ML20080L615
| ML20080L615 | |
| Person / Time | |
|---|---|
| Site: | Three Mile Island  |
| Issue date: | 09/27/1983 |
| From: | Trowbridge G METROPOLITAN EDISON CO., SHAW, PITTMAN, POTTS & TROWBRIDGE |
| To: | Chilk S NRC OFFICE OF THE SECRETARY (SECY) |
| References | |
| NUDOCS 8309300386 | |
| Download: ML20080L615 (57) | |
Text
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DOCKETED SHAW, PlTTMAN, PoTTs & TROWBRIDGE 09PC A PARTNER $Mlp OF PROFESSIONAL COPPORATIONS isoo - sTRE er. ~. ..
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. m. .e September 27, 1983 l WRITER S DIRECT OiAL NuusER 822-1026 Mr. Samuel J. Chilk Secretary U.S. Nuclear Regulatory Commission Washington, D.C. 20555 In the Matter of Metropolitan Edison Company (Three Mile Island Nuclear Station, Unit No. 1)
Docket No. 50-289 (Restart)
Dear Mr. Chilk:
l Please find enclosed copies of the following documents, which include information potentially relevant and material to matters under adjudication in the plant design and procedures phase of this proceeding, which is now before the Commission:
- 1. Letter 5211-83-219, August 15, 1983, H. D.
Hukill, GPU Nuclear, to D. G. Eisenhut, NRC, Auto RC Pump Trip (NUREG 0737, II.K.3.5);
- 2. Letter 5211-83-232, August 23, 1983, H. D.
Hukill, GPU Nuclear to J. F. Stolz, NRC, Long Term EFW Mcds (NUREG 0737, II.E.1.1);
- 3. Letter 5211-83-250, September 7, 1983, H. D.
Hukill, GPU Nuclear, to J. F. Stolz, NRC, i
25*F Subcooling Margin; and 8309300386 830927 .7 P9R ADOCK 03000289 [g G PDR - V
- ~ - , ~ -
SHAW,'PITTMAN, PoTTs & TROWBRIDGE A PAntpetagwip OF pmOFESS40NAL CompomanOhs Mr. Samuel J. Chilk September 27, 1983 Page Two
- 4. Letter 5211-83-243, September 9, 1983, H. D.
Hukill, GPU Nuclear, to J. F. Stolz, NRC, Relief and Safety Valve Testing (NUREG 0737, II.D.1).
Re tfully s itted, ,
i eor e F.
bh w ridge Counsel for License Enclosures cc: Service List i GFT/ lam f
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UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION BEFORE THE COMMISSION In the Matter of )
)
METROPOLITAN EDISON COMPANY ) Docket No. 50-289
) (Restart)
(Three Mile Island Nuclear )
Station, Unit No. 1) )
SERVICE LIST Gary J. Edles, Esqture James M. Cutchin, IV, Esquire Charman Office of the Executive Iegal Director Atanic Safety and Licensing Appeal U.S. Nuclear Regulatory Camtission Board Washington, D.C. 20555 U.S. Nuclear Pegulatory Ccemussion Washington, D.C. 20555 Docketing and Service Section Office of the Secretary Dr. John H. Buck U.S. Nuclear Regulatory Camlission Atanic Safety and Licensing Appeal Washington, D.C. 20555 Board U.S. Nuclear Regulatory Camussion John A. Levin, Esquire Washington, D.C. 20553 Assistant Cbunsel Pennsylvania Public Utility Camtission Dr. Reginald L. Gotchy P.O. Box 3265 Atanic Safety and Licensing Appeal Harrisburg, Pennsylvania 17120 Board U.S. Nuclear Regulatory Camussion Ihlglas R. Blazey, Esquire Washington, D.C. 20555 Chief Counsel Department of EnvircrInental Resources Ivan W. Smith, Esquire 514 Executive House, P.O. Box 2357 CN i =m Harrisburg, Pernsylvania 17120 Atanic Safety and Licensing Board U.S. Nuclear Regulatory Comission Ms. Iculse Bradford
. Washingtcn, D.C. 20555 'IMI ALERT 1011 Green Street Dr. Walter H. Jordan Harrisburg, Pennsylvania 17102 Atanic Safety and Licensing Board Panel Ellyn R. Weiss, Esquire .
881 West Outer Drive Hannon & Weiss Oak Ridge, Tennessee 37830 1725 Eye Street, N.W., Suite 506 ,
Washington, D.C. 20006 j Dr. Linda W. Little I Atanic Safety and Licensing Board Steven C. Sholly Panel Union of Con rned Scientists 5000 Hennitage Drive 1346' Connecticut Avenue, N.W. , Suite 1101 Raleigh, North Carolina 27612 Washington, D.C. 20036
Jordan D. Cunningham, Esqture 2320 North Second Street Harrisburg, Pennsylvania 17110 ANGRY /'IMI PIRC 1037 Maclay Street Harrisburg, Pennsylvania 17103 William S. Jordan, III, Esquire Harmon & Weiss 1725 Eye Street, N.W., Suite 506 Washington, D.C. 20006 Clauncey Kepford Judith H. Johnsrud Envirormental Coalition on Nuclear Power 433 Orlando Avenue State College, Pennsylvania 16801 Marjorie M. Aamodt R. D. 5 Coatesville, Pennsylvania 19320 1
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GPU Nuclear Corporation
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Post Office Box 480 Route 441 South Middletown. Pennsylvania 17057 0191 717 944 7621 TELEX 84 2386 Writer's Direct Dihl Nurnber:
August 15, 1983 5211-83-219
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Office of Nuclear Reactor Regulation M ) [
Attn: D. G. Eisenhut, Director Division of Licensing g j e
g's i U. S. Nuclear Regulatory Commission ,- ,, !
Washington, D.C. 20555 N ,-
Dear Sir:
Three Mile Island Nuclear Station, Unit 1 (TMI-1) l Operating License No. DPR-50 Docket No. 50-289 Auto RC Pump Trip (NUREG 0737, II.K.3.5)
Our letter of March 31, 1983 (5211-83-017) notified you of our plans te revise the RCP trip criterion from 1600 psig ESAS to 25 F subcooling =argin. This has been acco=plished. Our letter of June 8, 1983 also advised you of our intent to join the B&W Owners Group on this subject to further analyze and quantify the cargins associated with the new criterion we have adopted.
Enclosed is a description of the plan for the sub=ission of the supple = ental infor=ation consistent with the other B&W Owners. GPU will provide the l information consistent with other B&W Owners in May, 1984. i Sincerely, I g
. D. Eukil2 D:. rector, TM1-1 HDH:LWE:vjf cc: R. Conte J. F. Stol:
J. Van Vliet B. Sheron GPU Nuclear Corporation is a subsidiary of the Genera: :ubhe Utilities Corporation
PIM EUR RESOUJIION OF S'.I ACTION ITEM II.K.3.5
" Automatic Trip of Reactor Coolant PLmps" INTROCLCTION The criteria for resolution of NUREG-0737, Item II.K.3.5, " Automatic Trip of Reactor Coolant Pumps", are provided in a letter from D. G. Eisenhut (NRC) to GPU Nuclear on March 4,1983. As discussed in our letter of March 31, 1983, GPUN has revised the PCP Trip Criteria from 1600 psig ESAS to 25'F subcooling margin under 10CFR 50.59. We B&W Owners Group has been formulating a plan to demonstrate compliance with those criteria. Se following represents this overall position and plan.
PLAN FOR TPIAD!ENT OF IC PUMP OPERATION The treatment of reactor coolant pumps during accidents and transients has received extensive attention over the past several years. THE B&W Owners Group has performed analyses evaluating the effe:t of a delayed PC pump trip using Appendix K assunptions during the course of a small break IDCA accident and has determined that an early trip of PC pumps is recuired to show conformance to 10CFR 50.46 for a range of break sizes. Therefore, to be consistent with the conservative analyses performed, it is our position that the reactor coolant pumps should be tripped if indications of a small break IE A exist.
The B&W Owners Group and B&W maintain that it is highly desirable to maintain PC pump operation during non-LCCA events, as an aid in the mitigation of ;
transients. Consistent with this phiolosophy, the concept of subcooling margin was chosen as an indicator fcr the need to trip PC p.=ps. It is our intention to demonstrate that this concept is consistent with our philosophy _ for f handling PC pumps during transient conditions and eglies with the intent of the criteria stated in your letter of March 4, 1953. The sy ptom approach of subcooling margin, developed as part of the Abner .a1 Transient Operating Guidelines Program, is intended to replace the presen: guidelines of tripping solely on the presence of a low IC pressure ESFAS sig.al.
It is the position of the B&W Owners Group and S&W that reactor coolant p=p trip can be achieved safely and reliably by the cpera:cr. It has been determined that a lcss of subcooling margin will occcur for those SEIfCAs where a pump trip is required for compliance with 10CFR 50.46.
-= .__ _
The B&W CLners Group will undertake a program based cn de ateve positions to demonstrate that the concept of subcooling cargin is an appropriate indicator of the need to trip E pumps, yet still allows continued EP operation for steam gevrator tube rectures (SGIR). Tne ccncept of subcooling rargin will be examined for the rcre likely non-IDCA t ansients to dencastrate that under realistic conditicas an indicarica regiring RC pt=p trip is unlikely. ,
This program is also intended to provide the justification for ra:rual FCP trip on indication of loss of subcooling margin. Tripping on loss of subcooling margin will assure pump trip prior tc the development of significant system voids. No attengt will be made to demonstrate acceptability of continued RCP operation during small break conditions. No request for an exenption of 10CFR 50.46 will be made to allow continued IP operation during SECCA.
The specific plan for resolution of th'e RC pump trip issue is structured to address the specific criteria stated in the March 4, 1983 letter. A description of the plan, related to the criteria with which it is intended to address, follous:
I. Pumo Oceration Criteria Which Can Result in RCP Trip Durina Transients and Accidents
- 1. Setpoints for EP Trip:
- a. The RCP trip criterion, based on loss of subcooling margin, was developed with the intent of assuring that an indication l for E pump trip would occur for those SSIDCAs where puxp trip was required to meet the criteria of 10CFR 50.46. A spectrum of analyses has been performed using Appendix K assumptions which demonstrate that a loss of subcooling will always o: cur for small breaks that have de potential to uncover the core and exceed 10 CFR 50.46 criteda if the RC?s are nn.ppec uncer certain two-phase conditions. ?.erefcre,1 css of subcooling can be used as an indicator of the need for RCP trip. The actual value of the setpoint (25'F) will be verified te ensure that dis indicator will allow continued forced RCS ficw during realistic SGTPas up to and including the design basis 53~5. - a single doublo ended rupture. The setroint will als: te verified to include consideration for minimizing the indication for need :c trip RC purps for more likely non- E A events such as a =ild overcooling transients.
No partial or staggered RCP trip scheres will be considered except ftr the extreme case where mechanical damage to the pump is likely as this adds tc increased decision making cn the part of the operator during transient conditions.
i'
- b. The RCD trip critericn based en sicocling rargin precludes operation of the RC pt=ps in a highly voided system (except
! for ICC conditions).
- c. A prirary objective of the parameter and setpoint ve-ifica:icn
! is the avoidance of reactor coolant ptro trip for non-IDCA events carticularly SGIR. Realis ic coerator actions in accorda'n ce with th'e procedures are exo'ected to avoid loss of subcooling and the need to trip the reactor coolan: et==s for this event. Furtherrore, since subcooling rargin would be quickly regained following rakeuo or hoi initiatien. with-out loss of narral circula:icn even if the coerator failed to take actions to prevent RCD trioping and ESFAS actuation, restart of the ptrps would be allowed. Consequently, reliance on the PORV for depressurization is inlikely.
! d. The significance of prirary systen voiding due to flashing of hot coolant is disucssed as part of operator training.
The subjet void treatnent is being su plemented by additional guidance cn preventicn, detection, and ritigation of voids.
This is considered outside of de AIOG scope but will be addressed.
- e. Acticns follcwing ccntainment isolation sigrals will be reviewed to ensure censistency in the treatment of availability of cooling water and seal injection to prevent ping darage. Instructions for ptro trip are provided in the ATOG guidelines in the tulikely event of rechanical pino dxmge. Crtieria for restart of RC piros include asscing that cooling water and seal injectica are available.
Existing IMI-l procedures also include the guidance.
- f. Instructions for raintaining or reinitiating forced RC fics are contained in A10G for ICC conditicas.
- 2. Guidcace for Justifica:ica of Yz::;al RCD Trip
- a. A spectrint of s all break IDCAs has been analyzed for 17 and 205 FA plant types using the CRA_O code. Using the Aapendix K evaluation tec6.icues, dere eds s a ceiination cf. break sizes and RC ptro trip tires :6ich result in exceedi .g 10 C:R 50.46 lirits. Fcr de rcrs: breah size, i.e. , da:
size which requires the earlies p r : rip, crio rast occ c within 2 rinutes of the indicarict of need for ptro :-ip.
As break size decreases, tore d e is available for cperator action. d e critical ti e period of high void for a ic.
(>70%) when RC ptro trip is not recc nended, has ,also bean deter-ined. The critical ti.e neded for de break recui--int the earliest coeratica actic: th.e is she:: (5 :::nutes)' 16en' ping trip coul'd result in exceedi .g 10 CFR 50.4 criteria.
- b. A best esti: rate SELOCA analysis Wil'. be performed for each general plant type, over the spectrc of sizes detemined by the conservative analyses to de:ecine (a) the time available for a regaired r ptrg trip, and the period of time when r p=p trip is not reco::nended or (b) de lack of indication for a reqaired pirrp trip. If it is determined that a need for I pump trip exists, the time for cpera:c action will be determined and justified by cccparison to ANSI Standards and operating experience. An indication of reasonable operator action time is expected to justify :anual RCP trip.
- 3. Other Considerations
- a. The level of quality of instrumentation, as described in the enclosure to the March 4,1983 letter, used to produce the signal indicatire the need for PC p=p trip, will be provided by GPUN to supplement the B&h*OG generic subtittal for treat: rent of RC peps during transients.
- b. The A E guidelines and plant specific Emergency Operating Procedures contain criteria for the ti ely restart of reactor coolant pumps when conditions which will support safe p=p operation exist. Table 6 of the Egaipment Operator chapter of ATO3 provides the conditions when r pumps can be restarted,
- c. Plant operators have been trained in their responsibility for perfo=ing FCP trip in the event of a small break ICA.
Current plant procedures (non-AT33) regaire RC p=p trip on 25*F subcooling targin. Instructions for plant operation are reinforced by regular regaalification class and simulater training. Operators have been trained on the concept cf r pump trip on subcooling rrargin.
II. Pun = Ooeration Criteria hhich Till Not Result in PCF Trip Darinc Transients and Accidents Since it is the position of the E&h'33 and E&W ds, de safes method for PC pump operation following SSLOCA is (:anual) trip, .e criteria statef i.- dis section will not be addressed.
4_
PLAN EUR RESCLUTION CF 'S'.I ACTION I'1 lim II.K.3.5 ;
t
" Automatic Trip of Reactor Coolant Pumps" i
i INTRODLCTION The criteria for resolution of NUREG-0737, Ite: II.K.3.5, " Automatic " rip of Reactor Coolant Pu:tps", are provided in a letter from D. G. Eisenhut (h40) to GPU Nuclear on March 4, 1983. As discussed in cur letter of March 31, 1983, GPUN has revised the PCP Trip Criteria from 1600 psig ESAS to 25"F subcooling margin under 10CFR 50.59. The B&W CAmers Group has been formulating a plan to demonstrate compliance with those criteria. 2.e following represents this overall position and plan.
PLAN ECR TREADENT OF PC PUFP CPEFATION The treatment of reactor coolant prps during accidents and transients has received extensive attention over the past several years. THE B&W CAmers Group has performed analyses cvaluating the effect of a delayed PC p=p trip using Appendix K assurptions during the course of a small break IICA accident and has determined that an early trip of E p _ ps is recuired to sh0w .
conformance to 10CFR 50.46 for a range of break sires. Therefore, to be consistent with the conservative analyses perfc=ed, it is our position dat the reactor coolant pumps should be tripped if indications of a small break LOCA exist.
The B&W Oviners Group and B&W maintain that it is highly desirable to maintain FC pump cperation during non-L C. events, as an aid in de citigation cf transients. Consistent with this phioicsophy, the concept of subcooling margin was chosen as an indicator for the need to trip FC prps. It is cur intention te demonstrate that this concept is consistent with our philosophy for handling RC pumps during transient conditions end cc plies with de intent cf the criteria stated in your letter of March 4, 1953. The syrc tor approach cf subcooling margin, developed as part of the Ahn =El Cransient Opera ing Guidelines Program, is intended to replace the presen: guidelines of tripping solely on the presence of a low PC pressure ISTAS sig al.
It is the position of the B&W CAmers Group and 3&W dat reacter coolant pa p trip can be achieved safely and reliably by de Opera:cr. It has been determined that a loss of subcooling margin wi'1 occcur for those SELOCAs where a pc p trip is recuirec ,cr cogc_ance ._- .
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- 9. GPU Nuclear Corporation
[ 2 QQ gf Pcs: Office Sex 450
_eute 441 South n
Micetetown. Pennsylvania 17C57 0191 717 944-7621 TELEX 84 2356 Writer's Direct Dial Numoer:
August 23, 1953 5211-83-232 -
O/
d t office of Nuclear Reactor Regulation //
- .$ h 4' Attn: J. F. Stolz, Chief - 4 . 4)b ?.
Operating Reactor Branch No. 4 Dvision of Licensing I
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U. S. Nuclear Regulatory Co==ission / .'
Washington, D. C. 20555
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Dear Sir:
Three Mile Island Nuclear Station, Unit 1 (TMI-1)
Operating License No. DPR-30 Docket No. 50-289 Long Ter: E W Mods (NUREG 0737 II.E.1.1)
In response to NUREG 0737 Ite II.E.1.1 and as discussed in the meeting at TMI-l on July 11, 1983 with members of your S:aff and those of mine, enclesed please find a description of the modifications to the Energency Feedwater (EFW) System to be completed prior to startup fro: the Cycle 6 refueling.
The purpose of these modifications is to upgrade :ne :.:n sys:em to a safe:y grade syste= in order to provide increased reliability in 1:s capability :c citigate the effects of design basis accidents when the =ain feedwater sys:e is not available. These codifica:icns will be cade in accordance with :he recuirements of hTREG 057S Secticas 2.1. 7.a and 2.1. 7.b, NUREG 0737 See:1 ens II.E.1.1 and II.E.1.2, Atomic Safety and Licensing Scard (ASL3) Partial Initial Decision Section II, Subsection Q, and using the acceptance criteria of Standard Review Plan Sections 9.2.6, 10.4.9 and associated Eranch Technical pcsition ASE 20-1 as principal guidance.
The modifica:10ns being implemented as part cf this upgrade include techanica'_
sys:e: configuration changes, mechanical (seistic and elec:rical (enviren-cental) ecuip ent cualification upgrades, chan;es :e the con:rci syster f:r EFW co:ponents and seismic upgrade of piping see:i:ns in the "zin Stear.
Emergency Feedwater and Yain Feedwater Syste=s.
! Sincerely,
'N ! .
] . D. Eu%r;ill Directer. TMI-l HDR:LWH:vj f cc: R. Conte. J. Van Vlic:
GPU Nuclear Corporation is a subsidiary of the Genera: outlic Ut!!it:es Corpora:icn
WIBGEtCY FE!E7CER SYSTN ICG TEW.
SAFEIY GPADE MODIFICATIONS I. INTRCDLCIION A. This document describes the functional, design, quality assurance, health and safety, and licensing requirements for the installation and operation of modifications to the Emergency Feedwater (EN) System of Unit No.1 of the Three Mile Island Nuclear Station (TMI-1) .
B. The EN System shall retrain generally as presently configured with modifications to insure the addition of emergency feedwater to both OISGs assuming a single active failure concurrent with loss of offsite power. In addition, the !
modified system shall be capable of previding controlled {
emergency feedwater flow to an intact OISG for at least two !
hours without relying on alternating current (AC) power.
Conversion of direct current (DC) from the station batteries to alternating current is acceptable for this application.
- 1. All autwatic initiation features provided for the EN system shall be retained. A new automatic E N control system for controlling OrSG level independent of the Integrated Control System (ICS) shall be provided. In addition, the capability to manually control EN flow and set an autmatic level setpoint from the main control room shall be provided.
i
- 2. All the equignent required to initiate or control EN or to realign the 5ater source to the EN pumps with the j
exception of valves EF-V4 and 5 shall be operable from the main control room.
j 3.
A redundant control valve shall be installed in the ficw path to each OrSG in parallel with the existing control valve. A normally open block valve shall be installed downstream of each control valve to provide additional isolation capability of EN fl u to an OrSG. A cavitating venturi has been previded in the E N flow path co each OrSG to limit ficw.
- 4. The installation and arrangement of cavitating venturis, control valves and block valves shall provide accessibility for plant maintenance, inservice inspection and operability of the conponents.
- 5. The installation and arrange.ent of electrical, instrumentation and control ccrponents shall provide testability of equignent and maintenance of electrical separation.
- 6. Mechanical, electrical, instrumentation and control cmponents shall not be located in high energy line break jet zones unless they are shielded from such jets. Components shall be located such that they are not subject to damage from high energy pipe whip.
II. Mechanical Systems Recuirements and Modifications A. Requirements
- 1. Process piping design temperature and pressure shall be consistent with the original design basis of the EEW and related service systems as identified in GAI specification SP-5544 unless system modifications call I for more stringent requirements. I
- 2. All new piping which is part of the EEW system shall be designed, fabricated, inspected, tested and erected in accordance with ANSI B 31.1 " Power Piping Code".
- 3. Inspections required by ANSI B 31.1 shall be performed.
- 4. The seismic design criteria for the piping and support system shall be in accordance with Seismic Class I design bases as defined in GAI specifications SP-5544, item 2:15, " Plant Piping for 7MI" and the UMI-l FSAR.
Seismic identification symbol shall be S-I.
- 5. Installation, erection and testing of all piping shall be in accordance with ASME Section XI.
- 6. Installed cleannest class shall te Class B in accordance with GPU K Spec. 3050B-001.
- 7. All new valves and the cavitatire venturis shall be designed and fabricated in accordance with ASME Section III, Class 3.
B. Modifications
- 1. Add Cavitating Venturis in each Once Through Steam Generator (OrSG) EEW Line. (Complete)
- a. This modification has been implemented to limit the flow of EEW to a ruptured MSG in order to ensure sufficient EEW flow to the inc'act MSG and to limit the mass and energy release within the reactor cuilding for overpressure prevention. The venturis will limit the flow to the WSG in order to reduce excessive reactor coolant system (RCS) overcooling.
- 2. Provide Redun$ ant Safety Grade EEW Control and Block Valves
- a. This is being provided to prevent a single active failure from preventing the addition of EEW to an TSG and to ensure the capability to isolate EEW flow to a ruptured MSG.
- b. The control valves shall have sufficient range to control the EEW flow to the TSG(s) when the plant is being cooled and the TSG(s) are being depressurized and the EEW flow requirement is less than that initially required.
- c. The EEW system block valves shall normally be open, and in addition, the EEW initiating signals shall also provide an open signal to the block valves. Each valve shall be provided with an electric motor operator and shall fail "as is' on loss of power. The valves shall also have remote manual operation capability from the main control room.
III. Structural Recuirements and Modifications A. Requirements
- 1. All components which are part of the E N System or which are required to act in support of this system shall be qualified for Safe Shutdown Earthquake (SSE) loadings to ensure structural intecrity and functional operability of active corgonents during and after an earthquake.
All existing EEW system components sball be seismically qualified by analysis or by type tests if required. The qualification of new components shall be accomplished by cither analysis or testing.
- 2. 'Ihe structural design of the EiW system modifications shall be consistent with the original design basis of the EEW system and the related service systems as 1
l 9
identified in the MI-l FSAR and GAI specifications SP-5544 and SP-5661. htere practicable, all portions of the EEW system shall be installed indoors within Seismic Class S-I aircraf t-hardened structures. All portions of the system required to perform the safety function shall be designed to Seismic Class S-I requirements.
- 3. Portions of the EEW system located outdoors shall be designed to Seismic Class S-I requirements and shall be designed to withstand the effects of the design basis natural phenomena identified in the MI-l FSAR Section 2.
- 4. All piping and valves shall be connected and supported in such a manner that any stress due to weight, thermal effects, internal piping conditions and external enviroment will be within the maximum allowable stresses required by the ANSI B. 31.1 " Power Piping Code".
- 5. Structural steel shall be designed in accordance with AISC-70 (including latest supplements) using ASE-A36 steel, except weld unit stresses shall be as specified in Table 9.3.2.1 of AWS Dl.1, -79 " Structural Steel Welding Code".
B. Modifications
- 1. Upgrade the EEW pumps recirculation line from recirculation control valves (EF-V-8A/B/C) to Condensate Storage Tank (CO-TlB) to Seismic Class I requirements,
- a. This modification will ensure that failure of this piping due to a seismic event shall not occur and thus prevent depletion of the required CST inventory for the EEW function.
- 2. Evaluate and modify de vent stacks for safety valves MS-V22A/B and atmospheric dump valves MS-V4A/B to Seismic Class I requirements.
- a. The vent stacks for safety relief valves FS-V-22A/3 and atmospieric dtrp valves >S-V-4A/B are rcuted through the Intermediate Buildire floors. This modification will prevent the release of main steam to the Intermediate Building as a result of vent stack failure due to a seismic event. )
Therefore, this modification will reduce the :
possibility of overpressurization in the building 1
( and protect the Emergency Feedwater system components form the exposure to the hostile
_, -_ . - . . ,, ,- , - , - - - - - s ~ - - +-
envircraent and gravity missiles.
- 3. Intermediate Building Flood Protection from a Main Feedwater Line Break.
- a. This modification is being inplemented to mitigate the effects of flooding due to a postulated main feedwater line break in the Intermediate Building by allowing water to flow into the tendon access gallery and portions of the alligator pit which are presently isolated. By removing the upper half of the "stop walls" in the alligator pit and opening entrance "A" and "C" to the tendon access gallery, the time recuired for water to flood EL.
295' in the Intermediate Building will be increased from 86 seconds to approxiratey 25 minutes.
IV. Electrical Recuirements and Modifications A. Requirements
- 1. The electric power and control system shall be designed as a Class lE system. Components of the system required to operate during a loss of all AC power (Station Blackout) shall be powered from the non-interruotable vital AC or DC buses.
- 2. Each train of EEW to each OTSG shall be powered from its associated power sources to facilitate safety grade initiation and control of EEW to each OTSG. l
- 3. Electrical equipment shall be qualified in accordance with applicable sections of IEEE 323, IEEE 344, I m 382, and NUIEG-0588 or the Division of Operating Reactor Guidelines appended to I.E. Bulletin 79-OlB as appropriate.
B. Modifications
- 1. Provide a safey grade powcr supply to valves CC-V-lllA/B and upgrade the cable routing for power supply to valves CO-V-14A/B to meet Seismic Class I requirements.
- a. This modification shall provide the capability to isolate a damaged Condensate Storage Tank (CST) from the E m system by closing COV-lllA/B from the Main Control Roan so that the intact CST will have sufficient water available for the E m system function. Similarly, the ability to close CO-V-14A/B from the Main Control Room, will allow isolation of non-EEW functions from the CST.
These features will be used in conjunction with revised E N 'lant operating procedures to close CO-V-14A/BV and CO-V-lllA/B whenever there is an EN initiation and the CST has reached the Technical Specification limit for E N inventory.
- 2. Delete the existing cross connect between electrical busses that allows a control room operator to load both E N purp motors onto a single diesel generator in order to ensure electrical separation of the busses. (Camlete)
- 3. A review shall be conducted of the emergency power bus loadings to assure that changes in bus loadings resultirg from these modifications will maintain the bus loadings within acceptable limits.
V. Instrurentation and Control Recuirements and Modifications A. Recuirements
- 1. New control systems shall be installed to initate and regulate E N flow. Control of EN flow to each OTSG shall be independent of control for the other OTSG.
Each control system shall be of Class 1E (safety grade) design. Electric power for the control systems shall be from safety grade uninterruptable sources.
- 2. The control systems shall be designed so that no sincle active failure will prevent delivery of the recuired emergency feedwater to an OTSG. Also, the probability of a single failure causing inadvertent injection of E m into an OTSG shall be minimized.
- 3. The control system shall be designed to enable control of emergency feedweter for at least two hours during loss of all (on-site and off-site) alternative current (AC) power sources with the exception of the battery backed 120 VAC vital sources. During the loss of all AC
power condition for two hours, only the turbine driven emergency feedwater controls are required to be furetional.
- 4. The design of the safety grade controls shall be in accordance with applicable sections of IEEE 308, IEEE 279 and its supplements and IEEE 379. System level manual initiation ishall not be provided as recomended by IEEE-279. Instead, the system components shall be provided with a manual starting or control capability as appropriate for each camponent.
- 5. All cable routing of electrical and instrumentation shall be checked to comply with Appendix R of 10CFR50 (i.e. , Fire Protection Evaluation) .
- 6. The alligator pit flood detection system shall consist of level indication located in the alligator pit.
Condenser hotwell low-low level alarm can be accomplished via the existing hotwell low-low level i signals.
{
l
- 7. The EEW system shall receive automatic initiation signals for the following conditions:
- a. Loss of both Main Feedwater Pumps, or
- b. Loss of four (4) Reactor Coolant Pumps (FCP), or
- c. Feedwater line break as detected by high Main Steam to Feedwater differential pressure, or
- d. Iow OrSG water level.
- 8. The EEW system block valves shall normally be open and, in addition, the EEW initiating signals shall also l provide an open signal to the block valves. A control switch shall be provided for each block valve for remote operation from the control room. Direct indication of actual valve position shall also be provided in the control room.
- 9. The capability to manually control EEW flow fro:r the control room shall be provided. This capability shall include features to allow independent control of each flow control valve and pcsition indication from each control valve.
- 10. The capability of selecting an automatic level control setpoint shall also be provided,
- 11. The failure mode of the control valves shall be fail-closed on loss of either instrument air, electrical power, or control signal.
- 12. New steam generator level instruments external of ICS shall be provided for the followirg functions. Level is expressed as distance above the top of the lower tubesbeet:
- a. Automatic control of EEW at 30" for the condition of at least one EP operating and 240" for loss of all four EP's.
- b. Initiation of EEW at a low-low OTSG water level of 18".
- c. High level alarm at 337".
- d. Low level alarm at 23".
- e. High-high level alarm to indicate OrSG overfilling. Alarm is to occur at a water level of 380".
- f. Isclation of main feedwater (MEW) on a high-high level of 370" (which is above the ICS high level limit control point of 346") .
9 Operator selected auto level setpoint for use following a ICCA.
- 13. In addition, the ICS shall utilize the instruments for the following purposes:
- a. OrSG 1evel control durire heat up
- b. High OTSG level limit during power cperation
- c. Low OISG level limit during power operation
- d. OTSG level control after the reactor trip.
- 14. The modification of the OrSG level instruments shall use the top of the lower tubesheet as a reference point and use the same measurement unit (i.e., inch). These instruments shall be compensated for process pressure and environmental temperature to aid plant startup-and post trip level control.
- 15. Automatic EEW initiation signals for feedwater line break as detected by high main steam to feedwater differential pressure, or low OTSG water level shall be generated by using four (4) channels of level measurement and 2 out of 4 (2/4) logic for each actuation (Train A and B).
1 I
- 16. EEW control valve modulation shall utilize two (2) channels (one for each EEW control valve) of OrSG 1evel measurement oct of a total of four (4) channels.
However, EEW initiation on low water level shall be ,
dependent upon a 2 out of 4 (2/4) logic. Capability shall be provided to bypass this initiation from the main control room.
- 17. Main feedwater (MEW) control shall be performed by the existing Integrated Control System (ICS) . Isolated fully cortpensated level signals from one (1) of the four (4) channels of level measurements shall be utilized by the ICS as described above. Main feedwater isolation upon high OrSG 1evel shall be initiated by a 2 out of 4 (2/4) logic utilizing these same level signals. This shall be performed external of the ICS. Existing level instruments associated with ICS shall be removed.
- 18. Main feedwater isolation shall also be initiated on a feedwater line break utilizing a 2 out of 4 (2/4) logic based upon differential pressure between main steam and feedwater system and by the Main Steam Line Rupture Detection System (MSLEDS) . The MSLRDS also utilizes a 2 out of four (2/4) logic for detection of main steam pressure below 600 psig.
- 19. Two (2) safety grade wide range OrSG 1evel irdications shall be provided in the control room for each CTSG.
- 20. A safety grade water level indication and low-low water level alarm shall be provided in the control room for each condensate storage tank.
- 21. All instrumentation independent of the ICS and control ecuipment shall be qualified for operability during a Safe Shutdown Earthquake and, when instruments are to be located in the Intermediate Buildirg, for the environmental conditions existing in the Intermediate Building following a main steam line break.
B. Modifications
- 1. Deletion of the Main Steam Line Rupture Detecticn System (MSLRDS) Signals to the emergency feedwater control valves EF-V-30A/B. (Complete)
'Ibe deletion of the MSLRDS signals to the EFK System inproves the availability of the OrSG's as a heat sink
_g.
. _ . _ . .__ _ _ _ _ - ~_ . _ _ - - _
' and improves the reliability and capability of EEW flow to the MSG (s) during loss of normal feedwater flow.
- 2. Provide safety grade EN initiation and main feedwater i isolation on high main steaW feedwater differential pressure.
High main steam pressure relative to main feedwater pressure is an indication of a main feedwater line
- rupture. his indication along with low MSG 1evel) ,
- anticipates failure of the secondary heat sink due to a 1 main feedwater failure.
- 3. Provide a safety grade MSG level instrumentation and signals for main feedwater (MEW) MSG high water level isolation and MSG low water level initiation of the EEW system.
i The isolation of main feedwater on MSG high water level i protects against MSG overfilling caused by failure of the feedwater control system within the Integrated Control System (ICS) .
- 4. The control system shall be of dual setpoint design with j the setpoints dependent on whether or not the reactor coolant (E) pumps are running.
On loss of all four (4) reactor coolant (E) pumps, the control system shall open and control the EEW flow control valves to maintain a higher MSG water level setpoint as required to achieve reactor natural
)
circulation cooling within the Faactor Coolant System (ICS) . If at least one E pump is operating, the control system shall control M SG water level to a lower setpoint sufficient for forced circulation RCS cooling.
- 5. Provide a safety grade automatic control system independent of the Integrated Control System (ICS) that permits the Dnergency Feedwater System to control MSG level without control interaction with the main '.
j feedwater system.
- 6. Upgrade the controls for the Main Steam Line Rupture Detection System to safety grade such that a single failure of the control system will not prevent isolation when required. W e probability of a single failure causing inadvertent actuation shall be minimized.
i The MSLRDS shall identify a ruptured MSG when the main
! steam pressure falls below 600 psig and shall then i
automatically isolate the main feedwater to that M SG.
1
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- 8. Provide an overspeed trip alarm in the Pain Control Room for the turbine driven emergency feedwater pump
('IDEEWP) EF-P-1.
This alarm will provide indication of a loss of a portion of the EEW system.
- 9. Provide an " alligator pit" flood detection alarm using safety grade components and a control grade main l condenser hotwell low-low level alarm in the Main Control Room.
I This modification will provide an operator with a
- control room alarm indicating a possible main feedwater line break.
- 10. Evaluate the Emergency Feedwater ard Engineered Safeguard (ES) Electrical Power, Control, and Instrumentation Cables that are presently routed through the alligator pit.
The EEW and ES electrical power, control and instrumentation cables need to be evaluated to determine their capabilty of performing their safety function after a main feedwater line break incident and subsequent alligator pit flooding.
- 11. A portion of the existing EEW system controls is within the ICS. This interface is being replaced with the modification as identified in previous sections. OTSG level measurements associated with the EEW system shall be provided to the ICS through suitable isolation.
VI. Miscellaneous Criteria A. Electrical and Control Equipment Environmental Qualification Equignent which is part of the EEW system or which is required to act in support of this system and which is located in the Intermediate Building, shall either be upgraded to be qualified for the hostile environmental conditions resulting from a Main Steam Line Break (MSLB) in this building or te replaced with qualified equipment or be relocated to an environmentally acceptable location which is otherwise suitable for their safety function.
B. Maintenance Maintenance of valves, irstrumentation and controls shall be accar.plished in accordance with manufacturer's instructicas and recomerdations. Pipe routing and equipment location shall be selected to facilitate maintenance and be consistent with the regairements of Section I.B.
C. Surveillarce and In-Service Inspection Inservice inspection requirements of ASME B&PV Code Section XI for system design and inspection apply to the design of these modifications.
The system shall be designed to allow functional testing of all new equipr.ent during cold shutdown conditions. It shall also be designed to allow for periodic testing in accordance with the 'IMI-l Technical Specifications, Section 4.9. The design shall be consistent with requirements of the 'IMI-l Technical Specifications limiting conditions for operation of the turbine cycle, Section 3.4.
D. Interfacing Systems These modifications require interfaces with the Main Feedwater, Main Steam, Condensate, Instrument Air and Class lE electrical systems as specifically identified in previous sections.
Charges to any of these systeIrs shall not degrade the ability of these systems or any other plant systems to perform their design furrtions.
E. Testing Requirement Adequate provisions shall be made in the design of the system modifications to allow hydrostatic testing of the piping system, calibration of instrumentation, and functional testing of the controls and alarms.
F. Quality Assurarce This modification is classified as Important to Safety.
Quality Assurance requirements shall be in accordance with the
" Operational Quality Assurarce Plan for Tnree Mile Island Nuclear Station, Unit 1," with specific requirements as i indicated.
i I
)
i l_________________ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ . _ _ _ _ _ . _ _ _ _ _ _ . _ . _ _ _ _ _ _ _ _ _ . _ _ . . _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _
G. Human Factors Human factors reviews of the man-machine interfaces shall be performed to aid in the develo;xnent of the system modifications. The interface points of type, location and arrangement of controls and display, system labelling, alarm / warning system logic, maintenance recuirements, and procedural guidelines shall be reviewed and documented.
H. ALAPA The design of this sytem shall implement AIAFA concepts for both the construction activities and for the operating and maintenance aspects of these modifications. The ALAPA inpact of these modifications on other systems and personnel access shall also be considered in the design of these modifications.
/
1 y GPU Nuclear Corporation
- 2 }g Q %f ,
20st Office Box 45; Route 441 South Middletown, Pennsylvania 17057-0191 717 944 7621 TELEX 84 2386 Wnter's Direct Dial Nurnber:
September 7, 1983 5211-83-250 59 N
G i
Office of Nuclear Reactor Regulation 1
~
A: n: J. F. Stolz, Chief 8/
Operating Reactors Branch No. 4 % 3. T .d .d .S ,
Division of Licensing -0 U. S. Nuclear Regulatory Co==ission 6- 4 E83IEU IJashington, D.C. 20555
[
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Dear Sir:
a Three Mile Island Nuclear Station, Unit 1 (TMI-1) .
Operating License No. DPR-50 Docket No. 50-289
} 25 F Subcooling Margin l The purpose of this letter is to inform you of the results of recent y reevaluations of instru=ent string error and the RCS physical configura: ion j factor associated with the subcooling =argin =onitor system. In our letter i of March 31, 1983 (5211-83-017), GPUN indicated that a 25 F subcooling cargin (SCM) action point for RCP trip was justified based on calculations performed during accident conditions (i.e., SE LOCA) which showed that the j =aximum string error for pressures greater than 300 psig is -18.7 F (-21.7 F) with an assumed 5 7 physical configuration factor. This f actor was assured
{ :o bound any difference between the indicated pressure at the het leg pressure 4
instru:ent and the actual pressure at the top of the ho: leg.
1 t
Since March, we have reevaluated both the ohvsical conficuration factor i and the string error. These evaluations concluded that Ehe 5 F physical i configuration factor could be reduced to less than 1.3 ? (Ref. 1) to account for the elevation difference from the irstrument tap te the top of the ho: leg. Additionally, GPUN has reviewei ' m =r head _de;radation fer
- two phase flow and determined that for an inc. '
25'? SCM, the void fraction at the RC pump inlet is less than 5'i for R. =ure above S65 psig. Using a very conservative RC pu=p head / void f rac._ m relation (Ref. 2), the head degradation is less than 10';. The instruu. rcr
- for 55 LOCA was reevaluated using more conservative assumptions o.
deter ined to be + 22.1 F (Ref. 3 & 4) and for nornal condi: ions was evaluated to be 4 10.3c. ihese chanzes do not alter our cenclusion tha: the 25 ? indicated subcooling cargin action pein: for RCP trip is appropriate, but they do modify the assumption used by the Appeal Board in ALAS-729, dated May 26, 1983. The Appeal Scard agreed with the 25 F i
SCM action point "providing the 20 F error in the TMI-l instrumentation is no: exceeded". Our reevalua: ion shows tha: :he ins:rument string error GPU Nuclear Corporation is a subsidiary of the General Public Utilities Corporatic[ -
_y_ . _ _ _ _ . - . _ , - - _ _ - . , _ _
Mr. J. F. Stol: 5211-83-250 exceeds 20 F..., y; SB LOCA conditions, but is entirely offset by the conservatism in the physical configuration factor.
Consequently, our conclusion that the 25 F cetion point is appropriate remains valid.
Sincerely, j .I 1 i H. D. Hunill Director, TMI-l HDH:LWH:vj f cc: R. Conte i
J. Van Vliet 4
Ref. 1. GPUN Calculation 1101x-5450-015 (Attached) 9 EPRI Report (NP2578) "Two Phase Performance of Scale Models of i
a Primary Coolant Pump", dated 9/82, p. 6-12
- 3. GPUN Calculation 11014-3223-009, Rev. 2 & 3 (Attached) l 4. GPUN Calculation C-1101-655-5350-001 (Attached)
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< 'N September 9 S3 5211-83-2!. - *1,3 ,d .d .g -
ggg 1 3 33g ~3 Office of Nuclear Reactor Regulation ~ l Attn: J. F. Stair, Chief i Operating Reactors Branch #4 e' gg. Division of Licensing U. S. Nuclear Regulatory Commissica ~ Washington, D. C. 20555
Dear Sir:
Tnree Mile Island foclear Station, Unit (TMI-1) Operating License No. DPR-50 Docket it. 50-289 Relief and Safety Valve Testing (NUREG 0737, II.D.1) _a response to your letter of July 5,1983 and as discussec between members of your Staff and mine on July 26, 1983, enclosec clease find our response to your questions. Accitionally, RELAP V analysis for the 400cF succcclec water concition were transnitted to EG&G Idaho ori August 5,1983. Sinc
!; }erely ,
C~
~-
k.,,D.Hukill') Vice President - TMI-l cc: R. Conte J. Van Vliet GPU Nuclear Cor::cra!. is a s.:sc 2'. C' t-: GE~e .: ! !. : e5 C T'c 'a":-
i t RESPONSE TO NRC LETTER DATED JJLY 5,1983 RELIEF AND SAFETY VALVE TESTING 9
. Item 1. Selection of " feed and bleed" as the transient that would proouce the maximum loads on the discharge piping could not be verified since no discussion of the methods or details of analyses are 4
included in the submittal. The submittal cites the Electric Power Research Institute (EPRI) report, " Valve Inlet Fluid Conditions for Pressurizer Safety and Relief Valves for B&W 177-FA and 205-FA Plants", as justification for the selection. The cited report does
- .not describe a transient titled " feed and bleed". The conditions identified in the submittal, subcooled water at 4000F and 2500
) psig, appear to be those resulting from extended high pressure j injection events. A discussion should be provided describing the
- methods used to select the limiting transient and clarifying the events of the transient.
j Response: The teIm feed and bleed (also referred to as extended HPI) is discussed in section 4.4 of the " Valve Inlet Fluid Conditions for Pressurizer Safety and
- Relief Valves for B&W 177 and 205 FA Plants". In this report, 3 specific a
limiting cases are discussed. Case 1 - High temperature water SB LOCA less than 0.02 ft.2 i
, In this case the energy discharged through the break is not sufficient to remove core heat. No main or emergency feedwater is i assumed available to sustain natural circulation on the primary j side. Heat removal is accomplished by high pressure injection into the primary with discharge through the pressurizer safety / relief
] valves. Case 2 - Low Temperature Water - Steam Line Break l
- In this case the overcooling event is intensifed by using minimum
, core decay heat, large uncontrolled emergency feewater flow, and no j operator action to throttle or stop HPI. A minimum of 4000F ; subcooled water discharge resulting from the analyses was performec in response to IE Bulletin 79-05A&B.
)
; Case 3 - Steam - Startup Rod Withdrawal
~ The design basis event'for TMI-l with a steam discharge is the startup rod withdrawal accident (See FSAR Section 14.1.2.2). The
; transient is terminated by the high pressure trip.
The report on valve inlet fluid conditions also set the limit for pressurizer surge line flow' rate. As it rhall be presented in the response to Item 8 in detail, the TMI-l plant specific maximum surge line in-flow is much less than the set limit, and the corresponding EPRI test has resulted in a safety valve i flow rate much greater than that the TMI unit would generate. Since only one safety valve is assumed open at a time, then the surge line in-flow is 1 0 I
. conservatively equated to safety valve cisenarge flow. This leaos to the l conclusion that both the fluid conditions and the test results are applicable to TMI-1.
- Item 2. The submittal does not include a discussion of consideration of single failures after the initiating events. NUREG-0737 required selection of single failures that produce maximum loads on the
. safety valves. A discussion should be provided describing how the l single failure considerations required by NUREG-0737 are met.
Resoonse: As described in the response to item 1, the bounding cases are a hign and low temperature water condition. The single failure, for the purposes of this analysis, for the high temperature water case is an assumed loss of emergency feedwater which necessitates extended HPI operation (Feed and Bleed). The single failure, for the purposes of this analysis, for the low temperature water case is no operator action to throttle HPI during the overcooling event (additionally, EFW Flow is also considered uncontrolled). , The single failure, for the purposes of this analysis, for the steam case is no pressurizer spray capability in the pressurizer. All other license basis events result in lower loads on the safety / relief i valves and discharge piping. Item 3. Overpressure transients will cause the pressurizer sprays to activate adding moisture to the steam volume. When the safety valves lift or the power operated relief valves (PCRVs) are opened they would be passing a steam-water mixture. Was this effect
- censidered in the analyses done to select the transients that !
produced maximum loads on the discharge piping? l
Response
, l 1
The analyses performed on the safety / relief valves indicate that steam / water exist in the valve and down stream piping resulting from flashing of water or condensation of steam. A specific steam-water analysis was not performed. However, a steam analysis (Attachment 3) and a water analysis (Attachment 1) were performed which indicate maximum loads occur for water discharge. ) The purpose of the B&W report is to document the expected range of fluio inlet conditions to which the PORV and SRV's may be subjected. The B&W report does not evaluate two phase inlet conditions. Discharge piping design input assumptions such as: a) lower than expected
~
inlet water temperature, b) higher than ratec valve flow rate (see response to
a item no. 7), and c) fast opening time (see response to item no. 16), are deemed sufficient to insure conservatism in the analysis. Item 4: The evaluation by Babcock and Wilcox (B&W) that showed up to 20% blowdown can be tolerated without any adverse effect on safety could not be verified since details of the analyses were not provided. The evaluation was based on hot leg voiding but no
. discussion was included to demonstrate that it is the limiting criteria. The increased blowdown would also cause a higher rise in the pressurizer level during transients that result in the safety valves lifting. No discussion is provided to demonstrate the level will not reach the discharge piping connection resulting in a transition of flow through the safety valves from steam to water-steam mixture. Details of tne analyses supporting the I
conclusion that there will be no adverse effect on safety and details of the analyses demonstrating that the water level will not reach the discharge piping should be provided.
Response
Attached, please find a copy of the " Pressurizer Safety Valve Maximum Allowable Blowdown" (Attachment 2), which discusses the details of the analysis. Hot leg voiding has been identified as the primary safety concern relative to the maximum allowable PSV blowdown. The potential for hot leg voiding exists because of the lower system pressure that will be caused oy larger PSV blowdown values. These lower pressures combined with transients that produce high system temperatures could result in saturation conditions and voiding that could impede natural circulation cooling. This increase in pressurizer safety valve blowdown is not a direct safety concern. All nuclear plants are designed to accomodate Loss of Coolant Accidents including that which would result if a pressurizer safety valve sticks in the open position - i.e., an unlimited (100%) olowdown. An additional desirable criteria would be that the pressurizer not fill for f the larger PSV blowdown values. The pressurizer has a greater potential for ' filling because the larger blowdown values will allow large insurges during the blowdown cycle. The same EPRI tests that identified the blowdown concern also showed the safety valves were generally able to relieve two-phase fluid ' and water; thus, filling the pressurizer is a concern of secondary importance. Item 5. The B&W Report on " Valve Inlet Fluid Conditions for Pressurizer Safety and Relief Valves" does not include the consequences of a reactor coolant pump shaft seizure, which is the accident which, in some plants, results in the fastest increase in ano the highest peak reactor coolant system pressure. Why wasn't this considered in determining the worst case transient? O ____ __________w
= - . .-- _ .-. _ - -_ - - _ --
Fesconse: Section 14.1.2.6.3 of the TMI-l FSAR addresses the locked rotor transient 1 which results in a flux-flow trip. The B&W design mitigates the consequences of the accident which yields high pressures in the Westinghouse design. Attachment 2, Table 2 indicates high pressure and temperature events for B&W reactors. The " Valve Inlet Fluid Conditions for Pressurirer Safety Valves and Relief Valves for B&W 177 and 205 FA Plan B" did not include this transient sines it potentially does not challenge the PCRV or safety valves (15 psig above nominal). Item 6. The submittal states that the ring settings to be used for the safety valves are those that showed the most stable valve configuration during the Electric Power Research Institute (EPRI) , testing. The specific ring settings, however, are not identified. The back pressures for steam flow are given in the submittal but I the back pressures for flows with subcooled water at the valve I inlet are not provided. The submittal does not discuss the test valve performance to verify that the valve did perform satisfactorily. The specific ring settings to be used should be provided . A comparison should be provided that demonstrates, with the specfied ring settings and appropriate back pressures, the valves will have stable operation for the Final Safey Analysis (FSAR) transients, will pass rated steam flow and will pass adequate flow to protect the primary system from over pressure for transients with subcooled water at the valve inlet. Resconse: By GPUN letter cated October 28, 1982 (82-260), GPUN informed NRC that the safety valves had been adjusted to the EPRI ring settings. The TMI-l plant specific ring settings are as follows: Lower Ring +11 notches Middle Ring -40 notches Upper Ring -48 notches The EPRI test parameters were established to envelope the B&W, CE and l Westinghouse transient conditions by using the most severe transients. Backpressures were established by EPRI using the maximum allowable backpressures per valve manufacturer requirements. A valve that operates satisfactorily at the most severe test conditions will meet plant conditions , which are less severe. The TMI-l conditions are bounceo by the EPRI test conditions. The valve ring settings are based on satisfactory performance on steam transients because the valve was designed for steam. Therefore, the ring settings for steam have to be the ring settings for water. See answer to question 8 for discussion of valve performance with subcooled water.
f Item 7. The submittal describes the safey valves as Dresser Valves Model ' 31739A with a rated relief capacity of 317,973 lb/hr. however,
; the same model valve used in the EPRI test program is icentified 1
in the EPRI test report with a rated relief capacity of 297,845 l lb/hr. The apparent difference in rated flow should be explained. ' ) Resconse: See second note on bottom of Table 1 of revision 1 of Gilbert report (Attachment 1) for a discussion of flow rates. Dresser Valve Model 31739A has only one orifice size which is 2.545 in.2 Therefore, the only variable in the capacity equation (W=51.5 KAP) is the inlet pressure. The higher the inlet pressure, the higher the flow. W = capacity in lb/hr K = constant = .8775 = .9 x .975 A = orifice area = 2.545 P = pressure = 2500 psig + accumulation + 14.7 psig W = 51.5 x .8775 x 2.545 x (2500 + .03 x 2500 + 14.7) = 297,8461b/hr.
! W = 51.5 x .8775 x 2.545 x (2500 + .1 x 2500 + 14.7) = 317,9731b/hr.
The higher flow rate was used for conservatism in the analysis of the discharge piping. j Item 8. The EPRI test series for the Dresser Valve Model 31739A included a test at 400cF subcooled liquid in which the valve only partially
- opened. The system pressure continued to accumulate and the test
! was terminated. The test considerations nearly duplicated the i conditions for the subcooled transient selected in the submittal. Verifications should be provided to demonstrate that the valve j will provide sufficient flow to relieve the pressure for the ] selected transient. Resconse: ; Under the EPRI proposed bounding conditions, namely, extended operation of ! three large HPI pumps (620 gpm 8 2500 psig) and maximum (1.2 times ANS) dec&y i heat, assuming the valve inlet temperature to be 5790F, initially, the valve inlet temperature and surge line flow are calculated to be: } Time Temperature (oF) Flow (1bm/hr) 0 579.0 227,000 1 hr. 530.0 240,000 2 hrs. 470.1 255,000 3 hrs. 433.5 264,000 Under the realistic conditions of TMI-1, i.e., 2 HPI pumps (480 gpm G 2500 { psig) and 1.0 ANS decay heat, the fluid conditions are: f l
. . _ _ _ _ _ - - -~- - - - . . _ . - _ . - - . - - - -.-. .- ,_- .-_ -
Time Temoerature (oF) Flow (lbm/hr) ; O 579.0 174.000 1 hr. 547.5 182,000 2 hrs. 496.9 192,000 3 hrs. 463.5 200,000 The EPRI water tests at 550oF and 4000F (tests 1112 and 1114) resulted in maximum flow rates of 450,000 lbm/hr and 500,000 lbm/hr, respectively. Although in the latter case, the system pressure continued to 3ccumulate and the test was aborted at 2750 psia, the valve open flow rate excceeds that calculated for both realistic and bounding cases for TMI-1, and thus should be considered acceptable. Review of the B&W Valve Inlet Fluid Conditions reveals that in the determination of the surge flow, B&W has incorporated conservatism by taking the sum of two terms: one for HPI injection and one for thermal expansion. Actually, as cold HPI water is mixed with hot RCS water, a contraction is resulted that reduces the net expansion cwing to core decay heat. Item 9. The submittal lists the TMI-l power operated relief valve (PORV) as a model 31533VX-30 with a 1-3/32 in bore. The PORV tested by EPRI was a Dresser Model 31533VX-30-2 with a bore diameter of 2-5/16 in. The effect on performance resulting from the difference in models and bore diameter should be addressed. Resconse: The EPRI Valve Selection /3Jstification Report discusses the differences between the various Dresser Valve models and the differences in bore diameters. The TMI-l valves have been modified to have the -2 internals and therefore, there is no difference in operation between the TMI-l valve and the EPRI valve. Both valves have the same size internals. The only difference between the valves is in bore diameter and this affects capacity only and that only in a minor way. The valve functions as a result of pressure ratios based on seat diameter and both valves have the same seat size (1-5/16"). Item 10. The Dresser PORV tested by EPRI failed to close and had a delayea closure for the test conditions of low temperature water followed by 5500F water. Verification should be provided to oemonstrate that this performance of the valve will not have an adverse effect on the safety of the plant.
Response
These tests were for a cold loop seal discharge followed by hot pressurizer water. This test is for plants which have a loop seal before the PORV. TMI-l does not have a loop seal before its PORV. Therefore, this test is not applicable to TMI-1.
. Iten 11. NUREG 0737 requires qualificatien cf tne clock valve. Specific cata demenstrating qualification of the clock valve is not given in tne submittal. A reference is made to a report by R. C. Youncahl indicating satisfactory perfornance for a similar valve. Tne TMI-l block valve is identified as a velan 2-1/2 inch gate valve F9-4549-13MS with Limitorque operator SMS-00-10. The valve tested in the EPRI program was a Velan Valve, E10-30548-13MS. The EPRI tests demonstrated closure only with steam. Accitional information should be provioed to verify that the test valve adequately represents the TMI-l valve and the testing with steam only provices acequate l
assurance that the valve will open Eno clcse satisfactory for the required plant conditions. Resoonse: TMI-l Block Valve F9-4548-13MS EPRI Test Block Valve 810-30548-13MS F = flanged end B = Butt weld ends )No affect on representation 9 = 2-1/2" 10 = 3" ) cue to* similarity of valve 4 = 2500 lb rating 3 = 1500lb rating ) internals & operation 5 & 05 = conventional port gate valva, ) OMY l 48 - vertical stem, bolted bonnet ) 13 - 316 stainless steel body )Same for both valves MS = 316 stellited disc & seat, 630 stem ) The TMI-l valve and the EPRI test valve are the same Type Velan valve (style, internal design, operation) except for size, pressure rating ana valve ends which have no effect on valve operation. The valve motor operator sizing equations use pressure to determine required operator torque outputs. The fluid and/or flow rate are not used in the sizing equations. Therefore, an operator sized to close a valve against a 250 psi pressure differential will operate on eitner steam or water flow. Two Velan valves were tested curing the EPRI test, both with the same m0cel number. One was an olcer version of the valve ano is similar to the TMI valves. The other is a newer version and is also similar to the TMI valves with regard to internals and operation. Tne alcer valve has an SB-00-15 operator and the new valve has an SMB-000-10 orerator. Both valves operated
, satisfactorily during the testing. The older valve starteo with a torque switch setting of 1.7 (155ft-lbs). Supplemental tests were rua down to a toraue switch setting of 1.0 (82 ft-lbs). Tne new valve startec with a torque switch setting of 1.5 (110ft-lbs). The supplemental tests were run down to a torque switch setting of 1.0 (62ft-lbs). During the tests the inlet pressures during flow were approximately 2300 psig - 2L00 psig with flows of approximately 235,000 lb/hr. (The older valve's operator was originally procures for a 12" gate valve per Limitorque). Tnere was minor seat leakage at the lowest torque switch setting, but dic not affect valve operation.
m . __ _ , . . . _ - - ---Q
The TMI-l valve originally had a torque switch setting of 1.5 - 2.0 (60ft-lbs to 75ft-lbs). The setting was revised in 1981 to 2.75 (98ft-lbs). This revision was due to a review of the torque switch setting based on the EPRI test data and using a 2750-psi delta P. The required output torque was calculated in the same manner as the output torque calculated for the EPRI test valves. The reason why the EPRI test valves have a higher torque is because the EPRI valves are 3 in. valves. The area term of the differential pressure component is the reason for the increased required torque in the EPRI valves. Based on the Limitorque method of calculating, the TMI-l torque switch setting is consistent with the EPRI test data. The Limitorque method of calculating required output torque uses the differential pressure to determine the required total stem thrust. The type of fluid causing the oifferential pressure is not of a concern. Only the differential pressure is important. The EPRI valves were tested in the horizontal position and the TMI-l valve is installed in the vertical position. The difference in orientation coes not affect the test results or the application of the test results to TMI-1. The valves are designed for both orientations. Also the Limitorque sizing calculation does nct require the orientation. The valve disc is guided in the valve body so that internal valve forces do not affect valve operation or required stem thrust. Therefore, operator sizing is the same for both vertical and horizontal orientation. The THI-2 block valve is a Velan Model F9-3548-13MS, the TMI-l valve is a Velan Model F9-4548-13MS. The only difference is that the TMI-2 . valve is rated at 1500 lbs and the TMI-1 valve is rated at 2500 lbs. Both valves have the same size motor operator, SMB-00-10. Although the TMI-2 torque switch setting cannot be verified, it is assumed that it is the same as the original TMI-l torque switch setting. This assumption is based on the fact that the THI-1 valve was originally procured for THI-2 and the TMI-2 valve was purchased as a direct replacement for the original valve. The valve installed in TMI-2 did operate satisfactorily during the March 29, 1979 incioent. The torque switch setting is assumed to be approximately 1.5 - 2.0 (cutput torque of 60ft-lbs to 75ft-lbs). Item 12. Describe what steps are being taken to remedy the recent corrosion observed on the TMI-1 PORV which has been attributed to excessively corrosive reactor coolant water. Are the valves being modified in any way to help eliminate this problem? It is our
, understanding that the loop seal in the safety valve inlet piping has been eliminated. Will this aggravate the corrosion of the safety valves since the valves will now be in direct contact with the pressurizer steam?
Response
Recent corrosion problems associated with the PORV reported on March 7,1983 (LER 83-003) and the remedy was subsequently discussed in Rev.1 to that LER dated June 6, 1983. By eliminating the residual sulfur in the RCS through l
cleaning (H22 0 ) and hydrolazing, deletion of the sodium thiosulfate tank, ! refurbishment of the valve, frequent chemical monitoring, and valve inspection further corrosion is expected to be minimized. The safety and relief valves are not being modified as a result of this problem. The advantage of the loop seal was to reduce H2 cutting of the valve seats. Experience at similar plants has shown this effect to be very minor. Item 13. . The submittal describes the intended modifications to mount the i safety valves and the PORV on the pressurizer nozzles. This modification would significantly affect the loads on the pressurizer nozzle. The submittal does not discuss the effect of the modification and the effect of the valve oischarge loads on the ASME Section III, Class 1 analysis of the pressurizer nozzles. Verification that the Section III, Class 1 stress limits 4 are met should be provided.
Response
The original design of the B&W NSSS provided for safety valves to be mounted directly on the pressurizer nozzle. During the construction phase, Met Ed decided to move the valves to the end of the loop seal and provided a justification for that new design. GPUN, as a result of the EPRI test results, has returned the system to its original configuration.
; Item 14. The submittal states that the safety valves and PORV connecticns , to the pressurizer are assumed as anchors. It does not mention the large displacement of the connection due to the thermal expansion of the pressurizer when heated to operating conditions.
I Verification should be provided that the displacement were considered in the stress analyses of the piping and pressurizer nozzlcs. 1
Response
i Pressurizer nozzle thermal growths were accounted for by using anchor movement inputs in thermal analysis (for example, vertical thermal displacement = 1.375"). Thermal movement calculations are included in Attachment 1, pp. 32-34. - 9 Item 15. The submittal states that the valve nozzle loaos at the outlet flanges imposed by the discharge piping exceeds the allowable
. listed in the vendor catalog for the safety valves and exceecs those shown in the previous design for the PORV. It states that the loads for both types of valves have been re-evaluated by Dresser, the vendor, and found to be acceptable. However, the acceptance criteria and details of the analyses are not given.
Sufficient additional information should be provided so that the I acceptability of the nozzle loaos can be verified or appropriate references cited.
----n -- , - , - - - - , - - , , , , , - - . -v -- -- , , - - , , , - - - - p~---e- < - - - ,~---,gw,- w-w-, -+w-~--w -s w me ->
i
Response
3 By letter dated November 11, 1982, GPUN was notified by Dresser Industries as to the acceptablility of the loads at the outlet flanges: the loads were combined as follows: 1 Normal Operation Deadweight # + Thermal Case #
~
i Normal Operation (safe Deadweight # + 2 x OBE Seismic + ! shutdown earthquake-valve Thermal Case 3 1 closed) Upset Operation Deadweight + Thermal + Blowdown (valve open) Upset Operation Deadweight + Thermal + Blowdown + (safe shutdown earthquake- 2 x OBE Seismic valve open) Nozzle load information is provided on page 55 of the revised Attachment 1. i Item 16. The submittal identifies the initial conditions and valve opening
! times for the safety valves and PORV analyses. However, the l method of handling the valve resistances is not described and the corresponding flows are not reported. Since the ASME code requires derating the safety valves to 90% of predicted flow, j actual flows of 100% of rates are likely. Additional information should be proviced describing considerations of safety valve derating and describing methods used to predict the flows for the safety valves and the PORV.
Response
The valve flow areas used in the RELAP-V models were chosen so as to proouce a steady state steam flow of 370,968 lbm/hr G 2500 psig for each SRV and 116,667 lbm/hr 8 2300 psig for the PORV. These values correspond to rated flow corrected for 10% ASME derating and a 5% error. These values conservatively maximize the discharge piping analysis. The SRV opening times used were obtained from Tables 3.1.1.b and 3.1.1.c of the EPRI Safety Valve Test Data Report corresponding to the short inlet configuration. The shortest opening times reporteo are 0.012 sec. and 0.043 i sec for steam and water conditions, respectively. Therefore, the SRV opening l characteristic used in the RELAP5 analysis was linear opening at 0.012 and 1 0.040 sec, respectively for the steam and water cases. Item 17. Two valve opening sequences were considered in the submittal, the two safety valves cpening simultaneously and discharging without PORV flow and the PORV discharging by itself. These sequences however, may not bound the forces for all possible valve opening I y _
,_m.,_ _,,.3._,. ,.._,._.,p, , ..g-,, , , _ . ,_,-_,.-,.,-,,,-,T *'^"*-"'='-T *P - + ' ' ' ' " * * * *
..a sequences. The experience of EG&G Idaho indicates that maximun forces would be expected when the sequence of opening is such that the initial pressure waves from the safety valves opening reach the common junction, located 1-1/2 ft above the drain tank, simultaneously. The safety valve lines and the PORV line were apparently modeled indepenoently; however, if the PORV is discharging with flow past the junction when the safety valves
. open, piping loads may be significantly affected. Additional justification should be provided to oemonstrate that the sequences considered 37 the submittal are adequate.
Response
The sequences used for the SRV's and PORV are conservative for discharge piping transient analysis and provide bounding loads. (a) SRV Sequencing: Both SRV-A and SRV-8 are conservatively assumed to actuate simultaneously. The design basis loading on the SRV discharge piping is based on the 4000F subcooled water discharge case. Despite having a larger force magnitude, the initial wave spike is not the controlling l load. The fluid momentum results in a later and broader peak on the discharge piping which piping analysis has determined to be the controlling case. These force time history profiles may be seen by reviewing Attachment 1 of our submittal. The length of piping between the SRV's and the common junction is approximately 125 ft. The length of SRV-A discharge piping is approximately 6 ft. longer than that of SRV-B. Further information concerning the fluid condition within the SRV discharge lines and their commen junction can be obtained by reviewing the RELAPS computer run for 400oF subcooled water discharge included herein. Items such as nodal pressure within the discharge lines may be seen by studying the provided nodal pressu:e for components 7 and 17 for each RELAPS major edit cutput. RELAP5 minor edit output also provides information concerning individual pipe segment forces and flow rates from the valves, to the { common junction, and from the common junction in 1 millisecond intervals. (b) PORV - SRV Sequencing:
. The PCRV discharge piping analysis was done secarately. The resulting steady state backpressure at the common junction is 73 psia. Therefore, using a backpressure of 70 psia (RCDT rupture disc pressure rating) acequately models the SRV annalysis backpressure.
Conclusion:
Based on the above, the conservative flow rates, and opening times used in the analysis, the SRV/PORV discharge piping hydraulic loading functions used are conservative.
Item 18. The adequacy of the thermal-hycraulic analyses could not be verified since sufficient detail is not provided in the submittal. To provide for a more complete evaluation, additional discussion should be provided for the rationale used in the selecting key parameters such as node spacing, time steps, valve I flow area and choked flow junctions. Computer printouts of input and output for key problems should also be provided. Suggested i
. key problems are the RELAP5 printouts for the 4000F subcooleo ;
water case for both the safety valves ano the PORV.
Response
Calculations and computer output are available for inspection at GPUN or the contractors facilities. A copy of RELAP V analysis for 4000 subcooled water was transmitted to EG&G Idaho, August 5, 1983. In addition, the following general criteria were used in developing the RELAP V models: (a) Nodal Spacing Near the valve outlet the node size is initially restricted by the geometry of the pipe segment and are typically 0.5 ft. As downstream segments become longer, node length was sometimes increased but the volume change was always less than 50% for adjacent nodes. Our contractors' experience (See Appendix A of our previous submittal) and sensitivity studies described in EPRI/CE Reference 1 of our previous submittal indicate this criteria is sufficient in modelling relief valve discharge transients. (b) Time Step Size The maximum time steps were evaluated using the Courant limit. t= X V+C wnere: t = maximum time step X = minimum nadal length V = maximum phasic velocity C - speed of sound In addition, the minimum time step used was 1 x 10-10 seconds. The maximum time step used was 1.0 x 10-4 sec. (c) Valve Flow Rates
Valve flow rates are addressed ir. response to 16 above. (d) Choking RELAP V junctions were allowed to choke at all area changes. Item 19. Solving the acceleration term of tne momentum balance equation was
. used to develop a forcing function for the structural code. The experience of EG&G Idaho with this technique is that spurious cata spikes will occur during water cischarge transients if every RELAP 5 computational time step is used. However, if a finite time step is used the technique may not include the peak load. A discussion of the solution techniques should be provided which demonstrates the accuracy and applicability of results for water discharge transients. '
Response
The forcing functions for the structural code were calculated by solving the acceleration term of the momentum balance equation by using every RELAP V computational time step. Although this technique sometimes results in spurious force data spikes, this is not the case for most of the forces calculated. See Appendix B (Attachment 1) for force time histories for every RELAP V computation time step. No smoothing out was performed on the curves. Item 20. Insufficient.information is available to assess the structural analyses. A more complete assessment requires description to be key parameters used in the analyses such as damping, lumped mass spacing details of support models, and the integration time step. The submittal infers that only the net unbalanced forces for the RELAP elements were used as input to the structural analysis. A discussion should be provided that describes how the axial extension from the balancing forces on each end of the elements was treated. Computer printouts of input and output for key problems should be provided. Suggested key problems are the TPIPE printouts for the 4000F subcooled water case for the safety valves lifting simultaneously and for the PCRV lifting along.
Response
. The following parameters were used in the analyses.
(a) Damping Ratio = 0 How is zero damping applied? In the direct integration method of TPIPE, the damping matrix C used is computed by C = aM + $K l
Where M is the mass matrix, K is the stiffness matrix. The a ano J are arbitrary proportional facters. The damping ratio is specifieo by specifying a and S in the TPIPE time history analysis inputs. Zero damping is applied by specifying a = $ = 0 in TPIPE inputs. This method is derived from Eq. (13 - 24) in Dynamics of Structures, by R. W. Clough & J. Penzien, McGraw-Hill, 1975. j No damping factor was used in the dynamic analysis. (b) Lump Mass Spacing Lumped masses were calculated for each nodal point by TPIPE Computer Code internally. Analysis node spacings can be found from the isometric drawings to the report. (c) Modeling The support eccentricity has been modelled. The details are available for inspection at GPU or Contractors' facilities. (d) Integration Time Step Analysis time step T = 0.001 second was used in the TPIPE time history analysis for the blowdown load cases. j The forcing functions were checked between RELAP 5 result and TPIPE input to make sure that the analysis time step was acceptable and that the peak ) forces were accounted for. (e) Axial Extension The axial extension e'fect on piping stresses from the balancing forces on each end of the pipe elements were considered in the static pressure analysis by using peak pressure. This should cover the effects of transient pressure and momentum forces combined. Furthemore, the axial balanced forces have no effect on the support design. (f) SRV lifting simultaneously I (See response to item 21.) (g) Print-out of RELAP V for 400c subcooled water condition were transmittea to EG&G Idaho, August 5, 1983. ( Item 21. The submittal indicates that the three piping branches were I assumed to be structurally independent and that the connectons to the pressurizer and drain tank were treated as anchors. Tne interaction of the three branches at the junction 1-1/2 ft. above the drain tank and the flexibility of the connections would
~
appear to have a significant effect on the response ano stress level of the piping. Additional justifications for these assumptions should be provided.
Response
The three (3) piping branches were assumed to be structurally inoependent for the following reasons: (a) The interaction of the three (3) branch lines and the common header is isolated from the pressurizer connections by three (3) intermediate anchors, one on each branch. (b) 1he common junction is located in a relative stiff section of the piping adjacent to the pressurizer drain tank anchor. (c) The piping dynamic stress in the region of the common junction are very low (i.e., OBE stress 2000 psi and blowdown 1000 psi) leaving sufficient margins for the possible olfferences that may result from a more refined structural analysis model. I}}