ML19210E140

Amend 6 to 790912 Restart Rept

ML19210E140
Person / Time
Site:	Three Mile Island
Issue date:	11/28/1979
From:	METROPOLITAN EDISON CO.
To:
Shared Package
ML19210E139	List: ML19210E138 ML19210E140 ML19210E144
References
NUDOCS 7911300536
Download: ML19210E140 (100)

Text

E. The circuit breaker control switch will then be operated to close the ES circuit breaker feed to the transferred pres-surizer heaters when it has been established that bus loading and emergency D/G loading permit doing so.

When offsite power is restored, the reverse procedure will be used to transfer back to the BOP source.

2.1.1.3.1.5 Safety Evaluation The manual transfer scheme design provides double Class IE separation of the ES system from the BOP system - the ES circuit breaker and the removable element. Taking into account the single failure criteria, faults on the BOP system will, at most, cause the loss of one 480 volt ES system. The transfer scheme design also precludes the connection of the " Green" ES system to the " Red" ES system.

2.1.1.3.1.6 Inservice Testing Requirements The emergency diesel generator loading procedure will be rewrit-ten to incorporate this modification. Therefore, these transfer schemes will be tested when the emergency diesel generators are tested.

2.1.1.3.2 The PORV is powered from the RED / YELLOW battery. The motor operated block valve (RC-V3) is powered from Valve Control Center 1C which may be connected to either of the two onsite AC power sources. Normally, it is aligned to operate fram the RED ES bus. Since DC power is required to open the PORV and no power is required to _ lose it, it is preferable to have the PORV and the block val"e supplied from the same power train in order to increase the likelihood that if there is power available to open the PORV, there will also be power available to close the block valve. If, however, the PORV sticks open and the RED AC power source is disabled, Valve Control Center 1C can be transferred to the GREEN bus by means of a switch in the control room, allowing the block valve to ,

be closed.

2.1.1.3.3 Block Valve The present plant design is such that emergency diesel generator power will be supplied to the block valve (RC-V3) upon loss of offsite power. The block valve is powered from the 480 V En-gineered Safeguard Valve Conrol Center IC.

2.1.1.3.4 Pressurizer Leve' Instrumentation The present plant design is such that emergency diesel generator power will be supplied to the pressurizer level instrumentation power supplies (RC-1-LT1, RC-1-LT2, RC-1-LT3) upon loss of offsite power. The pressurizer level instrumentation power supplies are part of the ICS, NNI System, and are powered from the 120 volt ICS, NNI Power Dictribution Panel ATA. That panel is, in turn, powered from the 120 volt Vital Distribution Panel VBA.

\4 2.1-7 Am. 6 79I1300 t

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 following a LOCA, the hydrogen concentration in the containment results from radiolytic decomposition of water, zirconium-water reaction and aluminum reacting with the spray Lolution.

If excessive hydrogen is generated it may combine with oxygen in the containment atmosphere. The capability to mix the 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 l reducing the combustible gas concentrations within the contain-ment to below 4.1 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 bass 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 for 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 previsions shall be installed and available. The second hydrogen recombiners shall be installed af ter an accident within the time period availab!e before they need to be operational.

The system will be designed to meet the criteria of NRC Regula-tory Guide 1.7, the acceptance criteria of SRP 6.2.5, NUREG 0578 (July 1979), 10CFR50 Appendix A-General Design Criteria for containment design and integrity and 10CFR100 Reactor Site Criteria for limits of of fsite releases.

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2.1.1.4.3 System Design The system design provides an installed hydrogen recombiner and a  !

location with installed oiping for a future redundant hydrogen recombiner. The recombraers will be located in the Intermediate Building at floor elevation 305 f t. , in the Leak Rate Test equip-ment area, and their control consoles will be below at elevation 295 ft. 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 diagramatically 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-I. The recombiners will be oowered from Class IE power sources. The inside containment isolation valves will oe 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 system is designed to maintain the hydrogen concentration insile containment below the 4.1 percent by volume, lower flam-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 reaches 3 percent by volume of the total containment.

The recombiner is placed into operation by opening the contain-ment isolation valves af ter having sampled the containment atmosphere and then turning on the recombiner from its remote-local panel. Local monitoring of the control panel is required until the reaction chamber reaches the required temperature for a 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 dropped to an acceptable level, the system is shutdown and the containment isolation valves are closed.

2.1-9 Am. 6 1438 004

2.1.1.4.5 Safety Evaluation The hydrogen recombiner system is designed as a nuclear safety class 2, sesimic class S-I system with class lE power supply.

Containment integrity is normally maintained by double valve isolation (with a valve inside and another outside containment).

While the recombiner is being utilized for post-LOCA 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 blind flange also located outside containment.

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 provide per penetration with each of a redundant pan of valves powered from alternate de power supplies. These isolation valves are designed 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 System power supply.

Off site releases due to leakage and discharge to the atmosphere with the recombiner cooling air will be evaluated to demonstrate these releases to be below the 10CFR100 limits.

2.1.1.4.6 Inservice Testing Requirements No inservice testing is required for the Hydrogen Recombiner System. However, 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 Containment Isolation Modifications 2.1.1.5.1 System Description ihe 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 SFAS, or pfp l ,,

break signal. These signals will assure that radioactive matersal is not transferred out of the reactor building before a 4 psig isolation signal is reached.

2. All lines open tc the containment atmosphere or connected directly to the RCS (either normally or intermitteitly 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-ECCS 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 k 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 Interme-diate Closed Cooling (ICC) water, valves IC-V2, 3, 4, &

6, should be isolated in accordance with the logic of Figure 2.2.

c. Normal fan cooler coils will be isolated by 4 psig reactor building pressure signal and 1600 psig SFAS. l Emergency cooling will be initiated by the 1500 psig signal.

In order to utilize specific systems which have been auto-matically isolated, an isolation signal override capability is required. The isolation signal override shall be either on a total basis 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 reopt.n the isolation valves. Operator action to reopen selee'.' containment isolation valves will be required after the signal override has been accomplished. See Table 2.3-1 for a listing of penetrations and the required isolation override require-ments.

2.1-11 14 38 00 6 im. 6

The radiation monitoring shall be accomplished at the loca-tions indicated on Table 2.1-3.

A common High 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 attachea Table 2.1-2. This table identifies the isolation signal 5,r each valve and pipe upgrading requirements for each piping system.

5. Before the existing 4 psig reactor building press re isola-tion sigr.a1 may be deleted from the plant design, .Se piping system must be evaluated, utilizing the logic shown 'n attached Figure 2.1-5, to demonstrate that containme t integrity will be maintained.

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 laciation 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 type of override is noted by an "I" 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-ciated with the various penetrations which may be desired to reopen by the operator. The common isolation signal override shall also provide the override for the individual isolstion signal override. This type of override is noted by a "C" on Table 2.1-1. The initiating isolation condition may still exist when utilizing this override,

c. Individual Isolation Signal Bypass - This bypass shall be capable of bypassing only the specific isolation signal to the appropriate valves associated with only the penetra-tion which it is 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. Automat te Isolation Signal Override - 1he isolation signal for this type of override shall automatically be cleared although the initiating isolation condition may still exist. This will allow the operator to simply push the valve switches to "open" position in order to re-open the valves. This feature is ueed only for the RC system '

letdown isolation valves after they have been closed by a j reactor trip only. This type of override is noted by an '

"A" on Table 2.1-1.

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e. No Override or Bypass Capability - This override shall not permit the operator to re-open the valve unless the initiating condition is removed. If the isolation valves have been re-opened and the initiating condition re-occurs then the valves shall again be isolated.

The containment isolztion overrides shall be on an it.dividual signal source basis such that overriding the isolation signal due to one source will still allow the valves to be isolated by a second isolation source if it is activated.

2.1.1.5.2 Design Bases

1. The diverse containment isolation system shall meet the single failure criterion of IEEE No. 279.

2. Redundancy of sensors, measuring channels, logic, and actua-tion devices shall be maintained and not be degraded by the modifications.

3. Electrical independence and physical separation shall be in accordance with IEEE-383, where practicable. If not possible, existing physical separation criteria will be maintained.

4. Switches, independent of the automatic instrumentation, shall be provided for manual control of all containment isolation valves modified.

5. Manual testing f acilities shall be provided for on-line testing to prove operability and to demonstrate reliability.

Plant operation should not be adversely affected.

6. All new instrumentation shall meet nhe environmental and seismic requirements of IEEE-323.

7. The status of all containment isolation valves shall be provided in the control room and not be affected by the mooifications.

8. Non-safety related radiation isolation signal will meet all of the above criteria with the following exceptions:

a. The system will not be seismically qualified.

b. Testability requirements of IEEE-279 will be met to the extent practicable.

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 pressure (1800 psig) it is anticipatory of SFAS and occurs prior to SFAS initiation. Therefore the NRC 2.1-13 Am. 6 1438 008

directive would be fulfilled in a ecnservative way by the reactor trip signal rather than the SFAS signal.

The use of the RPS system would provide isolation for the follow-ing events:

a. Rod withdrawal accidents 5 Loss of coolant flow

c. Feedwater lina break or loss of feedwater

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 after trip

i. Loss of offsite power or station blackout The 1600 psig SFAS signal would not isolate containment for .tems a, b, c , f , g , h and i . Isolation on 1600 psig SFAS for items d and e would not cover a full spectrum of events.

As discussed above, lines which will be isolated on reactor trip are:

a. reactor building sump

b. RCDT gas vents and liquid discharge

c. RCS sample lines

d. containment purge lines

e. RCS letdown

f. demineralized water

g. OTSG sample lines (due to primary to secondary leaks)

Closure of these paths by a signal that is not dependent on building pressure assures that there will be no uncontrolled radioactivity release from containment for design basis tvents.

With the exception of the letdown and the demineralized water valver, 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 after reactor tripper existing operating procedures.

Special design provisions will be taken with letdown line isola-tion. If neither 4 psig building pressure nor high radiation 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; 2.1-14 Am. 6 1438 009

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)

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 rediation isolation signal for the following reasons.

First, reactor trip isolation will be anticipatory of a high radiation condition. Second, individual isolation is more sensitive to isolating tLe 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 building 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 override is a determinatior that neither an accident condition nor a radiation hazard exists. If either of these conditions exist, then speciti.- as to if or when the isolation can be bypassed will be developed en a case by case basis.

Individual reactor trip override capability has not been supplied for all lines except RCS letdown. When a stable post trip 1438 010' 2.1-15 Am. 6

condition is achieved, the operator can override the containment isolation signal at the system level in order to reestablish control of these systems.

2.1.1.5.4 Re ferences

1. Letter from Boyce Grier, of US NRC, to all owners of B&W reacto a dated April 5, 1979, IE Bulletins79-05A, 79-05B,79-05C.

2. 10CFR50, Appendix A, General Design 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 Accident."

4. B&W Company, Nuclear Power Generation Division, dated 5/22/79,

" Recommendations for Long-Term Cianges to be Considered to Containment Isolation Systems."

5. U.S. Nuclear Regulatory Commie 3 ion. 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-0578, July 1979.

2.1.1.5.5 Safety Evaluation The selective addition of the containment isclation signals on high radiation, reactor trip and 30 psig building pressure does not compromise plant safety for the following reasons:

1. The system is designed as safety grade and single failure proof (except for high radiation isolation). Thus, the system will perform its safety function when required.

The probability of containment isolation 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 ini intion of the existing 4 psig building pressure si;nal.

Finally, the design meets the intent of all NRC directives to Met-Ed regarding containment isolation namely the addition of isolation on high radiation, and low RCS pressure. The design meets the requirements of Standard Review Plan 6.2.4 to the extent practicable.

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2.1.1.7 Auxiliary Feedwater Modifications 2.1.1.7.1 System Description The TMI Unit #1 Emergency Feedwater System is being modified so that:

l. Both of the motor driven Auxiliary Feedwater (AFW) pumps automatically start upon loss of both main feedwater pumps or loss of four (4) Reactor Coolant Pumps.

2. The motor driven AFW pumps are automatically loaded on the diesel generator during loss of offsite power.

3. Indication is available in the control room of AFW flow to each steam generator.

4. Manual control of the AFW flow to each steam generator independent of the Integrated Control System (ICS) is available to the operator in the control room.

5. Control room annunciation for all auto start conditions of the AFW system is available.

2.1.1.7.2 Design Bases The TMI-l Auxiliary Feedwater System (AFW) is being modified so that a single failure will not result in the loss of auxiliary feedwater system function during a Loss of Coolant Accident.

To accomplish this the requirements of NUREG-0578 Section 2.1.7a and 2.1.7b will be met. In addition, the emergency feedwater control valves are being modified such that they fail open on loss of instrument air in order to meet the single failure criteria.

2.1.1.7.3 System Design As indicated in Chapter 10 of TMI Unit #1 FSAR, the Emergency Feedwater System was designed to operate: 1) on loss of all four Reactor Coolant pumps or 2) if both main feedwater pumps fail.

The original system design was based on use of three auxiliary feedwater pumps. O..e of the three pumps is turbine drivec and has a capacity of 9.0 gpm. The remaining two pumps are motor driven and have a capacity of 460 gpm each. The three pumps are located in the Intermediate Building which is designed to withstand seismic events, tornado, missiles and a hypothetical aircraf t incident.

The turbir.e driven pump is physically separated from the motor driven units. One of the motor driven pumps is powered from the class 1E 4160 volt bus ID while the other motor driven pump is powered from the redundant class 1E 4160 volt bus 1E. The design of the ID and IE Bus has been changed so that they continue to supply power to the motor-driven pumps during all lous of off-site l 1438 012 2.1-20 Am. 6

power conditions with or without ESAS actuation. To limit volt-age dip on the diesel generator during loss of off-site power and coincident ESAS actuation condition, the motor driven pumps will be loaded as a block 5 load (i.e. will be loaded 5 seconds after block 4 loading). For a loss of cffsite power only motor driven pumps will be loaded 5 seconds after the diesel generator has started. Power to the turbine driven pumps remains unchanged and is described in Chapter 10 of the FSAR.

Both of the motor driven and turbine-driven emergency feedwater pumps receive an aute-start signal on loss of all four reactor coolant pumps or loss of both main feedwater pumps. This is accomplished by utiliting contacts from the Reactor Coolant Pump power monitors and by sensing tl.e dif ferential pressure across the maia feedwater pumps. The RC pump power monitors are a safety grade system and are described in chapter 7 of the TMI-l FSAR. The main feed pump differential pressure sensing equipment is control grade. Both of the above initiation signals and circuits are designed so that a single failure will not result in the auxiliary feedwater system not functioning.

To accomplish this, the actuation system is arranged into two trains. Each train contains two differential pressure switches (one for each main feedwater pump), and four contacts from the RC pump power monitors (one for each pump).

Power for the "A" train is from the 120 V. AC Vital Distribution Panel VBA. Panel VBA can receive power either from the "A" station battery through the 1A inverter or from the "A" diesel generator. The "B" actuation train utilizes redundant pressure switches and RC pump power monitors and is powered from the 120 V. A.C. Vital Distribution Panel VBB. Panel VBB can receive power from either the "B" station battery through the 1B inverter or from the "B" diesel generator.

In addition to the above actuation signals, the turbine driven pump also receives an automatic start signal from the main feed pump trip circuitry. The details of this actuation signal are discussed in chapter 10 of the TMI-l FSAR.

All three emergency feedwater pumps discharge into a common header. From this common header a separate six inch line de-livers water to each steam generator. Each of the two supply lines contains r.n air operated control valve (EF-V30 A/B).

Under normal operations air for the control of these valves is supplied from the instrument air system. The instrument air system is described in chapter 5 of the TMI-l FSAR. In the event the main source of instrument air is not available, a back-up source of instrument air has been provided. The back-up air supply is received from a 80 gal. reservoir which is supplied by an 18 SCFM air compressor. Transfer to the back-up air supply is automatic and no operator action is required. The bcek-up air compressor is powered from the 1A 480V Engineered Safeguards Control Center.

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To provide further assurance that emergency feedwater can be delivered when required, the failure mode of control valves ZF-V30 A/B is being changed. Currently these valves fail half open on loss of electrical control signal and fail "as-is" on loss of instrument air. The change consists of modification to f

the operator such that on loss of air, the valves will fail in the open position and remain in this position.

Control valves EF-V30 A/B are controlled by the Integrated Control System. The design of this sytem is described in chapter 7 of the TMI-l FSAR. Upon loss of all reactor coolant pumps, and/or both feedwater pumps, the IC positions the control valves to maintain steam generator water level. If reactor coolant pumps are available, the ICS controls are set to maintain a 30 inch water level on the start-up range level indicator. If reactor coolant pumps are not available, the ICS maintains steam gener-ator water level at 50% on the operating range level indicator.

The Integrated Control System is a control grade system. It does, however, receive power from the Class lE power system. Specific-ally the ICS is supplied from Distribution Panal ATA. This panel can be powered from the station batterles thru inverter lA and Panel VBA or from ES Control Center lA through Panel TRA.

Manual Control of the emergency feedwater control valves can be taken from the control room. When manual control is aelected all active components of the ICS are bypassed except for the raise /

lower voltage circuit. As further assurance that control of the emergency feedwater control valves are available to the operator, an additional manual control station is being provided for each valve. The controls will be located in the control room and will be totally separate from the ICS. Power from the redundant por-tion of Class 1E power system will be provided to the back-up cratrols. A functional diagram of the new manual controls is c'own in Figure 2.1-3. A new manual loader station for each control valve will be mounted on the control room console. This will allow the operator to manually set a +10 volt control signal into the voltcge/ pneumatic converter in order to control the pocition of the EFW control valva. An adjacent selector switch connects the signal from the manual loader station to the voltage /

pneumatic converter and also replaces the ICS "EL" power supply with an independent 115 volt, 60 hz supply. Thus, if the EFW controls are disabled due to e failure in the ICS or failure of the "EL" power supply, the operator will have the ability to control flow to either steam generator entirely independent of the ICS.

Each of the emergency feedvater supply lines has also been pro-vided with,two redundant flow sensing devices. These devices are a sonic flow device as manufactured by Controltron and will be installed downstream of the control valves before *.he lines enter the containment building. The flow devices are sarety grade and have been seismically qualified. The output of the flow devices will transmit the signals to the main control room where meters will be installed to read flow directly. The equipment to se installed will be safety related. Cchling will be routed as 2.1-22 j 4 } 8 ()} kAm. 6

described in Section 7 of the TMI-l FSAR. The power supply 2 r the ir.struments will be derived from the vital 120 V power sy stem.

Redundant Power supplies will be used for redundant instrumet.ts.

A diverse means of monitoring emergency feedwater flow is provid-ed by the steam generator level indicators. The.e measurements are derived from Bailey type "BY" transmitters which, subsequent to their installation at TMI-1, have been seismically qualified and qualified for operation in a post-LOCA containment environ-ment. One start-up range and one operating range transmitter have been raised higher above the reactor building floor to avoid floodir g in a post-accident situation and have had their elec-trical connections protected to prevent degradation due to moisture. The level instruments are supplied from lE on-site power sources and their wiring is run in raceways which have been analyzed to assume heat. They will withstand a seismic event.

2.1.1.7.4 System Operation The TMI-1 Auxiliary Feedwater System is a stand-by plant system which is not used during normal plant start-ups, shutdowns or operation. The system is maintained in stand-by duri.ng piart operations and is automatically actuated upon loss of both main feedwater pumps or loss of all four RC pumps. The following table gives actuation time for the system:

Event Turbine-Driven Motor-Sriven a) Loss of Feedwater or Immediate 5 Sec.

Loss of RC Pumps b) Above with loss of Immediate 15 Sec.

off-site power (LOP) c) Above with ESAS but Immediate 20 Sec no LOP d) Above with ESAS and LOP Immediate 30 See Start-up and test data indicates that the turbine driven pump requires 18 seconds to reach full flow. The motor-driven pumps should be capable of accelerating to full speed in less than 10 se cor.d s . Therefore under worst case conditions emergency feed-water flow should be established within approximately 40 seconds.

Control of auxiliary feedwater flow following initiation is accom-plished by the ICS. The ICS controls the injection of auxiliary feedwater to maintain water level in each steam generator to one of two setpoints depending on whether RC pumps are or are not available. Under forced cooling conditions, the ICS controls level to 30 inches on the start-up range since this is suf ficient to provide core cooling. However upon loss of forced RCS cooling the ICS controls steam generator level to 50% on the operating range to promote natural circulation with the Reactor Coolant System.

Manual controls in the control room are available for the opera-tor to take control of the EFW flow to either steam generator when needed or in the event of ICS failure.

2.1-23 r Am. 6 1438 013

2.1.1.7.5 Design Evaluations Table 3-1 (supplement 1 to this RESTART REPORT) indicates that the heaviest loading an one diesel generator during an ESAS actuation would be 2913 Kw and durir.g a loss of offsite power only, the load would be 2817 Kw. The total load in either case is below the 2000 hour0.0231 days <br />0.556 hours <br />0.00331 weeks <br />7.61e-4 months <br /> rating of 3000 Kw. Gince no credit has been taken for the reduction in pumping requirements following e LOCA and since the dieselo 2000 hr rating is not exceeded, the diesel operability will aat affected. A detailed loading study has also verified this fact and testing will be performed to fur;her verify this fact.

2.1.1.7.6 Safety Evaluation Safety analyses performed on the 177 Fuel Assembly B&W plants have determined that the emergency fe edwater systems for a 2772 Mw plant must be capable of delivering 550 gpm (total to both generators). The basis for this criteria is contained in Volume 1; Section 6 - Supplement 3 of B&W's report entitled, " Evaluation of Transient Behavior and Small Reactor Coolant System Breaks in the 177 Fuel Assembly Plant". The analysis submitted by B&W is applicable to TMI-1. Several studies have also been performed by B&W for the 177 FA plants on loss of main feedwater transients.

These analysis have demonstrated that 500 gpm or lower auxiliary feedwater flow is adequate following upset transients such as loss of power and the loss of normal feedwater flow. Therefore, the small break LOCA conditions with a 20 minute delay in auxi-liary feedwater initiation sets the minimum emergency feedwater capacity requirements. Considering that TMI-1 is only a 2535 Mw, a minimum emergency feedwater capacity requirement of 550 gpm is very conservative.

As discussed in paragraph 2.1.1.7.3 above, the TMI-l emergency feedwater system is comprised of two b60 gpm capacity electric pumps and one 920 gpm capacity steam driven (turbine) pump The addition of the motor driven pumps (automatically) to tb , diesel block loading sequence and the turbine-driven pump stare circuit ensures that a single failure will not result in less than the minimum required pump capacity being available under all condi-tions including loss-of-off site power. That is at least two raotor driven or one motor driven and the turbine pump will be available under all single failure conditions.

1438 016 2.1-24 Am. 6

The addition of the motor driven EFW pumps auto-start circuits l and addition of these motors to the diesel block loading sequence ensures that a single failure will not result in less than the minimum required pump capacity being available under all conditions including loss-of-off site power.

The TMI-l AFW design provides an emergency feed line with control provisions in line to each steam generator. The design is such that the required quantity of water can be provided to at least one steam generator during all single failure conditions involv-ing a Loss of Coolant Accident or loss of normal feed. Under steam line or feed line break conditiont, when both main and auxiliary feedwate.r is isolated to t'ae affected steam generator, a single failure of the unaffected auxiliary feed line control valve will prohce unacceptable results. To counteract this situation several short term design improvements have been implemented. A Back-up instrument air s* stems have been added, the failure mode of the control valves have been changed, and an additional manual control station has been added. All of these changes provide additional assurance that the TMI-1 control valves will be operable when required or at least will fail in the open position. In the long term, the system will be re-designed to account for the extremely unlikely condition where a control valve sticks closed during a steam or feedline break acci 'ent .

As noted above, the failure mode of the feedwater control valves, EF-V30A/B, have been changed from a fail-as-is to a fail open position on loss of instrument air. This failure mode is con-sidered best because it gives priority to reliability of feed-water delivery for decay heat removal. Prevention of overfill is a second priority and a condition which should be prevented but without compromising decay heat removal Several changes have been made to ensure that the operator can prevent an overfill and overcooling condiiton. These changes consist of addition of the back-up class IE powered manual control stations for EF-V30A and EF-V30B in the control room.

These changes w. e made to back-up the existing automatic level control system tai plant instrumentation systems which in them-selves are highly reliable. In addition, plant procedures are being modified to provide guidance to the operator in recognizing overcooling incidents and taking prompt corrective action. The operators will be trained in the requirements of these procedures as part of the Operator Accelerated Retraining Program. These changes ensure that control of the emergency feedwater system will be available to the operator in the control room for preven-tion of steam generator overfilling conditions.

1438 017 2.1-25 Am. 6

e) The automatic initiating signals and circuits are designed so that failure will not result in the loss of manual capability to initiate AFW from the control room.

f) Safety-grade indication of cuxiliary feedwater flow to each steam generator is being provided in the control room. This design is consistent with the existing system design (i.e.,

two indicators per line is provided).

g) The Flow instruments are to be powered from Class lE power systems.

Manual capability to initiate the auxiliary feedwater syst em from the control room has been retained and is such that a single failure in the manual circuits will not result in the loss of syster funciton. In addition provisions for testing of the initiating circuits, although not currently included in the design, will be provided. Control room annunciation for all auto start conditions will also be provided.

2.1.1.7.7 Startup Testing and Inservice Testing / Inspection R quirements During the initial TMI-l start-up testing, hot functional testing was performed to:

1. .arify the Integrated Control System (ICS) controls the OTSG to the minimum level set point of 30 inches during HFT heat-up.

2. Verify the ICS controls the emergency feedwater system and OTSG 1evel for the following simulated conditions:

a. Both main feedwatet pumps tripped.

b. AC hand power to the ICS lost.

c. All four RC pumps tripped,

d. All four RC pump & both main F.W. pumps tripped.

3. Verify the auto start capability of the steam driven emer-gency fe2dwater pumps.

4. Verify operability of the Emergency Feedwater System to supply feedater when OTSG pressura is 1015 psig.

These tests are documented in Test procedure TP 600/11. Accept-able test results were obtained and therefore no need exists to re perform the above tests. However prior to re-start of TMI-l the following test will be conducted:

1. Functional tests shall be performed to verify the emergency feed pumps start on loss of feedwater or loss of four reactor coolant pumps.

1438 018 2.1-27 Am. 6

L.1.2 Long Term Modifications 2.1.2.1 Post Accident Monitoring 2.1.2.1.1 System Description Post accident monitoring capability will be provided in compliance wit" tag. Guide 1.97, Revision 3. Pending the availability ot appropriately qualified instrumet tation and equipment, the following modifications can be coupleted by Janu ry 1, 1981. The conceptual design will be provided for NRC review by January 1,1980.

Containment Pressure - Continuous containment pressure indication will be proviued in the control room using a range from -5 psig to three times the design pressure of the containment. The pressure indication will be safety grade and will meet the design and qualification requirements of Reg. Guide 1.97. Red undant indication of pressure will be provided.

Containment Water Level - Continuous coutainment water level indication shall be provided in the control room. A safety grade wide range indicator from the bottom of containment to a level of 10 feet will be installed in accordance with the requirements of Reg. Guide 1.97. In addition, a narrow range indicator from the bottom to the top of the sump with continuous indication in the control room shall be installed which meets the requirements of Reg. Guide 1.89 and is capable of being periodically tested.

Containment Hydrogen Indication -Safety grade continuous indica-tion of containment hydrogen will be provided in the control room. The range of indication will be 0-10% concentration assuming commercial availability over this range.

High Range Containment Radiation Monitor - Two safety grade con-tainnent radiation monitor for photon radiation shall be provided withcontinuousandrecordingdisplayinthecontrolroom.

range of this monitor shall be 10 R/hr and shall detect photen The radiation down to 60 Kev. Testability of the radiation monitor will be provided in accordance with Reg. Guide 1.118. To our knowledge, manufacture of appropriately qualified equipment to satisfy these requirements will commence by July, 1980.

High Range Effluent Monitor - One high range effluent monitor shall be installed for each normal noble gas release point. The range of these monitors shall be as follows:

Undiluted Containment Exhaust - 105 uCi/cc Diluted Containment Exhaust - 104 pCi/cc Auxiliary & Fuel Randling Building Exhaust - 103 pCi/cc Condenser Off Gas - 102 pCi/cc The design shall be seismically qualified in accordance with Reg.

Guide 1.97 and the power supply shall be non-interruptible. The display shall be continuous and recording in the control room Testability will be provided in accordance with Reg. Guide 1.118.

2.1-30 Am. 6 1438 019

2.1. 16 Auxiliary Feedwater System Auto start of the emergency-feedwater (EFW) System is being implemented in two phases: 1. Control Grade Auto Start - This is a non-safety related initiation as described in paragraph 2.1.1.7 and it is a short-term approach, 2. Safety Grade Auto Start - This will be a long-term modification where the initia-tion will meet the requirements for Class 1E syst - and the system is functionally described below.

1. he safety grade EFW auto start when impimented will automatically initiate the system on presenes of the following conditions with or without the availability of the of f-site power:

Loss of both normal feedwater pumps, or Loss of all four reactor coolant pumps, or Low differential pressure between the normal feedwater with main steam lines at each steam generator, he system initiation on low steam generator level will even-tually be added. This will be done after the necessary analysis and engineering has been completed to insure that this signal will give a satisfactory actuation end will not interact with other plant functions. Loss of normal feedwater pumps is detected by differential pressure switches across each pump (two switches per pump, i.e. , one switch per train).

Since they are installed in a non-seismic building, these switches are not safety grade instruments. However, they will be tied into the EFW initiating circuits (Train A & B) through buffer devices. he other components of the initiating cir-cuits will be safety grade items.

2. All cables associated with the initiating logic wil' be quali-fied for Class 1E application and the initiations wi.1 be designed to meet single failure criteria. All circuits will meet the regulatory criteria for separation of Class lE cir-cuits.

3. he initiating logic will include hardware for the following purposes:

Latching mechanism to secl-in the actuation Manual Reset Capability Testability of the initiating circuit

4. Indication will be provided in the control room to identify the source of the initiation.

5. Annunciation will be provided in the control room to alarm:

Auto start of the EFW system. This will be a common alarm for both the trains.

2.1-37 Am. 6 1438 020

THREE HII.E ISIAND UNIT NO.1 List of Isolati bgndt hverrideCapability Isolation Signal Penetration Reactor Higli 4 peig 30 psig iS00 poing Line Losa of Off-No. Trip Radlation BiilIding Building (SFAS) Ercok Site Power Containment Air Samplo 108 N/A N/A C N/A C N/A N/A R.B. Sump 353 C IA C N/A N/A N/A N/A RCDT 330,331 C IR C N/A N/A N/A N/A RCS Sample 328 C IB C N/A N/A N/A N/A R.B. Purge 336,423 C No NO N/A N/A N/A N/A, RCS Letdown 309 A IB C N/A N/A N/A N/A Demin Water 307 C N/A C, N/A N/A N/A N/A OTSG Sample 213, 214 C 15 C N/A N/A N/A N/A NSCCW 346, 347 N/A N/A N/A NO N/A No N/A

- ICCW 302, 333, N/A N]A, N/A NO N/A NO N/A A 334 u

• O R.B. Air Coolers 421, 422 N/A N/A N//

C C N/A N/A O R.C. Pump Seal Return 329 N/A N/A N/A No N/A N/A NO Iegend C = Connon Signal override; initiating isolation condition stay attf1 exist.

I = InJtvfdual isolation signal overrida capabilltyg procedures governing override to be developed.

g IB = Individual isolation signal g ass capability

- A = Automatic isolation signal override.

e NO = No override or bypass capability; initiating condition must clear to allow reopeninR of valve.

N/A = !!ot app 11 cable.

Note: For combinations of initiating signals that er s allowable, refer to Table I of Appendix A.

TWREE litLE istAND IRel? H0, i TABLE 2.1-2 LIST (F C0erTAIIIMtit? IsotAttoel TALTryEgt!!Rtp0 IIODIFICAtl0_NS Llee Talve Tstre reestrettee lietbed leermal Feet Aeleel Velve Telve 81:e, Talve Acteetten Sig,est searce Re- Service Sretee of Aceldent Feelfles Feeltlee WW ^ "*

Tea No. h le. Acteetten Feeltlee UfstiegjiollM ledicettee telst 1.dr erosed, ** adit ted

, I'*:t es 108 Cosee N eat Als SM 01-91 Bell 1 Air Open Cleeed Cleeed 1,50 Seerle 3-T2 Bell Tee 1,10 1.,2,6,10 i Al r Open Cleeed Cle.eed Tee .

01-4) tall 1 Air Open Cleeed Cleoed Q1-14 fee tell I Air Open Closed Cleeed Tee II) Stese Generates CA CA-T4A Clebe 3/8 RMS Open Sample Cleeed Closed Tee 1,80 -

1,4,5,4,1fs CA-934 Clebe 3/8 Air Open Cleoed se B4w recausenestfee Closed fes 214 Stees Cenerator CA CA-T4B Clebe 3/8 EMO Open Cleeed Cleeed Sample CA-158 Tee 1,80 =

1.4.1.6,40 lie may recome edeelee Clebe 3/8 Al r Open Cleeed Closed Tse 302 Intermeelsae Isa IC-T2 Cote 6 EMO Open Cleeed Opee/Cleaed fee Coellas IC-T 3 Cete 6 1.jal0 0.9,80 3,7,8,9,10 See b ee (11 belev Air Open Cleeed opee/Cleeed Ten W ies t%stlet Llne 307 Deeln. Water to CA CA-9189 Cete 2 Air Open Cleeed Closed ector sellding Tee 3,10 f . 10 1,9,80 309 letdoen 1. lee to Mu-TIA M Fertfleetles MII Clebe 2-1/2 EMO Open Cleeed Cle'eed Tae 1,80 1,1,13 1,4,5.4.10 Mts-928 Cinbe 2-1/2 ENO open Cleoed Claeed 6 Deelnevellsese Ini-13 Cete 2-1/2 Air Open Tee l.10 1,*,lc 3,; 5,6,10 Clemet Cl<eed Teo 1,10 e*m 1.2. 18' I,6,10 328 Freesertser and CA C4-TI Clebe 3/8 EMO Cleeed Cleeed Cleoed fee 1,10 teacter reelant CA-T! Cete 1,1,10 1,4,5,6,10 3/8 Air Closed Closed Cleoed g Sample t. lees CA-11 Clebe 3/8 EMO Cleeed Closed Cleoed Tee fee N CA-TI) Clebe 3/8 RMS Cleoed Cleoed Cleeed Tee N 329 Resetor Ceelset let las-T21 Clebe 4 FMG Open Cleeed Opee/Cleeed fee 1,7,10 7,10 temp Seal Retene HU-v26 Cete 4 3,7,8,91to,M r&w Jaes act addrese Air Open Cleoed Opee/ Closed Tee reed == veJ!s:Ica slesal.

RI Red elete ellt **

psevided 330 Beector Ceelset IfD0 lloc-T 3 Clebe 2 EMO Open Closed Closed Tee 1,10 Drele Teek ifDC-T4 Cete 2 1.2.10 8,4,5,10 Air Open Cleeed Cleoed Tea Test F ,,8

.re.t.r C.el..t l. _ T,0, C... 4 ,0 Cl .d C, e4 Cle..d f.e 1.10 Drete Tank Feep llDirT304 Cete 4 Air Closed 1.2.10 1,.. 10 Cb Diecha rge Cleaed Clueed Tee 333 fatermedlete IC IC-14 Cete & Air open Cleved- Open/ Closed Tee 1,3g10 Cr,elleg veter 0.9.10 j,7,8,9,10 849 does e- 6'8rees need Supply Line in elepelfy lepee se telente reteteet I. Alea ee. He t, (1) te;.ae.

334 Intermediate IC IC-96 Cete feeling to 3 Air Open Cleerd Cleved Tee f.jalO l.2,?,10 3.2.0ge,80 See p,te ll) bel...

CRD1 Coeling Colle

• ~-

TREES litLE IStAIIB Untf $10, i

. TABLE 2.1-2 [C3t 'sQ LIST OF (2187&lIBtENT ISOLATI0rt TALVES REgtlp0 9000lFICAf t0NS vol e velse Line Method IIernal Feet Actuel Actuettee Sfpel Bource ren.tretles er n..

felt. vel,e stee, vele. Accid.et r.etta.e reestle. ET v seretce sieten van me. 71re 8=- Act**t8ea raa t t s

• GiiiFas~ l9 Lng ledteouse retect.a p.ogeoed_ ne4tried netee 3J4 Saector Bettelng All AN-VIA tutter- 48 Air Closed Cleaed Closed Oatlet Purse Tea 3,In 3,7,10 3,4,5,10 IIr Line AM-Tit Butter. 48 EHo C.t eeed Closed Claced Tee f19 346 peectse reelset N5 NS-785 Cete Pt.ar Hoter S EMO Wes Cleaed cren/Cleeed Teo 1,99 A,9,50 7,0.9.10,M Cee state (11 helnae Ceeltog Water SuppIt 347 Reacter Coalest us m. d4 Cete rep %tas O EMO Oyes Cleeed Open/ Closed Tee 3,10 8,9,80 F.0,9,50 See Wete (t) belas NS-V)$ Cete 8 EMO cree Cleoed Open/ Closed fee Coeting veter MO 83 9d0 L3A g it Reture 353 peector sattelag WOL UDL-T514 Cete 4 Alr closed Cleoed Cleged 3,80 suop prete fee 1.2,80 1,4,5,10 S&W does set address WDiev515 cete 4 Air Cleeed cle.ed Cl. sed fee n,,A ,;. r,dtesten esteet 411 Seestcc autiding te SS-VIA Cete S g Cleeed Open 1,80 A reet Air

,BMG, Tee 0.9 Md3 Contese Sepp 1r

_ Lt..

add e t. s Itterlee af

.+be 4ll p,e-ter telldlag BS 38-T7 Co a g f:oreal Air S Air Open Cleeed Open Tee 1,19 8.9 Mal 0B f.a. siii l[ofLo.m f.l. cooline[n fg .}C Cootere senere gresente leeI~ su s'gnet3

@ Line 413 9esete. B. tiding A4 AN-Vic O Inlet P sge Dutter-fir 44 EMD Cleeed Cleoed Cleaed Tee 1.4.10 1,1,80 1,4,5.30 PN,) Line AN-fle Setter- 40 Air Cleeed Closed Closed fee u f8r

- s.C.p. seal reture ms-vsl Cete e rHe Open Coeling, etc.~

I r.le -

e.80.tl Ti.t e,_t. net _Ee..conseyeat h is velee shtienve is talete} e m prew at **.e g 5fn:T re- ='-

• Talve Actuetle. Signal S.wsco Os

1) 4 pela reacter building pressere feelettee 7) Cleselfy line to Selsete Categest !

I) 8600 pels (Seas) teelettes 8) 30 pelg reeeter betiding presente leeletten

3) Eedlette,eiere. escreter settee required 9) Line break teelet tee eignal er protect free pipe tAily and jet toplagement

4) lilah redlet ten (r.en-eefety) Seetettee 80) Remote mensal centrol

5) Descler trip sectessee II) Loss of effstte gamer testattee for NS peep renaist preteetleel thle_le,

6) 0'erside capabilley en Individh .' valves set f or containment Isolettee functies.

Metest (t) See esplanet ten to test of Tim - No. THI-857 pg.10, para IV 1) e) 18) and til) regarding line break leelettee.

A line breet lealet ten to eat seguireJ provided the line can wishetend, er to pensee ted fees, les te latesent s.nJ the only pipe wntp th4t ces break It le the R. C, ptplag.

TilREE MILE 151.AND UNIT NO. 1 TABLE 2.1-3 --

LIST OF CONTAIIGIENT PENETRATIONS REQUIRINC ISOLATION ON llI-RADIATION Isolation Radiation Penetration Valve Detector Type of No. Service System Tag No. I.ncation __

lionitor ,

213 Steam Generator CA CA-V4A Locate the monitors outaide the R.B. Area and Sample -VSA near the sampling line downstrear. of Caruna 214 ,

-V4B the containment isolation valve and Detectors

-V5B upstream of connection for Torb. (New)

Plant sampling 309 Letdown Line to HU HU-V2A Utilize existing Rad. lionitor Ril/L-1 inline Pu ri fication -V2B located outalde R.B. (Existing)

Demineralizers 328 Pressurizer and CA CA-V1 LocatethemonitoroutaldetheR.B. Area Camma Reactor Coolant

-V2 between the isolation valvu and tiie D tector~~~

Sample Lines -V3 sample cooler. (New)

-V13 329 Reactor Coolant HU HU-V33A Locate the online radiation monitnr Area Camma Pumpa Seal -33B downstream of the containment isola- Detector Return -33C tion valves outside of the R. B. for (t!cv)

-33D Alarm Operator action la re.guired to close valven.

330 Reactor Coolant WDC WDG-V3 Locate the monitor on the outside of Area Co.mma Drain Tank the tank. Detector

, and Vent -V4 (Existing) 331 Reactor Coolant WDL WDLeV303 Drain Tank Pump Discharge -V304 .

336 Reactor Building AH All-VIA Utilize the existing purge outist Inline Outlet and -VIB line Rad. Honitor RH/A-9 located (Existing)

--- a n.l Inlet Purge -VIC outside of R.B.

4:= 423 Lines -VID tr u -

CX) 353 Reactor Building

• WDL WDL-V534 Locate an area radiation monitor Sump Area Sump Drain -V535 in the R.B. Sump mounted inside Monitor CE)

TV a seismically sugported pipe. (New) d** 302 Interme,diate Cooling IC IC-V2,3 Locate the radiation monitor on the Strap 333 Supply & Return -V4,6 6" IC return line between valve on CH and IC-V3 and the 2" pump rect re. Itne. (iteu) 334 erampemewunamma usemuu . .. .; ::, - , , . a u. , -- -

_ Figure 2.1-5 t- Deletion of 4 Psig R.B. Isolation Signal I.ogic

!B-E, % Category S1 OR No Change mo ,

? .2  %

• A -

De~~ '

• E N

^

3 .5 Re classify to E' +, OR > 4 psig R.b. .

D c7) Seismic Cat. S-l

• lsolation Signat OR Leave as Non Seismic 2

m E

= Protected from or

.E

[

can withstand Jet Impingement Nh No Change l

b y A , Isolate on Line Protect from Jet OR

• Break Detection N ,

impingement ..

• ' O Signal DR Leave as is M Impingement er Pips

• Q U

whip from line break which will cause 30 psig A

m Isolate on 30 psig R.B. Pressure p N

• R. B. Pressure signal D

,g. Legend

$ Protected from or can withstand r No Change A

N AND gate which requires allinputs to be present in k ,$. Pipe Whip & D order te obtain an output.

• n. '

D:=

g OR gate which requires tr4 only one of the inputs to co he present in order to ob-Protect from Pipe tain an output C

• Whip O NOT gate which reverses Leave a is , ,

the output from the input.

5.0 THREE MILE ISLAND NUCLEAR STATION ORGANIZATION 5.1 GENERAL Following the TMI-2 accident, Metropolitan Edison Company recognized through its own and other investigations of the accident that major organizational changes were desirable for more effective management control. These changes indicate Met-Ed's commitment to operational safety and provide significant improvement in the control of opera-tional activities, and the technical and management resources directing and supporting facility operations.

The first step taken was to combine the technical and management resources of Met-Ed and GPU Service Corporation Generation Divisions into a single organizational entity identified as the TMI Generation Group.

ine TMI Generation Group was formed on July 30, 1979, to strengthen the overall management and provide greatly increased technical resources for the restart of TMI Unit 1 and the recovery of TMI Unit 2. The Group is headed by R. C. Arnold. To effect this new organizacion, Mr. Arnold was elected to the position of Senior Vice President of Met-Ed, and he continues to serve as a Vice President of GPU Service Corporation. In this position, Mr. Arnold reports to Herman M.

Dieckamp, President of GPU and GPUSC, and acting president of Met-Ed. This reporting structure provides a direct link from the Chief Operating Officer of these three companies to the activities at TMI. A primary objective of the TMI Generation Group is to insure that NRC Regulations, Technical Specifica-tions and established procedures are adhered to.

This group was formed to take advantage of the wealth of nuclear experience represented oy management and technical staff from within the GPU Service Corpo.ation and Metropolitan Edison Company. This reallignment more than tripled the number of professionals that have TMI as their primary responsibility.

There are senior management personnel with an average technical experience well over 20 years reporting to the head of the TMI Generation Group in the areas of:

. TMI-l Operations

. TMI-2 Recovery

. Environment, Health and Safety

)438 026 5-1 Am 6

. Reliability Engineering

. Radiological Controls

. Engineering and Design Various steps have been taken in this reorganization to strengthen key functions in the operation and support for Unit 1. Examples of this are:

. The line management responsibilities for TMI Units 1 and 2 are completely separated.

. Each 1MI unit is to the maximum extent feasible, to have direct control of the resources necessary for effective and safe conduct of plant activities.

. The head of the TMI-l Operations, Mr. J.G. Herbein, Vice President-Nuclear Operations is serving full time at TMI ahd his responsibilities and functions are described in Section 5.2.1.

. The organization formed under Mr. Herbein's direction specifically gives the Unit 1 Superin-tendent only the responsibility for operations and maintenance and relieves him of the direction of administration, training, engineering, radiation protection and chemistry functions.

. The radiological control functicn for Unit 1 has been elevated so that it reports directly to the Vice President-Nuclear Operations.

. The GPU Service Company and Metropolitan Edison Company Quality Assurance and Control organiza-tions were merged, and Operating Quality Assurance for TMI is their major function.

The following sections describe the pertinent details of the TMI Generation Group.

1438.0127 5-la Am. 6

5.4 Quality Assurance Program and Procedural Control the TMI-1 Restart 5.4.1 The TMI-2 accident has required major readjustments in the organization and management of the TMI Nuclear Station. The organizational structure of the General Public Utilities Service Corporation (GPUSC) and the Quality Assurance Program for con-trolling the operational activities, at TMI Nuclear Staton are centained in the Operational Quality Assurance Plan for TMI Units 1 and 2. This Plan establishes the organization and the manage-ment controls and Quality Assurance Program necessary to assure that the operational phase activities at the Nuclear Station are performed and controlled in a marner that will not endanger the health and safety of the public or the employees or contractors of Metropolitan Edison Company (Met-Ed) or the GPUSC. Ipherent in the oeprations of the Nuclear station are those day-to-day activities which are direcity associated with keeping Unit 1 on the line and Unit 2 in a safe configuration while the decontami-nation and/or restoration activities are being performed until such time as Unit 2 becomes operational. These activities are performed by the Operations personnel and those supporting activities such as radiation protection, surveillance testing, environmental monitoring, refueling, inservice inspection, modification, etc. which are required to assure continued opera-tion in a safe and economical manner. Inherent also in the operations of the Nuclear Station are those activities associated with the verification of the completeness and adequacy of the work perfromed and the provision of independent safety review and op3 rational advice.

This Operational Quality Assurance Plan is applicable to (1) the operation of THI Unit 1; (2) the maintenance of those TM1 Unit 2 items which hrve not been affected by the accident; (3) the maintenance of those TMI Uutt 2 items which upon satisfactory completion of decontamination and recovery are turned over to and accepted by Nuclear Operations; and, finally, (4) the operation of TMI Unit 2.

The overall responsibility for the establishment and implementa-tion of the Operational Quality Assurance Program and for assur-ing proper and complete interfacing of the organizations having responsibilities for performing the work rests with the TMI Generation Group. This group is managed by the Senior VP Met Ed/

VP GPUSC. The TMI Generation Group consists of one Vice Presi-dent and five Directors, as illustrated on Figure 5.4-1. The responsibilities of these departments relative to operations will be detailed separately in the Operational Quality Assurance Plan.

5.4.2 Quality Assurance Department The TMI Generation Group Quality Assurance Department under the direction of the Manager of Quality Assurance reports to the 1438 028 5-32a Am. 6

I Senior Vice-President Met-Ed Vice-President GPU Manager TMI-2 Vice President Director TMI-II Director Director Radiological and Director Recovery Technical Envircnmental Reliability Controls TMI-l Funct ions llealth & Safety Engineering Waste Management Engineering , Licensing Juality Design Assurance Project . Environmental Ma nagement Systems Systems Sngineering Labs TMI-II Recovery TMI Engineering Ma nagement t>

g V

. C13 os Figure 5.3-1 CC) Station Support Organization N

w

TMI GENERATION GROUP Senior V.P.

V.P. l Nuclear i Operaticas Director Manager Director Director Director I-Environment, Ramo ogkal Technical TMI-2 Recovery Reliability Health & Safety Functions Engineering FIGURE 5.4-1

'1438 030 Am. 6

8.0 SAFETY ANALYSIS

8.1 INTRODUCTION

Design changes af fecting the acceptance criteria for the TMI-l FSAR safety analyses arise from several sources. First is the TMI-l " Order and Notice of Hearing" (Reference 19) which contains NRC staff recommendations that certain changes be made to the plant. This order encompasses recommendations made in NRC bulletins 79-05 A, B and C and the TMI-2 Lessons Learned Task Force NUREG-0578 (Reference 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 changes are being evalu-ated as well. A third source of changes has originated from plant upgrades that Metropolitan Edison believes would improve plant performance. Some of these modifications were being evaluated prior to the TMI-2 accident on March 28, 1979.

8.2 AREAS OF INVESTIGATION 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

1. The reactor protection high pressure trip setpoint has been changed to 2300 psig from 2390 psig. This lower trip set-point in conjunction with the higher power operated relief valve (PORV) setpoint of 2450 psig results in a lower like-lihood of PORV operation.

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. control grade automatic initiation of the steam and master driver EFW pumps upon loss of all 4 reactor coolant pumps or a loss of both main feedwater 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 valves.

5. A long-term madification will provide safety grrde actua-tion of the EFW pumps on the following signals:

a. 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.

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b. negative feed to steam differential pressure.

c. loss of all four reactor coolant pumps.

d. loss of both main FW pumps.

8.2.2 Modification as Result of Order of May, 1978 Modifications to the high pressure injection system. 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.

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) wil'. be accomplished automatically rather than by operator action.

3. The reactor building spray system will be modified to delete sodium thiosulfate. Sodium hydroxide will be retained.

This change will provide equal drawdown of the BWST and NaOH tanks for a large spectrum of single failures.

8.2.4 I&E Bulletin 79-05C Met-Ed is in the process of evaluating the response to this bulletin. It is expected that a reactor coolant pump trip will be initiated on a SFAS coincident with an indication of a large (in excess of 10-20%) void fraction. This or any other change will be evaluated with regard to their effect on the plant accident, and transient analyses and plant operating guidelines.

8.3 EFFECT OF CHANGES ON SAFETY ANALYSIS Following are summaries of the accidents listed in Table 8.2-1.

Table 8.2-1 indicates where FSAR analyses took credit for non-safety grade equipment, or where mitigation is dependent on a 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 design before modification. The modifications discussed in the previous secitons were considered in the review of each accident.

If a modification affected that analysis, then a note as to its safety significance was made under the " conclusions" section.

8.3.1 Rod Withdrawal from Startup (FSAR Section 14.1.2.2)

1. Description Uncontrolled reactivity excursion starting from a suberitical condition of 1%Ak/k at hot standby.

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2. Acceptance Criteria '

i. Limit power to design overpower (112%)

11. RCS pressure not exceed code allowable of 2750 psig.

3. Mitigation

i. RPS trip on high pressure for fast power rises.

ii. Pressurizer code safety valves lift and peak pressure is limited to 2515 psia.

iii. Doppler coefficient provides a negative reactivity addition.

4. Conclusion The FSAR analysis still bounds the modified TMI-1 plant design. The RCS high pressure trip is lower and safety margins are increased. Since no credit was taken for opera-tion of the PORV, raising the valve setpoint does not change the analysis results. As discussed in Ref. 2, the PORV would lift for the worst case rod withdrawal accident which was analyzed in the FSAR. Nevertheless, the probability of occurrence has been decreased so that safety margins have been improved and lif ting of the PORV is not likely for a broad spectrum of rod withdrawal accidents.

8.3.2 Rod Withdrawal at Power (FSAR Section 14.1.2.3)

1. Description Accidental withdrawal of a control rod group at normal rated power, without ICS control and a 1% shutdown margin.

2. Acceptance Criteria

i. Limit power to design overpower of 112%.

ii. RCS pressure r.ot to exceed code allowable (2750 psig).

3. Mitigation

1. RPS trips on high pressure for slow transients and high neutron flux for fast transients.

ii. Doppler and moderator coefficients provide negative reactivity addition.

4. Conclusions The FSAR analysis bounds the modified TMI-1 plant design.

Lowering of the reactor trip setpoint increases safety margins for this event. Credit was not taken for PORV operation. As discussed in Reference 2, some low worth rod 8-3 1438 033 ^= 6

withdrawals can result in PORV actuation. Nevertheless, the probability of such an occurrence has been greatly decreased by the changes in the PORV and high pressure trip setpoints.

8.3.3 Moderator Dilution Accident (FSAR Section 14.1.2.4)

1. Description Diluted makeup water is inadvertently added to the reactor coolant system at a rate of 500 gpm beginning at normal power. RCS boron concentration is at its highest initial v alue . The result is a reactivity insertion, increased power, pressure and temperature. The addition of one makeup tank volume of unborated water changes the shutdown margin by

.8% Ak/k*

2. Acceptance Criteria

1. Reactor power will be limited to less than the design overpower (112%).

ii. Reactor coolant system pressure will be limited to less than code allowable 2750 psig, iii. The minimum shutdown margin will be at least 1% A k/ k'

3. Mitigation

i. High pressure or high temperature trip.

ii. Termination of deborated water to makeup tank on reactor trip.

iii. Termination of makeup flow on high pressurizer level.

4. Conclusion The FSAR analysis bounds tbt modified TMI-l plant design.

Lowering of the high pressure trip setpoint increases the safsty margins for this accident. Operation of the PORV was not assumed in the original analysis, and peak pressure is 2435 psxA. Therefore, the PCRV setpoint will not be reached during th.'s transient.

Reactor power I- limited to 107.3%, and the final shutdown margin is greater ti .. 1% A k/k even with the most reactive rod stuck out of the core all of the acceptance criteria for this accident are met.

8.3.4 Cold Water Addition (FSAR Section 14.1.2.5)

1. Description Startup of one or more idle reactor coolant pumps can cuase excess heat removal from the primary coolant system. This cooldown can cause positive reactivity insertions, which 8-' ^" 6 1438 034

result in a power rise. The worst case event is the startup of two reactor coolant pumps from 50% power. A tripped rod worth of 1% a k/k is used in the analysis.

2. Acceptance Criteria

1. Limit overpower to less than the maximum design overpower (112%).

3. Mitigation

1. RPS trip on high pressure for slow power increases or power / flow mismatch for rapid power increases.

11. RC pump / power monitor limits initial conditions under which event can occur.

4. Conclusion Lowering of reactor trip setpoint increases safety margins for this event. The ISAR analysis was performed without taking credit for PORV. Peak pressure did not exceed 2400 psia, hence the PORV will not lif t during this event.

The FSAR analysis bounds the modified TMI-l plant design.

8.3.5 Loss of Coolant Flow (FSAR Section 14.1.2.6)

1. Description Fuel rods experience a limiting DNB transient when all four reactor coolant pumps trip on loss of of fsite power or when one pump experiences a locked rotor resulting in an instan-taneous loss of flow. The loss of flow analysis is performed from 114% normal power, nominal reactor coolant pung flow, a

+2 F core inlet temperature error and a -65 psi error in pressure. Reactor trip delay is assumed to be 620 ms. and a 1% ak/k su5 critical margin is assumed at hot standby. The event is analyzed pcst the time that the minimum DNBR occurs.

The locked rotor accident is performed from an initial power level of 102% power, with a rampdown in flow from 100% to 75%

in 100 ms. Temperature and pressure were the same as for the loss of flow accident. Reactor trip delay is assumed to be 650 ms.

2. Acceptance Criteria

1. DNB is greater than 1.3 for a loss of coolant flow.

ii. DNBR is greater than 1.0 for a locked rotor accident.

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3. Mitigation

1. Protection f rom four pump coastdown is by limitation of peaking factors, limitations on power level and the pump power monitor.

ii. Protection for the locked rotor accident is by the flux /

flow monitor initiating reactor trip.

4. Conclusions The FSAR analysis for the four pump coastdown terminates prior to establishing stable decay heat removal by natural circulation. The EFW system will automatically start and maintain steam generator level at 50% on the operate range.

This design should result in the transition to stable condi-tions; as demonstrated by the natural circulation tests and events discussed in Reference 2.

8.3.6 Dropped Control Rod (FSAR Section 14.1.2.7)

1. Description A dropped control rod educes the average coolant temperature and reduces power. A return to full power may result in high local power density and heat fluxes. The analysis is per-formed at rated power with the most adverse values of the moderator and doppler coefficients (E01.) Rod worth are the maximum expected for full power operation with and without Xenon. Tripped rod worth is assumed to be 1% A k/k' l

2. Acceptance Criteria

1. DNBR remains above 1.3.

ii. Reactor coolant system pressure is less than code allow-able (2750 psig).

3. Mitigation

1. The integrated control system inhibits withdrawal of control rods and ramps secondary side steam demand to 60%

rated power to prevent overcooling.

4. Conclusions This analysis has not been changed as a result of any of any TMI-l plant design changes. Analysis results still show that the acceptance criteria are met. It should be noted that while ICS action is assumed in this analysis, acceptable results are not dependent on ICS operation. The dropped control rod analysis performed in tne TMI-2 FSAR does not assume ICS action, and demonstrates that the accident accept-ance criteria are met.

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8.3.7 Loss of Electric Power (FSAR Section 14.1.2.8)

1. Description Separation of the unit from the transmission network can result in the trip of the turbine and reactor. A more severe transient occurs if the ICS does not run back the reactor load demand. The result is reactor trip on high pressure.

Cooldown is accomplished through the atmospheric dump or steam relief valves. In the presence of failed fuel and primary to secondary leaks, this event can lead to low levels of radioactivity release.

2. Acceptance Criteria 1 DNBR shall not be less than 1.3.

ii. Reactor coolant system pressure will not exceed code allowable limits of 2750 psig.

3. Mitigation

i. Reactor trip on high pressure.

4. Conclusion This transient has an increasen safety margin. oves the analysis performed in the FSAR as a result of the high pressure trip setpoint reduction to 2300 psig and the antici-patory reactor trip with turbine trip. In addition, a PORV setpoint of 2450 assures that the PORV will not be activiated (Ref. 1).

8.3.8 Station Blackout (Loss of AC) (FSAR Section 14.1.2.8)

1. Description All AC power to the unit is lost, with only battery power available. The reactor and turbine trip, and reactor coolant and feedwater pumps are lost. Core cooling is accomplished through heat rejection to the secondary side using the turbine driven emergency feedwater pump with steam relief to the atmosphere. The analysis is performed starting at full power 2535 Mw (t), and takes credit for a condensate inven-tory of 200,000 gallons. NNI and ICS instrumentation is taken credit for in controlling the plant when it is powered from the vital ac inverters.

2. Acceptance Criteria

1. DNBR is not less than 1.3.

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11. Reactor coolant system pressure does not exceed code allowable pressure of 2750 psig.

3. Mitigation

1. Control of the steam driven emergency feedwater by the EFW level control system.

ii. Steam relief through the atmospheric dump and <ain steam relief valves either by the ICS or in accordance witF Emergency procedure 1202-2 and 2a.

4. Conclusion The FSAR analysis of this event remains bounding for the modified TMI-1 plant design. None of the plant modifications being made affect the systems and components which are necessary to mitigate this accident. Since the ICS is powered from the vital ac system, monitoring instrumentation will be powered by the station batteries. The operator will have all of the instrumentation available to bring the plant to a stable shutdown condition.

The extended Abnormal Transient Operating Guideline ( AI'.G) analysis of this event will determine:

1. When power would have to be restored to maintain stable shutdown.

ii. RCS system preasure response without pressurizer heaters available.

8.3.9 Steam Line Failure (FSAR Section 14.1.2.9)

1. Description A steam line rupture results in depressurization of the secondary system. This depressurization causes a primary system cooldown causing a DNBR transient and a positive reactivity addition. Blowdown can cause a significant mass and energy addition to containnent. Finally, offsite doses can result from the release of secondary side steam to the atmosphere, if steam generator tube leakage exists. The FSAR analysis addresses a variety of break sizes, including the rupture of all four main steam lines outside the reactor building. HPI was not assumed to operate during this event.

2. Acceptance Criteria

1. The core will be maintained in a coolable geometry.

ii. No a:eam generator tube loss of integrity will result fro.. the pressure / temperature transient.

iii. Offsite doses will be within the limits of 10CFR100.

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3. Mitigation

1. Reactcr trip on low pressure or high neutron flux.

ii. Feedwater isolation of the affected OTSG as a result of low steam generator pressure.

iii. Isolation of the unaffected steam generator by the turbine stop valves.

iv . Decay heat removal through the unaffected OTSG by manual control of emergency feedwater (Procedure 2203-2.3) and either atmospheric dump valves or the turbine bypass valves if they are available.

v. Containment temperature and pre. ;ures are limited by the containment fan coolers (and reactor building spray systems if reactor building pressure exceeds 28 psig).

4. Conclusion Recent, detailed analyses of IMI-2 (Refs. S through 8) allow broader conclusions about the acceptability of DiI-1 regard-ing steam line break. The Dil-2 analysis considered addi-tional single failures, the most limiting were the feedwater regulating and t arbine stop valve failures. In addition, the reactor core performance was analyzed assuming that: feed-water is not isolated, of fsite power is available if results are worse for that case, and both steam generetors blow down outside containment. Reference 3 explains why the TMI-2 core performance analysis bounds Unit 1.

At the Cycle 5 refueling outage, the feedwater latching signal was added to the upstream block valves (FW-V-5A/B).

The TMI-2 feedwater regulating valve and turbine stop valve failures cases thus bound the TMI-1 design. Although these failures are ret a licensing basis for the plant, they do demonstrate the additional safety margins available in this accident.

The difference in design of the main steam isolation valves between TMI-1 and TMI-2 results in less severe containment transients for TMI-1. The Unit I valves are a stop/ check design, so that they would prevent the blowdown of both steam generators inside containment. Since THI-1 does not have cavitating venturi's on the emergency feedwater lines, the operator would have to isolate the affected steam generator to prevent containment overpressure. The operator would have approximately 20 minutes to perform this actics.

THI-1 has not analyzed the environmental effect inside containment for the worst case single failure (because of the 143S 039 I

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stop/ check MSIV's, the worst failure is the feedwater regulat-ing valve failure). As noted previously, the blowdown will be less severe than for Unit 2. Although this issue is still being resolved, there are several reasons to expect accept-able results.

i. Heat shrink tubing is being added to splices inside containment. This change was made to THI-2 prior to receipt of the operating license to resolve this concern.

ii. Mach of the equipment which was analyzed and shown acceptable for TMI-2 is also used on iMI-1.

The radiological consequences of the unmitigated steam line break accident have also been addressed on the D4I-2 docket (Ref. 6 and 7). These analysis results demonstrate that worst case doses from a steam line break accident are within the limits of 10CFR100.

8.3.10 Steam Generator Tube Failure (FSAR Section 14.1.2.10)

1. Description The rupture of a steam generator tube concurrent with 1%

failed fuel results in the release of radioactive steam to the environment via the condenser air ejector. Leakage is greater than the capacity of the makeup system, so that the RCS depressurizes.

2. Acceptance Criteria

1. Doses are less than 10CFR100 limits.

3. Mitigation

1. Reactor trips on low pressure.

ii. iiigh pressure injection initiates and maintains primary system pressure and inventory.

iii. Turbine trip isolates the steam generator, and the release path of steam to the environment is via the turbine bypass line, through the condenser to the air ejector.

iv . Cooldown is achieved first via the unaffected steam generator and then through the decay heat cooling system.

4. Conclusions There have been no plant changes which change the results of this analysis. Results are still valid and acceptable.

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8.3.11 Fuel Handling Accident (FSAR Section 14.2.2.1 and References 8 through 10)

1. Description Failure of a spent fuel assembly, either in the fuel handling building or inside the containment building can result in release of radioactivity to the environment. The fuel handling accident in the fuel handling building considers a 72 hr. decay period for the fuel with the release of gap activity froc the entire row of fuel pins on due assembly.

100% of the acble gases and 1% of this iodine inventory is released from coent fuel pool. The fuel handling accident inside containment assumed failure of an entire aseambly, filtration by the refueling canal water, and release via the purge exhaust filtration system.

2. Acceptsice Criteria

1. Doses should be appropriate within the guidelines of 10CFR100 (less than 100 REM).

3. Mitigation

1. Filtration of releases through the fuel handling building ventilation system.

ii. Filtration of releases by the purge exhaust filter system for the accident inside containment.

iii. Meteorological dispersion of 6.8 x 10-4 sec/m 3 for the accident initiating inside containment.

4. Conclusion The plant design changes do nat affect the mitigation of the fuel handling accident inside containment. Results are still within the acceptance criteria.

l B.3.12 Rod Ejection Accident (FSAR Section 14.2.2.2)

1. Description Failure of a pressure barrier component could result in the rapid ejection of a control rod from the core. A power excursion and leakage of radioactive primary system fluid to the secondary side would result. Releases to the environment result both from releases via the secondary system and from leakage from containment.

2. Acceptance Criteria

1. The reactor coolant prersure boundary is not further degraded as a result of the ejected rod (no reactor vessel deformation).

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ii. Of fsite doses are within the limits of 10CFR100.

iii. Radially averaged enthalpy should not ce greater than 280 cal /gm at any axial location in any rod.

3. Mitigation

i. The power excursion is limited by the Doppler coefficient, ii. The power excurs.on is terminated by reactor trip on high pressure or high flux.

4. Conclusions The lower high pressure trip setpoint result s in increased safety margins over the FSAR analysis. Improvements to the containment isolation signal (radiation +Rx trip) make release of fluid from the containment building less likely.

8.3.13 Feedwater Line Break Accident (TMI-2 FSAR, Section 15.1.8,S3-21.49, S2-21.43, Reference 2, Q.3 of Supplement 1, Part 2)

1. Descriation This event has not been analyzed for TMI-1. The following description is based an FSAR analyses for TMI-2. A loss of feedwater flow results in a loss of heat sink, primary system heatup, increased pressurizer level and pressure, and reactor trip on high RCS pressure. The TMI-2 analysis assumes a complete loss of feedwater due to a break upstream of the first feedwater line check valves. No analysis of loss of feedwater due to pump trip or valve closures were analyzed.

The loss of feedwater flow due to the postulated break is analyzed as an immediate loss of flow, which results in a bounding analysis for loss of feedwater events. The reactor is initially at 2772 Mw(t). Assumptions were made to provide two worst case scenarios-one for containment, and one for l primary system conditions.

A double ended rupture (with a blowdown area limited by the feedwater nozzle area) was analyzed; steam generators are assumed to have a fouled inventory of 62,500 lbs. , and emergency feedwater is assumed to be at full flow within 40 seconds. The loss of feedwater is not directly calculated but taken as a conservative loss of heat demand (100-0% in 5 seconds for the affected generator and 100-0% in 20 seconds for the unaffected generator).

Reference 2 and Question 3, Supplement 1, Part 2 provide results for a loss of normal Feedwater event. Table 8-2 compares the analysis assumptions to the plant design.

2. Acceptance Criteria

i. Core thermal power shall not exceed 112% of rated power.

ii. Reactor coolant system pressure shall not exceed code allowable limits of 2750 psig.

iii. Pressurizer does not become water solid during a loss of Feedwater transient.

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3. Mitigation

i. Reactor coolant system trip on high pressure.

ii. The secondary system heat sink is restored by initiation of emergency feedwater to full flow within 40 seconds.

Heat removal is through the turbine bypass valves or main steam relief valves.

4. Conclusions Results of the TMI-2 feedwater line break accident have become bounding for Unit I with the addition of a feedwater line break initiating signal. The addition of reactor trip or loss of feedwater increases the safety margin over the TMI-2 analysis. Lowering of the high pressure trip setpoint also increases safety margins since reactor trip will be initiated sooner. The RCS heatup is thus reduced. PORV operation was not assumed in the feed line break analysis, so that the increase in the valve setpoint does not affect analysis results. The PORV would actuate for the worst case feedline break accident analyzed in the TMI-2 FSAR.

As demonstrated by Table 8-2 and Q3 Supp 1, Part 2, TMI-l meets the acceptance criteria for a loss of Feedwater transient and the analysis bounds the TMI-1 plant design.

8.3.14 Waste Gas Decay Tank Rupture (FSAR Section 14.2.2.5)

1. Description The rupture of a waste gas decay tank would result in radio-logical releases via the plant ventilation system. The tank contents es calculated assuming the activity evolved from degassing the primary coolant system after operation with 1%

failed fuel.

2. Acceptance Criteria Doses shall not exceed the limits of 10CFR100.

3. Mitigatio3 Elevated release of activity from the unit vent.

4. Conclusions This analysis has not been changed as a result of any plant modifications.

8.3.15 Small Break Loss of Coolant Accidents (LOCA)

1. Description Small break LOCA's a e piping ru range from as small as 0.005 ft.gtures whose break areasto as large as 0.5 ft These LOCA's may or may not involve depressurization of the Reactor Coolar.t System (RCS).

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2. Acceptance Criteria

1. Local fuel cladding oxidation (metal water reaction) shall not exceed 0.17 times the total cladding thickness, or .05 the overall cladding mass.

ii. Peak Cladding Temperature (PCT) shall not exceed 2200*F.

iii. A coolable geometry shall be maintained.

iv. Long term cooling shall be assured.

3. Mitigation

1. Inventory will be maintained by the high pressure injec-tion system.

ii. Emergency Feedwater flow within 20 minutes of very small break LOCA's allows depressurization of the RCS and allows sufficient inventory addition by the HPI system to maintain core cooling.

4. Conclusion Purr,snt to NRC regulations (10CFR50.46) and 10CFR50 Appendix K) B&W performed generic LOCA analyses of their 177 fuel assembly lowered loop plants. Initially this work was performed to meet the Interim Acceptance Criteria (IAC) and documented in BAW-10052. Later, the analyses were revised to the vinal Acceptance Criteria (FAC) using the approved Appendix K model (BAW-10104). The FAC analysis results were documented in BAW-10103.

The work performed for BAW-10052 was used as the basis for the small break LOCA lcoation and size senettivity study and therefore no new work was performed for BAW-10103 other than analysisofthgeespecificbreaksizesandlocations(0.04 ft.2, 0.44 ft. and 0.5 ft.2 break sizes).

In April 1978, B&W identified an error in their ECCS model.

The error was also evident in the model used for the BAW-10052 sensitivity studies and therefore the basis for the accepta-bility of the small break analysis was eliminated. B&W performed additional small break studies using the corrected model. The revised analyses are documented in a letter from J. H. Taylor, B&W to S. A. Varga, NRC dated July 18, 1978.

These analyses cover break sizes 0.04, .055, .07, .085, 0.1, 0.15, 0.2, 0.3, 0.13, and 0.17 ft.2, 1438 044 8-14 Am. 6

Key assumptions for the small break LOCA analyses versus the TMI-1 plant design are given below:

BAW-10103 Generic TMI-1 Reactor Power (MWt) 2772 2335 Reactor Trip (psig) 1900 1900*

RC Pumps (LOOP) Coastdown Coastdown AFW Available** Yes-40 sec. Yes****

ESFAS HPI (psig) 1600 1500 Operator Action Yes-cross-connect none***

HPI Distribution 70% to Core 70% to core within 10 min, from time zero***

HPI Flow (gpm) 450 at 600 psig 500 at 600 psig

• Variable low pressure at full power.

• • Amount assumed for generic analyses 550 gpm which is less than the minir.um 900 gpm available for TMI-1. Results of Reference 2 demonstrate that EFW is not required before 20 minutes.

• • • Prior to startup TMI-1 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 car- LOCA in which of fsite power is lost,.EFW is initiated by the control grade loss of feedwater signal.

In all cases, TMI-1 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 Reference 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 Sehavior 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, t ey h are also bounding assumptions for TMI-1 except for the distribution of HP1 flow as discussed below. The analysis in Reference 2 also established that EFW flow is not required less than 20 minutes before any steam line break accident.

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In Reference 2, credit is taken for operator action to initiate RPI or EFW. No mention is made as to whether whether operator action includes the time necessary to cross connect HPI as required in B&W's other small break accident analyses. IdI-1 will com-plete the installation of permanent cross connection of the RPI prior to startup, therefore, operator action will not be neces-sary. All of the B&W small break LOCA analyses assume essen-tially equal backpressure for all four HPI injection points.

This assumption is the basis for the 70%/30% flow split of HPI (assuming a single failure of one RPI train) between the core and the break respectively, af ter cross connection is accomplished.

Such an equal backpressure would not exist given an HPI line rupture. The back pressure on the broken RPI leg would be essentially zero and therefore the RPI loss out the break could be high resulting in inadequate injection to the core.

The criterion established by B&W for the small break analysis requires that 70% of the total flow for one HPI pump be injected into the broken legs of the reactor coolant system. This cri-teria applies to a 2772 MW thermal 177 fuel-assembly plant.

For THI-1 with a licensed core power of 2535 MWt, the 70% - 30%

criterion can be relaxed in direct proportion to the power reduction. This is justified based on the fact that the decay heat load following a small break LOCA is proportional to power and therefore cooling requirements will be directly proportional to the power at which the plant has operated. Therefore, for D41-1, the acceptable flow split can be relaxed to 64% - 36%.

The 64%/36% flow split would not be obtained for an HPI line break as explained above. Therefore, operator action would be reqv. ired to isolate the ruptured HPI line. The need to isolate cotid be determined by observing the individual flow indicators for the HPI legs. The high finw leg would then be isolated.

This action would be contrary to the operators instinct and would require considerable judgment since the initial flow imbalance may not be dramatic. Since too great a chance for operator error (arror of omission) exists, cavitating venturis will be added to the injection legs to limit flow in the broken leg.

The venturis have been sized to limit flow in each leg to 137.5 gpm when only one high pressure injection pump is operating and Reactor Coolant System is at atmospheric pressure. The venturi design ensures that for the worst case RPI line break condition, the 64%/36% flow split can be achieved when Reactor System Pres-sure is less than 1500 psig. At RCS pressure conditions greater than 1500 psig, a flow split beyond the 64%/36% acceptance criteria will occur. B&W has reviewed this situation and judged the cavitating venturi performance is acceptable. This conclu-sion is based on the fact that under KPI line break conditions, the Reactor Coolant System will not expend significant time above 1500 psig and that during the time the RCS is above 1500 psig the cavitating venturi ensures that there is significant f3cw of high pressure injection into the RC system. B&W also notes that a much larger small break than a RPI line break sets the generic flow split criteria and therefore for a HPI line break the flow split criteria can be relaxed.

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In addition to the benefits discussed above, the venturis provide two added benefits. Fi rs t, they balance flow of the injection legs under all other small break conditions such that TMI-1 flow split will be within the bounds of the generic analysis (i.e., 70%/30% flow split). Secondly, the cavitating can be relaxed.

8.3.16 Large Break Loss of Coolant Accidents (Reference FSAR Section 14.2.2.3)

1. Description Break sizes in the reactor coolant system (RCS) greater than 0.5 ft.2 are classified as large break loss of coolant accidents (LOCA's). These breaks involve rapid depressuri-zation of the RCS and are accompanied by rapid increases in containment pressure. Offsite doses are calculated from the design basis radioactivity release to containment, and the design basis containment leak rate.

2. Acceptance Criteria

1. Peak fuel clad temperature does not exceed 2200*F.

ii. The core is maintained in a coolable geometry.

iii. Local fuel cladding oxidation (metal water reaction) shall not exceed 0.17 times the total cladding thick-ness of .05 times the tocal cladding mass.

iv. Offsite doses are within the limits specified by 10 CFR 100.

3. Mitigation

1. Core flood tank actuation at 600 psig to establish water inventory.

ii. Low pressure injection system flow ,elow 200 psig to establish core cooling for the remainder of the accident.

iii. Building spray addition to put iodine in solution with the containment water volume thus preventing release to the environment.

iv. Containment leak tightness to limit radioactivity releases.

v. Switchover of the decay heat removal system suction source to the containment building sump on low-low BWST level.

4. Conclusion The calculated offsite dose resulting frcs the design basis LOCA will increase as a result of the deletion of sodium thiosulfate from the building spray system. Doses will still 8-17 ^= 6 047

be within the limits of 10 CFR 100. Dose calculations per-formed for TMI-2 (see TMI-2 FSAR, Section 15 and Reference 5) demonstrate that design basis LCCA doses are within the limits of 10 CFR 100. The TMI-2 dose calculations were performed taking no credit for sodium thiosulfate. Since Unit 2 has a slightly large thermal power level and allowable containment leak rate, then Unit 2 dose calculations conservatively bound the worst case LOCA dose for TMI-1.

Automated switchover of the BWST to the recirculation mode provides additional assuranc= that switchover will occur within the correct level band. Correct operator action had always been assumed in previous LOCA analyses. The automated switchover achieves the same f unction requirement by means of a safety grade control system.

8.4

SUMMARY

AND CONCLUSIONS Plant modifications to til-1 allow the plar; analyses to bound the expected plant behavior (see below). In some cases, analysis for TMI-2 have been referenced because they either analyze events that are not in the TMI-1 FSAR (feedline break) or provide additional assurances of safety margins (steam line break).

1. Raising the PORV setpoint and lowering the high pressure trip setpoint affects all of the pressurization transients in the FSAR. Safety margins are bnproved since the high pressure trip setpoint has been lowered. No credit was taken for operation of the PORV, so that raising the valve setpoint has no effect on the FSAR analysis results.

The combined effect of the PORV and RPS setpoint changes are to decrease the probability of PORV operation. The integrity of the primary coolant system will be challeng-ed less frequently, so that this change is in the conserva-tive direction. It should be noted that this modification could result in more frequent plant trips.

2. Reactor trip resulting from loss of feedwater results in improved safety margins for loss of feedwater events and does not degrade plant response for any accidents / transients.

3. Reactor trip as a result of turkine trip increases scfety margins for the loss of feedwater or feed line break analy-ses. The effect of retaining or deleting plant features that permitted this event to occur without a reactor trip is being analyzed.

4. The addition of emergency feedwater initiating signals for the feedline break accident makes the TMI-2 feedwater line break accident analysis bounding and conservative for Dil-1.

This event has additional safety margins beyond the THI-2 analysis since both turbine and feedwater trips result in a kkb0 8-18 Am. 6

reactor trip. This earlier reactor trip will result in a smaller heatup of the primary system.

5. Modifications to the high pressure injection system will al-low adequate HPI flow for the spectrum of LOCA's. System per-formance is not degraded for any other accidents / transients in which HPI flow is initiated.

6. Upgrading of instrumentation inside containment assures that instrumentation will be functional in the postulated accident environments.

7. Automated switchover of the BWST to the recirculation mode provides additional assurance that switchover will occur within the correct level band. Correct operator action had always been assumed in previous LOCA analyses. The automated switchover achieves the same function requirement by means of a safety grade control system.

8. Dose calculation performed for TMI-2 demonstrate that the requirements of 10CFR100 are met even after sodium thiosul-fate is deleted.

9. The transition to natural circulation following a complete loss of feedwater will be demonstrated by a startup test.

Reference 2 documents natural circulation tests and natural circulation events at B&W designed reactors. These tests and events demonstrate that natural circulation is a reli-able and effective means of core cooling.

10. An analysis of the station blackout will be performed as part of the B&W Owners Group ATOG program to determine what specific actions would be required to bring the plant to a safe shutdown condition.

11. A PORV setpoint of 2450 psig does not resu't in unacceptable interactions between the PORV and the pressurizer safety valves, whose setpoint is 2500 psig.

1438 049 8-19 Am. 6 L

REFERENCES

1. Three Mile Island Unit 1 Nuclear Station, Final Safety Analysis Report, USNRC Docket No. 50-289.

2. " Evaluation of Transient Behavior and Small Reactor Coolant System Breaks in the 177 Fuel Assembly Plant," Volumes I & II, Babcock and Wilcox, May 7, 1979.

3. "GPUSC Safety Evaluktion Report for Three Mile Island Unit 1 Cycle 5 Reload," dated March 1979.

4. Letter, Met-Ed (J. G. Herbein) to USNRC (R. W. Reid) on "High Pressure Trip and Pressurizer Code Safety Valve Settings," GQL-0669, April 17, 1978.

5. " Supplement No. 2 to the Safety Evaluation Report by the office of Nuclear Reactor Regulation, Three Mile Island Nuclear Station Unit No. 2 Docket Number 50-320," USNRC, NUREG 0107, dated February,1978.

6. Letter, Met-Ed (J. G. Herbein) to USNRC (S. A. Varga), on " Analysis of Fuel Performance During a Steamline Break for Dil-2," License No.

CPPR-66, Docket No. 50-320, dated November 18, 1977.

7. Letter, Met-Ed (J. G. Herbein) to USNRC (S. A. Varga), on " Response to Staff Questions on Analysis of Fuel Performance During a Steamline Break," dated December 9,1977.

8. Letter, Met-Ed (J. G. Herbein) to USNRC (R. W. Reid) on "TMI-1 Fuel Handling Accident Inside Containment," GQL-0460, dated April 20, 1977.

9. Letter, USNRC (R. W. Reid) to Met-Ed (J. G. Herbein), dated February 4, 1979.

10. Letter, Met-Ed (J. G. Herbein) to USNRC (R. W. Reid) on "TMI-I Fuel Handling Accident Inside Containment, "GQL-0460, dated May 8,1979.

11. ECCS Analysis of B&W's 177-FA Lowered Loop NSS, BAW-10103, Rev. 2, Babcock & Wilcox, April 1976.

12. USNRC to Met-Ed " Order for Modification of License," Docket No. 50-289, May 19, 1978.

13. Letter, Met-Ed (J. G. Herbein) to USNRC (R. W. Reid), on "Small Break LOCA," GQL-0809, May 3, 1978.

14. Safety Evaluation and Environmental Impact Appraisal by the Office Nuclear Reactor Regulation, Supporting Amendment No. 65 to Facility Operating License No. DPR-47, Amendment No. 62 to Facility Operating License No. DPR-55 Duke Power Company, Oconee Nuclear Station, Units Nos.

1, 2 and 3, Docket Nos. 50-269, 50-270, and 50-287, October 23, 1978.

15. THI-I Fuel Densification Report, BAW-1389, Babcock & Wilcox, June 1973.

8-20 4 Am. 6

REFERENCES - (Cont 'd)

16. GPUSC Safety Evaluation Report of B&W's TMI-1 Cyc1c 4 Reload Report, dated January 13, 1978.

17. GPUSC Safety Evaluation of B&W's TMI-1 Cycle 3 Reload Report, dated January 21, 1977.

18. Of fice of Standards Development, U.S. Nuclear Regulatory Commission, Regulatory Guide 1.70, " Standard Format and Content Guide, Rev. 3, LWR Edition.

19. " Order and. Notice of Hearing, Docket 50-289," dated August 9, 1979, USNRC.

20. "TMI-2 Lessons Learned Task Force Status Report and Short-Term Recom-mendations, NUREG-0578, July 1979.

21. Michelson, C. " Decay Heat Removal During a Very Small Break LOCA for a B&W 205-Fuel Assembly PWR". January, 1978.

22. Winks, Robert W., Analysis of the Requirements for Loss-of-Electrical-Load Transient at TMI-1. Babcock & Wilcox. October 28, 1975.

23. Winks, Robert W., Final Report on Phase 1 (Turbine Trip Test) and Evaluation for Phase 2 Testing for the Loss of Electrical Load Capa-bility at TMI-1. Babcock and Wilcox, May 20, 1975.

24. McFadden, J. F. , R. D. Hentzen, J. F. Harrison, N. S. Burrell. RETRAN-A Program for One-7imensional Transient Thermal-Hydraulic Analysis of Conplex Fluid Flow Systems: Volume 4: Applications, pp 72 thru 83 EPRIC-CCM-5. Palo Alto, California, December, 1978.

25. Harrison, J. F., N. G. Trikouros, A. A. Irani. "RETRAN Simulation of the Three Mile Island Unit 1 Turbine Trip Test." American Nuclear Society Transactions, Vol. 32, pp 455-459.

26. Denver, D. J., J. F. Harrison, N. G. Trikouros. "RETRAN Natural Circula-tion Analyses During the Three Mile Island Unit 2 Accident." General Public Utilities, Parsippany, N.J. November 1, 1979.

1438 051 8-21 Am. 6

TABLE 8-2 KEY INPUT PARA}ETERS FOR LOFW ANALYSIS B&W B&W Revised Parameter Generic Study (Ref. 2) (Q3, Supp. 1, Part 2) TMI-1 Reactor Coolant System Reactor powcr. MWt 27/2 (100% FP) 2772 2619 (102%)

Decay heat 1.0 ANS 5.1 1.2 ANS 5.1 System pressure, psig 2185 (core outlet) 2192 RCS coolant flow, % design flow 108.0 106.5 Reactor temperature, F Inlet 557 555 Average 582 579 Outlet 607 603 Configuration Lowered Loop Lowered Loop Lowered Loop Pressurizer Operating level, in. 220 220 Volume, ft3 Steam 708 708 1529 (total)

Water 800 800 Operating pressure, psig 2155 2157 Code safety valves Number 2 2

_ Flow area, in.2 3.34 5.09 3 Valve capacity, Ib/s-ft2 u Liquid Co Steam 8,130,000 lbm/hr.

@ 2600 psig CD Setpoints, psig W Open 2500 2500

'N Close 2460 ~ 2475 PORVs Number 1 1 Flow area, in.2 1.05 1.05 f Valve c.apacity, Ib/s-f t Liquid Steam 112,000 lbm/hr Setpoints, psig "

Open 2450 2450 Close 2400 2400

TABLE 8-2 (Cont.)

B&W B&W Revised l Parameter Generic Study (Ref. 2) (Q3, Supp. 1, Part 2) TMI-1 Reactivity Feedback Doppler coefficient, ak/k'F -

-5 Moderator coefficient, Ak/k*F -1.56x10f

-1.05 x 10- 0 -1.47 x 10 _4(BOC)

-0.77 x 10 (

BOC)

Reactor Protection High RC ressure trip setpoint, 2300 2300 2300 psig a) liigh RC pressure trip delay, s 0.4 1.0 ~ 0. 3 Auxiliary Feedwater b

Flow, gpm 1000 370 740 1160 Pressure, psig N/A 1000 1030 700b Time delay, sec. 40 35 35 Steam Generators Inventory, Ibm per OTSG 18,400 18,400

(* As measured at hot leg tap.

{

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g failure of the motor-driven recirculation line.

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pPPENDIX 8A RETRAN/GPU-01 ANALYSIS OF TMI-1 1438 054 Am. 6 s

. - _. ..e J

APPENDIX 8A Introduction As discussed in response to Question 39, Supplement 2, Part 2, GPU has embarked on an analysis of the TMI-1 plant response using RETRAN/GPU-01. This code is a modification of the RETRAN (see Reference 24) one-dimensional thermal hydraulic analysis code developed for the Electric Power Research Institute.

Model Description Two basic models have been developed for TMI-1. The first is the one-loop model shown on Figure 8A-1. This nodalization scheme has been developed to provide relatively detai'_ed analysis results for cases when non-symetric secondary effects are not important. The second model is shown on Figure 8A-2.

This model provides a representation of the RCS and secondary system as a two loop model. A nodalization of this type allows the modeling of non-symetric effects in either the RCS or secondary systems.

The control systems for both models are the samq,with the exception that secondary system controls are modeled separately for each secondary system. RETRAN/GPU-01 models all of the reactor protective system and SFAS trips and initiating signals. The model also initates SFAS on loss of all four reactor coolant pumps and 20% voiding at the pump inlet. Secondary system pressure control is explicitly modeled to separate the effects of the turbine bypass, atmospheric exhaust, and safety valves. Feedwater and emergency feedwater are terminated upon initiation of a feedwater latch signal (600 psig in the steam generator). The emergency feedwater system is modeled to separate the motor driven and steam driven pumps, with diesel generator load sequencing and mechanical flow coast up accounted for in each system, separately. Emergency feedwater is initiated by the RETRAN trips when an initiating condition is sensed. OTSG IcVel is controlled at a low or liigh IcVel, depending upon the availability of the RCS pumps.

The llPI/ makeup system is also modeled explicitly. The normal makeup pump controls pressuri:er 1cvel at the normal set point of 220 inches via the makeup control valve (MU-V17) . Upon SFAS initiation, normal makeup is isolated and ilPI is initiated, with flow varying with RCS system backpr 'sure.

Proposed Analyses Table 8A-1 lists the analyses which we intend to undertake using RETRAN/GPU-01.

There are four basic accidents / transients of interest: loss of feedwater, loss of offsite power, station blackout, and feedwater line break, h'c may also perform steam line break analyses if a suitable model can be developed.

None of the above analyses are intended for use in support of the TMI-1 restart e ffort . Ilowever, other analyses may be performed as docket analyses in the future.

1438.055

The scope of analyses is intended to provide a more detailed understanding of the overall plant response to a broad spectrum of likely design basis transients.

Analysis Results To date, several analyses have been completed. Results are discussed briefly below.

Figure 8A-5 provides results of the baso case loss of feedwater transient.

No equipment failures are assumed and no operator action is taken. The reactor trips as a result of the loss of fcedwater trip. The analysis was terminated after 10 minutes. Hot and cold Icg temperatures have converged, and pressuri:cr level is being restored by the normal makeup pump. Pressurizer spray is actuated very briefly, while the RCS pressure never approaches the PORV setpoint.

Emergency feedwater initiates as a result of the loss of feedwater pumps. Both the motor driven and the steam driven pumps achieve full flow, and flow is automatically controlled to maintain OTSG Icvel at 30 inches in the startup range. Secondary system pressure is limited by the safety valves, atmospheric exhaust valves, and turbine bypass in the first 50 seconds, and by the turbine bypass valves thereafter.

Figure 8A-6 provides results of a loss of feedwater event with an EFW system which has flow limiting devices. Two motor driven pumps run, but flow is limited to 740 gpm. The analysis was carried out until the plant achieved stabic conditions: RCS temperature and pressure were constant, pressuri:er 1cvel was restored, the secondary side heat sink was provided via the turbine bypass system. As can be seen from the "PSAT meter graph", the subcooled condition of the RCS was never challanged.

Figure 8A-7 provides results of the base case station blackout. After one hour, RCS cenditions have still not converged, i.e., hot leg temperature and RCS pressure are still decreasing and pressurizer level is about to go off scale (although the pressuri cr would not be empty). As in the other analyses, no operator actions were assumed, and no additional failures were imposed.

The analysis does provide some indication of the time frame for operator actions te restore onsite AC power.

1438 056

. _ - . ___ . . _ . - . - - - - -.a

TABLE 84-1 PROPOSED PF RAN/GPU-01 ANALYSES OF T!'I-l I. Loss of Offsite Power (LOOP)

Case 1: Base Show plant response to LOOP and transition to natural circulation.

Case 2: 1940 gpm EFW and 1% Examine overcooling potential with decay heat (max cooldown case) 200% EFW and minimum decay heat.

Case 3: Stuck open OTSG safety Exacine plant performance for valves (17% of design flow) first 10 minutes of secondary side depressurization ueing one OTSG model.

Case 4: EFW flow limitation Examine long-term plant response with EFW flow limitation and LOOP from 100% power.

Case 5: 1% decay heat with EFW Examine effect of flow limiters in flow limitation EFW system on max cooldown case.

Case 6: 2 OTSG model with stuck Evaluate efftet of non-symetric open relief valves cooldown on secondary side.

Case 7: 2 OTSG model & no EFW Evaluate non-symetric loss of heat to 1 OTSG sink.

Case 8: EFW in superheat region Evaluate effect on transition to natural circulation of putting EFW into superheat region rather than downcomer.

Shows more realistic plant response.

II. Station Blackout Case 1: Base Look at long-term plant response to event, including voiding in the RCS LOOP.

Case 2: 1 gpm pressurizer leakage Effect on plant response due to cool-and min. decay heat down of pressurizer steam space.

Case 3: Raise atmospheric exhaust Evaluate efficacy of blackout procedure, setpoint which calls for this action.

1438 057

TABLE 8A-1 (Cont.)

III. Loss of Feedwater Case 1: 460 gpm EFW Flcw Examine plant response to operation of only one motor-driven EFW pump.

Case 2: EFW flow limitation Look at plant transition to stable shutdown with EFW flow limited.

Case 3: 1940 gpm Contrast performance against EFW flow limitation.

Case 4: Failure of EFW 1evel Evaluate effect of continuous EFW control flow causing overfill of OTSG.

Case 5: Trip from low power and Look at plant response below turbine min. decay heat trip threshold.

Case 6: Case 2 or TMI-2 in 2 OTSG Compare 1 & 2 LOOP results.

model Case 7: Partial LOFW Compare response to complete LOFW &

evaluate ICS response.

Case 8: No EFW Look at time available before HPI must be initiated.

Case 9: Turbine stop valve fails Limiting overcooling case following open a LOFW.

Case 10: Manual actuation of HPI Look at effect on pressurizer level of operator initiating a second HPI pump immediately after reactor trip.

IV. Feed Line Break Accident Case 1: EFW initiation on feed / steam Demonstrate plant can tolerate the AP design basis feedline break accident.

Case 2: EFW initiation on low Evaluate timeliness of this signal OTSG level for feedline break, Case 3: Partial break which causes Determine if operator response is as gradual loss of OTSG level can be reasonably expected.

and no feed / steam AP signal kkb0

TABLE 8A-1 (Cont.)

V. Steam Line Break Accident Case 1: Benchmark of TMI-2 docket Establish benchmarked code for analysis use on TMI-1.

Case 2: TMI-1 design baais analysis Demonstrate means required to establish long-term safe shutdown.

Case 3: Break from startup condition Determine if startup from low with flooded nozzles OTSG level is necessitated by safety Concerns.

1438 059

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11.0 TECHNICAL SPECIFICATIONS

11.1 INTRODUCTION

A considerable number of plant modifications are being accom-plished in response to TMI-2 Lessons Learned (NUREG-0578), the TMI-l Order and Notice of Hearing - August 9, 1979, in Bulletins, and Met-Ed's review of the TMI-2 accident. The hardware modifi-cations 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 not formerly discussed in the TMI-l Technical Specifications. These new Technical Specifications to be provided are discussed in Section 11.2.

Formal requests to modify the TMI-l Technical Specifications will be forwarded separately for each area covered in Section 11.2 since certain committee review requirements of the existing Technical Specifications must be completed before final submittal.

11.2 TECHNICAL SPECIFICATION CHANGES 11.2,1 Auxiliary (Emergency) Feedvs.er ( AFW)

The importance of the AFW System was demonstrated during the TMI-2 accident, therefore, Limiting Conditions for Operation and Surveillance requirements are appropriate.

A LCO will be provided requiring an AFW flow path to each Steam Generator (SG) be available at 100% capacity. If a flew path becomes unavailable or if the capacity drops below 100% to either SG, the plant shall be shutdown within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> and placed in a condition not relying onf SG's for cooling within 12 additional hours. If a flow path is unavailable to both SG's or if a capacity drops below 100% to both SG'S, the reactor will be shutdown within one hour and placed in a coolin; mode not relying on SG's within an additional 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

Appropriate surveillance requirements will be pr)vided to specify flow capacity and flow paths as well as appropriate surveillance of instruments.

11.2.2 Reactor Trip on Loss cf Feedwater or Turbine Trip New Technical Specifications will be provided to imposc appro-priate LCO's and surveillance req:tirements.

11.2.3 High Pressure Trip Setpoint Red etion Technical Specification Changes will be proposed reducing the existing setpoint (2390 psig) to 2300 psig.

11.2.4 Containment Isol.' ion Setpoints The existing Technical Specifications will be changed to specify initiation of containment isolation on reactor trip.

1438 095 11-1 Am. 6

SUPPLE 5fENT 1, PART 1 1438 096

QUES! ION:

3. Provide the results of the detailed loading study on the diesel generators that confirm the acceptability of adding the AFW pumps. Provide your schedule and a description of the actual testing planned.

RESPONSE

The engirecred safeguard diesel generator loading sequence table (Table 3-1 attached) represents the heaviest loading on one diesel generator (D/G) in the event that the redundant D/G failed to start. The total automatic loading of the D/G, including the new loads as described in the Table 3-1 notes, is 2807 kilowatts. This total also includes the reactor building spray pump load which is actuated only when the containment pressure exceeds 4 psig.

The valve operator loads are non-continuous and will have been removed within approximately two minutes after actuation. Thus, the D/G load Nill reduce to 2716 kilotwatts.

Manual loads M-3, 4, 5 and 7 are actuated within 30 minutes increasing tue maximum D/G load under an engineered safeguard actuation to 2913 kilowatts.

For a loss of offsite power situation only, the total automatic D/G load is 1859 kilowatts (see Items 1-2, 1-3, 2-1, 2-2 & 4-1). All necessary manual loads, as described in Table 3-1 notes, can then be actuated. Under these conditions, she maximum D/G load is 2817 kilowatts.

In this study, no credit has been taken for reduction in pumping power re-quirements that occur with time following a LOCA. Likewise, no credit has been taken for operation of an engineered safeguard function at less than 100 percent capacity, i.e., diverse engineered safeguard functions were considered to be running at 100 percent simultaneously. Thus, the total required D/G loading is less than the diesel generator 2000 hour0.0231 days <br />0.556 hours <br />0.00331 weeks <br />7.61e-4 months <br /> rating of 3000 kilowatts.

Startup testing will be conducted in order to verify the diesel load sequence.

This testing will be conducted using an appropriately modified version of the preoperational startup test procedure. This procedure will be provided for NRC review by February 1, 1980.

[kbb Am. 6

TABr.E 3-1 Engineered Safeguard Diesel-Generator Loaling Sequence Total Total Loading Item Rated Total Load Sequence No. Quantity Description Notes HP or KW BIIP Eff KW Auto Load Block 1 1-1 1 Makeup Pump (Iligh Pressure Inj.) 1 700 HP 700 0 93 562 1-2 1 Decay IIeat Pump (Low Pressure Iaj.) 3 350 IIP 3ho 0.92 276 1-3 Lot Miscellaneous Valves 2 91 KW 91 1-h 3 Inverters 1" h5 KW 35 KW 0.78 h5 Lot Miscellaneous Loads 1 372 KW 372 1-5 2 Battery Chargers 1 37.5 KW 37 5 KW 0.8 47

$e Auto Load p Block 2 2-1 2 Reactor Building Ventilation Units 3 150 HP 92 09 76

. 2-2 1 Reactor Building Emergency Cooling River Water Pump 3 400 HP 380 0 92 308 Auto Load dD*

Block 3 3-1 1 nuclear Services closed Cooling

( 3-2 1 Pump Huclear Servicer River Water 1 125 HP 115 0.91 9h CZ) Pump 1 150 HP 150 0.92 122 syy 3-3 1 Decay Heat Closed Cooling Pump 1 100 HP 91 0.91 75 Cx) 3h 1 Decay IIcat River Water Pump 1 200 IIP 180 0.91 148 Auto Load Block h h-1 1 Reactor Building Spray Pump 10 250 IIP 2h0 0.91 197 h" h' 1 Air Cool F. for Dil & USP AlIE-15 1 3 IIP 3 0.72 3 h-3 1 Screen House AIIU Al!E-2T 1 15 IIP 35 0.9 13 CN h-4 1 Screen llouse Vent. Equip. Pump SW-P-2A 1 15 IIP 15 0.9 13

TABLE 3-1 Engineered Safeguard Diesel-Generator Loading Sequence (cont'd.)

Total Total Loading Item Rated 'Iot al Load Sequence Ilo . Quantity Description Ilotes IIP or KW B1IP Efr KW Auto Load Block 5 5-1 1 Dnergency Feedwater Pump 1,1 4 1450 lip 150 4 0 92 365 TOTAL AUTO LOAD 2807 y Manual g loads M-1 1 Instrument Air Compressor 8 60 HP 0.91 149 M-2 1 Spent Fuel Pump 8 10 HP 4 0.9 33 M-3 1 Control Building Dnergency Supply Fan 7 50 HP 0.9 I:1 M14 1 Control Building Exhaust Fan AIIE-19 7 10 HP 0.85 9 M-5 1 Control Building Chiller T 130 EW 130 M-6 1 Penetration Cooling Fan 8 75 llP 0.9 62

- 20 IIP M-7 1 Chilled Water Supply Pump 7 0.89 17 A M-8 1 Spent Fuel Pump Cooling Fan 8 2 IIP 0.82 2 U M-9 1 Turning Gear Motor 9 60 HP 0.9 50

@ M-10 1 Borie Acid Pump 11 2 IIP 0.82 2 g M-ll Is MSVlA, B, C, D 2 145 HP 0.9 37 g M-12 Lot Pressurizer Heaters 5,9 126 KW 126 w M-13 1 Post LOCA Hydrogen Recombiner 6 145 KW 15 4

g M-lls 3 Turb. Oil Lift Pumns 9 30 KW 0.87 316 M-15 1 Turning Gear Lube Oil Pump 9 50 HP 0.9 lil m M-16 1 Backup Inst. Air Comp. 12 5 HP 0.82 8

NOTES

1. Loaded for loss of offsite power with or without ES actuation-1.* Including estimated new inverter loads.

2. Ucn-Continuous operation (i.e. operates for short time only and tae.

is automatically turned off) .

3. Manually turned off on loss of offsite power only.

h. Ucv autcmatically started load.

5 New manually started load within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> of loss of offsite power only.

6. New manually started load approximately one day aft-r an ES actuation.

7 Manually started loads within 30 minutes with or without an ES actuation.

8. Manually started loads contingent upon D/G capacity.

9 Manually started loads locked out on ES actuation.

10. Started only upon ES actuation by Reactor Euilding pressure of 6reater than 4 psi.

I'. Backup to borati n source.

12. Starts on loss of instrument air compressor.

1438 100 Am. 6

RESPONSE TO APPENDIX A, QllESTION la The design basis event for sizing the Auxiliary Feedwater System (AFWS) is Loss of Feedwater (LOFW) with a concurrent Loss of Offsite Power (LOOP),

and subsequently loss of reactor coolant pumps. The pertinent parameters for this accident relative to the AFWS are design flowrate and required time to full AFWS flow. These parameters reflect the functional requirements of the AFWS to a) remove decay heat, and b) provide a smooth reactor coolant flow transition from RC pump operations to natural circulation. The design values which resulted from this analysis are 720 gpm deliverable to the steam generators within 40 seconds of the initiation signal. The 40 second time was chosen to allow the AFWS to inj ect feedwater and begin increasing '

SG level to the 507. operating range level, required for natural circulation, prior to completion of the RC pump coastdown. At that time, the design flowrate was selected to be equal to or greater than the decay heat generation rate. Since decay heat rate changes with ti,c, other values than 40 seconds and 720 gpm could have been used and been acceptable. All other transients which either require or assume the availability of AFW in the Safety Analysis use the design values derived from the LOFW analysis. The results of these other analyses are acceptable and are referenced in Table 1 attached.

Accidents 1, 2 and 3 of Table 1, which specifically require AFW for mitigation, were analyzed using the AFWS performance criteria established by the LOFW accident. The results of these analyses were acceptable and are described in the FSAR sections noted in Table 1. The other accidents listed in Table 1 (4-12) do not require AFW for mitigation though the availability of he AFWS, as defined by tha performance critcria established by the LOFW accident, is ascumed. The results of those analyses were acceptable and are described in the FSAR sections noted in Table 1.

Addressing the events included in the NRC Appendix A question la which have not been included in Table 1, we have the following comments:

LMFW w/ loss of onsite and offsite AC power - This event wac not a design basis of the plant and, consequently, is not included in Chapter 14 of FSAR.

Plant Cooldown - Plant cooldown with AFW is a new issue as stated in Reg.

Guide 1.139 and not a design basis for this plant. The NRC has not indicated how Reg. Guide 1.139 is to be applied to operating plants. The extent of plant cooldown for which the AFWS is designed is discussed in FSAR Section 14.1.2.8.3d.

Turbine Trip with and without bypass - This event does not af f ect the AFWS unless MFW f ails in which case the loss of MFW event previously addressed would bound the AFWS desir Main Steam Isolation Valve Closure - Again, this event does not directly affect the AFWS unless MlOl is lost as discussed above.

khb

. .....h

Main Feed Line Break - This event was not a required analysis for this plant and is not included in FSAR Section 14. Main Feedline Break is a more abrupt case of LOFW and results of an analysis would be -pproxi-mately the same.

Small Break LOCA - The AFW criteria assured for this event is described in Topical "eport RAW-10052 updated by Letter Report J.II. Taylor B&W to S.A. Varga NRC 7/16/78 and the recently submitted B&W Report titled

" Evaluation of Transient Behavior and Small Reactor Coolant System Breaks in the 177 FA Plant," 5/7/77.

1438 102

RESPONSE TO APPENDIX A, QUESTION lb The design basis event for sizing the AFWS is LOFW as discussed in response to question la. The acceptance criteria for the other transients which include or assume AFW are given in Table 1.

The RCS cooling rate is not a limit relative to accident acceptance criteria.

The safety limit for all transients which use AFW 'or mitigation is that the core remain cooled with ultimate acceptance criteria being those addressed in Table 1. For transients which result in draining the pressurizer or for ehich natural circulation is slowed or interrupted, restoration of pressurizer level and subcooling is accomplished by swelling due to core heat input and inventory restoration by HPI.

Steam Generator level is not based on decay heat removal rate or cooldown capability. SG level is set low for decay heat removal and high for natural circulation. It is also set high for Small LOCA as described in Topical Report RAW-10052, and in the B&W Report " Evaluation of Transient Behavior and Small Reactor Coolant System Breaks".

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RESPONSE TO APPENDIX A, QUESTION 2 As discussed in response to la) above, the design basis event regcrding AFWS design requirements is loss of main feedwater with concurrent loss of RC pumps; the analysis assumptions for this event are listed below kaved to the lettera of the question. Corresponding technical justifica-tions where not specifically listed below, is based on licensing require-ments and prudent engineering judgment at the time of the analysis.

a) Max. Rx Power - 100%

b) Time delay initiating event to Rx trip - The reactor will trip on high RCS pressure approximately 5-10 seconds after a LOFW event.

The initiation signal for AFW is loss of main feedwater.

c) AFWS initiation signal and time delay - The AFW initiation signal for the LOFW event is loss of both main feed pumps as sensed by steam inlet valve position on the two main feed pump turbines.

The design basis time delay from initiation event to full flow of AFW flow into SG is 40 seconds.

d) SG level at initiation event - Steam Generator inventory is dependent on power level. In the most restrictive case, AFW will be fed into the steam generators before they boil dry.

e) SG inventory and decay heat - For discussion of water inventory see d) above. Reactor decay heat rate is shown in FSAR Table 14-13.

f) Max. SG Pressure - 1103 psig g) Min. no. of SG - The number of generators was not specified in the analysis, heat removal capability is the pertinent parameter and can be accomodated by 1 SG.

h) RC Flow Condition - Both natural circulation and RC pump operation were analyzed.

1) Max. AFW inlet temperature - The maximum AFW inlet temperature assumed was 90 F.

j) Steam, Feed Line Break time delay - The feedwater line break was not a require 1 analysis for this plant. Refer to FSAR Section 14.1.2.9 for steam line break analytical information.

k) Main Feed Line volume and temperature between SG and AFWS - R/A -

There is not piping connection between the MFWS and AFWS.

1) SG Normal Blowdown - N/A - The OTSG's do not have a blowdown system.

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m) Water and metal sensible heat used - Plant cooldown capability was 6

not a design basis for AFWS. lx10 BTU / F was used for removal of sensible heat from power operation to the 0 power reactor trip set-point, n) Time at hot standby etc. relative to AFW inventory - The AFW in-ventory was sized for decay heat removal for 1 day af ter Rx trip as discussed in FSAR Section 14.1.2.8.3d. The design basis for AFWS is not plant cooldown; the NRC Reg. Guide 1.139 requirements for operating plants 5 ave not yet been established.

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TABLE 1 (1)

ACCIDENT DESCRIPTION FSAR SECTION ACCEPTANCE CRITERIA

1) Loss of Coolant Flow 14.1.2.6 A, B

2) Loss of Electric Power 14.1.2.8 A, B

3) Steam Line Break 14.1.2.9 D

4) Uncompensateu Operating Reactivity 14.1.2.1 A, B Changes

5) Start-Up Accident 14.1.2,2 A, B

6) Rod Withdrawal Accident at Rated 14.1.2.3 A, B Power Operation

7) Moderator Dilution Accident 14.1.2.4 A, B

8) Cold Water Accident 14.1.2.5 A, B

9) Stuck-Out, Stuck-In, or Dropped 14.1.2.7 A, B Control Rod Accident

10) Steam Generator Tube Failure 14.1.2.10 B, D

11) Rod Ejection Accident 14.2.2.2 C, D

12) Loss of Coolant Accident 14.2.2.3 D, E NOTE: (1)

KEY ACCEPTANCE CRITERIA TECHNICAL BASIS A Max. RCS Press. - 110% Design ASME Code B 1.3 with BAW-2 ,

SRP 4.4 C 200 cal./ gram fuel limit Reg. Guide 1.77 D Acceptable Doses 10CFR100 E Fuel Cladding 2200 " 10CFR50.46 1438 106

RESPONSE TO QUESTION 17, SUPPLEMENT 1, PART 1 Reactor Coolant System Pressure (h

'7 The pressure detectors are of the diaphram type and are located on the hot legs. Narrow range pressure,1700psig to 2500psig, for each loop is recorded on a strip chart located on the operator's console. Wide range pressure from Opsig to 2500psig is recorded on a strip chart located beside the narrow range recorders.

Reactor Coolant Flow The flow detectors are of the gentilli flow tube type in conjunction with a differential pressure instrument. There are four detectors located in each hot leg for a total of eight. Loop A and Loop B flows are displayed on vertical indicators located on the control console and total RC flow is recorded on a strip chart recorder.

Source Range Nuclear Instrumentation There gre two 9F3 proportional neutron detectors installed with a range from0.1 cps to 10 cps. A vertical indicator on the control console and a strip chart recorder above the console provide source range measurement in counts per second.

Reactor Coolant Pump Current The RC pump motor current is indicated on console cc. The arreters are scaled from 0 to 150% of full load current and are located adjacent to the respective RC pump control switches.

Analysis is being performed to develop additional guidelines that allow the reactor operator to recognize and respond to conditions of inadequate core cooling under the following conditions:

,.. a) Loss of RCS inventory with the reactor coolant pumps operating.

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' b) Loss of RCS inventory without reactor coolant pumps operating.

c) Loss of the Decay Heat Removal System.

d) DNB Transient at Power From these analysis guidelines for operator action and a description of the plant behavior for operator training will be developed. Additional procedural changes developed as a result of these analysis will be implemented within 30 days following the analysis.

Training in instrument response to various accident conditions that include inadequate core cooling is as follows:

(1) Prncedures review (2) Expected instrument and plant response to transients (3) Safety analysis work shop (4) TMI Control Room practical session The lectures will address existing unmodified instrumentation as well as the short term modification to existing instrumentation.

\h Am. 6

SUPPLEMENT 1, PART 2 1438 108 2%- e 4

QUESTION

1. Your response to Questions 1 and 10k are not complete.

A. Provide design drawings for the automatic EFW initiation modifications and provide "as-built" electrical drawings of the present EFW initiation syrrem design.

B. Provide the test plan (proctdure) and results for the proposed EFW initiation functional test.

C. Update Section S.2.1 of the Restart Report to clarify what automatic EFW initiation signals will be control grade and what signals will be upgraded to safety grade requirements. It is our pos.i tion that you have not adequately demonstrated that installation of safety-grade automatic EFW initiation signals (including low steam generator level) is not practicable prior to restart.

RESPONSE

A. Design drawings for the automatic EFL' initiation modifications were provided during a meeting on November 19, 1979, to R. Fitzpatrick and S. Newburry of the NRC. The drawings sub-itted were:

SS-208-129 SS-209-564 SS-208-163 S5-209-565 SS-208-164 SS-209-590 SS-208-168 SS-209-591 SS-208-169 SS-209-660 SS-208-203 SS-209-661 SS-208-204 SS-209-662 SS-208-206 SS-209-663 SS-209-C31 SS-209-664 SS-209-032 SS-209-665 SS-209-463 SS-209-666 SS-209-464 SS-209-667 SS-209-465 S5-209-755 SS-209-490 SS-209-756 SS-209-491 SS-209-919 SS-209-563 SS-209-923 B. The test procedure will be submitted prior to restart testing and the test results will be submitted af ter completion of the tests.

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C See Section 8.2.1. Engineering and procurement for a safety grade actuation system has been proceeding in parallel with that for t e control grade system. It is scheduled for installation (without a low steam generator signal) by March 21, 1980. If plant start-up procedures commence subsequent to that date, the safety grade system will be available before start-up. Engineering for the addition of a low steam generator signal will be completed March 1, 1980.

Long lead time items will be ordered by January 15, 1980. Delivery of safety grade transmitters and other instrumentation is anticipated to be 14 to 16 weeks. Installation should be completed by June 1, 1980

QUESTION

2. Your response to Question 9 is not complete. Answer the indicated concerns. In addition:

A. Provide design drawings of the modified instrument air system.

B. Provide the test plan (procedure) and results for the proposed EFW control valve failure mode verification test.

C. Provide the BGW evaluation on the consequences of overfilling the steam generator.

D. Provide the calculations which indicate that operator action is required within 7 to 15 minutes to prevent potentially adverse steam generator overfill conditions. Include sufficient information to allow us to identify the allowable tima delay beyond which the consequences would produce unacceptable effects.

Describe each manual action required.

E. Provide the revised procedures for preventing steam generator overfill conditions, and indicate that adequate operator training in these procedures has been completed.

RESPONSE

A. The design drawings of the modified instrument air system were provided to R. Fitzpatrick and S. Newburry of the NRC during a meeting on November 19, 1979. The drawings submitted were:

ECM Package WO-023 D-215-044 S-212-007 CH1102 E-215-053 S-212-007 CC1059 E-215-013 SS-208-712 E-215-011 B-210-527A C-302-271 B-210-528A C-302-272 B-201-044 E-304-275 B-201-043 E-304-277 B. The test procedure will be submitted prior to restart testing and the test results will be submitted after completion of the tests.

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C. "An overfill condition occurred at Rancho Seco in March of 1978. Analysis performed by B&W and others, including detailed stress analysis, on the conseqaences of this incident revealed that no unacceptable damage to the steam generators, steam liners or other equipment had occurred and the the Unit could return to services without any major repairs. The Rancho Seco overfilling incident, therefore, provides assurance that no unaccep-table consequences (i.e. steam generator rupture or main steam line break condition) will result from inadvertent overfilling. To verify these conclusions are valid for TMI Unit #1, a stress analysis will be performed on the consequences of flooding the TMI Unit #1 Main Steam line. The results of deadweight internal pressure and thermal expansion analysis will be provided by December 14, 1979. The possibility of transient hydraulic phenomena in the main steam line will be investigated and provided prior to start-up.

D. The times provided by B&W for steam generator overfill were based or.

calculations perfi rmed for B&W's generic 205 FA plant design and assumed flow rates aa hig;i as 1600 gpm to one steam generator. Based en above it has been concluded that a plant specific calculation should be performed and provided for your review. This evaluation will consider the specific pump and system arrangement installed at TMI-1 and the fact chat the TMI-1 system can not deliver flow rates as high as that t .umed in the 205 FA calculations. It is expected the TMI-l specific calculations will demonstrate that times on the order of 10 minutes are available for operator action. The plant specific calculation for TMI-1 will be provided by December 12, 1979.

Based on the flow instrumentation and level instrumentation available to the operator, the back-up controls and instrument air supplies that have been provided for the auxiliary feedwater control valves and key components, and the reasons discussed below, reliance on operator action to prevent steam generator overfill conditions is considered warranted. For the long term, the emergency feedwater system will be upgraded to meet safety grade criteria and further reduce the probability of steam generator overfill. The conceptual design for our long-term design changes and our schedule for accomplishing these changes will be provided by January 4, 1980. Due to the extent of the changes required, it is not expected that these changes can be completed prior to start-up.

The TMI Unit #1 Integrated Control System (ICS) is designed to control auxiliary feeduater flow to preset steam generator levels. If Reactor Coolant pumps are available the ICS will control steam generator level to 30 inches on the start-up. If RC pumps are not available, the ICS will then control steam generator level to 50% of the operating range level. If automatic level control is not achieved or if overcooling conditions start to occur, operator will take manual control of the energency feedwater control valves, EF-V30 A & B, using either the ICS manual controls or the back-up manual control station provided in the control room.

In the extremely unlikly event that control of EF-V30 A/B cannot be obtained from the control room, the operator has several other means to control auxiliary feedwater flow and steam generator level from the control room. These are as follows:

1) The motor driven emergency feedwater pumps can be started and stopped from the control room.

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2) The flow of auxiliary water from the turbine driven pump can be controlled using motor operated EFW valves EF-V-2 A/B. These valves are powered from 480V Engineered Safeguards Control Centers and the controls available in the control room.

3) If necessary, the turbine driven emergency feedwater pump can be stopped using Main Steam valves MS-V13 A/B. The controls for these valves are available in the control room. MS-V13 A/B are powered using instrument air and control power from 125 volt vital power sources. Valves MS-V13 A/B also receive instrument from the back-up instrument air system.

At the time it is determined that remote control of EF-V30 A/B is not available, an auxiliary operator will also be dispatched to the inter-mediate building to take local control of the emergency feedwater control valves.

The TMI Unit #1 operating procedures will be modified prior to restart to reflect the overfill potential and actions to be taken to present over-filling the steam generator.

E. The procedure revisions for preventing steam generator overfill conditions are in the draft stage and have not completed the review and approval process required by Adsl.listrative Procedure #1001.

The draft procedure revisions instruct the operators to:

l' Take manual control of EF-V30A/B from the control room as appropriate on high OTSG level to prevent overfill.

2) If control of EF-V30A/B is not available due to loss of control power on instrument air, then an auxiliary operator, in communica-tion with the control room, takes manual handwheel control of EF-V30A/B to prevent overfill.

3) If sufficient time does not exist for the auxiliary operator alone to prevent overfill, the control room operator takes immediate action to stop EFW flow to the high OTSGs by shuting the EF-V2A/B valves, as appropriate, or by stopping the appropriate EFW pumps from the control room until local manual control of the EF-V30A/B and OTSG 1evels can be established.

When the procedure revisions are approved, adequate operator training in these procedures will be completed.

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QUESTION

3. Your response to Question 8 is not complete. Provide the B6W study on transients such as loss of feedwater and loss of offsite power which verify that minimum EFW flow requirements meet the 550 gpm technical specification commitment. Pr3 vide the revised TMI-1 Technical Specifications for our review prior to restart. Justify the appilcability of the B6W study to TMI-1.

RESPONSE

Attached is the B&W study (document identifier 86-1102587-00) on the auxiliary feedwater flow requirements following a loss of main feedwater.

The analyses performed included the following assumptions:

1) The initial power level at the initiation of transient was 2772 Mwt.

2) The reactivity feedback coefficients used were representative of approximately 100 EFPD operation.

3) The ANS 5.1 decay heat curve was used with a 1.0 safety factor. The key input parameters used are documented in Table 3.2-1 of the B&W Report to the NRC dated May 7,1979 and entitled " Evaluation of Transient Behavior and Small Reactor Coolant System Breaks in the 177 Fuel Assembly Plant." The input parameters assumed in this study are applicable for TMI-l which is only a 2535 Mwt plant. As noted in the B&W study, auxiliary feedwater flow rates as low as 370 gpm were found to provide satis factory performance.

Additional work has also been done by B&W to demonstrate that 500 gpm auxiliary feedwater flow is adequate following upset transients such as the loss of offsite power and the loss of normal feedwater. 'Ihese analysis will be provided in December, 1979. These analysis were based on the following assumptions:

1. The anticipatory trip circuitry is in place and the reactor trips within 1.0 seconds following the loss of normal feedwater flow.

2. The initial power level at the initiation of the transient is 102%

of 2568 Mwt.

3. The highest vorth control rod remains stuck out of the core following a reactor trip such that only a .1% shutdown margin is available.

4. A safety factor of 1.2 is applied to the ANS 5.1 decay heat curve.

5. The moderator coefficient of temperature is zero.

6. The OTSG inventory following the loss of normal feedwater is based on a conservative time history taken from test data. The initial inventory was conservatively assumed to the 18,400 lbm per OTSG.

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7. As with the other analysis the PORC setpoint was assumed to be 2450 psig.

The Technical Specifications for EW will be provided in January,1980.

The acceptance criteria for the minimum auxiliary flow rate were that (1) the pressurizer does not go solid and (2) the electromatic relief valve does not actuate. An auxiliary flow rate of 500 gpm was found to meet these critetia. The assumptions used for these analysis are conservative for TMI Unit #1.

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