071 4 13 212 072 213 3 073 14 2
250 1 074 8 251 3 145 252 5 l 146 5 9 253 5 149 255 6 10 150 '
151 3 256 9 257 6 152 0 258 6 153 1 259 4 156 2 260 4 157 1 261 4 158 1 271 10 159 0 272 9 160 1 I 161 1 s
162 1 163 1 164 1 165 1 166 1 167 1 169 3 Am. 21 iii
- u-
206 SERIES Electrical Rev. # De scription 206011 20 Mn One Line & Relay Diagram 206021 07 1 Line & Rel Diag 6900 & 4160V Swgr 206022 10 1 Line & Rel Diag 4160V E.S. Swgr 206031 11 1 Line & Rel Ding-Turb. Reac. Aux & FBH&V 206032 06 1 Line & Re1 Ding E.S. Scrn Hse Reac 206051 11 One Line Diag-120V A C Instr l
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- GENERAL ARRANGEMENT SERIES Layout Rev. # Description 001013 60 Bsmt Fir-Reac & Aux Bldg 271 & 281
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001022 43 Aux & Reac Bldg 331' Int Bld 261' l 001023 45 Mezz Fir-Turb Bldg 322'
{ 001032 39 Oper F1r 346' Reac Bldg 348' 001034 14 Oper Fir-Int Bld 355'-Sect R-R 001042 19 Fir 365' - 6" Reac Bldg 001043 21 Htr Fir-Turb Bldg El 380-0 ,
002004 33 Sects A-A & B-B Reac Bldg 002005 39 Sects H-H&J-J-Aux Bldg Sect C-C Auc & Fuel Hdig Bldg 002006 30 i 002007 33 Sect D-DSE-E-Aux & Fuel H1dg Bldg 002008 20 Sect F-F & G-G Fuel Hdig Bldg
] 002010 21 Sect L-L Turb Bldg 002011 17 Sect H-N Turb Bldg 002013 21 Sect P-P Turb Bldg 002014 18 Sect Q-Q Turb Bldg 002015 09 Sect M-M Turb Bldg 002016 18 Interm Bldg Sects S-S & T-T
- 015021 07 Intake, Screen Hsc & Pump Hse l 015022 06 River Water Intake Chlor Hse j 015023 10 circ Water Chlor House 015024 14 Cyc Mu Water-Pretreatment Hse j
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11.0 TECHNICAL SPECIFICATIONS
11.1 INTRODUCTION
A considerable number of plant modifications are being accomplished in response to TMI-2 Lessons Learned (NUREG-0578), the TMI-1 Order and Notice of Hearing - Augast 9,1979, IE Bulletins, and Met-Ed's review of the TMI-2 accident. The hardware modifications are described in Section 2.0 of this report. In some instances, Technical Specification changes are appropriate to account for systems and changes to systems that play a significant role in mitigating the consequences of accidents or transients. These new draf t Technical Specifications are discussed in Section 11.2.
Formal requests to modify the TMI-l Technical Specifications will be forwarded to the NRC at an appropriate time following PORC and GRC review of the Technical Specifications which must be completed before final submittal.
J In addition, by'1etter dated July 2,1980, the NRC issued guidance, in the form of model Technical Specification, for implementation of i NUREG-0578. The draft Technical Specifications contained herein
) conform to the appropriate aspects of the NRC's July 2,1980 quid-ance except for Administrative Technical Specification (Section 6.0) which will be submitted at a later date.
11.2 DRAFT TECHNICAL SPECIFICATIONS This section contains evaluations of those proposed modifications for which changes to the Technical Specifications will be requested.
Draf t Technical Specifications pages in the TMI-l format are con-tained in Appendix 11A.
11.2.1 Reactor Trip on Loss of Feedwatcr or Turbine Trip )
I Introduction Item B.5 of IE Bulletin 79-05B requires licenses to " Provide for NRC approval a design review and schedule for implementation of a safety grade automatic anticipatory reactor scram for loss of feed-water, turbine trip, or a significant reduction in steam generator level." Item B.7 requires the submittal of Technical Specifications for design changes inciding those changes asociated with Item B.S.
Evaluation The reactor trips on loss of feedwater or turbine trip are designed as anticipatory reactor trips which respond to equipment situations which would produce significant primary system pressure transients.
By tripping the reactor on the anticipation of a presssure transient, (1) the probability of an overpressure trip is reduced and (2) the 11-1 Am. 21 1
y , ,, _..,.- .. , , . , . . . - _ _
Challenga rate to tha przeaurizar coda ecfety valvas is reduced. The design of the reactor trips on loss of feedwater or turbine trip incorporates a 2-out-of-4 logic, is fully testable, and meets the single failure criterion of IEEE-279. A description and evaluation of these reactor trips is contained in Section 2.1.1.1 of " Report in Response to NRC Staff Recommended Requirements for Restart of Three Mile Island Nuclear Station Unit 1."
Since the reactor trip on loss of feedwater and the reactor trip on turbine trip are of the same safety grade as other Reactor Protection System trip functions, the Limiting Conditions for Operation in draf t Technical Specifications 3.5.1.1 (Item 1 "Other Reactor Trips," Table 3.5-1) and the Surveillance Requirements in draf t Technical Specifica-tion 4.1.1 (Items 45 and 46 of Table 4.1-1) have been chosen to be consistant with other Reactor Protection System functions, a " check" being required each shif t, a " test" each month, and a " calibration" l
I during each refueling outage. Bypass of the loss of feedwater trip below 10% power, and turbine trip below 20% power is permitted to al- '
low normal reactor startup ceprations.
Conclusions In conclusion, we have determined that, with regard to the reactor f
' trip on loss-of-feedwater and the reactor trip on turbine trip: l i
t (1) The probability or consequences of accidents previously !
evaluated have not been increased. The proposed trips are l
anticipatory and have not been taken credit for in the accident analyses. The reactor trip on overpressure and the pressurizer Code Safety Valves remain the principal means of mitigating pressure transients.
(2) No accidents, other than those previously considered, will be introduced. The additional reactor trips have been de-signed so as not to introduce additional failure modes into the Reactor Protection System or other safety equipment.
Moreover, by anticipating significant pressure transients, the challenge rate to the overpressure trip and pressure relieving capacity has been reduced.
l (3) No safety margins have been reduced. Since the additional ,
reactor trips scram the reactor on anticipation of signifi- !
l l cant pressure transients, the peak pressure associated with l these transients can be expected to decrease which would result in an increase in safety margins as a result of postulated turbine trip or loss-of-feedwater transients.
For these reasons, we conclude that implementation of the design for additional reactor trips, and adoption of associated Technical Specifications, does not involve unreviewed safety questions with I regard to the criteria of 10CFR Part 50, Section 50.59(a)(2).
I i
11-2 Am. 21 t
11.2.2 Operebility of PORV and Block Velve, Position Indication of PORV and Safety Valvas, and Satpoints i
Introduction i Section 2.1.3 of NUREG-0578, "TMI-2 Lessons Learned Task Force Status Report and Short-Term Recommendations," July 1979, contains NRC recommendations on installations of valve position indications i for safety and relief valves. The guidance on safety / relief valve position is to, " Provide in the control room either a reliable, j direct position indication for the valves or a reliable flow in-dication device downstream of the valves."
Evaluation-In response to the above recommendations, a system of indirect safety and relief valve position indications has been designed.
The safety / relief valve position indication system, described in.
Section 2.1.1.2 of " Report in Response to NRC Staf f Recommended Requirements for Restart of Three Mile Island Nuclear Station Unit 1", consists of the following:
(1) delta-pressure taps, and monitors, at discharge piping elbows
! downstream of the safety and relief valves, and (2) acoustic monitor (accelerometer) mounted on the pressur-izer power operated relief valve.
The above sensors are in addition to the tailpipe thermocouples which are presently installed.
Technical Specifications, Limiting Conditions for Operation and Surveillance Requirements, will be proposed for the safety / relief valve position instrumentation. The Limiting Conditions for Operation, contained in draf t Technical Specification 3.5.5, requires the three delta-pressure monitors and an accoustic I monitor to be operable. The remedial action to be taken if one
- or more delta pressure monitors or the acoustic monitor becomes inoperabic is to require operability of an alternate indication of safety or relief valve postions (tail pipe thermo couples) and fix the monitors prior to startup following the next cold shutdown.
This requirement is based upon the following considerations:
1 (1) The sensors for the delta-pressure and accoustic monitors are located inside containment and would most likely require containment entry for repair or replacement.
(2) Extended periods of operation without the delta pressure or acoustic monitors will not precluda lhe reactor operator detecting a leaking or stuck-open safety or relief valve.
Several indications of safety or relief valve discharge flow are available including safety and relief valve tailpipe (discharge) temperature.
11-3 Am. 21
In addition to delt: preceure and accoustic conitor Technical Specifications, Limiting Conditions for Operations are proposed to require operability of the PORV and the associated Block Valve.
Draft Technical Specification 3.1.12.4 requires the Block Valve to be closed within one (1) hour of determining that the PORV is in-i operable or be in at least hot shutdown within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. If the Block Valve becomes inoperable the PORV is to be closed with one (1) hour and power removed from the PORV. The above . actions are appro-priate since the PORV has been shown to be a potential path for reactor coolant system depresurization; however, concurrent failure of both the PORV and the Block Valve is unlikely, and thus there is a high degree of certainty that the PORV discharge line can be isolated.
One aspect of IE Bulletin 79-05E, item B.3, involved a decrease in the RPS high pressure trip setpoint to reduce the challenge rate to the pressurizer Electromatic relief valve. The recommendations of B&W, in an April 20, 1979 communication, indicated that the RPS high pressure trip setpoint should be reduced to 2300 psig. The decrease 1 in the RPS high pressure trip, from 2390 to 2300 psig is incorporated in TMI-1 draft Technical Specification 2.3.1 (see Section 11.2.12).
The Surveillance Requirements associated with the delta pressure and acoustic safety and relief valve monitors are contained in draf t Technical Specification 4.1.1 (Items 47a and b in Table 4.1-1); these monitors are to be checked each shif t and tested /
calibrated each refueling period. The " check" and " test" surveil-lance need not be performed when TAVG is below 200*F since the reactor would be shutdown and this safety functioa unnecessary.
Surveillance that is not performed due to a reactor shutdown greater than one month should be performed prior to s;artup. This requirement has been presented in draf t Technical Specification 4.1.1 and made applicable to all surveillance requirements in Table 4.1-1. Accessibility considerations, as noted previously are significant with regard to the delta pressure and accoustic monitors and are the determining factor in the test / calibration interval.
A Surveillance Requirement (setpoint test) for the pressurizer Electromatic relief valve is incorporated in draf t Technical I
Specificatioc 4.1.2 (Item 48 of Table 4.1-1); a refueling period interval has been selected to be consistent with the pressurizer safety valve surveillance interval. Functional testing of the PORV Block Vive is specified as quarterly in draft Technical Specifi-cation Table 4.1-2.
Conclusion In conclusion, with regard to the additional requirements for the delta pressure and acoustic monitors, PORV and Block Valve, oper-ability, and the setpoint requirer.ents for the pressurizer Electro-matic relief valve:
11-4 Am. 21
[
(1) The probability or consequences of accidents, previously evaluated have not been increased. The requirement for PORV and Block Valve Operability and opecability and surveillance of the safety and relief valve monitora increases the proba-bility that misoperation of the relief or safety valves will be detected, remedial action taken, and thus reduces the consequences associated with certain small-break loss-of-coolant accidents. ,
I (2) No accidents, other than those previously considered, will be introduced. The delta pressure and acoustic instrumentation have no automatic functions and therefore cannot change the course of any accident or transient; sufficient confirmatory information is available in the control room to detect improper functioning of these monitors. With regard to the pressurizer Electromatic relief valve, the requirement for periodic testing of the setpoint will enhance the availability of this equipment.
(3) No safety margins have been reduced. Although the setpoint of the pressurizer Electromatic relief valve has been increased, no credit was taken for this equipment in the safety analysis.
The decrease in the RPS high pressure trip setpoint will 1 cause the reactor to trip earlier in the course of significant I
pressure transients and thus reduce the peak pressure during
- the transient.
For the reasons presented above, implementation of the design changes associated with the delta-pressure and acoustic monitors and associ-ated Technical Specifications, including those addressing the setpoint of the pressurizer Electromatic relief valve, do not involve any un-
- reviewed safety considerations with regard to the criteria of 10CFR i
Part 50, Section 50.59(a)(2).
11.2.3 Emergency Power Supply Requirements - Pressurizer Heaters Introduction Section B.I.b of IE Bulletin 79-05B requires licensees or operating reactors ta develop procedures and train personnel to
"... assure availability of adequate capacity of pressurizer heaters, for pressure control and maintain primary system pressure to satisfy the subcooling cirterion for natural circulation."
Section 2.1.1 of NUREG-0578, "TMI-2 Lessons Learned Task Force Status Report and Short-Term Recommendations," goes further in l that it recommends that reactors, " Provide redundant emergency j power for the minimum number of pressurizer heaters required to c irtain natural circulation conditions in the event of loss of offsite power. Also provide emergency power to the control and motive power systems for the power-operated relief valves and associated block valves and to the pressurizer 1cvel indication instrument c,hannels."
11-5 Am. 21 V
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Evaluation Section 2.1.3 of " Report in Response to NRC Staff Recommended Requirements for Restart of Three 1111e Island Nuclear Station Unit 1" describes design changea, and operator actions, that are required to supply 126 KW of pressurizer heaters from each of two independent engineered safeguard power sources in the event offsite power is lost. The manual transfer of power from the normal (balance of plant) to the back-up (engineered safeguards) power source involves the use of a " Kirk Key" system that assures proper transfer of power from the normal to the back-up power source. With regard to operability of pressurizer heaters and emergency power supplies; Draf t Technical Specification 3 1.3.4 requires two pressurizer heater groups of 107 kw (each) to be operable together with the respective emergency power sources.
In addition, draft Technical Specification 4.6.3 requires that the manual transfer of power to pressurizer heater groups 8 and 9, f rom normal to backup supply, be demonstrated during each refueling outage.
In the event that an engineered safeguards actuation signal is received while the pressurizer heaters are powered f rom the diesel generators, the pressurizer heater loads are automatically shed f rom the diesel generators to prevent overloading of the diesels.
Upon existence of an engineered safety features actuation signal (indicating a LOCA), primary system pressurization is no longer a consideration. To assure proper load shedding (breaker operation) of the pressurizer heaters, from the diesel generators epon an engineered safety feature actuation signal, a test of the engi-neered safety features pressurizer heater supply breaker will be andertaken on a periodic basis. Technical Specification 4.6.1.b requires a test of the diesel generators, during each refueling shutdown, to determine proper automatic response under loss of normal AC power conditions concurrent with an engineered safety features actuation signal. Draft Technical Specification 4.6.1.b would also include a requirement to confirm proper operation of the engineered safety features pressurizer heater supply breakers upon receipt of an engineered safety features actuation signal.
With regard to the remaining requirements of NUREG-0578, Section 2.1.1, to supply emergency power capability for the PORV, the block valve, and pressurizer level instrumentation, Sections 4.1.1.3.2, 2.1.1.3.3, and 2.1.1.3.4 of the Restart Report indicata that these requirements are satisfied by existing equipment, Conclusion In conclusion, with regard to the provisions for transfer of pressurizer heater loads from normal tc back-up power supplies:
11-6 Am. 21
(1) The probability or consequences of accidents, previously ,
evaluated, have not increased. Periodic tecting of the t engineered safety features pressurizer heater supply breaker will assure that, in the event that the pressurizer heaters
- are powered by the diesels generators when an engineered safety features actuation signal is received, the. pressurizer heaters will be shed from the diesel generators supply busses.
(2) No accidents, other than those previously considered, will be introduced. The manual transfer of the pressurizer heater supply loads, in the correct manner, is assured by the Kirk Key system. !
Periodic testing of the engineered safety features pressurizer heater supply breaker will prevent diesel overloading in the event that the pressurizer heaters are powered by the diesels-generators when an engineered safety features actuation signal is received.
(3) No safety margins have been reduced. The availability of the I pressurizer heaters on loss of offsite power provides additional ]
assurance that primary system subcooling margin can be maintained such that natural circulation will be enhanced. l
! Based upon the above, we conclude that plant modifications necessary to allow manual transfer of selected pressurizer heater loads, from normal backup power sources, and adoption of associated Technical ,
Specifications, do not involve an unreviewed safety question with regard to the criteria of 10CFR Part 50, Section 50.59(a)(2). l 4
11.2.4 Post-LOCA Ilydrogen Recombiner System
]
i Introduction i
i Section 2.1.5 of "TMI-2 Lessons Learned Task Force Status Report and Short-Term Recommendations," NUREG-0578, July 1979, contains a Task Force minority opinion that, "...all operating reactors, I which do not already have the capability, be required to provide the capability to add, within a few days af ter an accident, a hydro-gen recombiner system for post-accident hydrogen control." Section 2.1.4 of " Report in Response to NRC Staff Recommended Requirements for Restart of Three Mile Island Nuclear Station Unit 1" contains a description and evaluation of design modifications that are re-quired to:
(1) Install at TM1-1 a hydrogen recombiner that was purchased for TMI-2, and (2) Provide structural, piping, and electrical facilities such that a second hydrogen recombiner can be installed after an accident, within the time period available before it is required to be operational.
11-7 Am. 21
Evalustion Present NRC Policy, as reflected in " Standard Technical Specifica-tions for Babcock and Wilcox Pressurized Water Reactors", NUREG-0103, requires Technical Specifications for installed hydrogen recombiners.
The proposed Technical Specifications for the hydrogen recombiners have been adopted from the Technical Specifications for TMI-2, specifically, TMI-2 Technical Specification 3/4 6.4.2. The hydro-gen recombiner Technical Specifications for TMI-2, based upon NRC's Babcock and Wilcox Standard Technical Specifications, contain:
(1) Limiting Conditions for Operation requiring one operable hy-drogen recombiner during startup and power operation, (2) Surveillance Requirements for the following inservice inspection program:
(a) A recombiner functional test once per 92 days, and (b) The following surveillance every 18 months: Channel calibration of recombiner instrumentation, visual examin-ation, heater functional test, and heater electrical circuit integrity.
In addition, the hydrogen recombiner is required to undergo surveillance prior to startup following on extended outage.
The Limiting Condition for Operation for the hydrogen recombiner is incorporated in draf t TMI Technical Specification 3.6, " Reactor Building"; the Surveillance Requirements for the hydrogen recom-biner are contained in TMI-1 draf t Technical Specification 4.4.4, i "llydrogen Recombiner System."
Conclusion J
In conclusion, with regard to the installed hydrogen recombiner and associated Technical Specifications:
(1) The probability or consequences of accidents previously evaluated have not increased. The use of hydrogen recombiners at TM1-1 would result in lower off-site doses, in the event of a LOCA, l when ecmpared with other post-accident hydrogen control tech-niques requiring containment venting.*
- The recombiner cooling air is vented directly to the environment.
An evaluation involving failure of this cooling air system indicates I that the resulting off-site doses are not significant (see Question l 91, Supplement 1, Part 2, Restart Report) i 11-8 Am. 21
l (2) No accidents, other than those previously considered, will be introduced. The design and installation features of the hydro-gen recombiner are designed so as to preclude the compromising of containment integrity or other safety features.
l (3) No safety margins have been reduced. The hydrogen recombiner is a post-accident system that is not operated under normal con-ditions and thus is not involved in consideration of any safety margin.
l Based upon the above, we conclude that plant modifications needed for l installation of the hydrogen recombiner(s), and associated Technical Specifications, do not involve any unreviewed safety questions with regard to the criteria of 10CFR Part 50, Section 50.59(a)(2).
11.2.5 Containment Isolation Modifications Introduction Section 6 of IE Bulletin 70-05A required licensees of operating B&W i facilities to, " Review the containment isolation design and proce-l dures, and prepare and implement all changes necessary to cause containment isolation of all lines whose isolation doas not degrade core cooling capability upon automatic initiation of safety in-jection." Section 2. . 4 cf "TM1-2 Lessons Learned Task Force Status Report and Short-Term Recommendations," NUREG-0578, July 1979, ex-panded the requirements of I&E Bulletin 79-05A, Section 6, as follows:
" Provide containment isolation on diverse signals in conformance with Section 6.2.4 of the Standard Review Plan, review isolation provisions for non-essential systems and revise as necessary, and modify containment isolation designs as necessary to eliminate the potential for inadvertent reopening upon reset of the isolation signal."
l Evaluation Section 2.1.1.5 of " Report in Response to NRC Staf f Recommended Requirements for Restart of Three Mile Island Nuclear Station Unit 1" provides the details and evaluation of a redesigned contain-ment isolation system with the following new features:
(1) Containment isolation on reactor trip, (2) Containment isolation on 30 psig building pressure (3) Specific line isolation on high radiation l
11-9 Am. 21 i
With regard to the revised containment isolation design, this design meets the NRC's requirements in that:
(1) The system initiates automatically on safety injection (IE Bulletin 79-05A) - The reactor trip signal is utilized to obtain a diverse isolation signal. Since the RPS trips the reactor on low pressure (1800 psig)* prior to the safety injection signal (1600 psig), an RPS trip signal on low pressure will always preceed a safety injection signal. The reactor trip signal, therefore, isolates the containment more quickly than a safety injection signal.
(2) The system is diverse (NUREG-0578) - The redesigned containment isolation system provides containment isolation on the follow-ing signals:
(a) Reactor trip (b) High radiation (individual line isolation)
(c) Pipe break (individual line islolation)
(d) The 1600 psig safety features actuation signal (e) The 30 psig containment signal (f) The 4 psig containment signal (to be eventually removed)
(3) Following isolation, lines should not be vulnerable to inad-verten reopening (NUREG-0578). Overriding the containment isolation signal does not open the containment isolation valves, deliberate operator action is required to reopen selected in-dividual valves.
Draft Technical Specifications, described herein, provide Limiting 1 Conditions for Operation and Surveillance Requirements for the additional containment isolation functions. Limiting Conditions for Operation for containment isolation on the RPS Trip and the 30 psig containment pressure have been incorporated into TMI-1 draf t Technical Specification 3.5.1.1 (Items 3.c and 3.d of Table 3.5-1).
The operability of the Reactor duilding Purge Isolation (on high radiation) is required by Item 1, Reactor Building Isolation, in i draf t Technical Specification Table 3.5-1. The minimum channel operability for containment isolation on RPS trip, and on Reactor 4 I
Building 30 psig, have been chosen to be the same as tha existing containment isolation functions; this would require a minimum of two channels to be operable or place the reactor in hot shutdown.
- Section 11.2.12 herein proposes an increase in the low pressure trip setpoint l from 1800 psig to 1900 psig.
11-10 Am. 21
)
With regard to Surveillanca Requiremants, surveillance for contain-ment isolation on RPS trip, and on Reactor Building 30 psig, have been incorporated into TM1-1 draf t Technical Specification 4.1.1 (Items 19.c and 19.d of Table 4.1-1) and chosen to be the same as the existing containment isolation system surveillance requirements for the Reactor Building 4 psig signal; this requires a channel check each shift, testing each month, and calibration each refueling period.* A surveillance requirement for the manual containment isolation function has also been included (Item 19.b of Table 4.1-1) requiring a check each shift and a monthly test. Surveillance Requiements for containment and individual line isolation on high radiation are presently provided for in Technical Specification 4.1.1 (Item 28, " Radiation Monitoring Systems," Table 4.1-1). The
" check" and " test" surveillances are required to be performed only when containment integrity is required. This provision deletes surveillance requirements during extended outages when containment isolation may not be needed.
Conclusion In conclusion, with regard to the revised containment isolation design and associated Technical Specifications:
(1) The probability or consequences of accidents previously evaluated have not inc reased . The increased diversity of the containment isolation signals increases the proba-bility and timeliness of containment isolation.
(2) No accidents, other than those previously considered, will be introduced. The revised containment isolation design does not in any way hamper the function of systems designed to mitigate the consequences of postulated accidents. Supurious initiation of any of the additional containment isolation signals would not isolate any components that would not also be isolated by a spurious initiation of the existing 4 psig building pressure signal, ,
I (3) No safety margins have been reduced. The plant safety features required to mitigate the consequences of postulated transients and accidents are not impacted by the revised conta inment isolation design.
Based upon the above, we conclude that the modifications associated with the revised containment isolation design, and associated Tcchnical Specifications, do not involve any unreviewed safety questions with regard to the criteria of 10CFR Part 50, Section 50.59(a)(2).
l l
- The RPS containment isolation function is not calibrated since no analog function is involved.
11-11 Am. 21
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l
- 11.2.6 Instrumentation to Detect Inadtquste Core Cooling i
I Introduction i Section 2.1.3b of Appendix A to "TMI-2 Lessons Learned Task Force Status Report and Short-Term Recommendations," NUREG-0578, July 1979, requires that:
i
"...each PWR shall install a primary coolant saturation meter to provide on-line indication of coolant saturation condi-tion (SIC). Operator instruction as to use of this meter shall include consideration that is (SIC) not to be used exclusive of other related plant parameters."
Section 2.1.1.6 of " Report in Response to NRC Staff Recommended r
Requirements for Restart of Three Mile Island Nuclear Station Unit l 1" contains a description or a saturation margin meter which is
! proposed for installation at TM1-1.
Evaluation The saturation margin meter will display, in the contfoi room, the l margin between the actua} primary plant temperature ( H) and the l satugation temperature ( sat) for the existing plant pressure.
l The sat will be computed using primagy system pressure measure-
! ments and compared to the wide range H instrument reading. The temperature margin will be displayed in the control room. An alarm will be initiated if the margin fal s below a pre-set value.
Redundancy will be provided by computing } sat margin independently for each reactor coolant loop. The lower temperature for each loop will automatically be selected for the computations. Satura-tion pressure margin is also computed in a similar manner so that the operator has the option of displaying the saturation margins in terms of temperature or pressure. The equipment used for these computations will be safety grade and seismically qualified. In addition,thepgantcompgter,usingthesameinputs,willindepen- l l
dently compute sat and sat margin for logging, trending, and
! alarm.
l Draft Technical Specifications Limiting Conditions for Operation and Surveillance Requirements are presented, herein for the saturation margin meter. Draf t TMI-l Technical Specification Table 3.5-2, " Accident Monitoring Instrumentation" requires the saturation margin meter to be operable during start-up and power operation. If the saturation margin meter is not operable, the reactor operator is to have a procedure available for calculatica of saturation temperature. This remedial action is appropriate !
since (1) no automatic actuations of safety features are associated with the saturation meter and (2) saturation temperature is easily calculated using reactor coolant system measurements and " steam tables." Surveillance Requirements for the saturation t
! 11-12 Am. 21 l
margin meter to be checked each shif t, tested monthly, and calibrated each refueling period are stated in Item 49, draft Technical Specifi-cation Table 4.1-1. The " check" surveillance is only required whea TAVG is above 200* such that this requirement is deleted during ex-tended outages when the saturation margin meter is not needed. The proposed surveillance schedule is consistent with surveillance schedules for safety grade instrumentation at TM1-1 and is suf ficient to assure reliable performance from the saturation meter.
Conclusion In ;onclusion, with regard to the saturation margin meter and associated Technical Specifications:
(1) The probability or consequences of accidents previously evaluated have not increased. The saturation margin meter is not required for the prevention or mitigation of accidents, l or transients, previously considered.
(2) No accidents, other than those previously considered, will l be introduced. No automatic actuations of safety features are associated with the saturation margin meter nor is the saturation margin meter capable of effecting any safety features.
(3) No safety margins have been reduced. The saturation margin meter is not associated with any safety margins; both low pressure and high temperature RPS trips protect the reactor's thermal margins. Based upon the above, we conclude that the installation and use of the saturation margin meter, and the associated Technical Specifications, do not involve any unreviewed safety questions with regard to the criteria of 10CFR Part 50, Section 50.59(a)(2).
11.2.7 Emergency Feedwater System Modifications Introduction By letter dated June 28, 1979, Met-Ed presented NRC with recommen-dations for modifications to TM1-1 which would be completed prior to restart of TMI-1. The June 28, 1979 letter recommended the following changes to the emergency feedwater system and associated procedures:
- 1. Automatic initiation of the motor driven AFW pumps upon loss of both feedwater pumps or loss of four (4) Reactor Coolant Pumps.
- 2. Modification of the AFW control valves such that they fail open on loss of control air.
- 3. Automatic block loading of the motor driven AFW pumps on the emergency diesel generators.
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i l
- 5. Provide indication in the control room of AFW flow to each Steam Generator.
- 7. To assure that AFW will be aligned in a timely manner to inject on all AFW demand events when in the surveillance test mode, procedures will be implemented and training conducted to pro-vide an operator at the necessary location in communications l with the control room during the surveillance mode to carry out l
alignment changes necessary upon AFW demand events.
- 3. Design review and modifications, as necessary, will be conducted l to provide control room annunciation for all auto start condi-l tions of the AFW system.
On August 9,1979 the NRC issued an " Order and Notice of Hearing" which addressed modifications to the TMI-1 f acility. With regard to those changes proposed for the emergency feedwater system in the June 28, 1979 letter, the August 9,1979 Order directed that these changes should be made. A description and evaluation of changes to the emergency feedwater system, involving equipment modifications (items 1,2,3,5 and 8, as described above) are con-tained in Section 2.1.1.7 of " Report in Response to NRC Staff Recommended Requirements for Restart of Three tule Island Nuclear Station Unit 1." Draf t Technical Specifications for the modified emergency feedwater system are discussed herein.
Draf t THI-1 Technical Specification 3.4 provides Limiting Conditions l for Operation for the emergency feedwater system. Guidance on oper-ability of the emergency feedwater System is contained in IE Bulletin 79-05A, Item 8, as follows:
" Prepare and implement immediately procedures which assure that two independent steam generator auxiliary feedwater flow paths, each with 100% flow capacity, are operable at any time when heat removal from the primary system is through the steam generators. When two independent 100% capacity flow paths are not available, the capacity shall be restored within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> l
or the plant shall be placed in a cooling mode which does not I rely on steam generators for cooling within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
When at least one 100% capacity flow path is not available, the reactor shall be made suberitical within one hour and the facil-ity placed in a shutdown cooling mode which does not rely on steam generators for cooling within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> or at the maximum safe shutdown rate."
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! The guidance contained in IE Bulletin 79-05A has been incorporated I in Draf t TMI-1 Technical Specification 3.4.1 with the exception that the restoration time for the emergency feedwater systec has
! been reduced from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> as a result of subsequent j requirements from the NRC. Existing Technical Specifications 3.4.3 and 3.4.6 have been rewritten to incorporate remedial action l
in the event that the condensate storage tanks and/or the main steam safety valves are inoperable. For both the condensate l
storage tank and the main steam safety valves, remedial action has i been proposed that is consistent with NRC guidance as reflected in the B&W Standard Technical Specifications. Operability requirements for the automatic EFW initiation channels are contained in draft Technical Specification Table 3.5-1, Item 1, " Emergency Feedwater System." Operability of the EFW flow instrumentation is required by draf t Technical Specification 3.5.5 (Table 3.5-2) .
With regard to surveillence requirements, draf t Technical Specifica-l tions are presented as follows:
(1) Existing Technical Specification 4.9.1.1 which requires testing of the emergency feedwater pumps every three months, as modified, would require pump testing every 31 days and also require verification of specific pump flow values during the testing. The flow testing would be based the requirements of the ASME Boiler and Pressure Vessel Code,Section XI, Article IWP-3220, and would confirm that the emergency feedwater system can deliver at least 500 gpm to either steam generator flow path.
(2) Draf t Technical Specification 4.9.1.2 would require that, ,
during testing of the EFW, a qualified, dedicated individual l in communication with the control room, be maintained at the j EFW manual valves. In the event that the EFW is required to l function, the individual would promptly realign the manual l valves from test to operational positions. I (3) Draf t Technical Specification 4.9.1.3 would require valve l
verification (correct position and locked, if appropriate)
! for valves in the emergency feedwater system, every 31 days.
In addition, locked valves could only be maintained in an un-locked condition under administrative control.
l (4) Draf t Technical Specification 4.9.1.4 would require a test, I l each 31 d "s, of automatic pump start logic and automatic valve l lineup following an emergency feedwater actuation signal. In l addition, the operability of the manual control valve station would be verified.
(5) Draf t Technical Specification 4.9.1.5 would require testing of the EFW injection valves on s quarterly basis.
l I
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(6) Item 10F of NRC's October 26, 1979 letter to Mr. R. C. Arnold requires a, "... Technical Specifications to assure that prior to plant startup following an extended cold shutdown, a flow test w'uld be performed to verify the normal flow path from the primary EFW system water source to the steam generators.
The flow test should be conducted with EFW system valves in
( their normal alignment." This test is incorporated in draf t l
Technical Specification 4.9.1.6 where the term " extended cold shutdown" is interpreted as "a cold shutdown of longer than 30 days' duration."
(7) Existing Technical Specification 4.1.2 (Table 4.1-2), would require a functional test of the Backup Instrument Air Supply System (backup air supply for the emergency feedwater control valves), every refueling period.
l (8) Existing Technical Specification 4.1.1 (Item 50 in Table i
4.1-1), as modified, would require. a check each shif t, monthly testing, and calibration e sch refueling period, for the emergency feedwater flow instr smentation. The " check" and "te st" surveillances would not be required when TAVG is less than 200*F since the reactor would be shutdown and this safety function not needed.
(9) Existing Technical Specification 4.5.1.1, as modified would incorporate the motor driven feedwater pumps into the list of equipment whose operation is verified during the testing of the emergency diesel generators. In this case, an addi-tional test signal is required to start the pumps since the pumps do not actually start on loss of AC power (the actual start signal is on loss of main feedwater or loss of reactor coolant pumps.)
f l (10) With regard to surveillance on the automatic initiation
! circuitry for the Emergency Feedwater System, draft Technical l Specification 4.1.1 (Table 4.1-1, Item 51) provides check, test, and calibration frequencies.
Conclusion In conclusion, with regard to the modifictions to the emergency feedwater systems and associated Technical Specifications:
(1) The probability or consequences of accidents previously evaluated have not increased. The more conservative Limiting Condition for Operation and Surveillance Requirements for the emergency feedwater system provide increased assurance that the system will operate properly, when required.
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(2) No accidents, other than those previously considered, will l be introduced. The modifications to the emergency feedwater I system could only effect the non-operation or spurious l I
operation of the system; both of these conditions have been previously evaluated. The only aspect of the emergency feedwater system modification with the potential for effecting j other systems involves the loading of the motor driven feedwater pumps on the emergency diesel generators. An analysis of the diesel generator loading indicates that the maximum load, with the emergency feedwater pumps is 2817 Kw l compcred to the 2000 hour0.0231 days <br />0.556 hours <br />0.00331 weeks <br />7.61e-4 months <br /> rating of 3000 Kw. The proper diesel generator loading sequence with the emergency feedwater pumps will be verified prior to startup and every 18 months thereafter. Other aspects of the emergency feedwater system will be tested prior to startup, and periodically thereaftsr.
(3) No safety margins have been reduced. The modifications to the emergency feedwater system did not involve any changes which resulted in a decrease in capacity of this system to perform its designed function.
Based upon the above, we conclude that the modifications to the emergency feedwater system, and associated Technical Specifications, do not involve any unreviewed safety questions with regard to the criteria of 10CFR Part 50, Section 50.59(a)(2).
11.2.8 Post Accident Monitoring Introduction Section 2.1.8 of, "TMI-2 Lessons Learned Task Force Status Report and Short-Term Recommendations," NUREG-0578, July 1979 makes the following recommendations with regard to the increased range of radiation monitors:
" Provide high range radiation monitors for noble gases in plant effluent lines cnd a high-range radiation monitor in the contain-ment. Provide instrumentation for moltoring ef fluent releases lines capable of measuring and identifying radioiodine and par-ticulate radioactive effluents under accident conditions." In addition, the NRC recommended that facilities " Provide instrumen-tation for accurately determining in plant airborne radioiodine concentrations to minimize the need for unnecessary use of res-piratory equipment. In an August 13, 1979 ACRS memorandum to the NRC, the ACRS recommended the following additional post-accident instrumentation: (1) containment pressure, (2) containment water level, and (3) on-line monitoring of hydrogen concentration in the containment.
The post-accident monitoring instruments to be installed at TMI-1 are responsive to the recommendations of the NRC and the ACRS.
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i Evtluation Section 2.1.2.1 of " Report in Response to NRC Staff Recommended Requirements for Restart of Three Mile Island Nuclear Station Unit 1" describes the post-accident monitoring instrumentation to be installed at TMI-1. The post-accident instrumentation, in conformance with Regulatory Guide 1.97, consists of the following:
(1) Containment Pressure - the range will be - 5 psig to three times the containment design pressure;
. (2) Containment Water Level - a narrow range monitor will measure containment sump level while the wide range monitor will measure from the bottom of the containment to a 10 ft.
level; (3) Containment Hydrogen Indication - continuous reading of tly concentration of hydrogen in the containment, from 0 to 10%,
! will be available in the control room; (4) High Range Containment Radiation Monitor - two monitors with a range to 107R/hr will be provided; l (5) High Range Ef fluent Monitors:
1 5
(a) Undiluted Containment Exhaust - 10 Ci/cc (b) Main Steam Lines - 10 2 c17ec (c) Auxiliary and Fuel Handling Building Exhaust 103 Ci/et (d) Condenser Off Gas - 105 Ci/cc (e) High Range Ef fluent Radio Iodine & Particulate Sampling and Analysis - silver zeolite cartridges.
l Although the above instrumentation does not actuate safety equipment, nor is it required by safety analyses, it is appropriate to provide l
Surveillance Requirements to assure reliable post-accident performance of the instrumentation. Surveillance Requirements for post-accident monitoring instrumentation is incorporated into TMI-l Draft Technical l
Specification 4.1.1 (Table 4.1-1) as follows:
(1) Item 13 of Table 4.1-1, "High Reactor Building Pressure," is l provided with a footnote to include the post-accident instru-mentation in the existing containment pressure instrumentation surveillance program; (2) Item 28 of Table 4.1-1, " Radiation Monitoring Systems," is provided with a footnote to include the post-accident instru-mentation, described in item (5)(a) thru (5)(d) above, in the existing radiation monitor system surveillance program; 11-18 Am. 21 en.
l (3) Item 37 of Table 4.1-1 " Reactor Building Sump Level" has been changed to " Reactor Building Sump and Containment Level." A foot-note has also been added to include the post-accident intrumentation in the sump level instrument l surveillance program.
l (4) A new item 52, " Reactor Building Hydrogen Concentration,"
has been added to address Surveillance Requirements for the reactor building hydrogen concentration instrumentation. The
" check" and " test" surveillance need not be performed when TAVG is less than 200*F since the reactor would be shutdown l
and this safety function not needed.
Conclusion With regard to TMI-1 post-accident monitoring instrumentation, and associated Technical Specifications, since the instrumentation does
< not actuate safety' equipment, nor is it required by the safety analysis:
(1) The probability or consequences of accidents previously evalu-ated have not increased.
l (2) No accidents of a type, not previously evaluated, will occur, and l
(3) No safety margins have been reduced.
Based upon the above, we conclude that the post-accident monitoring instrumentation, and associated Technical Specifications, do not involve any unreviewed safety issues with regard to the criteria of 10CFR, Part 50, Section 50.59 (a)(2).
11.2.9 Reactor Coolant Pump Trip on Coincident HPI (1600 psig) and Loss of Saturation tiargin Introduction !
The IE Bulletin Nos.79-05C and 79-06C, July 26, 1979 states that, l "Recent preliminary calculations performed by Babcock & Wilcox, Westinghouse and Combustion Engineering indicate that, for a certain spectrum of small breaks in the reactor coolant system, continued operation of the RCPs can increase the mass lost through the break l
l and prolong or aggravate the uncovering of the reactor core.
i The damage to the reactor core at THI-2 followed tripping of the last operating RCP, when two phase fluid was being pumped through the reactor coolant system. It is our current understanding that all three of the nuclear steam system suppliers for PWRs now agree that an acceptable action under LOCA symptoms 13 to trip all oper-ating RCPs immediately, before significant voiding in the reactor l coolant system occurs."
With regard to reactor coolant pump trip, IE Bulletin Nos.79-05C and 79-06C recommends the following long-term action: i i
11-19 Am. 21 l l
" Propose and submit a design which will assure automatic tripping of the operating RCPs under all circumstances in which this action may be needed."
l Section 2.1.2.5 of " Report in Response to NRC Staff Repommended Response to NRC Staff Recommended Requirements for Restart of Three Mile Island Nuclear Station Unit 1" contains a description of the reactor coolant pump trip that is proposed for TM1-1.
Evaluation The logic for the reactor coolant pump trip receives inputs from the High Pressure Injection (HPI) signal f rom the ESFAS, and loss of saturation margin as determined f rom the Saturation Margin Meter. Details of the trip logic will be supplied at a later date. Limiting Conditions for Operation and Surviellance Requirements for tl}e Reactor Coolant Pump Trip are addressed below.
{ Limiting Conditions for Operation for the Reactor Coolant Pump Trip are presented in TMI-1 draf t Technical Specification 3.5.7.
The draft Technical Specification requires that the RCP trip to be operable during reactor startup, and power operation. In the l event that the reactor coolant pump trip is inoperable, hot shut-down must be achieved within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The draft Technical Spec-ification only allows continued reactor operation if the pump trip is in a condition which assures reliable operation. The remedial action is specified to allow a reasonable time to restore the reactor coolant pump trip to operability or achieve an orderly shutdown. The Surveillance Requirement for the reactor coolant pump trip is contained in TM1-1 draf t Technical Specification 4.1.1 (Table 4.1-1). A new item, number 51, proposes a pump trip channel check en shift, a test each month, and a calibration t
each refueling period. The draft Surveillance Requirement for the
~
l pump trip is consistent with the surveillance for other safety instrumentation channels. The " check" and " test" surveillances need not be performed when TAVG is less than 200*F since the
! reactor is shut down and this safety function is not needed.
Conclusion l
With regard to the reactor coolant pump trip, the logic is designed to provide high assurance that the reacto- coolant pumps will be triped when required. Any single failure within the reactor coolant pump trip logic will result in only a single reactor coolant pump being tripped. Tpe draft Limiting Condition for Operation for the reactor l
coolant pump trip prevents extended reactor operation if the reactor j coolant pump trip is significantly degraded. The draft Surveillance Requirement for the reactor coolant pump trip provides assurance of reliable operation.
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11.2.10 THI-1/TMI-2 Separation Introduction Item 11.4 of the NRC's August 9,1979 " Order and Notice of Hearing,"
requires that, "The licensee shall demonstrate that decontamination l
and/or restoration operations at TMI-2 will not affect safe operations at TMI-1. The licensee shall provide separation and/or isolation of TMI 1/2 radioactive liquid transfer lines. Fuel handling areas, vent-11ation systems, and sampling lines. Effluent monitoring instruments shall have the capability of discriminating between effluents resulting i from Unit 1 or Unit 2 operations."
l Section 7.2 of " Report in Response to NRC Staff Recommended Require-l ments for Restart of Three Mile Island Nuclear Station Unit 1" de-scribes a plan to separate THI-1/THI-2 interfaces that have the potential of transf. erring significant quantities of contamination as a result of restoration activities at TMI-2.
Evaluation The two major pathways for potential transfer of contamination from THI-2 to THI-1 are the waste management interconnections and I the common air space of the Fuel Handling Building. The following i TMI-1/THI-2 waste menagement interfaces have been identified:
I (1) Unit 2 Reactor Coolant Bleed Holdup Tank - Unit 1 Reactor Coolant Waste Evaporator.
l (2) Unit 1 Miscellaneous Waste Evaporator - Unit 2 Evaporator Condensate Test Tank.
(3) Unit 2 Nuctralizer Tanks, Contaminated Drain Tanks, Reactor Coolant Bleed Holdup Tanks, Auxiliary Building Sump Tanks and Miscellaneous Waste Holdup Tanks - Unit 1 Liquid Waste Disposal Sys, tem.
(4) Onit 1 Evaporator Concentrate - Unit 2 Evaporator Concentrate.
(5) Unit 1 Spent Ion Exchange Resin - Unit 2 Spent Ion Exchange Resin.
Draf t THI-1 Technical Specification 4.1.2 (Table 4.1-2, Item 13) l requires the isolation devices (valves, blank flanges, etc.) on
' the above ticlines to be verified to be isolated, by visual in-spection, on a monthly basis. Draf t TMI-1 Technical Specification 3.19 requires that, if an isolation device is found to be open with-out prior NRC authorization, a " Thirty Day Written Report" must be 1 l
prepared per THI-1 draft Technical Specification 6.9.2.B(5). In l addition, THI-1 draf t Technical Specification 3.19.2 requires NRC .
approval prior to creation of additional TML-1/THI-2 system inter- ]
ties that can transfer potentially significant quantities of con-tamination. i i
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' With regard to the separation 'of the air space in the Fuel Handling Building, the details of this modification have not been finalized.
Additional evaluations and preparation of draf t Technical Specifica- ,
-tions will be undertaken, if appropriate, following finalization of the design details of the Fuel Handling Building isolation system.
Conclusion l
The draf t TMI-l Technical Specifications 3.19 and 4.1.2 for the THI-1/
. TMI-2 interties provide assurance that: i (1). System _intenties that could potentially transfer ~significant quantities of contamination from THI-1 to THI-2 will remain
[ ,
closed.
(2) If permission is received from the NRC to open system interties,
~
these interties will be used in accordance with plant procedures.
l (3) No new system interties, with the potential for transferring
! significant quantities of contamination from THI-2 to THI-1, l
will be. created without prior NRC approval.
The above controls limit releases from THI-1 to materials under control at THI-1 and thus to previously evaluated quantities and concentrations of contamination, 11.2.11 Low Reactor Coolant System Pressure Channel for HPI/LPI Initiatin, Introduction The Low Reactor Coolant System Pressure Channel setpoint, which is used as input to the ESFAS logic, is determined based on a ;eneric LOCA analysis. The generic LOCA analysis for THI, referenced as ,
"ECCS Analysis of B&W's 177-FA Lowered-Loop NSS." BAW-10103, has I referenced the Low Reactor Coolant System Pressure setpoint as 1600'psig compared with the Technical Specification value of 1500 psig. The setpoint actually used in the BAW-10103 calculations, however, was 1350 psig.
Evaluation The TMI-l Technical Specification 3.5.3.1, " Engineered Safeguards Protection System Actuation Setpoints," requires the Low Reactor 4 Coolant- System' Pressure HPI/LPI initiation setpoint to be 2; 1500 psig. Draft TMI-1 Technical Specification 3.5.3.1 would require l the Low Reactor Coolant System Pre'ssure HPI/LPI initiation setpoint I to be raised to 2; 1600 psig. In the event of a LOCA, the only impact of the 100 psig increase in the minimuu Low Reactor Coolant System Pressure setpoint.would be to initiate actions, based on this signal, at an' earlier time in the accident (e.g., in conjunc-tion with,the 4'psig High Reactor Building Pressure, both HPI and !
LPCI pumps would start earlier in the accident.)
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i Conclusion With regard to the 100 psig increase in the minimum Low Reactor Coolant System Pressure HPI/LPI initiation setpoint:
(1) The probability or consequences of accidents previously evalu-ated have not increased. The potential initiation of engineered safety feature ' equipment at an earlier time in a LOCA is not expected to have a significant impact on peak clad temperature
'and other LOCA limits (any changes would be expected to be in direction of a less severe accident).
(2)' No accidents of a type not previously evaluated will occur.
The proposed change in the Low Reactor Coolant System Pressure Setpoint would have only a small impact on the severity of the LOCA, in the conservative direction, rather than change the j
nature of the. accident.
(3) No safety margins have been reduced. The applicable LOCA calculations continue to be those for which the Low Reactor Coolant System Pressure HPI/LPI initiation setpoint is 1350 psig; operationally, raising the Linimum setpoint to 1600 psig would slightly increase the LOCA margins.
Based upon the above, we conclude that raising the minimum Low Reactor Coolant Pressure setpoint.from 1500 psig to 1600 psig does not lnvolve any unreviewed safety questions with regard to the criteria of 10CFR Part 50, Section 50.59(a)(2).
11.2.12 Raising the Low Reactor Coolant System Pressure Trip Setpoint Introduction The TM1-1 Technical Specification 2.3.1 (Table 2.3-1, Figure 2.3-1) provides a value of 1800 psig for the RPS Low Reactor Coolant Pressure trip setpoint. The B&W generic ECCS analysis, "ECCS Anal-j ysis of B&W's 177-FA Lowered Loop NSS," BAW-10103, Rev. 2, April 1976, referenced a value of 1900 psig for the Low Reactor Coclant
< Pressure Trip setpoint. Draft Technical Specification 2.3.1 would increase the Low Reactor Coolant System Pressure Trip Setpoint from 1800 psig to 1900 psig.
Evaluation i
) The principal reason for the Low Reactor Coolant System trip set-point in to maintain thermal margins for the fuel by preventing the minimum DNB ratio from decreasing below the safety limit of 1.3; the transient analysis for TM1-1 is based on an 1800 psig Low Reactor. Coolant System trip setpoint. The Low Reactor Coolant t System trip setpoint is also credited in the ECCS analysis since a reactor trip is part of the assumed LOCA scenario.
s 11-23 Am. 21 1
)
, . + , . y m , . . . _ . _ . . _ , . _ _ . , _ . _ , , , .
By increasing the Low Reactor Coolant System Pressure setpoint from 1890 psig to 1900 psig, the reactor would trip earlier in the LOCA scenario and thus the decay heat would be slightly less when the ECCS functions. Increasing the Low Reactor Coolant System trip setpoint also has the effect of increasing the margin to DNB following a trip on low pressure; the reactor would trip earlier on low pressure and thus the final minimum DNB would be higher (more conservative) than if the reactor tripped at 1800 psig.
Conclusion With regard to increasing the Low Reactor Coolant System trip setpoint from 1800 psig to 1900 psig:
(1) The probability or consequences of accidents previously con-sidered have not increased. For any accident that involves a pressure decrease, the reactor will trip earlier in the trans-ient and thus the result of the accident will be more conser-vative.
(2) No accident of a type not previously evaluated, will occur.
The increasing of the Low Reactor Coolant System trip setpoint will not have any effect other than tripping the reactor at an earlier time in pressure reduction transients.
(3) No safety margins have been decreased. It is expected that for pressure reduction transients, DNB following the reactor trip will be higher (more conservative) and f or the LOCA, the peak clad temperature and other system parameters will be more favorable.
Based upon the above, we conclude that increasing the Low Reactor Coolant System trip setpoint from 1800 psig to 1900 psig does not involve unreviewed safety questions with regard to the criteria of 10CFR Part 50, Section 50.59(a)(2).
11.2.13 Post,-Accident Pressure Temperature Limits Introduction Item 2 of the IE Bulletin 79-05B addresses actions to be taken by i
reactor operators following automatic actuation of the High Pressure Injection (HPI) system due to low reactor coolant system pressure. Based upon IE. Bulletin 79-05B, continued operation of HP is based upon maintenance of a 50*F subcooling margin in the reactor coolant system; however, "The degree of subcooling beyond 50-degrees F and the length of time HPI is in operation shall be limited by the pressure temperature considerations for vessel integrity." The purpose of this section is to describe draft Technical Specifications which incorporate pressure temperature limits to be utilized following HPI initiation.
i 11-24' Am. 21
Discussion During certain Loss of Coolant Accident (LOCA) conditions generated by small breaks in the Reactor Coolant System (RCS), the HPI system is relied upon to effect cooling of the core. Cold HPI water is injected into a telatively high pressure, stagnant, RCS loop which can potentially cause a reduction in the margin to brittle failure of the reactor pressure vessel.
The high differential temperature between the RCS and HPI water has two significant effects:
(1) As HPI water flows into the reactor vessel, it will cool the metal. This consequently reduces the fracture resistance of the metal.
(2) Thermal stresses will be developed because of rapid cooling of the inside metal surface (thermal shock). This stress will be superimposed on the existing residual stresses and those stresses that are generated by internal pressure. This combined stress field is significant, especially at a time when the fracture toughness of the reactor pressure vessel has decreased.
Analyses were made (Reference 1,2) of the consequences of HPI actuation on the THI-1 reactor pressure vessel considering effects of:
(1) Neutron fluence on fracture toughness of the material.
(2) Resulting stress field.
(3) Linear elastic fracture mechanics techniques that are out-lined in Appendix A to ASME Code Section XI and Appendix G to ASME Code, Section 111.
The results of the analyses are incorporated in a pressure-tem-perature curve presented in Figure 3.1-la of draf t Technical l Specification 3.1.2.1, " Pressurization Heatup and Cooldown ;
Limitation." Draf t Technical Specification 3.1.2.1 requires Figure 3.1-la to be used following HPI initiation and until i HPI is secured and the reactor is in cold shutdown. Existing pressure-temperature limits for heatup/cooldown and in-service leak and hydrostatic testing, which apply to normal operation )
and testing conditions, would not be effected by the additional limitations. The additional pressure-temperature limitations only apply to transient and accident conditions which result '
in HPI initiation.
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' Conclusion The use of the post accider'. pressure-temperature limits pre-4 sented in Figure 3.1-la of draft Technical Specification 3.1.2.1 will assure that an appropriate margin to reactor vessel brittle failure will be maintained following accidents and transients resulting in HPI initiation.
References (1) B&W Evaluation of RV Brittle Failure Due to Injection of Cold HP1 Water During Small LOCA Events. June 13, 1979.
(2) New B&W study to be finalized 1st week of liarch,1980.
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i 11-26 Am.21 4
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Draft Technical Specifications Corresponding to Section 11." '
as Amended by Amendment 21 1
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3.5.5 ACCIDENT MONITORING INSTRUMENTATION Applicability Applies to the operability requirements for the instruments ident-ified in Table 3.5-2 during START UP and POWER OPERATION.
Objective To assure operability of key instrumentation useful in diagnosing situations which could lead to inadequate core cooling.
Specification 3.5.5.1 The minimum number of channels or alternate indications, identified for the instruments in Table 3.5-2, shall be OPERABLE. With the number of instrumentation channels less than the minimum required and the alternate indication inoperable, restore the inoperable channel (s) to OPERABLE status within seven (7) days or be in at least HOT SHUTDOWN within the next twelve (12) hours. Prior to start-up following a COLD SHUTDOWN, the minimum number of channels shown in Table 3.5-2 shall be OPERABLE.
Bases The Saturation Margin Meter provides a quick and reliable means for determination of saturation temperature and saturation pressure margins. The hand calculation of saturation pressure and saturation temperature margins can be easily and quickly performed since it only requires knowledge of recirculation loop temperatures and system pressure, and the use of steam tables; accordingly, hand calculation provides a suitable alternate indication for the Sat-uration Margin Indicator.
Discharge flow from the two (2) pressurizer code safety valves and the Electromatic relief valve is measured by differential pressure transmitters connected across elbow taps downstream of each valve.
A delta pressure indication from each pressure transmitter is available in the control room to indicate safety or relief valve line flow. An alarm is also provided in the control room to indi-cate that discharge from a pressurizer safety or relief valve is oceuring. In addition, an acoustic monitor is provided to detect flow in the relief valve discharge line. An alarm and a flow indication is provided in the control room for the acoustic monitor.
In the event that a delta pressure monitor or the acoustic monitor becomes inoperable, access to the containment would most likely be required; however, a reactor shutdown to allow containment access for this repair is not justifiablo due to the existence of alter-nate means of detecting and monitoring safety or relief valve dis-charge flow. The alternate means of monitoring safety / relief valve discharge flow consists of a thermo-couple in each discharge wine.
The Emergency Feedwater System is provided with two channels of flow instrumentation on each of the two discharge lines. Local flow in-dication is also available for the emergency feedwater system.
Although the prersurizer has multiple level indications, the separate indications are selectable via a switch for display on a single dis-play. Thus, only a single pressurizer level channel is available from the control room. Pressurizer level, however, can also be determined via the remote shutdown panel and the computer log.
Although the instruments identified in Table 3.5-2 are significant in diagnosing situations which could lead to inadequate core cooling, loss of any one of the instruments in Table 3.5-2 would not prevent continued, safe, reactor operation provided that the alternate indi-cation is operable. Loss of an instrument and its alternate indication would degrade the' reactor operators diagnostic capability and, thus, should be restored within seven (7) days.
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TABLE 3.5-2 ACCIDENT 110NITORING INSTRU 1ENTS MINI!!Uli ALTERNATE INSTRUllENTS NUf!BER OF CHA?;NELS NU?iBER OF CHANNELS INDICATION FUNCTION Saturatien targin tieter 1 1 1
Safety / Relief Valve P 1 per discharge line 1 per discharge line Thermo couple /l per 2
discharge line Relief Yalve Acoustic !!onitor 1 1 Thermo couple /
3 discharge line Emergency Feedwater Flow 2 per discharge line 1 per discharge line Local flow 4
indication 5 Pressurizer Level 1 1 Pressurizer Level (remote shutdown pannel) or Computer Log 0 If the Saturation !!argin !!cter is inoperable, the operabilit.y requirement for the Saturation 11argin 11eter is satisfied by implementing the procedure for hand calculation of saturation pressure and temperature margins.
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3.1.12 Electromatic-Relief Valve and Block Valve Applicability Applies to the settings, and conditions for isolation of the electromatic relief. valve.
Objective
~
To prevent the possibility of inadvertently overpressurizing the primary loop.
Specification 3.1.12.1 The electromatic relief valve shall not be taken out of service, nor shall it.be isolated from the system (except that the elec-tromatic relf ef valve may be isolated to limit leakage to within the limits of specification 3.1.6), unless one of the following is in effect:
- a. liigh Pressure Injection Pump breakers are racked out or MU-V16A/B/C/D and MU-V217 are closed.
- b. Ilead of the Reactor Vessel is removed.
- c. T avg. is above 320*F.
3.1.12.2 The electromatic relief valve settings shall be as follows, within the tolerances of + 25 psi and + 12*F:
Above 275*F - 2450 psig Below 275'F - 485 psig 3.1.12.3 If the reactor vessel head is installed and T avg. is <275'F, liigh Pressure Injection Pump breakers shall not be racked in unless:
- a. MU-V16 A/B/C/D and MU-V217 are closed, and
- b. Pressurizer level is _( 220 inches.
3.1.12.4 Pressurizer Electromatic Power Operated Relief Valve (PORV) and
! Block Valve -
The Electromatic PORV and the associated block valve shall be
-OPERABLE during Il0T STANDBY, START UP AND POWER OPERATION:
- a. With the PORV inoperable within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> either restore the l PORV to OPERABLE status or close the associated block l valve and remove power from the block valve; otherwise, be i in at least 110T STANDBY within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in COLD SilUTDOWN within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.
- b. With the PORV block valve inoperable, within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> either restore the PORV block valve to OPERABLE status or close
! the PORV (verify closed) and remove power from the PORV.
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Bases If.the electromatic relief valve is removed from service, sufficient measures are incorporated to prevent overpressurization by either eliminating the high pressure sources or flowpaths or assuring that the RCS is open to atmosphere.
In order to prevent exceeding leakage rates specified in T.S. 3.1.6. the elec-tromaric relief valve may be isolated.
The electromatic relief valve setpoints are specified with tolerances assumed
'in the bases for Technical. Specification 3.1.2.
With RCS temperatures less than 275*F and the makeup pumps running, the high pressure injection valves are closed and the pressurizer level is maintained less than 220 inches to prevent overpressurization in ene event of any single failure.
Both the PORV and the PORV block valve should be operable during the HOT STANDBY, STARTUP and POWER OPERATION. If either the PORV or the PORV block valve are inoperable the PORV discharge line should be isolated to prevent uncontrolled RCS depressurization.
- 4. SURVEILLANCE STANDARDS Specified intervals may-be adjusted plus or minus 25 percent to accommodate normal test schedules.
4.1 OPERATIONAL SAFETY REVIEW Applicability A'pplies to items directly related to safety limits and limiting conditions for operation.
Objective l To specify the minimum frequency and type of surveillance to be applied to unit equipment and conditions.
Specification 4.1.1 The minimum frequency and type of surveillance required for reactor protection system and engineered safety feature protection system instrumentation when the reactor is critical shall be as stated in Table 4.1-1. Surveillances in Table 4.1-1, not performed due to reactor shutdown greater than one month, shall be performed prior to STARTUP.
4.1.2 Equipment and sampling test shall be performed as detailed in Tables
- 14.1-2 and 4.1-3.
Bases Check-t Failures such as blown instrument fuses, defective indicators, or faulted amplifiers which result in " upscale" or "downscale" indication can be easily recognized by simple observation of the functioning of an instrument or system. Furthermore, uuch' failures are, in many cases, revealed by alarm or annunciator action. Comparison of output and/or state of independent
} channels measuring the same variable supplements this type of built-in sur-veillance. Based on experience in operation of both conventional and nuclear aystems, when the unit is. in operation, the minimum checking f requency stated is deemed adequate for reactor system instrumentation.
Calibration Calibration;shall be-performed to assure the presentation and acquisition of
- accurate information. The nuclear flux (power range) channels amplifiers shall be checked'and calibrated.if necessary, every shift against a heat balance standard. The frequency of heat balance checks will assure that the difference between the out-of-core instrumentation and the heat balance remains less th'an 4%.
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TABLE 4.1-1 (Cantinued)
CHECK TEST CALIBRATE REMARKS CHANNEL DESCRIPTION
- 38. ~ Steam Generator Water Level W NA -R
- 39. Turbine Overspeed Trip NA R NA
- 40. Sodium Thiosulfate Tank Level NA NA R Indicator
- 41. Sodium Hydroxide Tank Level NA NA R Indicator
- 42. Diesel Generator Protective NA N R
-Relaying
- 44. Reactor Coolant Pressure S(l) M R ( 1) When reactor coolant system is DH Valve Interlock Bistable pressurized above 300 psig or Taves is greater than 200*F.
- 45. Loss of Feedwater Trip S(l) M(1) R (1) When reactor >10% power S(1) M(1) R (1) When reactor >20% power
- 46. Turbine Trip / Reactor Trip 47.a Pressurizer Code Safety Valve and S(l) M(1) R (1) When TAVG is greater than 200*F Electromatic Relief Valve delta P/ flow ,
M(1) R (1) When TAVG is greater than 200*F 47b. Pressurizer Electromatic Relief NA Valve- Acoustic / Flow PORV Setpoint NA M(1) R (1) When TAVG is greater than 200* F
- 48. Excluding valve operation.
T/W - Twice per week R - Each Refueling Period S - Each Shift NA - Not Applicable D - Daily B/M - Every 2 months W - Weekly Q - Quarterly B/W - Every two weeks M - tionthly P - Prior to each startup if not done previous week
TABLE 4.1-2 MIN 111U11 EQUI?!1ENT TEST FREQUENCY Item Test Frequency
- 1. Control Rods Rod drop times of all Each refueling shutdown full length rods
- 2. Control Rod Movement of each rod Every two weeks, when reactor Movement is critical
- 3. Pressurizer Safety Setpoint* 50% each refueling period Valves
- 4. Main Steam Safety Setpoint 25% each refueling period Valves
- 5. Refueling System Functional Start of each refueling period Interlocks
- 6. Main Steam (See Section 4.8)
Isolation Valves
- 7. Reactor Coolant Evaluate Daily, when reactor coolant System Leakage system temperature is greater than 525*F
- 9. Spent Fuel Cooling Functional Each refueling period prior to System fuel handling
- 10. Intake Pump House (a) Silt Accumulation- Each refueling period Floor Visual inspection of Intake (Elevation 262 Ft. Pump House Floor 6 in.) (b) Silt Accut ulation Quarterly tieasurement of Pump House Flow
- 11. Pressurizer PORV Functional ** Quarterly Block Valce
- The setpoint of the pressurizer code safety valves shall be in accordance with ASME Boiler and Pressurizer Vessel Code,Section III, Article 9, Winter, 1968.
- Function shall be demonstrated by operating the valve through one complete cycle of full travel.
Draft Technical Specification Corresonding to Section 11.2.3 as Amended by Amendment 21 i
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3.1.3 MINIMUM CONDITIONS FOR CRITICALITY
' Applicability Applies to reactor coolant system conditions requ'. red prior to criticality.
Objective
- a. To limit the magnitude of any power excursions resulting f rom reactivity insertion due to moderator pressure and moderator temperature coefficients.
- b. To assure that the reactor coolant system will not go solid in the event of a rod withdrawal or startup accident.
Specification 3.1.3.1 The reactor coolant temperature shall be above 525 F except for portions of low power physics testing when the requirements of Specification 3.1.9 shall apply.
3.1.3.2 Reactor coolant temperature shall be above DTT +10 F. !
3.1.3.3 When the reactor coolant temperature is below the minimum temp-erature specified in 3.1.3.1 above, except for portions of low f power physics testing when the requirements of Specification l 3.1.9 shall apply, the reactor shall be subcritical by an amount eq a1 to or greater than the calculated reactivity insertion due to depressurization. ;
I 3.1.3.4 The reactor shall be maintained subcritical by at least one percent k/k until a steam bubble is formed and an indicated water level between 80 and 385 inches is established in the pressurizer and a minimum of 107 kw of pressurizer heaters, i from each of two pressurizer heater groups, are OPERABLE.
Each OPERABLE 107 kw of pressurizer heaters shall be capable-of receiving power from a 480 volt ES bus via the established manual transfer scheme.
(a) With the pressurizer inoperable due to one (1) inoperable '
emergency power supply to the pressurizer heaters either restore the inoperable emergency power supply within 30 days or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> i and in HOT SHUTDOWN within the following 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. l (b) With the pressurizer inoperable due to two (2) inoperable emergency power supplies to the pressurizer heaters either restore the inoperable emergency power supplies within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in HOT SHUTDOWN within the following 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. l (c) With the pressurizer otherwise inoperable, be in at least HOT STANDBY with the reactor trip breakers open within i 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in HOT SHUTDOWN within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. !
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3.1.3.5 Safety rod groups.shall be fully withdrawn prior to any other reduction in shutdown margin by deboration or regulating rod withdrawal during the approach to criticality with the following exceptions:
- a. Inoperable rod per 3.5.2.2. ;
- b. Physics Testing per 3.1.9.
- c. Shutdown margin may not be reduced below 1% Ak/k per 3.5.2.1.
- d. Exercising rods per 4.1.2.
Following safety rod withdrawal, the regulating rods shall be positioned within their position limits as defined by Specifi-cation 3.5.2.5 prior to deboration.
Bases At the beginning of life of the initial fuel cycle, the moderator temperature coefficient is expected to be slightly positive at operating temperatures with the operating configuration of control rods. (1) Calculations show thar above 525 F the positive moderator coefficient is acceptable.
Since the moderator temperature coefficient at lower temperatures will be less negative or more positive than an operating temperature, (2) startup and opera-tion of the reactor when reactor coolant temperature is less than 525 F is pro-hibited except where necessary for low power physics tests.
The potential reactivity insertion due to the moderator pressure coefficient (2) that could result from depressurizing the coolant from 2100 psia to satur-ation pressure of 900 psia is approximately 0.1 percent Ak/k.
During physics tests, special operating precautions will be taken. In addition, the strong negative Doppler coefficient (1) and the small integrated Ak/k would '
limit the magnitude of a power excursion resulting from a reduction of moderator density.
The requirement that the reactor is not to be made critical below DTT +10F pro-vides increased assurances that the proper relationship between primary coolant pressure and temperatures will be maintained relative to the NDTT of the primary coolant system. Heatup to this temperature will be accomplished by operating the reactor coolant pumps.
If the shutdown margin required by Specification 3.5.2 is maintained, there is no possibility of an accidental criticality as a result of a decrease of coolant pressure.
The availability of at least 107 kw in pressurizer heater capability is suf-ficient to maintain primary system pressure assuming normal system heat losses.
Emergency ) ver to heater groups 8 and 9, supplied via a manual transfer scheme, assures redundant capability upon loss of of fsite power.
The requirement that the safety rod groups be fully withdrawn before criticality ensures shutdown capability during startup. This does not prohibit rod latch confirmation, i.e., withdrawal by group to a maximum of 3 inches withdrawn of all seven groups prior to safety rod withdrawal.
The requirement for regulating rods being within their rod position limits en-sures that the shutdown margin and ejected rod criteria at hot zero power are not violated.
REFERENCES (1) FSAR, Section 3.
(2) FS AR, Section 3.2.2.1.
4.6 EMERCENCY POWER SYSTEM PERIODIC TESTS
{ ,
Applicability Applies to periodic testing and surveillance requirement of the emergency power system.
Objective To verify that the emergency power system will respond promptly and properly when req.' ad.
Specific. . ion The fol] .. wing tevts and surveillance shall be performed as stated:
4.6.1 Diesel Generators
- a. Manually-initiated start of the diesel generator, f ollowed by manual synchronization with other power sources and assumption of load by the diesel generator up to the nameplate rating (3000 kw). This test will be conducted every month on each diesel generator. Normal plant operation will not be affected.
- b. Automatic start of each diesel generator and restoration to operation of particular vital equipment, initiated by an l f actual loss of normal a-c station service power supply to-I
( gether with a simulated Engineered Safeguards Actuation Signal.
Following input of the Engineered Safeguards Actustion Signal, it shall be verified than the circuit breakers, supplying power to the manually transferred loads for pressurizer heater Groups 8 and 9, have been tripped. This test will be conducted during reactor shutdown for refueling to assure that the diesel gen-erator will start assuming load in ten seconds and assume the load of all safeguards equipment listed in 4.5.1.lb within 60 seconds after the initial starting signal.
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- c. Each diesel generator shall be given an inspection at least annually in accordance with the manuf acturer's recommendations for this class of stand-by service.
4.6.2 Station Batteries
- a. The voltage, specific gravity, and liquid level of each cell will be measured and recorded monthly.
- b. The voltage and specific gravity of a pilot cell will be measured and recorded weekly.
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- c. Each time data are recorded, new data shall be compared with old to detect signs of abuse or deterioration.
(- .
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- d. The battery will be subjected to a load test at a frequency not to exceed refueling periods. The battery voltage as a l function of time will be monitored to establish that the
( battery performs as expected during this load test.
4.6.3 Pressurizer Heaterr t The emergency power supply for the pressurizer heater shall be demonstrated OPERABLE during reactor shutdown for refueling by transferring Heater Groups 8 and 9 from the nornsi to the emer-gency power supply and energizing the heaters, lizing either offsite or onsite power.
Bases l
The tests spec'fied are designed to demonstrate that one diesel-gener-ator will provide power for operation of safeguards equipment. They also assure that the emergency generator control system and the control systems for the safeguards equipment will function automatically in the event of a loss of normal a-c station service power or upon the receipt of an an engineered safeguards Actuation Signal. The automatic tripping l of manually transferred loads, on an Engineered Safeguards Actuation Signal, protects the diesel generators from a potential over-load con-l dition. The testing frequency specified is intended to identify and permit correction of any mechanical or electrical deficiency before it can result in a system failure. The fuel oil supply, starting circuits, and controls are continuously monitored and any faults are alarmed and indicated. An abnormal condition is these systems wauld be signaled without having to place the diesel generators on test.
Percipitous failure of the station battery is extremely unlikely. The surveillance specified is that which has been demonstrated over the years to provide an indication o a cell becoming unserviceable long before it fails.
The PORV has a remotely operated block vt .ve to provide a positive shutoff capability should the relief valve become inoperable. The electrical power for both the relief valve and the L.ock valves is supplied from an ESF power source to ensure the ability to seal this possible RCS leakage path.
The requirement that a minimum of 107 kw of pressurizer heaters and their associated controls be capable of being supplied electrical power from an emergency bus provides assurance that these heaters can be energized during a loss of offsite power condition to maintain natural circulation j at HOT STANDBY.
REFERENCE
! (1) FSAR, Section 8.2 I
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Draft Technical Specifications Corresponding to Section 11.2.5 as Amended by Amendment 21 i
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/' TABLE 3.5-1 Contr'Ned rg INSTRUMENTS OPERATING CONDITIONS
- I Functional Unit (A) (B) (C)
+
Minimum Minimum Engineered Safeguards Operable Degree of Operator Action if Conditions +
Channels Recondancy of Column A cannot be met (a)
- 3. Reactor Building isolation and Reactor Building Cooling System
- a. Reactor. Building 4 psig Instrument Channel 2 1 Hot Shutdown
- b. Manual Pushbutton 2 1 Hot Shutdown
- c. RPS Trip 2 1 Hot Shutdown
- d. Reactor Building 30 psig 2 1 Hot Shutdown (a) If minimum ci ..ditions are not met within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, the unit shall then be placed u in a cold shutdown condition.
O N (b) Also initiates Low Pressure injection.
- 4. Reactor Building Spray System
- a. Reactor Building 30 psig Instrument Channel 2 (b) 1 Hot Shutdown
- b. Spray Pump Manual Hot Shutdown Switches (c) 2 1 (a) If minimum conditions are not met within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, the unit shall then be placed in a cold shutdown condition.
(b) Two out of three switches in each actuation channel operable. .
(c) Spray valves opened by manual pushbutton listed in item 3 above.
_ . . . _ . . - . _ _ _ . _ _ _ _ _ _ _ . _ . _____m._ _
_. _ _ __ m. .
TABLE 3.5-1 Continued INSTRUMENTS OPERATING CONDITIONS Functional Unit (A) (B) (C)
Minimum tiinimum Reactor Building Isolation Operable ~ Degree of Operator Action if Conditions 4 Channels Redundancy of Column A cannot be met (a)
- 1. Reactor Building Purge
- a. High Radiation 1 0 Purging shall be secured p
1 (a) If minimum conditions are.not met within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, the unit shall then be placed in a cold shutdown condition.
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/"N TABLE 4.1-1 ConyA yed ,
N INSTRUMENTS OPERATING CONDITIONS ClANNEL j DESCRIPTION CllECK TEST CALIBRATE REMARKS
- 19. Reactor Building Emergency Cooling and Isolation System Channels
- a. Reactor Building S(l) M(1) R (1) When CONTAli ' .f INTEGRITY is required 4 psig Channels
- b. Ibnual Pushbutton S(l) M(1) NA (1) When CONTAINMENT INTEGRITY is required
- c. RPS Trip S(l) M(1) NA (1) When CONTAINMENT INTEGRITY is required
- d. Reactor Building 30 psig S(l) M(1) R (1) When CONTAINMENT INTEGRITY is required
- 20. Reactor Building Spray NA Q NA System Logic Channel i
v' 21. Reactor Building Spray System Analog Channels
- a. Reactor Building NA M R 30 psig Channels
- 22. Pressurizer Temperature S NA R Channels
- 23. Control Rod Absolute Position S(l) NA R (1) ' Check with Relative Position Indicator
- 24. Control Rod Relative Position S(l) NA R (1) Check with Absolute Position Indicator
- 25. Core Flooding Tanks
- a. Pressure Channels S(1) NA R (1) When Reactor Coolant system pressure is greater than 700 psig
- b. Level Channels S(1) NA R
- 26. Pressurizer Level Channels S NA R
- 27. Ikkeup Tank Level Channels D(1) NA R (1) When Makeup and Purification System is in operation
Draft Technical
^
Specification Corresponding to Section 11.2.6 as Amended by Amendment 21 k
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3.5.5 ACCIDENT MONITORING INSTRUMENTATION Applicability Applies to the operability requirements for the instruments ident-ified in Tabic 3.5-2 during START UP and POWER OPERATION.
Objective To assure operability of key instrumentation useful in diagnosing situations which could lead to inadequate core cooling.
Specification 3.5.5.1 The minimum number of channels or alternate indications, identified for the instruments in Table 3.5-2, shall be OPERABLE. With the number of instrumentation channels les. than the minimum required and the alternate indication inoperable, restore the inoperable channel (s) to OPERABLE status within seven (7) days or be in at least HOT SHUTDLWN within the next twelve (12) hours. Prior to start-up following a COLD SHUTDOWN, the minimum number of channels shown in Table 3.5-2 shall be OPERABLE.
Bases The Saturation Margin Meter provides a quick and reliable means for determination of saturation temperature and saturation pressure margins. The hand calculation of saturation pressure and saturation temperature margins can be easily and quickly performed since it only requires knowledge of recirculation loop temperatures and system pressure, and the use of steaa tables; accordingly, hand calculation provides a suitable alternate indication for the Sat-uration Margin Indicator.
Discharge flow from the two (2) pressurizer code safety valves and the Electromatic relief valve is measured by dif ferential pressure transmitters connected across elbow taps downstream of each valve.
A delta-pressure indication from each pressure transmitter is available in the control room to indicate safety or relief valve line flow. An alarm is also provided in the control room to indi-cate that discharge from a pressurizer safety or relief valve is occuring. In addition, an acoustic monitor is provided to detect flow in the relief valve discharge line. An alara and a flow indication is provided in the control room for the acoustic monitor.
In the v2nt that a delta-pressure monitor or the acoustic monitor becomes inoperable, access to the containment would most likely be required; however, a reactoc shutdown to allow containment access for-this renair is not justifiable due to the existence of alter-nate means of detecting and monitoring safety or relief valve dis-charge flow. The alternate means of monitoring safety / relief valve discharge flow consists of a thermo-couple in each discharge line.
The Emergency Feedwater System is provided with two channels of flow instrumentation on each of t'ac two discharge lines. Local flow in-dication is also available for the emergency feedwater system.
Although the pressurizer has multiple level indications, the separate indications are selecta' ole via a switch for display on a single dis-play. Thus, only a single pressurizer level channel is available from the control room. Pressurizer level, however, can also be determined via the remote shutdown panel and the computer log.
Although the instr;ments identified in Table 3.5-2 are significant in diagnosing situations which could lead to inadequate core cooling, loss of any one of the instruments in Table 3.5-2 would not prevent continued, safe, reactor operation provided that the alternate indi-cation is operable. Loss of an instrument and its alternate indication would degrade the reactor operators diagnostic capability and, thus, should be restored within seven (7) days.
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--. _ . . _ . - . _ . . _ . . . _ . __ _ . _ . . . .- .-_ ..-. ~ ._.. _..-_.m. ._.____....m.m_ .. _ . ~ _ . . . . . . . _ . . _ . ._ ._
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TABLE 3.5-2 ACCIDENT MONITORING INSTRU1ENTS l11 nit!UM . ALTERNATE
' FliNCTION INSTRUl!ENTS NL'11BER OF CHANNELS NU:1BER OF CHANNELS INDICATION 1 Saturation !!argin Meter 1 1 2 Safety / Relief Valve P 1 per discharge line 1 per discharge line Thermo couple /1 per discharge line w
3 Relief Valve Acoustic'!!onitor 1 1. Thercio couple / _t discharge line 4 Emergency Feedwater Flow ~ 2 per discharge line 1 per discharge line I.o c a l flow indication i 5 Pressurizer Level 1 1 Pressurizer Level i
<' (ranote chutdown panr.o.1) or Cosputer a Log O H the Saturation Itargin l!cter is inoperable, the operability requirement for the Saturation !!argin !!eter is satisfied by implementing the procedure .i for hand calculation of saturation pressure and temperature margins.
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TABLE 4.1-1 (Continued)
CHANNEL DESCRIPTION CHECK TEST CALIBRATE 'lEMARKS
- 38. Steam Generator Water Level W NA R
- 39. Turbine Overspeed Trip NA R NA
- 40. Sodium Thiocu. fate Tank Level NA NA R Indicator
- 41. Sodium Hydroxide Tank Level NA NA R Indicator
- 42. Diesel Generator Protective NA NA R Relaying
(Diesel Start)
- 44. Reactor Coolant Pressure S(1) !! R (1) When reactor coolant system is Dll Valve Interlock Bistable pressurized above 300 psig or Taves is greater than 200*F.
- 45. Loss of Feedwater Trip S(l) lis t) R (1) When reactor > 10% power.
- 46. Turbine Trip / Reactor Trip S(l) M(1) R (1) When reactor > 20% power.
47.a Pressurizer Code Safety Valve and S(1) R (1) When TAVG is greater than 200*F.
Electromatic Relief Valve delta P/ flow 47b. Pressurizer Electromatic Relief NA M R ( 1) when TAVG is greater than 200*F.
l Valve - Acoustic /Fiow ,
- 48. PORV Setpoint NA M(1) R (1) When TAVG is greater than 200*F.
Excluding valve operation.
- 49. Saturation Margin Meter S(l) R R (1) When TAVG is greater than 200*F.
T/W - Twice per week R - Each Refueling Period-S - Each Shift D - Daily B/M - Every 2 months NA - Not Applicable W - Weekly Q - Quarterly B/W - Every two weeks M - Monthly P gigtgel ggp eek f
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I Draft Technical l
Specification Corresponding to Section 11.2.7 as Aciended by Amendment 21 w,, - m-- -= - m.
3.4 DECAY HEAT REMOVAL - TURBINE CYCLE Applicability Applies to the operating status of equipment that functions to remove decay heat, utilizing the secondary side of the steam generators.
Objective To define the conditions necessary to assure immediate availability of the auxiliary feedwater system and main steam safety valves.
Specification 3.4.1 With the reactor coolant system temperature greater than 250oF, three independent steam generator emergency feedwater pumps and associated flow paths
- shall be OPERABLE with:
- inoperable, restore the inoperable pump or flow path l to OPERABLE status within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> or be in COLD SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. With more than one emergency feedwater pump l
l or flow path
- inoperable, restore the inoperable emergency feedwater l pumps or flow paths
- to operable status or be subcritical within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, in at least HOT SHUTDOWN within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, and in COLD SilUTDOWN within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
- c. Four of six turbine bypass valves are OPERABLE.
3.4.2 The condensate storage tanks (CSTS) shall be OPERALLE with a mini-mum of 150,000 gallons of condensate available in each CST. With a CST inoperable, restore the CST to operability within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> or be in at least 110T STANDBY within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, at least HOT SilUTDOWN within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, and COLD SHUTDOWN within the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
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- For the purpose of this requirement, an OPERABLE flow path shall mean an unobstructed path from the water source to the pump and from the pump to a steam generator.
3-23 Am.19
3.4.3 With the reactor coolant system temperature greater than 2500F, all eighteen (loj main steam safety valves shall be operable or, if any are not operable, the maximum overpower trip setpoint (see Table 2.3-1) shall be reset as follows:
Maximum Number of Maximum Overpower Safety Valves Disabled on Trip Setpoint Any Steam Generator (% of Rated Power) 1 92.4 2 79.4 3 66.3 With more than 3 main steam safety valves inoperable, restore at least fifteen (15) main steam safety valves to operable status within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> or be in at least hot standby within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in cold shutdown within the following 30 haurs.
Bases A reactor shutdown following power operation requires removal of core decay heat. Normal decay heat removal is by the steam generators with the steam dump to the condenser when system temperature is above 250*F and by the decay heat removal system below 250*F. Core decay heat can be continuously dissipated up to 15 percent of full power via the steam bypass to thee condenser as feedwater in the steam generator is converted to steam by heat absorption.
Normally, the capability to return feedwater flow to the steam generators is provided by the main feedwater system.
l The main steam safety valves will be able to relieve to atmosphere the total steam flow if necessary. If main steam safety valves are inoperable, the power level must be reduced, as stated in Technical Specification , 3.4.3, such that the remaining safety valves can accommodate the decay haat. l In the unlikely event of complete loss of of f-site electrical power to the station, decay heat removal is by either the steam-driven emergency feedwater pump, or two half-sized motor-driven pumps. Steam discharge is to the atmosphere via the main steam safety valves and controlled at-mospheric relief valves, and in the case of the turbine driven pump, from the turbine exhaust.(1)
Both motor-driven pumps are required initially to remove decay heat with one eventually suf ficing. The minimum amount of water in the condensate storage tanks, contained in Technical Specification 3.4.2, will allow cooldown to 250*F with steam being discharged to the atmosphere. Af ter cooling to 250*F, the decay heat removal system is used to achieve further cooling.
An unlimited emergency feedwater supply is availnble from the river via either of the two motor-driven reactor building emergency cooling water pumps for an indefinite eriod of time.
l 3-26 Am.19 l
The requirements of Technical Specification 3.4.1 assure that before the reactor is heated to above 250*F, adequate auxiliary feedwater capacity is available. One turbine driven pump full capacity (920 gpm) and the two half-capacity motor-driven pumps (460 gpm, each) are specified. However, only one half-capacity motor-driven pump is necessary to supply auxiliary feedwater flow to the steam generators in the onset of a small break loss-of-coolant accident (Reference 2).
The requirements of Technical Specification 3.4.1 assure that at least
. 920 gpm is available at all times to both steam generators giving re-dundant capacity except for a limited time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to allow for com-ponent maintenance. Further degradation of the emergency feedwater system requires the reactor to be subcritical within 1 heur.
The feedwater line break accident performed for TM1-2 (Reference 3) shows satisfaction of core thermal power limits and reactor coolant syste, l pressure limits assuming full auxiliary feedwater flow within 40 set,nds.
The Technical Specification 3.4.1 provides assurance that this flow will be
- l. available with automatic initiation following loss of both main feedwater pumps.
1
! REFERENCES l
,1) FSAR, Section 10.2.1.3 l
(2) " Evaluation of Transient Behavior and Small Reactor Coolant System Breaks in the 177 Fuel Assembly Plant," Volume I and II, Babcock and Wilcox, May 7, 1979.
(3) Three Mile Island Nuclear Station - Unit 2, Final Safety Analysis Report, USNRC Docket No. 50-320.
l l I l l 3-26a Am.19 1
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.i TABLE 3.5-1 Continued INSTRUMENTS OPERATING CONDITIONS Functional Unit (A) (B) (C) 111nimum 111nimum
~,
Operable Degree of Operator Action if Conditions of Column A Channels Redundancy cannot be met (a)
- 1. Emergency Feedwater System Loss of Feedwater or RCP 2 1 COLD SHUTDOWN Pump (all four) - Start tiotor and Turbine Pumps 4
H
\
- (a) If minimum conditions are not met within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, the unit shall then be placed in a cold shutdcwn conditions. ,
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3.5.5 ACCIDENT MONITORING INSTRUMENTATION Applicability Applies to the operability requirements for the instruments ident-ified in Table 3.5-2 during START UP and POWER OPERATION.
Objective To assure operability of key instrumentation i.seful in diagnosing situations which could lead to inadequate core cooling.
Sp3cification 3.5.5.1 The minimum number of channels or alternate indications, identified for the instruments in Table 3.5-2, shall be OPERABLE. With the number of instrume'ntation channels less than the minimum required and the alternate indication inoperable, restore the inoperable channel (s) to OPERABLE status within seven (7) days or be in at least HOT SHUTDOWN within the next twelve (12) hours. Prior to start-up following a COLD SHUTDOWN, the minimum number of channels shown in Table 3.5-2 shall be OPERABLE.
Bases The Saturation Margin Meter provides a quick and reliable means for determination of saturation temperature and saturation pressure margins. The hand calculation of saturation pressure and saturation temperature margins can be easily and quickly performed since it only requires knowledge of recirculation loop temperatures and system pressure, and the use of steam tables; accordingly, hand calculation provides a suitable alternate indication for the Sat-uration Margin Indicator.
Discharge flow from the two (2) pressurizer code safety valves and the Electromatic relief valve is measured by differential pressure transmitters connected across elbow taps downstream of each valve.
A delta pressure indication from each pressure transmitter is available in the control room to indicate safety or relief valve line flow. An alarm is also provided in the control room to indi-cate that discharge f rom a pressurizer safety or relief valve is occuring. In addition, an acoust;s monitor is provided to detect flow in the relief valve discharge line. An alarm and a flow indication is provided in the control room for the acoustic monitor.
In the event that a delta-pressure monitor or the acoustic monitor becomes inoperable, access to the containment would most likely be required; however, a reactor shutdown to allow containment access for this repair is not justifiable due to the existence of alter-nate means of detecting and monitoring safety or relief valve dis-charge flow. The alternate means of monitoring safety / relief valve discharge flow consists of a thermo-couple in each discharge line.
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The Emergency Feedwater System is provided with two channels of flow instrumentation on each of the two discharge lines. Local flow in-dication is also available for the emergency feedwater system.
Although the pressurizer has multiple level indications, the separate indications are selectable via a switch for display on a single dis-play. Thus, only a single pressurizer level channel is available from the control room. Pressurizer level, however, can also be determined via the remote shutdown panel and the computer log.
Although the instruments identified in Table 3.5-2 are significant in diagnosing situations which could lead to inadequate core cooling, loss of any one of the instruments in Table 3.5-2 would not prevent continued, safe, reactor operation provided thac the alternate indi-cation is operable. Loss of an instrument and its alternate indication would degrade the reactor operators diagnostic capability and, thus, should be restored within seven (7) days.
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l TABLE 3.5-2 ACCIDENT MONITORING INSTM'!!ENTS
!IIN1!!Utt ALTERNATE-F'INCTION ,INSTRU!ENTS NUl!BER OF CHANNELS NU:tBER OF CHANNELS ,EDICATION 1 Saturation !!argin !!eter 1 1
'2 Safety / Relief Valve A P 1 per discharge line 1 per discharge.line Thermo couple /l per discharge line 3 Relief Valve Acoustic lionitor 1 1. Thermo couple /
discharge line 3
~4 Emergency Feedwater Flow 2 per discharge line 1 per discharge line Local flow indication 5 Pressurizer Level 1 1 Pressurizer Level (remote anutdown 4
pannel) or Computer '
Log O If the Saturation Itargin Iteter is inoperable, the operability requirement for the Saturation !!argin !!eter .is satisfied by implementing the procedure for hand calculation of saturation pressure and temperature margias.
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4.9 EMERCENCY FEEDWATER SYSTEM PERIODIC TESTING Applicability Applies to the perodic testing of the turbine driven and two motor-driven emergency feedwater pumps, assocaited actuation signals, and valves.
Objective To verify that the auxiliary feedwater system is capable of performing its design function.
Specification 4.9.1 TEST 4.9.1.1 Whenever the Reactor Coolant System temperature is greater than 2500F, the emergency feedwater pumps shall be tested in the recirculation mode in accordance with the requirements and acceptanct criteria of ASME Section XI Article IWP-3000. The test frequency shall be at least every 31 days +7 days of plant operation at Reactor Coolant Temperature above 250oF.
4.9.1.2 During testing of the emergency feedwater system when the reactor 1.- in STARTUP or POWER OPERATION, if one steam gen-erator flow path is made inoperable, a dedicated qualified in-dividual who is in communication with the control room shall be continuously stationed at the EFW manual valves. On in-struction from the control room, the individual shall realign the valves from the test mode to their operational alignment.
4.9.1.3 At least once per 31 days each valve listed in Table 4.9-1 shall be verified to be in the status specified in Table 4.9-1.
4.9.1.4 At least once per 31 days, during shutdown, verify that:
(a) each emergency feedwater pump starting logic actuates upon receipt of an auxiliary feedwater test signal, and (b) valves in the emergency feedwater flow paths
- actuate to their correct position on an emergency feedwater test signal and that the manual control valve station functions properly.
4.9.1.5 On a quarterly basis, the valves which are a part of the emer-gency feed system discharge (EFV-30A and 30B) will be checked for proper operation by cyt: ling the valve over its full stroke.
4.9.1.6 Prior to start-up, following a cold shutdown of longer than 30 ,
days' duration, conduct a test to demonstrate that the motor driven emergency feed pumps can pump water from the CST to the steam generators.
- For the purpose of this requirement, an OPERABLE flow shall mean an unobstructed path from the water source to the pump and from the pump to a steam generator.
4-52 Am.19
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4.9.2 ACCEPTANCE CRITERIA These tests shall be considered satisfactory if control board indication and visual observation of the equipment demonstrates that all components have operated properly.
Bases The 31 day testing frequency will be suf ficient to verify that the turbine driven and two motor-driven emergency feedwater pumps are operable and that the associated valves are in the correct alignment. ASME Section XI Article IWP-3000 specifies requirements and acceptance standards for the testing of nuclear safety related pumps. Compliance with the normal acceptance criteria of IWP-3000 assures that the emergency feedwater pumps are operating as expected. The test frequency of 31 days (nominal) has been demonstrated by the B&W Emergen'cy Feedwater Reliability Study to assure an appropriate level of reliability. If testing under: Article IWP-3000 indicates that the flow and/or pump head for a particular pump is not within the normal acceptance standard, Article IWP-3000 requires that an evaluation of the pump performance shall be completed within 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> or the pump declared inoperable. For the. case of the emergency feedwater system, the system shall be considered operable if under the worst case single pump failure, a minimum of 500 gpm of emergency feedwater can be delivered when steam generator pressure is 1050 psig and one steam generation is isolated. A flow of 500 gpm, at 1050 psig head, ensures that suf ficient emergency feedwater, demonstrated to be acceptable for plant cooling requirements under transient and accident conditions, can be delivered to either steam generator flow path.' The 18 month surveillance requirements ensure that the overall emergency feedwater system functional capability is maintained comparable to the original design standards.
4-52a Au.19 eg - e. e'_
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Table 4.9-1 Status of EFW Valves Valve No. Status C0-V-10A Open CD-V-10B Open i
EF-V-1A Open EF-V-1B Open EF-V-2A Open EF-V-2B Open ItSV-2A Open h3V-2B Open EF-V4 Locked Closed
- EF-V5 Locked Closed
- EF-V6 Locked Open*
EF-V10A Locked Open*
EF-V10B Iocked Open*
EF-V-16A Locked Open*
1 EF-V-16B Locked Open*
EF-V-20A Locked Open*
!, EF-V-20B Locked Open*
EF-V-22 Locked Open* ,
- Locked Valves, if Maintained in a statt.s other than indicated, shall be under the administrative control of a dedicated qual-ified, individual who is in communication with the control room.
The individual shall be continuously stationed at the EFW ranual valves and, on instr"a' ion from the control room, shall realign the valves from the t.st mode to their operational alignment.
Am.19
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TABLE 4.1-2 MIN 111Uti EQUIP!!ENT TEST FREQUENCY Item Test Frequency
- 1. Control Rods Rod drop times of all Each refueling shutdown full length rods
- 2. Control Rod Movement of each rod Every two weeks, when reactor 11ovement is critical
- 3. Preasurizer Safety Setpoint* S0% each refueling period Valves
- 4. Mtin Steam Safety Setpoint 25% each refueling period Valves
- 5. Refueling System Functional Start of each refueling period Interlocks 6.11ain Steam (See Section 4.8)
Isolation Valves
- 7. Reactor Coolant Evaluate Daily, when reactor coolant System Leakage system temperature is greater than 525'F
- 9. Spent Fuel Cooling Functional Each refueling period prior to System fuel handling
- 10. Intake Pump House (a) Silt Accumulation- Each refueling period Floor Visual inspection of (Elevation 262 Ft. Intake Pump House Floor 6 in.) (b) Silt Accumulation Quarterly Measurement of Pump
- House Flow j l
- 11. Pressurizer PROV Functional ** Quarterly )
Block Valve 1 1
- 12. Back-up instrument Functional Each refueling period air supply system
- The setupoint of the pressurizer code safety valves shall be in accordance with ASME Boiler and Pressurizer Vessel Code,Section III, Article 9, Winter, 1968.
- Function shall be demonstrated by operating the valve through one complete ,
cycle of full travel. l
.- .j i
TAQ.E 6.1-1 (Continued)
CMA%EL DESCRIPTIO4 CNECK g CALIEPATE R DtARK S
- 33. Steam Generator Water Level W NA L
- 39. Turbine overspe'ed Trip NA R NA
- 40. Sodium Thiosulf ate Tank Level NA NA R Indicator
- 41. Sodium Hydroxide Tank Level NA NA R Indicator
- 42. Diesel Generator Protective NA NA R Relaying
- 44. Reactor Coolant Pressure S(!) M R (1) When reactor coolant system is DH Valve Interlock B1 stable pressurized above 300 psig or Taves is greater than 2G3*F.
- 45. Loss of teedwater Trip S(1) M(1) R (1) Whenreact$r>10% power.
- 46. Turbine Trip / Reactor Trip 5(1) M(1) R (1) When reactor > 20% power.
47.a Pressuriser Code Safety Valve and S(1) R (I) When TAVG is grerter than 200*F.
Electromatic Relief Valve delta P/ flow 47b. Pressuriser Electromatic Relief NA M R (1) when TAVG is greater than 200*F.
valve - Acoustic / Flow
- 48. PORY Setpoint NA M(1) R (1) When T AVG is greater than 200*F.
Excluding valve operation.
- 49. Saturation Margin Meter S(1) M(1) R(1) (1) When TAVG is greater than 200*F.
- 50. Emergency Feecwater Flow NA M(1) R (1) When TAVG is greater than 200*F.
Instrumentation
- 51. Emergency Feedwater Initiation
S - Each Shif t T/W - Tulce per week R - Each Refueling Period D - Daily B/M - Every 2 months NA - Not Applicable W - Weekly Q - Quarterly B/W - Every two weeks
!! - Monthly P - Prior to each startup if not done previous week f
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4.5 EMERGENCY Le ADING SEOUENCE AND POWER TRANSFER, EMERGENCY CORE COOLING SYSTEM AND REACTOR BUILDING COOLING SYSTEM PERIODIC TESTING 4.5.1 EMERCENCY LOADING SEQUENCE Applicability Applies to periodic testing requirements for safety actuation systems.
Objective To verify that the Emergency loading sequence and automatic power trans-fer is operable.
Specifications 4.5.1.1 Sequence and i>ower Transfer Test
- a. During each refueling interval, a test shall be conducted to demon-strate that the emergency loading sequence and power transfer is operable.
b The test will be considered satisfactory if the following pumps and fans have been successfully started and the following valves have completed their travel on preferred power and transferred to the emergency power as evidenced by the control board component operating lights, and either the station computer or pressure /
flow indication.
- M. U. Pump
- D. H. Pump and D. H. Injection Valves and D. L Supply Valves
- R. B. Cooling Pump
- R. B. Ventilators
- D. H. Closed Cycle Cooling Pump
- N. S. Closed Cycle Cooling Pump
- D. H. River Cooling Ptrap
- N. S. River Cooling Pump
- D. H. and N. S. Pump Area Cooling Fan
- Scrren House Area Cooling Fan
- Spray Pump. (Initiated in coincidence with a 2 out of 3 R. B. 30 psi Pressure Test Signal.)
, - Motor Driven Emergency Feedwater Pump.
4.5.1.2 Sequence Test
- c. At intervals not to exceed 3 months, a test shall be conducted to demonstrate that the emergency loading sequence is operable, this test shall be performed on either preferred power or emer-gency power.
- b. The test will be considered satisfactory if the pumps and fans listed in 4.5 lb have been successfully 2 tarted and the valves listed in 4.5.1 lb have completed their travel as evidenced by the control board component operating lights, and either
( the station computer or pressure / flow indication.
4-39 m e no-a
. . .. . .. - _ -. - - = .
Bases The Emergency loading sequence and automatic power transfer controls the operation of the pumps associated with the emergency core cooling system and Reactor Building cooling system. A successful test of the emergency loading sequence and automatic power transfer is a prerequisite to any system '
test of the emergency core cooling system or reactor building cooling system.
1 References (1) FSAR Section 7 (2) FSAR Section 1.4 i
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4-40
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Draft Technical Specification Corresponding to Section 11.2.9 As Revised By Amendment 21 4
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3.5.7 Reactor Coolent Pump Trip Applicability Applies to the operational status of the reactor coolant pump trip.
Objective To specify requirements for operability of the reactor coolant pump trip.
Specification 3.5.6.1 The reactor coolant pump trip, shall be OPERABLE during reactor STARTUP and POWER OPERATION. With the reactor coolant pump trip inoperable, place the reactor in hot shut-down within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
Bases
. Analysis has shown that, for a certain range of small primary breaks, inacceptable clad temperatures may result if the reactor coolant pumps are not tripped at a time when the Reactor Coolant System void fraction has achieved a high level. To prevent these detrimental consequences, the reactor coolant pump trip will promptly trip the reactor coolant pumps when system conditions indicate that a small break in this range may be in progress. The system actuates on coincident High Pressure Injection (1600 psig) and loss of saturation margin as indicated by the Saturation Margin
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QUESTION H? 16. Your response to Question 33 is not complete. Provide or reference a schedule for submitting the necessary analyses, operator guide-lines and revised emergency procedures required by Bulletin 05C.
In addition, demonstrate that installation of a safety grade automatic pump trip is not practicable prior to restart.
RESPONSE
The Loss of Reactor Coolant Emergency includes instructions to trip all Reactor Coolant Pumps upon receipt of automatic actuation of High Pressure Injection (1600 psig). Guidance is being incorporated regarding restarting of the Reactor Coolant Pumps. These procedures are based on the Small Break Operating Guideli,nes dated November, 1979 and supporting analysis.
The analysis was submitted titled " Analysis Summary In Support of Inadequate Core Cooling Guidelines f or a Loss of RCS Inventory", document No. 86-1105508-
- 00. This document was sent to the NRC by Babcock and Wilcox and is intended
- to this requirement from NU REG 0578.
j The modification to automatically trip the RCP's has only recently been initiated therefore the material requirements are not known. Without l these details it is not possible to determine when the earliest possible date for installation might be.
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f QUESTION I('
- 52. Provide detailed design features of Fuel llandling Building environmental barrier.
RESPONSE
The following describes the TMI 1 and 2 Fuel Handling and Auxiliary Building l supply and exhaust systems. The potential leakage paths between buildings
- or systems and the modifications designed to ir slate the unit I refueling floor from tha unit 1 Auxiliary Building and from the Control Access Building are discussed. These modifications include ventilation system changes and certain bu*.1 ding layout changes. The major ventilation considerations are as follows:
l A. The supply and exhaust systems for unit 1 are separate from those of unit 2. However, the unit I refueling floor air communicates directly with the unit 2 refueling floor air.
B. The supply systems of the Auxiliary and Fuel Handling Building (FHB)
I of TMI-1 are separate from each other. Both systems supply air to the building areas through duct distribution systems using outside air drawn from the air intake tunnel. Both supply fans are located in a common tunnel in close proximity to each other.
None of the supply ducts of the Auxiliary Building are located in the y; ;;
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FilB area. Thus, there is no potential for air leakage between Auxili-ary and FH Building through outlets or through leaks in the Auxiliary Building supply duct system.
The supply duct main for the FHB serves the general area at elevation 305'-0" - the Spent Fuel Cooling Pump area at elevation 305'-0" and then serves thu refueling floor at elevation 348'-0". The FHB refueling floor could communicate with the Auxiliary Building through the supply duct system because the general area and the Spent Fuel Cooling Pump area are open to the Auxiliary Building through an open doorway at elevation 305'-0".
C. The exhaust systems for Auxiliary and FH buildings of TMI-1 are separate in the specific buildings they serve but the FHB exhaust main becomes i common with the auxiliary building exhaust main af ter leaving the FHB.
The common main is directed to multiple filter plenums and fans that exhaust the mixed air.
The building modifications designed to isolate the TMI-1 refueling floor from the TMI-1 Auxiliary Building and from the Control Access Building include (See Drawing 010-006 attached):
4 A. Two pairs of double doors at elevation 281'-0".
B. An enclosed passage at elevation 305'-0" with two main doors and '
22h one pair of equipment doors.
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PAGE 2 0F RESPONSE TO QUESTION 52 C. A wall at the east end of the truck bay at elevation 305'-0".
3.-S[pjg The wall should be removabic for large equipment access to the 1
W machine shop.
D. A security fence at *be west end of the dock adjacent to the new enclosure at elevation 305'-0".
E. The stair v_r between elevations 299'-2k" & 211'-0" will be modified.
F. Pressure tight doors for the new fuel storage room at elevation 329'-0".
G. Pressure tight doors for the stair tower at elevation 331'-0".
H. An enclosure at elevator entrance with a cressure scaled door.
I. An enclosure for the ventilation duct chase in the northwest corner of the refueling floor with one pair of pressure tight doors.
The TMI-l ventilation system modifications designed to prevent the leakage paths are given below:
t A. Air leakage from the FHB through the supply duct, to the de-energized FHB supply fan.to the Auxiliary Building are stopped of., ,
by adding a leak tight damper in the discharge of the FHB supply
. .: .4 fan.
B. Air leakage from the FHB through the supply duct, and the 48" x 24" branch duct, to the FHB general area at elevation 305'-0", and then to the Auxiliary Building will be stopped by blanking of f this duct and providing an equivalent opening in the FHB supply duct. This would discharge the required 8000 cfm on the south side of the i
elevator shaft and this air would rise through the open stairwell to be exhausted at the refueling floor.
C. Air leakage following the same path as item B above but through a 12 x 12 branch duct in the spent fuel pool cooler area at elevation 305'-0" will be stopped by blanking 'off this duct. The 1000 cfm exhaust required by this area will then be supplied from the Auxili-ary Building through the wall opening at elevation 305'-0".
D. Air leakage from the Auxiliary Building to the fuel building will be stopped by adding a leak tight damper in the exhaust duct main as it leaves the FHB but upstream of the connection with the Auxiliary Building main (60 x 50, elev. 348) .
E. The leak tight dampers added to the FHB supply and exhaust ducts and the suppiy fan will function as follows:
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PAGE 3 0F RESPONSE TO QUESTION 52 D;w 1. Automatically close on detection of differential pressure y;T[ fy* in the FHB with respect to the Auxiliary Building.
- 2. Automatically close on detection of high radiation on the refueling floor or in the FHB return air duct.
- 3. Open or close on manual command from control stations in the FHB and in the Control Room. The manual station would "over-ride" the above automatic signals.
The post modification system response following various assumed accidents and events is given below:
ACCIDENT / EVENT RESPONSE l
- 1. Differential A differential between these two areas could develop pressure develops as a result of the loss of either the fuel building between the Auxili- or the auxiliary building supply fans or failure-in ary and FHB. the closed position of the dampers in the exhaust mains from either of the buildings. Leakage between the buildings in either direction would be stopped by adding the building and the ventilation system modifications.
7,
- 2. High radiation The ventilation system modification would automatically in the FHB or in isolate the TMI-1 FHB from the Auxiliary Building.
l g(( 3.
l the FHB exhaust Supply air flow and exhaust air dampers would initially l duct. close and the FHB supply fan would stop. However, j
subsequently, these dampers could be opened and air flow i through the fuel building could be re-established at l the discretion of the plant operator. Also, the operator I could limit the exhaust flow by opening only_the exhaust damper. Operation of the Auxiliary Building supply and exhaust system would continue during the isolation phase.
- 3. High radiation High radiation would ba detected and alarmed locally and in TMI-l Auxiliary in the control room by area monitors and by a monitor in-Building, the exhaust duct from this area. The supply and exhaust ;
system could continue operation to reduce the radiation level. If necessary, the refueling floor could be manu- ,
elly isolated.
- 4. High radiation The same response as noted in item 3 above would occur. l in TM1-2 refueling i
' fl oor .
- 3. ,.
- rs.
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i l Am. 21
. . . . ... . . _ _ .._. .i
SUPPLEMEN'l 1, PART 2 RESPONSE TO QUESTION 52, PAGE 4 l In addition to the modifications described above, a ventilation system to mitigate the consequences of a postulated fuel handling accident in the FHB will be installed. This new system will meet the requirements of Regulatory
'cuide 1.52, Revision 2. This system, and intermediate modifications to the Auxiliary and Fuel Handling Building Ventilation System, are described be-low.
The Auxiliary and Fuel Handling Building Ventilation System will undergo ex-tensive modifications which will be undertaken in two phases as described
- below. ,
. Phase 1 Prior to restart, the TMI-l ventilation system will have been modified as j shown in Attachment 2. The following equipment will have been added:
- 1. Damper U with interconnecting ductwork.
- 2. Damper T In the event that contamination (radioactivity) is sensed in the ductwork, Dampers U and T will close, Fan F will trip, and ventilation will be via filter trains M and N. Dampers U and T are seismic Category 1, meet AMSIN-i 509 Construction Classification B, Leakage Classification 11, and are de-signed to fail closed.
Phase 2 Prior to the next refueling, the following additional modifications will be i made, as shown in Attachment 3:
- 1. Filter trains Q and R will be added. From the intake side of the filter trains, the composition of the train will consist of a prefilter, an electric heater, a HEPA filter, a charcoal filter, and a final HEPA filter. The design of filter trains Q and R will meet the requirements of NRC's Regulatory Guide 1.52, " Design, Testing and Maintenance Criteria for Post Accident Engineered-Safety Feature Atmospheric Cleanup System Air Filtration and Absorption Units of Light Water-Cooled Nuclear Power Plants."
- 2. Dampers S and V will be added. l
- 3. Fans G and H will be installed together with all connecting ductwork and l dampers. i l
i i
- 4. Dampers U and T will be blocked open and will no longer respond to closure
, signals.
1 l During normal operation, filter trains M and N will be utilized together with
. fans A, C, E, and F. .During refueling. operation, in addition to the equip-1 ment normally operating, filter trains Q'and fan G would also operate.
Am. 21 i
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SUPPLEMENT 1, PART 2 J
RESPONSE TO QUESTION 52, PAGE 5 i
l If contamination (radioactivity) is sensed in the ductwork, dampers S and V-
- will close and fan F will trip. This action will serve to separate the Auxiliary Building and Fuel liandling Building Ventilation systems and
! assure that all air leakage will be int a the fuel handling building.
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SUPPLEMENT 1, PART 2 ATTACIB1ENT 2 TO QUESTIG" 52
- 1. Fans: A,B,C,D,E,F - Existing
- 2. Filters: M,N,0,P - Existing
- 3. Ducts: Solid Line - Existing Aux. Bldg. Fuel 11. B1dg. Control Bldg.
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- 4. Dampers: T and U - Upgraded -i
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SUPPLEMEMT 1, PART 2 ATTAClIMENT 3 TO QUESTION 52
- 1. Fans: A,B,C,D,E,F . Existing G,Il - New ESF Filter System Aux. Bldg. Fuel 11. Bldg. Control Bldg.
- 2. Filters: M,N,0.P - Existing Q,R - New ESF Filter System g
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SUPPLEMENT 1, PART 2 QUESTION
- 95. Paragraph 2.1.3.b of NUREG-0578 requires a description of further measures and supporting analyses that will yield more direct in-l dication of low reactor coolant level and inadequate core cooling such as reactor vessel water level instrumentation. Scction 2.1.1.6 ;
of the Restart Report does not address further measures (to be im-plemented by January 1,1981), nor does it address the question of reactor vessel water level instrumentation. ProviIa a conceptual description of what additional measures will P caken to detect inadequate core cooling. Provide an implementation schedule for these changes.
RESPONSE
I l
Babcock & Wilcox has evaluated the need fo; further measures beyond those described in Section 2.1.1.6 that will yield more direct indication of low reactor coolant level and inadequate core cooling. A copy of the B&W report prepared for the B&W owners is attached. We concur with C.e con-clusions of this report tha t the existing instrumentation is adequate to
! recognize and respond to conditions of inadequate core cooling using the inadequate core cooling guidelines attached to our response to question 45 of Supplement 1 part 1. The basis for our position that additional instrumentation in particular, Reactor Vessel Water level is neither nec-essary nor desirable, is that the guidelines are complete and adequate and that no additional operator action is appropriate or can be specified to l respond to inadequate core cooling.
l l
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l Am. 21 i
I SUPPLEMENT 1, PART 2 ATTACILMENT 1 TO QUESTION 95 I
.I 1
1 1
EVALUATION OF INSTRUMENTATION TO DETECT INADEQUATE CORE COOLING PREPARED FOR j 177 OWNERS GROUP 1 l 1
Issued: August 15, 1980 Document No: 86 1170R1R 0n l Contract No/ File sR;_7113 Prepared By /f Reviewed By #f9M Mr EJ D Released By #)hne))W h g / .
4.
Babcock & Wilcox Nuclear Power Generation Division P. O. Box 1260 Lynchburg, Virginia
'I
'l .
I TABLE OF CONTENTS PAGE 1
! 1.0 BACKGROUNO 2
2.0 DEFINITION Ol INADEQUATE CORE COOLING 1 3
- 3.0 OPERATOR GUIDELINES FOR INADEQUATE CORE C0QLING 5
4.0 DISCUSSION OF METHODS TO DETECT INADEQUATE CORE COOLING 5
1 4.1 Core Outlet Thermocouples 6
j 4.2 Axial Incore Thermocouples 6
4.3 Ultrasonic Techniques 7
4.4 Neutron and Gama Beams 3
4.5 Differential Pressure Transmitters 10
5.0 CONCLUSION
S A-1 APPENDIX A - NUREG-0578 POSITION ON INSTRUMENTATION A-2 FOR DETECTION OF INADEQUATE CORE COOLING AND CLARIFICATION FROM H. R. DENTON'S
( LETTER OF OCTOBER 30, 1979 A
TABLE 4.0 PROPOSED INADEQUATE CORE COOLING INDICATIONS COMPARED TO ESTABLISHED CRITERA FIGURE 3.1 CORE EXIT THERM 0 COUPLE TEMPERATURE FOR j INADEQUATE CORE COOLING FIG'JRE 4.1 LAYOUT OF CORE THERMOCOUPLE FIGURE 4.1 LOCATION OF THERM 0 COUPLE 1
1 1
-j-1 1
e
I 1.0 SACKGROUi10 The major concerns raised in the af termath of the TMI-2 accident were identified in the "lMI-2 LESSONS LEARNED TASK FORCE STATUS REPORT, NUREG-0578". Section 2.1.3.b of that report addressed additional instr mentation which could assist in the detection of inadequate core cooling. The NRC position on additional instrtrnentation was that j " licensees shall provide a description of any additional instrumentation or controls (primary or backup) proposed for the plant .... giving an unambiguous, easy-to-interpret indication of inadequate core cooling. ....
j Subsequently, the NRC's position was clarified and amplified in Enclosure 1 to H. R. Denton's letter of October 30, 1979 to all operating nuclear puwer plants entitled " Discussion of Lessons Learned Short Term Requirements". This letter addressed the following requirements for any additional instrumentation proposed. (The complete clarification is reproduced in Appendix A.)
- a. Design of new instrumentation should provide an unambiguous indication of inadequate core cooling.
- b. The indication should have the following properties:
(1)
It must indicate the existence of inadequate core cooling caused by various phenomena.
}:' (c) It must not erroneously indicate core cooling because of the presence of an unrelated phenomena.
- c. The indication must give advanced warning of the approach of inadequate core cooling.
j
- d. The indication must cover the full range from normal operation to complete core uncovering.
l I
l l
1 H. R. Denton's letter of October 30, 1979 clarified the requirements that 0
any investigation of additional instrumentation include an evaluation of reactor water level indication.
In response to ilVREG-0578 B&W has developed operator guidelines for action to recover from a condition of inadequate core cooling using existing j nstrumentation (References 1-5).
The evaluation provided in the following sections reviews the adequacy of existing and proposed instrumentation to indicate inadeauate core cooling (ICC). To perform this review, it is important to understand when ICC actually occurs, what l operator actions occur prior to ICC, and the guidelines followed once ICC 3
has occured. The next two sections describe ICC and the actions taken 1 These sections are then followed by a before and after ICC is indicated.
comparison of existing and proposed equipment for Indicating ICC which l j
conclude with a section describing why the existing installed instrunentation provides the best indication.
2.0 OEFIrllTI0tt 0F ItlADEOUATE CORE COOLING lJ in a depressurization event, the reactor coolant system (RCS) must first reach saturation conditions before there is any danger of inadequate core cooling. Subsequently if the RCS inventory is reduced and uncovery of the core begins, temperatures in the uncovered region will increase causing
} superheating. It is important to note in this discussion that inadequate core cooling does not begin until reactor vessel (RV) water inventory f alls below the top of the core thus r c.sulting in an increasing fuel clad temperature.
I 1 2-1 3
3.0 OPERATING PHILOSOPHY AND GUIDELINES FOR INADE0VATE CORE C00LlNG The goals of the operator prior to ICC are different than those once ICC j has occured. Prior to an indication that ICC has occured, the operator is le goal taking actions which will stabilize pressure and refill the RCS.
is to re-establish the subcooling margin at the hign pressure condition or cooldown and depressurize to low pressure injection plant conditions.
Indication that ICC has occured changes the operator's guidance because The the goal of refilling at the high pressure cannot be attained.
operator at this point is instructed to partially depressurize using the PORV to increase RC5 inventory addition rate. Note: If this f ails the operator is instructed to further depressurize and establish low pressure injection (LPI). These last two steps are based on conscious decisions that recovery at the higher pressure is not possible and that depressurization will cause more immediate core voiding, but in the longer term will result in improved core cooling by increased RCS inventory.
Based on this logic it is important that the indication not be ambiguous and not occur prematurely. It is important to provide as much time as f possible for recovery a't the higher pressure which leads to the preferred mode of operation.
Synptoms of an overcooling transient are similar to the small break loss of coolant transient up to the point of inadequate core cooling. At this y
point, if the operator has taken actions for inadequate core cooling when
& in fact overcooling exists, an unnecessary serious transient would result.
Thus, the operator must not proceed with the inadequate core cooling actions until inadequate core cooling is confirmed.
I .
i The following sections describe the actual operator actions taken prior to I ICC and those once ICC is indicated.
3.1 Operator Actions During Approach to ICC g
Operator actiorq during the approach to an inadequate core cooling condition are sumar zed as follows:
i
- 1. Initiate HPI
- 2. Maintain OTSG level
- 3. Trip RC pumps if ESFAS initiated by low RC pressure 2 4. Monitor incore thermocouple temperatures to determine if inadequate core cooling exists.
Thase actions are verified when saturation conditions exist. No further actions are taken until thermocouple temperatures reach a predetermined temperature t,om Small Break Operating Guidelines (see Figure 3.1-1, Curve 1). This indicates that superheating is ocurring, that fuel clad
. temperature has increased above saturaction and that inadequate core cooling exists.
3.2 Operator Actions Once ICC is Indicated j Once inadequate core e'; ling is indicated the operator is instructed to take the following actions:
h 3. Open the PORV to maintain RCS pressure within 50 psi of 0TSG pressure
- 4. Continue cooldown by maintaining 100*F/hr decrease in secondary saturation temperature to achieve 150 psig RCS pressure 3
5 .
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FIGURE 3.1-1 i "
CORE EXIT THER.0C00PLE TE.,1PERATURE FOR INADEQUATE CCRE COOLING
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t t
i 1200 -
3 t 1100 -
" CURVE #2 1
3" l TCLAG LESS THAN 1500'F j 1000 -
f I
o E 900 -
E
>( 1
-e CURVE #1 800 5 / 1 o - T CLAD LESS THAN 1400 F g
700 -
II '
600 -
500 -
l 3 ' '
400 2200 3 200 600 1000 1400 1800 Pressure, psia
1 These actions are taker to reduce RC pressure thus increasing HPI flow and RCS inventory addition rate. If thermocouple temperature continues to rise above a higher predetermined temperature which indicates a f
significant increase in fuel clad temperature (see Figure 3.1-1, Curve 2) the operator should:
- 1. Start all RCPs
- 2. Depressurize OTSG(s) to atmospheric pressure
j 4.1 DISCUSSION OF METHODS TO DETECT INADEQUATE CORE COOLING The following methods of indicating core cooling were examined in this evaluation:
1 1. Existing core thermocouples
- 2. Additional axial core thermocouples
- 3. Ultrasonic RV level indication
- 4. Neutron or gamma beam RV level indication j
- 5. Differential pressure (dp) transmitters for RV level indication The capabilities and evaluations associated with each type of indication are discussed below. Table 4.0-1 provides a summary of the methods and
.- r their capabilities.
4.1 Core Outlet Thermocouples The existing core thermocouple instruments indicate inadequate core
} cooling when interpreted using the operator guidelines of References 1, 2 and 3. The location of these thermocouples provides indication of sharply increased temperatures at the top of the core when the top of the core reaches conditions of inadequate cooling. The locations of the thermocouples in the core and fuel assembly are shown on figures 4.1-1 and 4.1-2.
! Figure 4.1-1 Layout of Core Thermocouoles r INLET .
INLET INTERMEDIATE
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RANGE DETECTOR SOURCE RANGE 9.8 OETECTOR %.
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.: . 2 Axial Incere Thermocouples Additional thermocouples installed axially in the incore instrument guide tube will provide an indication of the extent of inadequate core cooling; but, an indication that the middle of the core is inadequately cooled will not elicit any further operator action over and above the actions taken W when the top of the core indicates inadequate core cooling. There would be no change in operator guidance even if this thermocouple information were available.
l 4.3 Ultrasonic Techniques Several methods of ultrasonic techniques were considered. These included l
j using existing internal struccures as wave guides, installing an
! externally excited ultrasnnic vibrating rod and installing a head mounted transducer. In simple applications, all of these methods have been i
proven. However, in the reactor vessel the core provides a heat source 3 which changes the density of the fluid. The fluid changes state from a single phase liquid to a two phase fluid, and finally to a single phase vapor. Ultrasonic level measurement techniques are frequently used where there is a sharp density change at the fluid interface. The level created in a reactor vessel as a result of a LOCA will be a frothy, two-phase mixture height rather than a fixed phase interface. The variable density change will not provide an easy-co-interpret indit:ation, and could provide an ambiguous output signal.
ll The ambiguous signal could lead the operator tc believe that the core was inadequately cooled when in fact sufficient heat transfer was causing the As a consequence frothy condition and adequate cooling was in progress.
of the incorrect belief, the operator would take the incorrect actions of depressurizing the RCS.
3 ,
3
I 4.4 Neutron and Gamma Beams Neutron and gamma beams have been used successfully to determine the level of fluid in a vessel. The application of this method to a RV level would be the use of the core as a source and use the existing out of core detectors to monitor the water level through changes in count rate.
Normally, the detector count rate decreases at rates characteristic of the various mechanisms of neutron production that exist following a reactor trip.
I One concept of water level measurement uses the installed source range detectors which respond to a decrease in water density. As water level decreases, the detector output increases. However, if the water level decreases to below the top of the core, the detector output decreases.
The intensity of the neutron beam and thus detector output would be very dependent on previous power history, thus requiring calibration prior to each use of the instrument. This is not reasonable during accident conditions. For this reason, further investigation of this method was terminated. A more detailed discussion of the application of this nuclear radiation method is included in Reference 6.
Another concept of RV water level measurement system has been tested at three reactor 4 sites. The system employs BF3 neutron detectors above and below the reactor vessel. Data was collected and extrapolated to determine neutron count rate between one and six days af ter shutdown 'as a function of water level above the core. The data showed a relatively slow increase in count rate as the water level decreased from a full condition, with a marked increase in count rate when the water level reached five feet above the top of the core. At this level water was still above the hot leg nozzles. This indication system is capable of providing a discrete data point indicating that reactor vessel level is five feet 1
above the core. Evaluation of the remaining data requires interpretation The by the operator to determine the correct reactor vessel water level.
i l
l capability of this instrtment must be evaluated imediately af ter a l shutdown to show its effectiveness in a high background level which would f be the case following a LOCA.
l 4.5 DfferentialPressureTransmitters The use of differential pressure transmitters to measure reactor vessel level was considered. Three level measurement ranges, one across the reactor vessel, a second acro s the hot leg, and one combining these f f
ranges, were evaluated..
The first, a reactor vessel differential pressure (dp) measurement, would require new penetrations in an incore nozzle at the bottom of the reactor An vessel and at the top in a control rod drive mechanism (CRDM) closure.
7J'. instrtment could be installed to provide a differential pressure between the bottom of the core and the top of the reactor vessel, but the diff erential pressure (dp) would be affected by not only the water level head, but also by shock loss, friction loss, and flow acceleration loss.
During forced flow conditions, the shock loss, friction loss, and flow acceleration loss terms' dominate the signal.
.g
-5 Additionally, the magnitude of these terms varies depending on the Due to the changing density, and thus flowrate, of the pumped fluid.
}.-
~
magnitude of these terms, it is not possible to compensate the dp signal to achieve a water level from head only. During stagnant boiloff, the decay heat in the core will cause the level of coolant in the core region to swell to a level greater than that in the downcomer region of the reactor vessel. A dp level measurement would measure the collapsed level in the downcomer region. A swelied level of 12 feet might be indicated by a collapsed level of between 7.4 and 8.625 feet, depending on system The unpredictable peak ps distribution and decay heat let<el pressure.
Although the preclude compensating the dp signal for this error.
the dp cell parameter of interest in this case is the mixture height, would measure a collapsed level which means that under some conditions this signal would be ambiguous, and could lead to premature depressurization of the plant by the operator's misinterpretation o' the indication.
The second method, a hot leg differential pressure measurement would require new penetrations at the bottom of the hot leg and the vent line at the top of the hot leg. This instrument would provide & dp signal and not In this instance, measuring any water level would an actual water level.
During flow conditions, ba a valid indication that the core was covered.
the output 'ignal would be affected by the same effects as the reactor vessel dp signal discussed above.
However, the hot leg dp signal could be temperature compensated.
The fact that the hot leg contains coolant woulu indicate that the core was covered and thus no new operator actions for However, if the operator takes inadequate core cooling would be required.
actions for inadequate core cooling based on only a level in the hot leg then he would be taking incorrect actions fo- some casualties which could also be indicated by a' level in the hot leg; i.e., overcooling, partial j
steam voiding in +he hot leg caused by transients.
The third method, a differential pressure measurement from the bottom of the reactor vessel to the top of the hot leg, would require new penetrations in an incore nozzle at the bottom of the reactor vessel and at the vent.line at the top of the hot leg. This range is a combination of the two previous instrument ranges. It provides an advantage over the hot leg level measurement in that it can measure the entire RV level span, but it would still exhibit the same ambiguity as the reactor vessel dp g
ag?
j l
described earlier. In addition, due to the greatly expanded range the o inaccuracy of the instrunent would be greater, perhaps as large as + 4.0 feet. This measurement would be inaccurate in the hot leg range and would be ambiguous in the reactor vessel range as discussed above.
All three methods of dp level measurement require additional structural penetrations or modifications. Additionally, the operator would not be directed to take action until he confirmed the existence of insfequate core cooling with the core exit thermocouple, thus these additions would j 1 not change any operator guidance.
5.0 CONCLUSION
S As has been discussed, no proposed method of indication of inadequate core cooling would meet all the established criteria. The introduction of i l
j l
ambiguous information provided by some propored systems of inadequate core cooling indication would cause operator confusion. This confusion could i.e., premature lead to incorrect and unsafe actions in some situations; i
depressurization during LO:As, or incorrect actions during overcooling events.
g .
Reliance on existing core exit thermocouples and previously published 4
operator guidelines for interpreting the available information is the bes,t and most., direct method of determining that the inadequate core cooling conditic.i has ocurred. The existing instrunentation in the B&W designed nuclear steam supply system is able to detect inadequate core cooling. The incore thermocouples provide an unambiguous indication of the existence of inadequate core cooling, and will not erroneously indicate inadequate core cooling. The thermocouples provide the most discriminating capability of defining the existence of inadequate core cooling.
3 The basis for this conclusion is further supported by the following:
- The recently installed T sat meter provides a long term indication of the approach to inadequate core cooling since saturation conditions must be achieved prior to the onset of inadequate core cooling. Saturation conditions would be reached a significant time before inadequate core cooling, thus the operator j would be alerted to the condition.
- The existing core thermocouples will indicate the immediate approach, the existence of and termination of 'he t inadequate core cooling condition.
- The instruments will ensure direct, appropriate interpretation of plant conditions by the operator when used in conjunction with previously published operator guidelines.
- Each proposed reactor vessel level measurement system concept f ails to provide any additional aid to the operator for detection of l
inadequate core cooling. Core cooling is directly indicated by ,
Secondly, each of temperature measurement, not level measurement.
3 the level measurement concepts f ails to meet all of the established criteria as outlined in Table 4.0-1.
- The potentially ambiguous information provided by the proposed RV level indication instrument systems could lead to unsafe and
~ incorrdct actions if the operator acted on the level indication.
- No new or additional detectors are required to cover the full range of plant conditions. Adequate core cooling is determined by core heat removal capabilities. It is directly indicated by the reactor coolant system temperature / pressure relationship. The approac" to inadequate core cooling is indicated in sufficient time by the meter to allow the operator to take mitigating action. If T,
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his actions are unsuccessful and inadequate core heat removal conditions exists, sufficien.t indication for the operator is available by means of the core thermocouples. As superheated 1
conditions are reached the thermocouple temperature will increase.
' If additional operator actions of partial depressurization of the RCS are successful and he can regain control of the core heat removal, the thermocouple indication will provide the necessary feedback to tell him that his actions were effective.
It is B&W's technical judgement that the existing plant sensors provide a reliable and accurate method of detecting the approach to and existence of inadequate core cooling for all modes of plant operation.
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TABLE 4.0-1 LEVEL MEASUREMENT METHOD Wi!CH MEET EXISTING CR11EHI A LEVEL MEASUREMENT MflHUDS Neutron or Ex is t ing Additfonal HV CRITERIA -
incore Ultra- Gamna Hut Le9 Sudgooling Incore Level t.P Ranked in Order of PAW T/C Sonics Bean
- SPND Monitor T/C Assigned Priority X X
- 1. Must be direct indica-tion of ICC _ _ _ _ _ . _ _ . . _ _ _ _
- 2. Unambiguous - not 'X X erroneously indicate ICC _
X ,
X X
- 3. Cover full range from normal operation to core uncovery . _ _ .__________ _ _ _ . _ _ . _
X X X
X
- 4. Provide advanced warn-ing of ICC __
- 5. Unanhiguous - indicate X X ICC during pumped high wold fraction and stageiant boiloff _ _ _ _ _ _ _ _ . . . .
X X X
- 6. No major structural X l changes to piant _ _ _ _ _ _ . _ _ _ ______ .
- 7. Unambiguous _ meeets safety grade criteria ** __. _ ________.____.______
- Develop wrk is still required to prove capability of this method innediately af ter shutdown.
- State _of-the-art hardwa-e to meet safety grade criteria is not available to co.aply with the schedule installation date.
1 APPENDXX A l
NUREG-0578 POSITION ON INSTRUMENTATION FOR DETECTION OF INADE00 ATE CORE COOLING AND CLARIFICATION FROM H. R. DENTON' S LETTER OF OCTOBER 30, 1979 1 POSITION Licensees shall provide a description of any additional instrumentation or j
controls (primary or backup) proposed for the plant to supplement those devices cited in the preceding section giving an unambiguous, easy-to-interpret indication of inadequate core cooling. A description of the functional design i A description of the requirements for the system shall also be included.
procedures to be used with the proposed equipment, the analysis used in developing these procedures, and a schedule for installing the equipment shall be provided.
CLARIFICATION l
- 1. Design of. new instrument $ tion should provide an unambiguous indication of inadequate core cooling. This may require new measurements to or a I synthesis of existing measurements which meet safety-grade criteria'.
- 2. The evaluation is to include reactor water level indication.
- 3. A conmitment to provide the necessary analysis and to study advantages of various instruments to monitor water level and core coolng is required in the response to the September 13, 1979 letter.
- 4. The indication of inadequate core cooling must bc unambiguous, in that, it i should have the following properties:
a) it must indicate the existence of inadequate core cooling caused by various phenomena (i.e. , high void fraction pumped flow as well as stagnant boil off).
b)
It must not erroneously indicate inadequate core cooling because of the i presence of an unrelated phenomenon.
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l APPENDIX A (Cont'd)
- 5. The indication must give advanced warning of the approach of inadequate l
Core Cooling.
- 6. The indication must cover the full range from normal operation to Qm complete core uncovering. For example, if water level is chosen as the unambiguous indication, then the range of the instrument (or instrunents) must (.over the full range from normal water level to the bottom of the core.
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REFEREUCES 1
a 1 Sma'l Break Operating Guidelines, B&W Document 69-1106001-00, November 1979
- 2. Small Break Operating Guidelines, B&W Document 69-1106003-00, November 1979
- 3. Small Break Operating Guidelines, B&W Document 69-1106002-00, November 1979 I
j a. Inadequate Core Cooling Decay Heat Removal System Mode of Operation, B&W Document 69-1106921-00, December 1979 3/4/9/187, 5/355, s 5. Inadequate Core Cooling - DNB at Power, Site Instruction 2 l 7/364, 8/172, 11/191, 14/402 dated December 21, 1979 )
j
- 5. Analysis Sunmary in Support of Inadequate Core Cooling Guidelines, 8&W l Document 86-1105508-01, December 5, 1979
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SUPPLDIENT 1, PART 3 PAGE 2 TO QUESTION 11 Operational Characteristics
.l. The setpoint of the< monitor will be equivalent to zero fahrenheit degrees margin, plus allowance for instrument errce coincident with a 1600 psig SFAS signal.
- 2. Response time of the system will be testable from the outside of the R13 thermowell through closure of the output contacts. Response ;
time will be ne greater than the response time of the existing instrument channels.
- 3. Bypass capability should be provided when pressure is below 1650 psig to allow restart of the pumps during startup. The bypass will be automatically removed above this pressure. Note: Depending on system design, this requirement may be met by the existing 1600 psig SFAS bypass.
- 4. Override capability should be provided to allow pump operation during inadequate core cooling conditions.
This major advantage of the revised design is that the use of measured process variables (reactor coolant system temperature and pressure) together with an accurate correlation to determine saturation conditions, and associated subcooling margin, provides for conceptual design simplicity.
The use of RCP power / current correlated to void fraction is more difficult due to the uncertainty associated with local voiding conditions.
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